e10vk
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, 2007
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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:
Common Stock, $.01 par value
(Title of Class)
Securities Registered Pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of
the Securities Act.
Yes o No þ
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or
Section 15(d) of the Act.
Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of 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 10,125,585 shares of Common Stock of the registrant held by
non-affiliates of the registrant on July 31, 2006, the last business day of the registrants second
fiscal quarter, computed by reference to the closing sale price of such stock on the Nasdaq Stock
Market on that date was $294,046,988.
At March 30, 2007, there were 15,517,724 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 2007 Annual Meeting of Stockholders to be filed with the
Commission pursuant to Regulation 14A Part III.
TABLE OF CONTENTS
PART I
Item 1. Business
General
Layne Christensen Company (the Company) provides drilling and construction services and
related products in two principal markets: water and wastewater infrastructure and mineral
exploration, as well as being a producer of unconventional natural gas for the energy market. The
Company operates throughout North America, as well as Africa, Australia, Europe and, through its
affiliates, South America. Layne Christensens 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,
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 industries in which the Company operates are described
below. See Note 15 to the Consolidated Financial Statements for certain financial information about
the Companys operating segments and its foreign operations.
Water and Wastewater Infrastructure
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 rehabilitation 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. Rehabilitation work is often required on an
emergency basis or within a relatively short period of time after a performance decline is
recognized. Scheduling flexibility, combined with technical expertise and equipment, are critical
for a repair and maintenance service provider. Like the water well drilling market, the market for
rehabilitation is highly fragmented.
Demand for water and wastewater treatment services continues to grow, 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, Collector Wells
International in June 2006, and American Water Services Underground Infrastructure, Inc. in
November 2006, the Company has continued to expand 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
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blocked the development of certain projects, forcing mining companies to look overseas for
growth. In addition, technological advancements now allow development of mineral resources
previously regarded as uneconomical. The mining industry has also increased its focus on these
areas due to their early stage of mining development relative to the more mature mining regions of
the world such as the United States and South Africa.
Factors that have contributed to the recent robust international markets for gold and base
metals include the rapid economic growth of China 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.
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 further expand the Companys pipeline
construction and sewer rehabilitation techniques into its geographic markets.
The Company expects to continue to grow in the water well drilling and development, pump
installation and well rehabilitation markets by executing its proven operating strategies that the
Company believes has 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 further expand its pipeline construction and sewer rehabilitation
operations, currently primarily based in the midwest and southeastern United States, into the
broader national markets 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. 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 Oklahoma 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.
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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 and Wastewater Infrastructure
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 systems. The
Company believes its water and wastewater infrastructure division is the market leader in the water
well drilling industry and provides a full line of water-related products and services. Water and
wastewater infrastructure 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 installation and pipeline construction. In fiscal 2007, these services and products
generated approximately 50% of the revenues in the water and wastewater infrastructure division.
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.
Well and Pump Rehabilitation The Company believes it is the leader in the
rehabilitation of wells and well equipment. Its involvement in the initial drilling of a well
positions the Company to win follow-up rehabilitation business, which is generally a higher margin
business than well drilling. Such rehabilitation is required periodically during the life of a
well. For instance, in locations where the groundwater contains bacteria, iron, or high mineral
content, screen openings may become blocked, reducing the capacity and productivity of the well.
The Company offers complete diagnostic and rehabilitation 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 pump performance 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 and Wastewater Treatment 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 provision of filter media
and membranes, the
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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 treatment equipment and
filtration media, 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. The Company intends to continue to explore new
rehabilitation processes and technology.
Environmental Assessment Drilling Customers use the Companys environmental
drilling services to assist in assessing, investigating, monitoring and characterizing water
quality and aquifer parameters. The customers are typically national and regional consulting firms
engaged by federal and state agencies, as well as industrial companies that need to assess, define
or clean up groundwater contamination sources. The Company offers a wide range of environmental
drilling services including: investigative drilling, installation and testing of monitoring wells
to assist the customer in determining the extent of groundwater contamination, installation of
recovery wells that extract contaminated groundwater for treatment, which is known as pump and
treat remediation, and specialized site safety programs associated with drilling at contaminated
sites. In its environmental health sciences department, the Company employs a full-time staff
qualified to prepare site specific health and safety plans for hazardous waste cleanup sites as
required by the Occupational Safety and Health Administration, (OSHA) and the Mine Safety and
Health Administration of the Department of Labor (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 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 230,000 gross acres under lease and currently has 361 net producing wells. The
Company has utilized to date approximately 30% 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 its development potential. The Com-
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pany 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 can be its fastest growing business.
Operations
The Company operates on a decentralized basis, with approximately 87 sales and operations
offices located in most regions of the United States as well as in Australia, Africa, Mexico,
Canada 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 and
wastewater infrastructure, mineral exploration 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 and wastewater
infrastructure 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 and wastewater infrastructure 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 and wastewater infrastructure division, the Companys customers are typically
municipalities and local operations of industrial businesses. Of the Companys water and wastewater
infrastructure revenues in fiscal 2007, approximately 58% were derived from municipalities and
approximately 10% were derived from industrial customers while the balance was derived from other
customer groups. The term municipalities includes local water districts, water utilities, cities,
counties and other local governmental entities and agencies that have the responsibility to provide
water supplies to residential and commercial users. In the drilling of new water wells, 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.
The Company markets its unconventional gas production to large energy pipeline companies and
local industrial customers.
Backlog
The Companys backlog consists of the expected gross revenues associated with executed
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 $361,343,000 at January 31, 2007, compared to approximately $237,890,000 at January
31, 2006. The Companys backlog as of year-end is generally completed within the following twelve
to twenty-four months.
Competition
The Companys competition for its water and wastewater infrastructure 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
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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 and pump rehabilitation 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. Rehabilitation projects are typically
negotiated at the time of repair or contracted for in advance depending upon the lead time
available for the repair work. Since well and pump rehabilitation work is typically negotiated on
an emergency basis or within a relatively short period of time, those companies with available rigs
and the requisite expertise have a competitive advantage by being able to respond quickly to repair
requests.
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.
In the energy production market, 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, 2007, the Company had 3,919 employees, 607 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 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 a safety department 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 17 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
7
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.
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 and wastewater infrastructure business is dependant on
municipalities and a decline in municipal spending could adversely impact our business
For the fiscal year ended January 31, 2007, approximately 58% of water and wastewater
infrastructure division revenues were derived from contracts with governmental entities or
agencies. Reduced tax revenues in certain regions may limit spending and new development by local
municipalities which in turn may affect 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 services depends in significant part upon the level of mineral
exploration and development activities conducted by mining companies, particularly with respect to
gold and copper. Mineral exploration is highly speculative and is influenced by a variety of
factors, including the prevailing prices for various metals, which often fluctuate widely. In
addition, the price of gold is affected by numerous factors, including international economic
trends, currency exchange fluctuations, expectations for inflation, speculative activities,
consumption patterns, purchases and sales of gold bullion holdings by central banks and others,
world production levels and political events. In addition to prevailing prices for minerals,
mineral exploration activity is influenced by the following factors:
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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
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.
8
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 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 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, 2007, our total liabilities were
approximately $342 million and our total assets were approximately $547 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 2007, 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 perform work at mining operations in countries such as Tanzania, Guinea, Chile, Peru and
Mexico, which have experienced instability in the past, or may experience instability in the
future. The mining industry is subject to regulation by governments around the world, including the
regions in which we have operations relating to matters such as environmental protection, controls
and restrictions on production, and, potentially, nationalization, expropriation or cancellation of
contract rights, as well as restrictions on conducting business in such countries. In addition, in
our foreign operations we face operating difficulties, including, 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.
9
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 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 unconventional 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 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.
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.
10
Our bonding capacity may be limited in certain circumstances
A significant portion of our projects require 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 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 materials used in our rehabilitation business is dependent upon the availability
of resin, a petroleum-based product. Resin prices have fluctuated on the basis of the prevailing
prices of oil and we anticipate that prices will continue to be heavily influenced by the events
affecting the oil market. We also purchase a significant amount of steel for use in connection with
all of our businesses. In addition, we purchase a significant volume of fuel to operate our trucks
and equipment. At present, we do not engage in any type of hedging activities to mitigate the risks
of fluctuating market prices for oil, steel or fuel and increases in the price of these materials
may 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, 2007, our backlog was approximately $361 million. This consists of the expected
gross revenues associated with executed contracts, or portions thereof, not yet performed by the
Company. 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 some of our projects. To the extent that we
cannot engage subcontractors, our ability to complete a project in a timely fashion or at a profit
may be impaired. If the amount we are required to pay for subcontracted services exceeds the amount
we have estimated in bidding for fixed-price work, we could experience losses in the performance of
these contracts. In addition, if a subcontractor is unable to deliver its services according to the
negotiated terms for any reason, including the deterioration of its financial condition, we may be
required to purchase the services from another source at a higher price. 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.
11
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,
2007, approximately 15% of our workforce is unionized and 3 of our 31 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 and wastewater infrastructure 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 and wastewater 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.
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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 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, $500,000 and $500,000,
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:
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contract costs and profits and application of
percentage-of-completion accounting and revenue recognition of
contract claims; |
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recoverability of inventory and application of lower of
cost or market accounting; |
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provisions for uncollectible receivables and customer
claims and recoveries of costs from subcontractors, vendors
and others; |
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provisions for income taxes and related valuation
allowances; |
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recoverability of goodwill; |
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recoverability of other intangibles and related estimated
lives; |
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valuation of assets acquired and liabilities assumed in
connection with business combinations; and |
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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.
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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 $65 million as of January
31, 2007. If we make additional acquisitions, it is likely that we will record additional
intangible assets on our books. We also have long-lived assets consisting of property and equipment
and other identifiable intangible assets of $231 million as of January 31, 2007 which are reviewed
for impairment annually or whenever events or circumstances indicate the carrying amount of an
asset may not be recoverable. If a determination that a significant impairment in value of our
unamortized intangible assets or long-lived assets occurs, such determination would require us to
write off a substantial portion of our assets. 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 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,
expansion into new businesses 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 was recently amended to eliminate our staggered board. However, we are in the first
year of a three-year process to de-stagger our board. Accordingly, at our annual meeting this year
shareholders may elect only a minority of our board, which may have the effect of delaying or
preventing changes in management. 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 may 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.
14
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 American
Water Services Underground Infrastructure, Inc. (UIG) business, which was acquired on November
20, 2006. We will include UIG in our evaluation of the design and effectiveness of internal control
over financial reporting as of January 31, 2008. If we are unable to conclude that we have
effective internal controls over financial reporting or, if our independent auditors are unable to
provide us with an unqualified report as to the effectiveness of our internal controls over
financial reporting as of each fiscal year-end as required by Section 404 of the Sarbanes-Oxley Act
of 2002, investors could lose confidence in the reliability of our financial statements, 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 a significant portion of our outstanding common stock. 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, 2007, the Company (excluding foreign affiliates) owned or leased
approximately 595 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, 2007, the Companys foreign
affiliates owned or leased approximately 134 drill rigs.
The Companys coalbed methane projects consist of working interests in developed and
undeveloped properties primarily 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, 2007 and 2006, were prepared by the independent petroleum
engineers, Cawley, Gillespie & Associates, Inc (in MMcf and thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
Proved developed (MMcf) |
|
|
25,010 |
|
|
|
19,402 |
|
Proved undeveloped (MMCf) |
|
|
32,068 |
|
|
|
25,718 |
|
|
Total proved reserves (MMcf) |
|
|
57,078 |
|
|
|
45,120 |
|
|
Estimated future net revenue - pre-tax |
|
$ |
199,569 |
|
|
$ |
192,235 |
|
|
Present value of future net
revenues-pre-tax |
|
$ |
126,442 |
|
|
$ |
120,116 |
|
|
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 $6.89 and $7.31 per Mcf for 2007 and 2006, respectively. 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 $89,012,000.
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 2007, we filed estimates of our natural gas and
oil reserves for the year 2006 with the Energy Information
Administration of the U.S. Department of Energy on Form EIA-23L. The
data on Form EIA-23L was presented on a different basis, and included
100% of the natural gas and oil volumes from our operated properties
only, regardless of our net interest. The difference between the
natural gas and oil reserves reported on Form EIA-23L and those
reported in this report exceeds 5%.
15
Productive Wells, Production and Acreage
As of January 31, 2007, the Company had 374 gross producing wells and 361 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, |
|
2007 |
|
2006 |
|
Revenues |
|
$ |
5.95 |
|
|
$ |
8.52 |
|
Lease operating expenses |
|
|
1.46 |
|
|
|
1.94 |
|
Transportation costs |
|
|
1.88 |
|
|
|
2.57 |
|
Production and property taxes |
|
|
0.16 |
|
|
|
0.24 |
|
The gross and net acreage on leases expiring in each of the following five years and
thereafter were as follows:
|
|
|
|
|
|
|
|
|
|
|
Gross |
|
Net |
|
|
Acres |
|
Acres |
|
2008 |
|
|
62,572 |
|
|
|
60,940 |
|
2009 |
|
|
27,729 |
|
|
|
27,729 |
|
2010 |
|
|
20,568 |
|
|
|
20,568 |
|
2011 |
|
|
10,852 |
|
|
|
1,840 |
|
2012 |
|
|
13,363 |
|
|
|
625 |
|
Thereafter |
|
|
637 |
|
|
|
637 |
|
Gross and net developed and undeveloped acreage were as follows:
|
|
|
|
|
|
|
|
|
|
|
Acres |
Fiscal Years Ended January 31, |
|
2007 |
|
2006 |
|
Gross developed |
|
|
63,973 |
|
|
|
23,187 |
|
Net developed |
|
|
50,159 |
|
|
|
20,883 |
|
Gross undeveloped |
|
|
161,301 |
|
|
|
155,716 |
|
Net undeveloped |
|
|
161,301 |
|
|
|
144,164 |
|
Drilling Activity
In connection with the Companys efforts to develop its unconventional gas activities, 93
gross and net development wells and no exploratory wells were drilled during 2007. As of January
31, 2007, 55 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, 2007.
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
|
|
|
58 |
|
|
President, Chief Executive Officer and Director |
|
Jeffrey J. Reynolds
|
|
|
40 |
|
|
Executive Vice President and Director |
|
Gregory F. Aluce
|
|
|
51 |
|
|
Senior Vice President and Division President Water Resources |
|
Eric R. Despain
|
|
|
58 |
|
|
Senior Vice President and Division President Mineral Exploration |
|
Steven F. Crooke
|
|
|
50 |
|
|
Senior Vice President, Secretary and General Counsel |
|
Jerry W. Fanska
|
|
|
58 |
|
|
Senior Vice President-Finance and Treasurer |
Set forth below are the name, age and position of other significant employees of the Company.
|
|
|
|
|
|
|
Name |
|
Age |
|
Position |
|
Colin B. Kinley
|
|
|
47 |
|
|
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, a component
of the water and wastewater infrastructure division,
16
and is responsible for the Companys
groundwater supply, well and pump rehabilitation and potable water treatment services. 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.
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 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.
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 2007. The following table sets forth the range of high and low sales
prices of the Companys stock by quarter for fiscal 2007 and 2006, as reported by the Nasdaq Stock
Market. These quotations represent prices between dealers and do not include retail mark-up,
mark-down or commissions.
|
|
|
|
|
|
|
|
|
Fiscal Year 2007 |
|
High |
|
Low |
|
First Quarter |
|
$ |
33.93 |
|
|
$ |
25.60 |
|
Second Quarter |
|
|
32.04 |
|
|
|
25.12 |
|
Third Quarter |
|
|
33.68 |
|
|
|
26.57 |
|
Fourth Quarter |
|
|
36.46 |
|
|
|
28.67 |
|
|
|
|
|
|
|
|
|
|
Fiscal Year 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 |
|
At March 31, 2007, there were 106 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.
17
Item 6. Selected Financial Data
The following selected historical financial information as of and for each of the five
fiscal years ended January 31, 2007, 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)
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, |
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
Income Statement Data (in thousands, except per share data): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
722,768 |
|
|
$ |
463,015 |
|
|
$ |
343,462 |
|
|
$ |
272,053 |
|
|
$ |
255,523 |
|
Cost of revenues (exclusive of depreciation shown below) |
|
|
536,373 |
|
|
|
344,628 |
|
|
|
250,244 |
|
|
|
196,462 |
|
|
|
180,351 |
|
Selling, general and administrative expense |
|
|
102,603 |
|
|
|
69,979 |
|
|
|
60,214 |
|
|
|
53,920 |
|
|
|
52,425 |
|
Depreciation, depletion and amorization |
|
|
32,853 |
|
|
|
20,024 |
|
|
|
14,441 |
|
|
|
11,877 |
|
|
|
13,204 |
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of affiliates |
|
|
4,452 |
|
|
|
4,345 |
|
|
|
2,637 |
|
|
|
1,398 |
|
|
|
842 |
|
Interest |
|
|
(9,781 |
) |
|
|
(5,773 |
) |
|
|
(3,221 |
) |
|
|
(2,604 |
) |
|
|
(2,490 |
) |
Debt extinguishment costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,320 |
) |
|
|
(1,135 |
) |
Other, net |
|
|
2,557 |
|
|
|
900 |
|
|
|
1,220 |
|
|
|
358 |
|
|
|
1,694 |
|
|
Income from continuing operations before income taxes
and minority interest |
|
|
48,167 |
|
|
|
27,856 |
|
|
|
19,199 |
|
|
|
6,626 |
|
|
|
8,454 |
|
Income tax expense |
|
|
21,915 |
|
|
|
13,121 |
|
|
|
9,215 |
|
|
|
4,265 |
|
|
|
5,084 |
|
Minority interest |
|
|
|
|
|
|
(50 |
) |
|
|
(17 |
) |
|
|
|
|
|
|
(188 |
) |
|
Net income from continuing operations before discontinued
operations and cumulative effect of accounting change |
|
|
26,252 |
|
|
|
14,685 |
|
|
|
9,967 |
|
|
|
2,361 |
|
|
|
3,182 |
|
Gain (loss) from discontinued operations, net of income taxes |
|
|
|
|
|
|
(4 |
) |
|
|
(213 |
) |
|
|
(1,456 |
) |
|
|
(2,225 |
) |
Gain (loss) on sale of discontinued operations, net of income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,746 |
|
|
|
(23 |
) |
|
Net income before cumulative effect of accounting change |
|
|
26,252 |
|
|
|
14,681 |
|
|
|
9,754 |
|
|
|
2,651 |
|
|
|
934 |
|
Cumulative effect of accounting change, net of income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14,429 |
) |
|
Net income (loss) |
|
$ |
26,252 |
|
|
$ |
14,681 |
|
|
$ |
9,754 |
|
|
$ |
2,651 |
|
|
$ |
(13,495 |
) |
|
Basic income (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations before discontinued
operations and cumulative effect of accounting change |
|
$ |
1.71 |
|
|
$ |
1.08 |
|
|
$ |
0.79 |
|
|
$ |
0.20 |
|
|
$ |
0.27 |
|
Income (loss) from discontinued operations, net of income taxes |
|
|
|
|
|
|
|
|
|
|
(0.01 |
) |
|
|
0.02 |
|
|
|
(0.19 |
) |
|
Net income before cumulative effect of accounting change |
|
|
1.71 |
|
|
|
1.08 |
|
|
|
0.78 |
|
|
|
0.22 |
|
|
|
0.08 |
|
Cumulative effect of accounting change, net of income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1.22 |
) |
|
Net income (loss) per share |
|
$ |
1.71 |
|
|
$ |
1.08 |
|
|
$ |
0.78 |
|
|
$ |
0.22 |
|
|
$ |
(1.14 |
) |
|
Diluted income (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations before discontinued
operations and cumulative effect of accounting change |
|
$ |
1.68 |
|
|
$ |
1.05 |
|
|
$ |
0.77 |
|
|
$ |
0.19 |
|
|
$ |
0.26 |
|
Income (loss) from discontinued operations, net of income taxes |
|
|
|
|
|
|
|
|
|
|
(0.02 |
) |
|
|
0.02 |
|
|
|
(0.18 |
) |
|
Net income before cumulative effect of accounting change |
|
|
1.68 |
|
|
|
1.05 |
|
|
|
0.75 |
|
|
|
0.21 |
|
|
|
0.08 |
|
Cumulative effect of accounting change, net of income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1.19 |
) |
|
Net income (loss) per share |
|
$ |
1.68 |
|
|
$ |
1.05 |
|
|
$ |
0.75 |
|
|
$ |
0.21 |
|
|
$ |
(1.11 |
) |
|
Balance Sheet Data (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working capital, excluding debt |
|
$ |
66,989 |
|
|
$ |
69,996 |
|
|
$ |
54,455 |
|
|
$ |
52,406 |
|
|
$ |
37,613 |
|
Total assets |
|
|
547,164 |
|
|
|
449,335 |
|
|
|
245,380 |
|
|
|
217,327 |
|
|
|
178,100 |
|
Total debt |
|
|
151,600 |
|
|
|
128,900 |
|
|
|
60,000 |
|
|
|
42,000 |
|
|
|
32,370 |
|
Total stockholders equity |
|
|
205,034 |
|
|
|
171,626 |
|
|
|
104,697 |
|
|
|
93,685 |
|
|
|
83,373 |
|
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
man-
18
agements intentions, hopes, beliefs, expectations or predictions of the future. Forward looking
statements can often be identified by the use of forward-looking terminology, such as should,
intended, continue, believe, may, hope, anticipate, goal, forecast, plan,
estimate and similar words or phrases. Such statements are based on current expectations and are
subject to certain risks, uncertainties and assumptions, including but not limited to prevailing
prices for various commodities, unanticipated slowdowns in the 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 mineral exploration division office
performed water well drilling services, the revenues would be recorded in the mineral exploration
division rather than the water and wastewater infrastructure division. The Companys reportable
segments are defined as follows:
Water and Wastewater Infrastructure
This division provides a full line of water-related services and products including
hydrological studies, site selection, well design, drilling and well development, pump
installation, and well rehabilitation. The divisions offerings include the design and construction
of water treatment facilities and the provision of filter media and membranes to treat volatile
organics and other contaminants such as nitrates, iron, manganese, arsenic, radium and radon in
groundwater. The division also offers environmental drilling services to assess and monitor
groundwater contaminants.
With the acquisition of Reynolds in September 2005, Collector Wells International in June
2006, and American Water Services Underground Infrastructure, Inc. in November 2006, the division
has continued to expand its capabilities in the areas of the design and build of water and
wastewater treatment plants, Ranney collector wells, sewer rehabilitation and water and wastewater
transmission lines.
The divisions operations rely heavily on the municipal sector as approximately 58% of the
divisions fiscal 2007 revenues were derived from the municipal market. The municipal sector can be
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.
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.
The division relies heavily on mining activity in Africa where 41% of total division revenues
were generated for fiscal 2007. The Company believes this concentration of risk is mitigated by
working for larger international mining companies and the establishment of permanent operating
facilities in Africa. Operating difficulties, including but not limited to, political instability,
workforce instability, harsh environment, disease and remote locations, all create natural barriers
to entry in this market by competitors. The Company believes it has positioned itself as the market
leader in Africa and has established the infrastructure to operate effectively.
Energy Division
This division focuses on the exploration and production of unconventional gas properties. To
date this division has been concentrated on projects in the mid-continent region of the United
States.
The expansion of the Companys energy segment is contingent upon significant cash investments
to develop the Companys unproved acreage. As of January 31, 2007, the Company has invested
$95,912,000 in oil and gas related assets and expects to spend approximately $25,000,000 in
development activities in fiscal 2008. 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
19
discovery rate of new gas reserves. The Company has 361 net producing wells
on-line as of January 31, 2007.
Other
Other includes two small specialty energy service companies and any other specialty operations
not included in one of the other divisions.
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
|
2007 |
|
2006 |
|
2005 |
|
vs. 2006 |
|
vs. 2005 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Water and wastewater infrastructure |
|
|
73.6 |
% |
|
|
69.3 |
% |
|
|
67.9 |
% |
|
|
65.7 |
% |
|
|
37.7 |
% |
Mineral exploration |
|
|
20.6 |
|
|
|
26.8 |
|
|
|
30.4 |
|
|
|
19.9 |
|
|
|
19.1 |
|
Energy |
|
|
3.7 |
|
|
|
2.7 |
|
|
|
1.1 |
|
|
|
116.0 |
|
|
|
228.1 |
|
Other |
|
|
2.1 |
|
|
|
1.2 |
|
|
|
0.6 |
|
|
|
181.6 |
|
|
|
136.5 |
|
|
Total revenues |
|
|
100.0 |
% |
|
|
100.0 |
% |
|
|
100.0 |
% |
|
|
56.1 |
|
|
|
34.8 |
|
|
Cost of revenues (exclusive of depreciation shown below) |
|
|
74.2 |
% |
|
|
74.4 |
% |
|
|
72.9 |
% |
|
|
55.6 |
|
|
|
37.7 |
|
|
Gross profit, as adjusted** |
|
|
25.8 |
|
|
|
25.6 |
|
|
|
27.1 |
|
|
|
57.4 |
|
|
|
27.0 |
|
Selling, general and administrative expense |
|
|
14.2 |
|
|
|
15.1 |
|
|
|
17.5 |
|
|
|
46.6 |
|
|
|
16.2 |
|
Depreciation, depletion and amortization |
|
|
4.5 |
|
|
|
4.3 |
|
|
|
4.2 |
|
|
|
64.1 |
|
|
|
38.7 |
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of affiliates |
|
|
0.6 |
|
|
|
0.9 |
|
|
|
0.8 |
|
|
|
2.5 |
|
|
|
64.8 |
|
Interest |
|
|
(1.4 |
) |
|
|
(1.3 |
) |
|
|
(0.9 |
) |
|
|
69.4 |
|
|
|
79.2 |
|
Other, net |
|
|
0.3 |
|
|
|
0.2 |
|
|
|
0.3 |
|
|
|
184.1 |
|
|
|
(26.2 |
) |
|
Income from continuing operations before income taxes |
|
|
6.6 |
|
|
|
6.0 |
|
|
|
5.6 |
|
|
|
72.9 |
|
|
|
45.1 |
|
Income tax expense |
|
|
3.0 |
|
|
|
2.8 |
|
|
|
2.7 |
|
|
|
67.0 |
|
|
|
42.4 |
|
|
Net income from continuing operations |
|
|
3.6 |
|
|
|
3.2 |
|
|
|
2.9 |
|
|
|
78.8 |
|
|
|
47.3 |
|
Loss from discontinued operations, net of income taxes |
|
|
|
|
|
|
|
|
|
|
(0.1 |
) |
|
|
* |
|
|
|
* |
|
|
Net income |
|
|
3.6 |
% |
|
|
3.2 |
% |
|
|
2.8 |
% |
|
|
78.8 |
% |
|
|
50.5 |
% |
|
|
|
|
* |
|
Not meaningful |
|
** |
|
As used, gross profit is defined as revenues less cost of
revenues, excluding depreciation, depletion and amortization |
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. Operating segment
revenues and income from continuing operations before income taxes are summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
Fiscal Years Ended January 31, |
|
2007 |
|
2006 |
|
2005 |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Water and wastewater infrastructure |
|
$ |
531,916 |
|
|
$ |
320,996 |
|
|
$ |
233,111 |
|
Mineral exploration |
|
|
148,911 |
|
|
|
124,206 |
|
|
|
104,299 |
|
Energy |
|
|
27,081 |
|
|
|
12,536 |
|
|
|
3,821 |
|
Other |
|
|
14,860 |
|
|
|
5,277 |
|
|
|
2,231 |
|
|
Total revenues |
|
$ |
722,768 |
|
|
$ |
463,015 |
|
|
$ |
343,462 |
|
|
Equity in earnings of affiliates |
|
|
|
|
|
|
|
|
|
|
|
|
Water and wastewater infrastructure |
|
$ |
|
|
|
$ |
839 |
|
|
$ |
(127 |
) |
Mineral exploration |
|
|
4,452 |
|
|
|
3,506 |
|
|
|
2,764 |
|
|
Total equity in earnings of affiliates |
|
$ |
4,452 |
|
|
$ |
4,345 |
|
|
$ |
2,637 |
|
|
Income (loss) from continuing operations before income taxes and minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
Water and wastewater infrastructure |
|
$ |
35,000 |
|
|
$ |
28,255 |
|
|
$ |
26,393 |
|
Mineral exploration |
|
|
26,557 |
|
|
|
13,947 |
|
|
|
11,791 |
|
Energy |
|
|
10,680 |
|
|
|
2,891 |
|
|
|
(1,993 |
) |
Other |
|
|
4,094 |
|
|
|
1,307 |
|
|
|
(43 |
) |
Unallocated corporate expenses |
|
|
(18,383 |
) |
|
|
(12,771 |
) |
|
|
(13,728 |
) |
Interest |
|
|
(9,781 |
) |
|
|
(5,773 |
) |
|
|
(3,221 |
) |
|
Total income from continuing operations before income taxes and minority interest |
|
$ |
48,167 |
|
|
$ |
27,856 |
|
|
$ |
19,199 |
|
|
20
Comparison of Fiscal 2007 to Fiscal 2006
Revenues for fiscal 2007 increased $259,753,000, or 56.1%, to $722,768,000 compared to
$463,015,000 for fiscal 2006. Revenues were up across all divisions with the main increase in the
water and wastewater infrastructure division, primarily resulting from the acquisition of Reynolds,
Inc. (Reynolds) that closed on September 28, 2005, the Collector Wells, International (CWI)
acquisition that closed on June 16, 2006 and the acquisition of American Water Services Underground
Infrastructure, Inc. (UIG) that closed on November 20, 2006. A further discussion of results of
operations by division is presented below.
Gross profit, as adjusted, as a percentage of revenues was 25.8% for fiscal 2007 compared to
25.6% for fiscal 2006. The increase in the percentage was primarily the result of improved margins
in the mineral exploration division due to improved pricing and efficiency and the energy division
due to the increased production of unconventional gas, offset by reduced margins in the water and
wastewater infrastructure division arising from the change in product mix with the acquisition of
Reynolds.
Selling, general and administrative expenses increased to $102,603,000 for fiscal 2007
compared to $69,979,000 for fiscal 2006 (14.2% and 15.1% of revenues, respectively). The increase
was primarily the result of $12,653,000 in incremental expenses added from the acquired businesses,
additional incentive compensation expense of $6,300,000 from increased profitability, wage and
benefit increases of $4,281,000 and increases in compensation expense of $2,187,000 associated with
stock options under SFAS 123R, Share Based Payments.
Depreciation, depletion and amortization increased to $32,853,000 for fiscal 2007 compared to
$20,024,000 for fiscal 2006. The increase was primarily the result of higher levels of capital
expenditures, increased depreciation and amortization of $5,930,000 associated with the acquired
businesses and increased depletion expense of $2,896,000 resulting from the increase in production
of unconventional gas from the Companys energy operations.
Equity in earnings of affiliates increased to $4,452,000 for fiscal 2007 compared to
$4,345,000 for fiscal 2006. The increase reflects increase earnings of $946,000 from foreign
affiliates in mineral exploration offset by a decrease of $839,000 from a non-recurring domestic
joint venture in the water and wastewater infrastructure division completed in the prior year.
Interest expense increased to $9,781,000 for fiscal 2007 compared to $5,773,000 for fiscal
2006. The increase was primarily a result of increases in the Companys average borrowings for the
year in conjunction with the financing of the acquisitions.
Other, net increased to $2,557,000 for fiscal 2007 from $900,000 for fiscal 2006, primarily
due to a gain of $920,000 in fiscal 2007 in connection with the Companys sale of its interest in a
minerals concession.
The Companys effective tax rate was 45.5% for fiscal 2007, compared to 47.1% for fiscal 2006.
The improvement in the effective rate was primarily attributable to the increase in pre-tax
earnings, especially in international operations. The effective rates in excess of the statutory
federal rate were due primarily to the impact of nondeductible expenses and the tax treatment of
certain foreign operations.
Water and Wastewater Infrastructure Division
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
Fiscal Years Ended January 31, |
|
2007 |
|
2006 |
|
Revenues |
|
$ |
531,916 |
|
|
$ |
320,996 |
|
Income from continuing
operations before income taxes |
|
|
35,000 |
|
|
|
28,255 |
|
Water and wastewater infrastructure revenues increased 65.7% to $531,916,000 for the year
ended January 31, 2007, from $320,996,000 for the year ended January 31, 2006. The increase in
revenues was primarily attributable to incremental increases of $169,124,000 from the Companys
acquisitions and additional revenues of $21,064,000 from the Companys continued expansion into
water treatment markets.
Income from continuing operations for the water and wastewater infrastructure division
increased 23.9% to $35,000,000 for the year ended January 31, 2007, compared to $28,255,000 for the
year ended January 31, 2006. The increase in income from continuing operations was primarily
attributable to incremental increases of $8,374,000 from the acquired businesses and an increase in
earnings from the Companys water treatment initiatives of $2,678,000. These were partially offset
by an increase in accrued incentive compensation of $3,219,000 due to higher profitability in the
current year, reduced operating earnings of $4,081,000 as a result of a slowdown in certain ground
stabilization construction operations in the western United States and a decrease of $839,000 from
a domestic joint venture completed in the prior year.
Mineral Exploration Division
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
Fiscal Years Ended January 31, |
|
2007 |
|
2006 |
|
Revenues |
|
$ |
148,911 |
|
|
$ |
124,206 |
|
Income from continuing
operations before income taxes |
|
|
26,557 |
|
|
|
13,947 |
|
Mineral exploration revenues increased 19.9% to $148,911,000 for the year ended January 31,
2007, compared to revenues of $124,206,000 for the year ended January 31, 2006. The increase in
revenues was primarily attributable to continued strength in worldwide explorations activity as a
result of the relatively high gold and base metal prices.
Income from continuing operations for the mineral exploration division increased 90.4% to
$26,557,000 for the year ended January 31, 2007, compared to $13,947,000 for the year ended January
31, 2006. The improved earnings were attributable to the impact of increased exploration activity
in most of the Companys markets and increased earnings by the Companys Latin American affiliates
of $946,000. In addition, in January 2007 the division recognized a gain of $920,000 on the sale of
its interest in a mineral concession. The improved earnings were partially offset by an increase in
accrued incentive compensation of $808,000 due to higher profitability in the current year.
21
Energy Division
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
Fiscal Years Ended January 31, |
|
2007 |
|
2006 |
|
Revenues |
|
$ |
27,081 |
|
|
$ |
12,536 |
|
Income from continuing
operations before income taxes |
|
|
10,680 |
|
|
|
2,891 |
|
Energy division revenues increased 116.0% to $27,081,000 for the year ended January 31, 2007
compared to revenues of $12,536,000 for the year ended January 31, 2006. The increase in revenues
was primarily attributable to increased production from the Companys unconventional gas
properties.
The division had income from continuing operations of $10,680,000 for the year ended January
31, 2007, compared to a $2,891,000 for the year ended January 31, 2006. The increase in income from
continuing operations was due to the increase in production noted above.
Other
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
Fiscal Years Ended January 31, |
|
2007 |
|
2006 |
|
Revenues |
|
$ |
14,860 |
|
|
$ |
5,277 |
|
Income from continuing
operations before income taxes |
|
|
4,094 |
|
|
|
1,307 |
|
The increases in revenues and income from continuing operations as compared to the prior year
were primarily due to a non-recurring contract to provide equipment and supplies to an
international oil exploration company. Revenues of $8,798,000 were recognized during 2007,
primarily in the second quarter, as the equipment and supplies were delivered and accepted.
Unallocated Corporate Expenses
Corporate expenses not allocated to individual divisions, primarily included in selling,
general and administrative expenses, were $18,383,000 and $12,771,000 for the years ended January
31, 2007 and 2006, respectively. The increase for the year was primarily due to the recognition of
compensation expense under SFAS 123R of $2,187,000 and increases in wage and benefit costs of
$1,077,000, accrued incentive compensation of $815,000 and consulting services of $732,000.
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 and wastewater infrastructure 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 adjusted, as a percentage of revenues was 25.6% for fiscal 2006 compared to
27.1% for fiscal 2005. The decrease in the percentage was primarily the result of reduced margins
in the water and wastewater infrastructure division arising from a change in product mix with the
acquisition of Reynolds, higher than expected costs on certain water supply contracts especially in
the California market and competitive pricing pressures in Texas. These decreases were partially
offset by improved margins in the energy division due to the increased sales of natural gas as a
result of increased production and pricing.
Selling, general and administrative expenses 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 acquired businesses 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 domestic joint venture in the water and wastewater infrastructure 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 and Wastewater Infrastructure Division
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
Fiscal Years Ended January 31, |
|
2006 |
|
2005 |
|
Revenues |
|
$ |
320,996 |
|
|
$ |
233,111 |
|
Income from continuing
operations before income taxes |
|
|
28,255 |
|
|
|
26,393 |
|
Water and wastewater infrastructure revenues increased 37.7% to $320,996,000 for the year
ended January 31, 2006, from $233,111,000 for the year ended January 31, 2005. The increase was
primarily attributable to the acquired businesses, the divisions water treatment initiatives and
strong sales in the fourth quarter from the Companys manufacturing operations in Italy.
Income from continuing operations for the water and wastewater infrastructure division
increased 7.1% to $28,255,000 for the year ended January 31, 2006, compared to $26,393,000 for the
year ended January 31, 2005. The increase in income from continuing operations was primarily the
result of an increase of $966,000 in equity in earnings from a domestic joint venture substantially
completed in fiscal 2006, additional earnings from the manufacturing products described above and
the settlement
22
of several contract change orders, offset by higher than expected costs on certain water
supply contracts especially in the California market, competitive pricing pressures in the Texas
market and the introduction of membrane technology to the divisions water treatment initiatives.
Mineral Exploration Division
|
|
|
|
|
|
|
|
|
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.
Energy Division
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
Fiscal Years Ended January 31, |
|
2007 |
|
2006 |
|
Revenues |
|
$ |
12,536 |
|
|
$ |
3,821 |
|
Income 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.
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
23
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, 2007, the Company has $60,000,000 in notes outstanding under the
Master Shelf Agreement. Additionally, the Company holds an unsecured $200,000,000 revolving credit
facility (the Credit Agreement). The Credit Agreement was amended in November 2006 to increase
the revolving loan commitment from $130,000,000 to $200,000,000. At January 31, 2007, the Company
had $91,600,000 outstanding under the Credit Agreement. The Company was in compliance with its
financial covenants at January 31, 2007 and expects to remain in compliance through the foreseeable
future.
The Companys working capital as of January 31, 2007, 2006 and 2005, was $66,989,000,
$69,996,000 and $54,455,000, respectively. The decrease in working capital of $3,007,000 in the
current year was attributable to an increase in accrued compensation of $9,591,000 primarily due to
increased incentive compensation and an increase in income taxes payable, partially offset by
working capital in the businesses acquired by the Company during the year.
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 2008.
Operating Activities
Cash from operating activities was $74,676,000, $40,869,000 and $16,954,000 for fiscal 2007,
2006 and 2005, respectively. The growth over the last two years was primarily due to increased
earnings and increases in accrued incentive compensation and income taxes payable. Operating cash
is normally required in the first quarter of the subsequent fiscal year when such accrued items are
paid.
Investing Activities
The Companys capital expenditures, net of disposals, of $70,166,000 for the year ended
January 31, 2007, were directed primarily toward the Companys expansion into unconventional gas
exploration and production. The expenditures related to the Companys unconventional gas efforts
totaled $38,662,000 including the construction of gas pipeline infrastructure near the Companys
development projects. Also, during the year, the Company invested $27,496,000 to acquire the
business of UIG, $3,809,000 to acquire the business of Collector Wells International, Inc.,
$1,988,000 to acquire certain producing oil and gas properties and mineral interests, and paid cash
purchase price adjustments in accordance with the Reynolds purchase agreement of $6,120,000.
The Companys capital expenditures, net of disposals, of $42,025,000 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 $18,490,000
during fiscal 2006 including the construction of gas pipeline infrastructure near the Companys
development projects. The Company also acquired two unconventional gas projects totaling $4,704,000
and acquired the remaining 25% interest in a gas transportation facility for $1,445,000.
Also in fiscal 2006, the Company acquired all of the outstanding stock of Reynolds for total
consideration of $61,542,000 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 (see Note 2 of
the Notes to Consolidated Financial Statements).
Investing activities for fiscal 2005 included the expansion of the Companys water and
wastewater infrastructure division through the acquisition of the assets of Beylik for total
consideration of $14,743,000 (see Note 2 of the Notes to Consolidated Financial Statements).
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, 2007, the Company had net borrowings of $22,700,000 under its
credit facilities primarily to fund the acquisition of UIG, working capital requirements and
capital expenditures. Additionally, proceeds of $3,010,000 were received from issuance of common
stock related to the exercise of stock options.
In fiscal 2006, the Company had net borrowings of $68,900,000 under its credit facilities
primarily for the Reynolds acquisition, working capital requirements and to fund capital
expenditures. Additionally, proceeds of $3,324,000 were received from issuance of common stock
related to the exercise of stock options. The increase in the exercise of stock options in fiscal
2006 was due to increases in the Companys stock price and a number of options with impending
expiration dates. Financing activities also include payments of $1,080,000 related to a 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 payments of $1,740,000 related to a
promissory note.
24
Contractual Obligations and Commercial Commitments
The Companys contractual obligations and commercial commitments as of January 31, 2007,
are 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
|
|
$ |
91,600 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
91,600 |
|
|
$ |
|
|
Senior Notes |
|
|
60,000 |
|
|
|
|
|
|
|
33,333 |
|
|
|
26,667 |
|
|
|
|
|
Operating leases |
|
|
17,652 |
|
|
|
6,951 |
|
|
|
7,815 |
|
|
|
2,886 |
|
|
|
|
|
Mineral interest obligations |
|
|
552 |
|
|
|
118 |
|
|
|
211 |
|
|
|
208 |
|
|
|
15 |
|
|
Total cash contractual obligations |
|
|
169,804 |
|
|
|
7,069 |
|
|
|
41,359 |
|
|
|
121,361 |
|
|
|
15 |
|
Standby letters of credit |
|
|
9,844 |
|
|
|
9,844 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations |
|
|
812 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
812 |
|
|
Total contractual obligations and commercial commitments |
|
$ |
180,460 |
|
|
$ |
16,913 |
|
|
$ |
41,359 |
|
|
$ |
121,361 |
|
|
$ |
827 |
|
|
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 in the table 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 0.75% 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 11 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 Revenues are recognized on large, long-term construction contracts
meeting the criteria of Statement of Position 81-1, Accounting for Performance of Construction-Type
and Certain Production-Type Contracts (SOP 81-1), using the percentage-of-completion method based
upon the ratio of costs incurred to total estimated costs at completion. Contract price and cost
estimates are reviewed periodically as work progresses and adjustments proportionate to the
percentage of completion are reflected in contract revenues in the reporting period when such
estimates are revised. Changes in job performance, job conditions and estimated profitability,
including those arising from contract penalty provisions, change orders and final contract
settlements may result in revisions to costs and income and are recognized in the period in which
the revisions are determined. As allowed by SOP 81-1, revenue is recognized on smaller, short-term
construction contracts using the completed contract method. Provisions for estimated losses on
uncompleted construction contracts are made in the period in which such losses are determined.
Revenues for direct sales of equipment and other ancillary products not provided in
conjunction with the performance of construction contracts are recognized at the date of delivery
to, and acceptance by, the customer. Provisions for estimated warranty obligations are made in the
period in which the sales occur.
Contracts for the Companys mineral exploration drilling services are billable based on the
quantity of drilling performed. Thus, revenues for these drilling contracts are recognized on the
basis of actual footage or meterage drilled.
Revenues for the sale of oil and gas by the Companys energy division are recognized on the
basis of volumes sold at the time of delivery to an end user or an interstate pipeline, net of
amounts attributable to royalty or working interest holders.
The Companys revenues are presented net of taxes imposed on revenue-producing transactions
with its customers, such as, but not limited to, sales, use, value-added and some excise taxes.
Oil and Gas Properties and Mineral Interests The Company follows the full-cost method of
accounting for oil and gas properties. Under this method, all productive and nonproductive costs
incurred in connection with the exploration for and development of oil and gas reserves are
capitalized. Such capitalized costs include lease acquisition, geological and geophysical work,
delay rentals, drilling, completing and equipping oil and
25
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.
Goodwill and Other Intangibles The Company accounts for goodwill and other
intangible assets in accordance with SFAS 142, Goodwill and Other Intangible Assets. Other
intangible assets primarily consist of trademarks, customer-related intangible assets and patents
obtained through business acquisitions. Amortizable intangible assets are being amortized over
their estimated useful lives, which range from one to 40 years.
The impairment evaluation for goodwill is conducted annually, or more frequently, if events or
changes in circumstances indicate that an asset might be impaired. The evaluation is performed by
using a two-step process. In the first step, the fair value of each reporting unit is compared with
the carrying amount of the reporting unit, including goodwill. The estimated fair value of the
reporting unit is generally determined on the basis of discounted future cash flows. If the
estimated fair value of the reporting unit is less than the carrying amount of the reporting unit,
then a second step must be completed in order to determine the amount of the goodwill impairment
that should be recorded. In the second step, the implied fair value of the reporting 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.
Other Long-lived Assets In the event of an indication of possible impairment, the
Company evaluates the fair value and future benefits of long-lived assets, including the Companys
gas transportation facilities and equipment, by performing an analysis of the anticipated future
net cash flows of the related long-lived assets and reducing their carrying value by the excess, if
any, of the result of such calculation. The Company believes at this time that the carrying values
and useful lives of its long-lived assets continues to be appropriate.
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.
26
Costs estimated to be incurred in the future for employee health and welfare benefits,
property, workers compensation and casualty insurance programs resulting from claims which have
occurred are accrued currently. Under the terms of the 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.
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 16 of the Notes to Consolidated Financial Statements for a discussion of new
accounting pronouncements and their impact on the Company.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The principal market risks to which the Company is exposed are interest rate risk on variable
rate debt, foreign exchange rate risk that could give rise to translation and transaction gains and
losses and fluctuations in the price of natural gas.
The Company centrally manages its debt portfolio considering overall financing strategies and
tax consequences. A description of the Companys debt is included in Note 11 of the Notes to
Consolidated Financial Statements of this Form 10-K. As of January 31, 2007, an instantaneous
change in interest rates of one percentage point would change the Companys annual interest expense
by $916,000.
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 15 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 12 of the Notes to Consolidated Financial Statements). As of
January 31, 2007, 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 $416,000, $276,000 and $59,000 for the
years ended January 31, 2007, 2006 and 2005, respectively. This represents approximately 10% 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
gains (losses) for the years ended January 31, 2007, 2006 and 2005, were $95,000, ($290,000) and
($342,000), 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, 2007, the Company held contracts for physical delivery of 3,825,000 million British Thermal
Units (MMBtu) of natural gas at prices ranging from $7.74 to $10.15 per MMBtu through March 31,
2008. The estimated fair value of such contracts at January 31, 2007 was $1,918,000. The Company
generally intends to maintain contracts in place to cover 50% to 75% 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 $1,137,000 for the year ended January 31,
2007.
27
Item 8. Financial Statements and Supplementary Data
Index to Consolidated Financial Statements and Financial Statement Schedules
Layne Christensen Company and Subsidiaries
|
|
|
|
|
|
|
Page |
Statement of Management Responsibility |
|
|
29 |
|
Report of Independent Registered Public Accounting Firm |
|
|
30 |
|
Financial Statements: |
|
|
|
|
Consolidated Balance Sheets as of January 31, 2007 and 2006 |
|
|
31 |
|
Consolidated Statements of Income for the Years Ended January 31, 2007, 2006 and 2005 |
|
|
32 |
|
Consolidated Statements of Stockholders Equity for the Years Ended January 31, 2007, 2006 and 2005 |
|
|
33 |
|
Consolidated Statements of Cash Flows for the Years Ended January 31, 2007, 2006 and 2005 |
|
|
34 |
|
Notes to Consolidated Financial Statements |
|
|
35 |
|
Financial Statement Schedule II Valuation and Qualifying Accounts |
|
|
54 |
|
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.
28
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/A. B. Schmitt
|
|
/s/Jerry W. Fanska |
|
|
|
Andrew B. Schmitt
|
|
Jerry W. Fanska |
President and Chief
|
|
Senior Vice President and Chief |
Executive Officer
|
|
Financial Officer |
29
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Layne Christensen Company
Mission Woods, Kansas
We have audited the accompanying consolidated balance sheets of Layne Christensen Company and
subsidiaries (the Company) as of January 31, 2007 and 2006, and the related consolidated
statements of income, stockholders equity, and cash flows for each of the three years in the
period ended January 31, 2007. Our audits also included the financial statement schedule listed in
the Index 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, 2007 and 2006,
and the results of their operations and their cash flows for each of the three years in the period
ended January 31, 2007, in conformity with accounting principles generally accepted in the United
States of America. Also, in our opinion, such financial statement schedule, when considered in
relation to the basic consolidated financial statements taken as a whole, presents fairly, in all
material respects, the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, the Company changed its method of
accounting for share-based compensation upon its adoption of Statement of Financial Accounting
Standards (SFAS) No. 123(R), Share-Based Payment, on February 1, 2006. Also, as discussed in Note
10 to the consolidated financial statements, the Company changed its method of accounting for
pension and post retirement benefits as of January 31, 2007 to conform to SFAS No. 158, Employers
Accounting for Defined Benefit Pension and Other Postretirement Plans an amendment of FASB
Statements No. 87, 88, 106 and 132(R).
We have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the effectiveness of the Companys internal control over financial reporting
as of January 31, 2007, 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 16, 2007 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
Kansas City, Missouri
April 16, 2007
30
Layne Christensen Company and Subsidiaries
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
January 31, |
|
2007 |
|
2006 |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
13,007 |
|
|
$ |
17,983 |
|
Customer receivables, less allowance of $7,020 and $5,573, respectively |
|
|
109,615 |
|
|
|
91,159 |
|
Costs and estimated earnings in excess of billings on uncompleted contracts |
|
|
51,210 |
|
|
|
36,538 |
|
Inventories |
|
|
18,456 |
|
|
|
16,663 |
|
Deferred income taxes |
|
|
16,551 |
|
|
|
11,976 |
|
Income taxes receivable |
|
|
521 |
|
|
|
1,284 |
|
Restricted cash current |
|
|
8,270 |
|
|
|
|
|
Other |
|
|
5,578 |
|
|
|
5,975 |
|
|
Total current assets |
|
|
223,208 |
|
|
|
181,578 |
|
|
Property and equipment: |
|
|
|
|
|
|
|
|
Land |
|
|
8,180 |
|
|
|
9,486 |
|
Buildings |
|
|
21,457 |
|
|
|
19,595 |
|
Machinery and equipment |
|
|
263,049 |
|
|
|
222,531 |
|
Gas transportation facilities and equipment |
|
|
24,939 |
|
|
|
12,526 |
|
Oil and gas properties |
|
|
58,458 |
|
|
|
34,308 |
|
Mineral interests in oil and gas properties |
|
|
12,515 |
|
|
|
8,430 |
|
|
|
|
|
388,598 |
|
|
|
306,876 |
|
Less accumulated depreciation and depletion |
|
|
(174,081 |
) |
|
|
(148,751 |
) |
|
Net property and equipment |
|
|
214,517 |
|
|
|
158,125 |
|
|
Other assets: |
|
|
|
|
|
|
|
|
Investment in affiliates |
|
|
24,280 |
|
|
|
21,741 |
|
Goodwill |
|
|
65,184 |
|
|
|
57,857 |
|
Other intangible assets, net |
|
|
16,017 |
|
|
|
16,948 |
|
Restricted cash long term |
|
|
|
|
|
|
9,143 |
|
Other |
|
|
3,958 |
|
|
|
3,943 |
|
|
Total other assets |
|
|
109,439 |
|
|
|
109,632 |
|
|
|
|
$ |
547,164 |
|
|
$ |
449,335 |
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
52,156 |
|
|
$ |
43,695 |
|
Accrued compensation |
|
|
29,616 |
|
|
|
20,025 |
|
Cash purchase price adjustments |
|
|
240 |
|
|
|
6,120 |
|
Accrued insurance expense |
|
|
7,303 |
|
|
|
5,562 |
|
Other accrued expenses |
|
|
14,222 |
|
|
|
12,212 |
|
Acquisition escrow obligation current |
|
|
9,395 |
|
|
|
|
|
Income taxes payable |
|
|
9,045 |
|
|
|
2,606 |
|
Billings in excess of costs and estimated earnings on uncompleted contracts |
|
|
34,242 |
|
|
|
21,362 |
|
|
Total current liabilities |
|
|
156,219 |
|
|
|
111,582 |
|
|
Noncurrent and deferred liabilities: |
|
|
|
|
|
|
|
|
Long-term debt |
|
|
151,600 |
|
|
|
128,900 |
|
Accrued insurance expense |
|
|
8,160 |
|
|
|
6,228 |
|
Deferred income taxes |
|
|
23,302 |
|
|
|
19,555 |
|
Acquisition escrow obligation long term |
|
|
|
|
|
|
9,143 |
|
Other |
|
|
2,849 |
|
|
|
2,301 |
|
|
Total noncurrent and deferred liabilities |
|
|
185,911 |
|
|
|
166,127 |
|
|
Contingencies |
|
|
|
|
|
|
|
|
Stockholders equity: |
|
|
|
|
|
|
|
|
Common stock, par value $.01 per share, 30,000,000 shares authorized,
15,517,724 and 15,233,472 shares issued and outstanding, respectively |
|
|
155 |
|
|
|
152 |
|
Capital in excess of par value |
|
|
149,187 |
|
|
|
141,067 |
|
Retained earnings |
|
|
64,145 |
|
|
|
37,893 |
|
Accumulated other comprehensive loss |
|
|
(8,453 |
) |
|
|
(7,442 |
) |
Unearned compensation |
|
|
|
|
|
|
(44 |
) |
|
Total stockholders equity |
|
|
205,034 |
|
|
|
171,626 |
|
|
|
|
$ |
547,164 |
|
|
$ |
449,335 |
|
|
See Notes to Consolidated Financial Statements.
31
Layne Christensen Company and Subsidiaries
Consolidated Statements of Income
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per share data) |
|
|
|
|
|
|
Years Ended January 31, |
|
2007 |
|
2006 |
|
2005 |
|
Revenues |
|
$ |
722,768 |
|
|
$ |
463,015 |
|
|
$ |
343,462 |
|
Cost of revenues (exclusive of depreciation, depletion and amortization shown below) |
|
|
536,373 |
|
|
|
344,628 |
|
|
|
250,244 |
|
Selling, general and administrative expense |
|
|
102,603 |
|
|
|
69,979 |
|
|
|
60,214 |
|
Depreciation, depletion and amortization |
|
|
32,853 |
|
|
|
20,024 |
|
|
|
14,441 |
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of affiliates |
|
|
4,452 |
|
|
|
4,345 |
|
|
|
2,637 |
|
Interest |
|
|
(9,781 |
) |
|
|
(5,773 |
) |
|
|
(3,221 |
) |
Other, net |
|
|
2,557 |
|
|
|
900 |
|
|
|
1,220 |
|
|
Income from continuing operations before income taxes and minority interest |
|
|
48,167 |
|
|
|
27,856 |
|
|
|
19,199 |
|
Income tax expense |
|
|
21,915 |
|
|
|
13,121 |
|
|
|
9,215 |
|
Minority interest |
|
|
|
|
|
|
(50 |
) |
|
|
(17 |
) |
|
Net income from continuing operations before discontinued operations |
|
|
26,252 |
|
|
|
14,685 |
|
|
|
9,967 |
|
Loss from discontinued operations, net of income tax benefit (expense) of $(2) and $127 |
|
|
|
|
|
|
(4 |
) |
|
|
(213 |
) |
|
Net income |
|
$ |
26,252 |
|
|
$ |
14,681 |
|
|
$ |
9,754 |
|
|
Basic income (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations |
|
$ |
1.71 |
|
|
$ |
1.08 |
|
|
$ |
0.79 |
|
Loss from discontinued operations, net of income taxes |
|
|
|
|
|
|
|
|
|
|
(0.01 |
) |
|
Net income per share |
|
$ |
1.71 |
|
|
$ |
1.08 |
|
|
$ |
0.78 |
|
|
Diluted income (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations |
|
$ |
1.68 |
|
|
$ |
1.05 |
|
|
$ |
0.77 |
|
Loss from discontinued operations, net of income taxes |
|
|
|
|
|
|
|
|
|
|
(0.02 |
) |
|
Net income per share |
|
$ |
1.68 |
|
|
$ |
1.05 |
|
|
$ |
0.75 |
|
|
Weighted average shares outstanding basic |
|
|
15,320 |
|
|
|
13,550 |
|
|
|
12,563 |
|
Dilutive stock options |
|
|
311 |
|
|
|
477 |
|
|
|
368 |
|
|
Weighted average shares outstanding diluted |
|
|
15,631 |
|
|
|
14,027 |
|
|
|
12,931 |
|
|
See Notes to Consolidated Financial Statements.
32
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, 2004 |
|
|
12,533,818 |
|
|
$ |
125 |
|
|
$ |
89,759 |
|
|
$ |
13,458 |
|
|
$ |
(9,629 |
) |
|
$ |
|
|
|
$ |
(28 |
) |
|
$ |
93,685 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,754 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,754 |
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in unrecognized pension liability,
net of income tax benefit of $75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(118 |
) |
|
|
|
|
|
|
|
|
|
|
(118 |
) |
Foreign currency translation adjustments,
net of income tax benefit of $328 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,536 |
|
|
|
|
|
|
|
|
|
|
|
1,536 |
|
Change in unrealized gain on exchange
contracts, net of income tax benefit
of $539 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(856 |
) |
|
|
|
|
|
|
|
|
|
|
(856 |
) |
|
Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,316 |
|
|
Issuance of unvested shares |
|
|
24,576 |
|
|
|
|
|
|
|
375 |
|
|
|
|
|
|
|
|
|
|
|
(375 |
) |
|
|
|
|
|
|
|
|
Amortization of unearned compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
94 |
|
|
|
|
|
|
|
94 |
|
Issuance of stock upon exercise of options |
|
|
60,247 |
|
|
|
1 |
|
|
|
346 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
347 |
|
Income tax benefit on exercise of options |
|
|
|
|
|
|
|
|
|
|
227 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
227 |
|
Payment of notes receivable |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28 |
|
|
|
28 |
|
|
Balance, January 31, 2005 |
|
|
12,618,641 |
|
|
|
126 |
|
|
|
90,707 |
|
|
|
23,212 |
|
|
|
(9,067 |
) |
|
|
(281 |
) |
|
|
|
|
|
|
104,697 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,681 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,681 |
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in unrecognized pension liability,
net of income tax benefit of $1,198 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,902 |
|
|
|
|
|
|
|
|
|
|
|
1,902 |
|
Foreign currency translation adjustments,
net of income tax expense of $155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(277 |
) |
|
|
|
|
|
|
|
|
|
|
(277 |
) |
|
Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,306 |
|
|
Cancellation of unvested shares |
|
|
(5,734 |
) |
|
|
|
|
|
|
(87 |
) |
|
|
|
|
|
|
|
|
|
|
67 |
|
|
|
|
|
|
|
(20 |
) |
Amortization of unearned compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
170 |
|
|
|
|
|
|
|
170 |
|
Issuance of stock upon acquisition
of business |
|
|
2,222,216 |
|
|
|
22 |
|
|
|
45,031 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45,053 |
|
Issuance of stock upon exercise of options |
|
|
398,349 |
|
|
|
4 |
|
|
|
3,320 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,324 |
|
Income tax benefit on exercise of options |
|
|
|
|
|
|
|
|
|
|
2,096 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,096 |
|
|
Balance, January 31, 2006 |
|
|
15,233,472 |
|
|
|
152 |
|
|
|
141,067 |
|
|
|
37,893 |
|
|
|
(7,442 |
) |
|
|
(44 |
) |
|
|
|
|
|
|
171,626 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,252 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,252 |
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustments,
net of income tax expense of $35 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
291 |
|
|
|
|
|
|
|
|
|
|
|
291 |
|
|
Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,543 |
|
|
Issuance of unvested shares |
|
|
1,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification of unearned compensation
related to the adoption of SFAS 123R |
|
|
|
|
|
|
|
|
|
|
(44 |
) |
|
|
|
|
|
|
|
|
|
|
44 |
|
|
|
|
|
|
|
|
|
Adjustment to initially apply SFAS 158,
net of income tax benefit of $819 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,302 |
) |
|
|
|
|
|
|
|
|
|
|
(1,302 |
) |
Issuance of stock upon acquisition
of business |
|
|
45,563 |
|
|
|
1 |
|
|
|
1,262 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,263 |
|
Issuance of stock upon exercise of options |
|
|
237,689 |
|
|
|
2 |
|
|
|
3,008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,010 |
|
Income tax benefit on exercise of options |
|
|
|
|
|
|
|
|
|
|
1,654 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,654 |
|
Share-based compensation |
|
|
|
|
|
|
|
|
|
|
2,240 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,240 |
|
|
Balance, January 31, 2007 |
|
|
15,517,724 |
|
|
$ |
155 |
|
|
$ |
149,187 |
|
|
$ |
64,145 |
|
|
$ |
(8,453 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
205,034 |
|
|
See Notes to Consolidated Financial Statements.
33
Layne Christensen Company and Subsidiaries
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
Years Ended January 31, |
|
2007 |
|
2006 |
|
2005 |
|
Cash flow from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
26,252 |
|
|
$ |
14,681 |
|
|
$ |
9,754 |
|
Adjustments to reconcile net income to cash from operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Loss from discontinued operations, net of income taxes |
|
|
|
|
|
|
4 |
|
|
|
213 |
|
Depreciation, depletion and amortization |
|
|
32,853 |
|
|
|
20,024 |
|
|
|
14,441 |
|
Deferred income taxes |
|
|
(2,985 |
) |
|
|
6,540 |
|
|
|
2,806 |
|
Equity in earnings of affiliates |
|
|
(4,452 |
) |
|
|
(4,345 |
) |
|
|
(2,637 |
) |
Dividends received from affiliates |
|
|
1,502 |
|
|
|
1,693 |
|
|
|
1,386 |
|
Minority interest |
|
|
|
|
|
|
50 |
|
|
|
17 |
|
(Gain) loss on disposal of property and equipment |
|
|
(994 |
) |
|
|
295 |
|
|
|
(1,744 |
) |
Gain on sale of domestic affiliate |
|
|
|
|
|
|
(1,289 |
) |
|
|
|
|
Gain on sale of mineral concession |
|
|
(920 |
) |
|
|
|
|
|
|
|
|
Share-based compensation |
|
|
2,240 |
|
|
|
|
|
|
|
|
|
Share-based compensation excess tax benefits |
|
|
(1,382 |
) |
|
|
|
|
|
|
|
|
Changes in current assets and liabilities, (exclusive of effects of acquisitions and
disposals): |
|
|
|
|
|
|
|
|
|
|
|
|
Increase in customer receivables |
|
|
(7,691 |
) |
|
|
(3,139 |
) |
|
|
(7,983 |
) |
Increase in costs and estimated earnings in excess of
billings on uncompleted contracts |
|
|
(10,044 |
) |
|
|
(432 |
) |
|
|
(3,240 |
) |
(Increase) decrease in inventories |
|
|
462 |
|
|
|
3,682 |
|
|
|
(3,428 |
) |
(Increase) decrease in other current assets |
|
|
598 |
|
|
|
(866 |
) |
|
|
939 |
|
Increase in accounts payable and accrued expenses |
|
|
27,522 |
|
|
|
1,594 |
|
|
|
11,336 |
|
Increase (decrease) in billings in excess of costs and estimated
earnings on uncompleted contracts |
|
|
12,312 |
|
|
|
3,534 |
|
|
|
(1,215 |
) |
Other, net |
|
|
(597 |
) |
|
|
(1,185 |
) |
|
|
(722 |
) |
|
Cash from continuing operations |
|
|
74,676 |
|
|
|
40,841 |
|
|
|
19,923 |
|
Cash from (used in) discontinued operations |
|
|
|
|
|
|
28 |
|
|
|
(2,969 |
) |
|
Cash from operating activities |
|
|
74,676 |
|
|
|
40,869 |
|
|
|
16,954 |
|
|
Cash flow used in investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Additions to property and equipment |
|
|
(36,150 |
) |
|
|
(24,427 |
) |
|
|
(15,603 |
) |
Additions to gas transportation facilities and equipment |
|
|
(12,413 |
) |
|
|
(5,125 |
) |
|
|
(2,360 |
) |
Additions to oil and gas properties |
|
|
(23,075 |
) |
|
|
(11,084 |
) |
|
|
(8,608 |
) |
Additions to mineral interests in oil and gas properties |
|
|
(3,174 |
) |
|
|
(2,281 |
) |
|
|
(1,121 |
) |
Payment of cash purchase price adjustment on prior year acquisition |
|
|
(6,120 |
) |
|
|
|
|
|
|
|
|
Deposit of cash into restricted accounts |
|
|
(4,473 |
) |
|
|
|
|
|
|
|
|
Release of cash from restricted accounts |
|
|
5,597 |
|
|
|
|
|
|
|
|
|
Proceeds from disposal of property and equipment |
|
|
4,646 |
|
|
|
892 |
|
|
|
3,214 |
|
Proceeds from sale of businesses |
|
|
|
|
|
|
2,355 |
|
|
|
300 |
|
Proceeds from sale of mineral concession |
|
|
920 |
|
|
|
|
|
|
|
|
|
Acquisition of businesses, net of cash acquired |
|
|
(31,305 |
) |
|
|
(61,542 |
) |
|
|
(14,743 |
) |
Acquisition of gas transportation facilities and equipment |
|
|
|
|
|
|
(1,445 |
) |
|
|
(654 |
) |
Acquisition of oil and gas properties and mineral interests |
|
|
(1,988 |
) |
|
|
(4,704 |
) |
|
|
(2,728 |
) |
Return of capital from (investment in) affiliates |
|
|
411 |
|
|
|
(69 |
) |
|
|
(98 |
) |
|
Cash used in investing activities |
|
|
(107,124 |
) |
|
|
(107,430 |
) |
|
|
(42,401 |
) |
|
Cash flow from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings under revolving credit facilities |
|
|
425,925 |
|
|
|
335,155 |
|
|
|
46,900 |
|
Repayments under revolving credit facilities |
|
|
(403,225 |
) |
|
|
(266,255 |
) |
|
|
(48,900 |
) |
Issuance of long-term debt |
|
|
|
|
|
|
|
|
|
|
20,000 |
|
Debt issuance costs |
|
|
|
|
|
|
(605 |
) |
|
|
|
|
Payments on promissory note |
|
|
|
|
|
|
(1,080 |
) |
|
|
(1,740 |
) |
Issuance of common stock |
|
|
3,010 |
|
|
|
3,324 |
|
|
|
347 |
|
Excess tax benefit on exercise of share-based instruments |
|
|
1,382 |
|
|
|
|
|
|
|
|
|
Payments on notes receivable from management stockholders |
|
|
|
|
|
|
|
|
|
|
28 |
|
|
Cash from financing activities |
|
|
27,092 |
|
|
|
70,539 |
|
|
|
16,635 |
|
|
Effects of exchange rate changes on cash |
|
|
380 |
|
|
|
(403 |
) |
|
|
1,618 |
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
(4,976 |
) |
|
|
3,575 |
|
|
|
(7,194 |
) |
Cash and cash equivalents at beginning of year |
|
|
17,983 |
|
|
|
14,408 |
|
|
|
21,602 |
|
|
Cash and cash equivalents at end of year |
|
$ |
13,007 |
|
|
$ |
17,983 |
|
|
$ |
14,408 |
|
|
See Notes to Consolidated Financial Statements.
34
Notes to Consolidated Financial Statements
(1) Summary of Significant Accounting Policies
Description of Business Layne Christensen Company and subsidiaries (together, the Company)
provide drilling and construction services and related products in two principal markets: water and
wastewater infrastructure and mineral exploration, as well as being a producer of unconventional
natural gas for the energy market. The Company operates throughout North America as well as in
Africa, Australia and Europe. Its customers include municipalities, investor-owned water utilities,
industrial companies, global mining companies, consulting and engineering firms, heavy civil
construction contractors, oil and 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 gains (losses) for 2007, 2006 and 2005 were $95,000,
($290,000) and ($342,000), respectively.
Revenue Recognition Revenues are recognized on large, long-term construction contracts
meeting the criteria of Statement of Position 81-1, Accounting for Performance of Construction-Type
and Certain Production-Type Contracts (SOP 81-1), using the percentage-of-completion method based
upon the ratio of costs incurred to total estimated costs at completion. Contract price and cost
estimates are reviewed periodically as work progresses and adjustments proportionate to the
percentage of completion are reflected in contract revenues in the reporting period when such
estimates are revised. Changes in job performance, job conditions and estimated profitability,
including those arising from contract penalty provisions, change orders and final contract
settlements may result in revisions to costs and income and are recognized in the period in which
the revisions are determined. As allowed by SOP 81-1, revenue is recognized on smaller, short-term
construction contracts using the completed contract method. Provisions for estimated losses on
uncompleted construction contracts are made in the period in which such losses are determined.
Revenues for direct sales of equipment and other ancillary products not provided in
conjunction with the performance of construction contracts are recognized at the date of delivery
to, and acceptance by, the customer. Provisions for estimated warranty obligations are made in the
period in which the sales occur.
Contracts for the Companys mineral exploration drilling services are billable based on the
quantity of drilling performed. Thus, revenues for these drilling contracts are recognized on the
basis of actual footage or meterage drilled.
Revenues for the sale of oil and gas by the Companys energy division are recognized on the
basis of volumes sold at the time of delivery to an end user or an interstate pipeline, net of
amounts attributable to royalty or working interest holders.
The Companys revenues are presented net of taxes imposed on revenue-producing transactions
with its customers, such as, but not limited to, sales, use, value-added, and some excise taxes.
Inventories The Company values inventories at the lower of cost (first-in, first-out) or
market. Allowances are recorded for inventory considered to be excess or obsolete. Inventories
consist primarily of parts and supplies.
Property and Equipment and Related Depreciation Property and equipment (including major
renewals and improvements) are recorded at cost. Depreciation is provided using the straight-line
method. Depreciation expense was $26,825,000, $17,589,000 and $13,561,000 in 2007, 2006 and 2005,
respectively. The lives used for the items within each property classification are as follows:
|
|
|
|
|
|
|
Years |
|
|
Buildings |
|
|
15 35 |
|
Machinery and equipment |
|
|
3 10 |
|
Gas transportation facilities and equipment |
|
|
15 |
|
35
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 $4,917,000, $2,021,000 and $880,000 in 2007, 2006
and 2005, 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%. Application
of the ceiling test generally requires pricing future revenues at the unescalated prices in effect
as of the last day of the quarter, with effect given to the 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 SFAS 142, Goodwill and Other Intangible Assets. Other intangible assets
primarily consist of trademarks, customer-related intangible assets and patents obtained through
business acquisitions. Amortizable intangible assets are being amortized over their estimated
useful lives, which range from two to 40 years.
The impairment evaluation for goodwill is conducted annually, or more frequently if events or
changes in circumstances indicate that an asset might be impaired. The evaluation is performed by
using a two-step process. In the first step, the fair value of each reporting unit is compared with
the carrying amount of the reporting unit, including goodwill. The estimated fair value of the
reporting unit is generally determined on the basis of discounted future cash flows. If the
estimated fair value of the reporting unit is less than the carrying amount of the reporting unit,
then a second step must be completed in order to determine the amount of the goodwill impairment
that should be recorded. In the second step, the implied fair value of the reporting 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.
Other Long-Lived Assets In the event of an indication of possible impairment, the
Company evaluates the carrying value of long-lived assets, including the Companys gas
transportation facilities and equipment, by performing an analysis of the anticipated future net
cash flows of the related long-lived assets and reducing their carrying value by the excess, if
any, of the result of such calculation. The Company believes at this time that the carrying value
and useful lives of its long-lived assets continues to be appropriate.
Restricted Cash Restricted cash consists of escrow funds associated with the
acquisition of Reynolds as described in Note 2 of the Notes to Consolidated Financial Statements.
Accrued Insurance Expense Costs estimated to be incurred in the future for employee
health and welfare benefits, workers
36
compensation, 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.
Fair Value of Financial Instruments The carrying amounts of financial instruments
including cash and cash equivalents, customer receivables and accounts payable approximate fair
value at January 31, 2007 and 2006, because of the relatively short maturity of those instruments.
See Note 11 for disclosure regarding the fair value of indebtedness of the Company and Note 12 for
disclosure regarding the fair value of derivative instruments.
Litigation and Other Contingencies The Company is involved in litigation incidental to
its business, the disposition of which is not expected to have a material effect on the 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 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 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. 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) |
|
2007 |
|
2006 |
|
2005 |
|
Income taxes |
|
$ |
15,489 |
|
|
$ |
7,399 |
|
|
$ |
3,017 |
|
Interest |
|
|
9,564 |
|
|
|
5,547 |
|
|
|
3,665 |
|
Supplemental Non-cash Transactions The Company had earnings on restricted cash of
$252,000 and $143,000 for 2007 and 2006, which was treated as a non-cash item as it was restricted
for the account of the escrow beneficiaries.
In connection with the Collector Wells Acquisition (see Note 2), the Company issued 45,563
shares of common stock during the year ended January 31, 2007. The shares were valued at $1,263,000
based upon a five-day average of the closing price of the stock two days before and two days after
the terms of the acquisition were agreed to and publicly announced.
In connection with the Reynolds acquisition (see Note 2), the Company issued 2,222,216 shares
of common stock during the year ended January 31, 2006. The shares were valued at $45,053,000 based
upon a five-day average of the closing price of the stock two days before and two days after the
terms of the acquisition were agreed to and publicly announced.
In connection with the Beylik acquisition (see Note 2), the Company issued 24,576 shares of
restricted common stock during the year ended January 31, 2005. The shares had a fair market value
of $375,000 and vested over two years.
Income Taxes Income taxes are provided using the asset/ liability method, in which
deferred taxes are recognized for the tax consequences of temporary differences between the
financial statement carrying amounts and tax bases of existing assets and liabilities. Deferred tax
assets are reviewed for recoverability and valuation allowances are provided as necessary.
Provision for U.S. income taxes on undistributed earnings of foreign subsidiaries and affiliates is
made only on those amounts in excess of those funds considered to be invested indefinitely (see
Note 8).
Earnings Per Share Earnings per common share are based upon the weighted average number
of common and dilutive equivalent shares outstanding. Options to purchase common stock are included
based on the treasury stock method for dilutive earnings per share except when their effect is
antidilutive. Options to purchase 311,344, 460,231 and 310,000 shares have been excluded from
weighted average shares in 2007, 2006 and 2005, respectively, as their effect was
antidilutive.
37
Share-Based Compensation The Company adopted SFAS 123R (revised December 2004),
Share-Based Compensation effective February 1, 2006, which requires the recognition of all
share-based instruments in the financial statements and establishes a fair-value measurement of the
associated costs. The Company has elected to adopt the new standard using the Modified Prospective
Method which requires recognition of compensation expense related to all unvested share-based
instruments as of the effective date over the remaining term of the instrument. As a result of
adopting SFAS 123R on February 1, 2006, our income before income taxes is $2,186,000 lower for the
year ended January 31, 2007, and net income is $1,509,000 lower for the year ended January 31,
2007, than if we had continued to account for share-based compensation under APB 25. The impact of
the adoption of SFAS 123R was to lower basic and diluted earnings per share for the year ended
January 31, 2007 by $0.10 per share. The Modified Prospective Method has no financial impact on
prior fiscal years. As of January 31, 2007, the Company had unrecognized compensation expense of
$5,034,000 to be recognized over a weighted average period of 2.65 years. The Company determines
the fair value of share-based compensation using the Black-Scholes model.
In November 2005, the FASB issued FASB Staff Position FAS 123R-3 Transition Election Related
to Accounting for Tax Effects of Share-Based Payment Awards. The Company has elected to adopt the
alternative transition method provided in the FASB Staff Position for calculating the tax effects
of share-based compensation pursuant to SFAS 123R. The alternative transition method includes
simplified methods to establish the beginning balance of the additional paid-in capital pool (APIC
pool) related to the tax effects of employee share-based compensation, and to determine the
subsequent impact on the APIC pool and Consolidated Statements of Cash Flows of the tax effects of
employee share-based compensation awards that are outstanding upon adoption of SFAS 123R.
Share-based compensation prior to the effective date of SFAS 123R may be accounted for based
on either the estimated fair value of the awards at the date they are granted (the SFAS 123
Method) or on the difference, if any, between the market price of the stock at the date of grant
and the amount the employee must pay to acquire the stock (the APB 25 Method). The Company used
the APB 25 Method to account for its share-based compensation programs that were vested prior to
the effective date of SFAS 123R and recognized no compensation expense under this method.
Pro forma net income and earnings per share for 2006 and 2005, determined as if the SFAS 123
Method has been applied, is presented in the following table:
|
|
|
|
|
|
|
|
|
(in thousands, |
|
|
|
|
except per share amounts) |
|
2006 |
|
2005 |
|
Net income, as reported |
|
$ |
14,681 |
|
|
$ |
9,754 |
|
Deduct: |
|
|
|
|
|
|
|
|
Total stock-based employee
compensation determined under
fair value based method for all
awards, net of income taxes of
$428 and $260 |
|
|
(681 |
) |
|
|
(414 |
) |
|
Pro forma net income |
|
$ |
14,000 |
|
|
$ |
9,340 |
|
|
Net income per share: |
|
|
|
|
|
|
|
|
Basic as reported |
|
$ |
1.08 |
|
|
$ |
0.78 |
|
|
Basic pro forma |
|
$ |
1.03 |
|
|
$ |
0.74 |
|
|
Diluted as reported |
|
$ |
1.05 |
|
|
$ |
0.75 |
|
|
Diluted proforma |
|
$ |
1.00 |
|
|
$ |
0.72 |
|
|
Unearned Compensation Unearned compensation expense associated with the issuance of
unvested shares is amortized on a straight-line basis as the restrictions on the stock expire. As
required by SFAS 123R, unearned compensation of $44,000, which was previously reflected as a
reduction to shareholders equity as of January 31, 2006, was reclassified as a reduction to
additional paid in capital.
Other Comprehensive Loss Accumulated balances, net of
income taxes, of Other Comprehensive Loss are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
Cumulative |
|
Unrecognized |
|
Other |
|
|
Translation |
|
Pension |
|
Comprehensive |
(in thousands) |
|
Adjustment |
|
Liability |
|
Loss |
|
Balance, February 1, 2005 |
|
$ |
(7,165 |
) |
|
$ |
(1,902 |
) |
|
$ |
(9,067 |
) |
Period change |
|
|
(277 |
) |
|
|
1,902 |
|
|
|
1,625 |
|
|
Balance, January 31, 2006 |
|
|
(7,442 |
) |
|
|
|
|
|
|
(7,442 |
) |
Period change |
|
|
291 |
|
|
|
(1,302 |
) |
|
|
(1,011 |
) |
|
Balance, January 31, 2007 |
|
$ |
(7,151 |
) |
|
$ |
(1,302 |
) |
|
$ |
(8,453 |
) |
|
38
(2) Acquisitions
On November 20, 2006, the Company acquired 100% of the stock of American Water Services
Underground Infrastructure, Inc. (UIG), a wholly-owned subsidiary of American Water (USA), Inc.
UIG is engaged in the business of providing trenchless pipeline rehabilitation services for sewer
and stormwater systems and will be combined with a similar service line acquired in the acquisition
of Reynolds, Inc. The purchase price for UIG was $27,662,000, consisting of cash of $27,524,000 and
costs of $138,000. The cash portion of the purchase price is net of certain purchase price
adjustments based on the amount of tangible net worth at the closing date, $1,101,000 of which was
received by the Company in February 2007.
The purchase price has been allocated based on the fair value of the assets and liabilities
acquired, determined based on UIGs historical cost basis of assets and liabilities, appraisals and
other analyses. Such amounts may be subject to revision as UIG is integrated into the Company and
the revisions may be significant and will be recorded by the Company as further adjustments to the
purchase price allocation.
Based on the Companys preliminary allocation of the purchase price, the acquisition had the
following effect on the Companys consolidated financial position:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Working capital |
|
$ |
11,723 |
|
Property and equipment |
|
|
13,602 |
|
Goodwill |
|
|
3,891 |
|
Other intangible assets |
|
|
143 |
|
Other long-term assets |
|
|
69 |
|
Deferred income taxes |
|
|
(1,766 |
) |
|
Total purchase price |
|
$ |
27,662 |
|
|
The results of operations of UIG have been included in the Companys consolidated statements of
income commencing with the closing date. Assuming UIG had been acquired as of the beginning of each
period, the unaudited pro forma consolidated revenues, net income from continuing operations, net
income and net income per share would have been as follows:
|
|
|
|
|
|
|
|
|
(in thousands, except per share data) |
|
2007 |
|
2006 |
|
Revenues |
|
$ |
760,752 |
|
|
$ |
506,776 |
|
Net income |
|
|
25,199 |
|
|
|
14,303 |
|
Basic earnings per share |
|
$ |
1.64 |
|
|
$ |
1.06 |
|
Diluted earnings per share |
|
$ |
1.61 |
|
|
$ |
1.02 |
|
The pro forma information provided above is not necessarily indicative of the results of operations
that would actually have resulted if the acquisition was made as of those dates or of results that
may occur in the future. Pro forma results include adjustments for interest expense on the cash
purchase price and depreciation and amortization expense on the acquisition adjustments to property
and equipment and other intangible assets.
In July 2006 and January 2007, the Company purchased certain gas wells and mineral interests
in oil and gas properties from unrelated operators totaling $1,988,000 in cash. The acquisitions
complemented the Companys existing operation in the mid-continent region of the United States. The
purchase price was allocated $1,376,000 to oil and gas properties and $612,000 to mineral interests
in oil and gas properties.
On June 16, 2006 (the CWI Closing Date), the Company acquired 100% of the stock of Collector
Wells International, Inc. (CWI), a privately held specialty water services company that designs
and constructs water supply systems. CWI will be combined with a similar service line acquired in
the acquisition of Reynolds, Inc. The purchase price for CWI was $5,442,000, consisting of
$3,150,000 cash, 45,563 shares of Layne common stock (valued at $1,263,000), cash purchase price
adjustments and costs of $1,029,000 ($240,000 of which will be paid in future periods). Layne
common stock was valued in the transaction based upon a five-day average of the closing price of
the stock two days before and two days after the CWI Closing Date. The stock was placed in escrow
to secure certain representations, warranties and indemnifications under the purchase agreement and
will be released in three annual installments. The cash purchase price adjustments were based on
the amount by which working capital at the CWI Closing Date exceeded a threshold amount established
in the purchase agreement.
In addition, there is contingent consideration up to a maximum of $1,400,000 (the CWI Earnout
Amount), which is based on a percentage of the amount by which CWIs earnings before interest,
taxes, depreciation and amortization exceed a threshold amount during the thirty-six months
following the acquisition. If earned, up to 20% of the CWI Earnout Amount may be paid with Layne
common stock, at the Companys discretion. Any portion of the CWI Earnout Amount which is
ultimately paid will be accounted for as additional purchase consideration.
The purchase price has been allocated based on the fair value of the assets and liabilities
acquired, determined based on CWIs historical cost basis of assets and liabilities and other
analyses. Such amounts may be subject to revision as CWI is integrated into the Company and the
revisions may be significant and will be recorded by the Company as further adjustments to the
purchase price allocation.
Based on the Companys allocation of the purchase price, the acquisition had the following
effect on the Companys consolidated financial position (in thousands):
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Working capital |
|
$ |
1,016 |
|
Property and equipment |
|
|
1,580 |
|
Goodwill |
|
|
3,436 |
|
Deferred income taxes |
|
|
(590 |
) |
|
Total purchase price |
|
$ |
5,442 |
|
|
The results of operations of CWI have been included in the Companys consolidated statements of
income commencing with the CWI Closing Date. The acquisition did not have a significant effect on
the Companys results of operations or cash flows.
On September 28, 2005 (the Closing Date), the Company acquired 100% of the outstanding stock
of Reynolds, Inc. (Reynolds), a privately held company and a major supplier of products and
services to the water and wastewater industries. The acquisition expanded the capabilities of the
Companys water and wastewater infrastructure division in the areas of water and wastewater
infrastructure. Reynolds primary service lines include design and building of water and wastewater
treatment plants, water and wastewater transmission lines, cured
in place pipe (CIPP) services for sewer rehabilitation, water supply wells and Ranney
collector wells.
39
The purchase price for Reynolds was $112,356,000, consisting of $60,000,000 cash, 2,222,216
shares of Layne common stock (valued at $45,053,000), cash purchase price adjustments of $6,120,000
(paid in 2007) and costs of $1,183,000. Layne common stock was valued in the transaction based upon
a five-day average of the closing price of the stock two days before and two days after the terms
of the acquisition were agreed to and publicly announced. Of the cash and stock consideration,
$9,000,000 and 333,333 shares of Layne common stock were placed in escrow to secure certain
representations, warranties and indemnifications under the purchase agreement (the Escrow Fund).
The Escrow Fund will be released to the Reynolds 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. The cash purchase price adjustments
consist primarily of an adjustment to be paid based on the amount by which working capital at the
Closing Date exceeded a threshold amount established in the purchase agreement. Under the terms of
the agreement, a portion of the cash purchase price adjustments was paid to the Reynolds
shareholders from the Escrow Fund in 2007. The Escrow Fund will be replenished by this amount based
on the collection of certain contract retainage amounts during the twenty-four months following the
Closing Date.
In addition, there is contingent consideration up to a maximum of $15,000,000 (the Earnout
Amount), which is based on Reynolds operating performance over a period of thirty-six months
following the Closing Date (the Earnout Period). The Earnout Payment is based on a multiple of
Reynolds earnings before interest, taxes, depreciation and amortization which exceed a threshold
amount during the Earnout Period. If earned, the contingent payment will be paid 60% in cash and
40% in Layne common stock, subject to stockholder approval of the shares to be issued, if required.
Any shares not approved for issuance will be paid in cash. Any portion of the Earnout Amount which
is ultimately paid will be accounted for as additional purchase consideration.
The purchase price has been allocated based on the fair value of the assets and liabilities
acquired, determined based on Reynolds historical cost basis of assets and liabilities, appraisals
and other analyses.
Based on the 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 commencing with the Closing Date. Assuming Reynolds had been acquired as of the beginning
of each period, the unaudited pro forma consolidated revenues, net income from continuing
operations, net income and net income per share would have been as follows:
|
|
|
|
|
|
|
|
|
(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 is not necessarily indicative of the results of operations
that would actually have resulted if the acquisition were made as of those dates or of results that
may occur in the future. Pro forma results include adjustments for interest expense on the cash
purchase price, depreciation and amortization expense on the acquisition adjustments to property
and equipment and other intangible assets and for the additional shares outstanding.
In October 2005, the Company purchased the remaining 25% working interest in various 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:
|
|
|
|
|
(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 strengthened the Companys water resources presence on the
40
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:
(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. 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, 2007:
|
|
|
|
|
|
|
Owned |
|
Christensen Chile, S.A. (Chile) |
|
|
49.99 |
% |
Christensen Commercial, S.A. (Chile) |
|
|
50.00 |
|
Geotec Boyles Bros., S.A. (Chile) |
|
|
49.75 |
|
Boyles Bros. Diamantina, S.A. (Chile) |
|
|
29.49 |
|
Christensen Commercial, S.A. (Peru) |
|
|
35.38 |
|
Geotec, S.A. (Peru) |
|
|
35.38 |
|
Boytec, S.A. (Panama) |
|
|
49.99 |
|
Plantel Industrial S.A. (Chile) |
|
|
50.00 |
|
Boytec Sondajes de Mexico, S.A. de C.V. (Mexico) |
|
|
49.99 |
|
Geoductos Chile, S.A. (Chile) |
|
|
50.00 |
|
Mining Drilling Fluids (Panama) |
|
|
25.00 |
|
Diamantina Christensen Trading (Panama) |
|
|
42.69 |
|
Boyles Bros. do Brasil Ltd. (Brazil) |
|
|
40.00 |
|
In May 2004, the Company entered into a domestic corporate joint venture with Nicholson
Construction Company to complete a construction project. The Company invested $200,000 to acquire
50% ownership in the joint venture. The project was substantially completed in 2006 and the joint
venture was liquidated in 2007.
Financial information of the affiliates is reported with a one-month lag in the reporting
period. Summarized financial information of the affiliates as of January 31, 2007, 2006 and 2005,
and for the years then ended, was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2007 |
|
2006 |
|
2005 |
|
Current assets |
|
$ |
42,584 |
|
|
$ |
36,937 |
|
|
$ |
34,402 |
|
Noncurrent assets |
|
|
29,696 |
|
|
|
28,866 |
|
|
|
24,552 |
|
Current liabilities |
|
|
19,857 |
|
|
|
17,178 |
|
|
|
17,208 |
|
Noncurrent liabilities |
|
|
4,755 |
|
|
|
5,211 |
|
|
|
3,391 |
|
Revenues |
|
|
130,090 |
|
|
|
103,735 |
|
|
|
86,661 |
|
Gross profit |
|
|
23,274 |
|
|
|
18,003 |
|
|
|
14,056 |
|
Operating income |
|
|
14,319 |
|
|
|
10,828 |
|
|
|
7,966 |
|
Net income |
|
|
10,862 |
|
|
|
9,452 |
|
|
|
5,902 |
|
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, 2007, 2006 and
2005, and for the years then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2007 |
|
2006 |
|
2005 |
|
Accounts Receivable |
|
$ |
|
|
|
$ |
|
|
|
$ |
202 |
|
Revenues |
|
|
3 |
|
|
|
302 |
|
|
|
955 |
|
Undistributed equity in earnings of the affiliates totaled $9,635,000, $7,096,000 and $4,870,000 as
of January 31, 2007, 2006 and 2005, respectively.
In September 2002, the Company invested in a joint venture with a privately-held limited
partnership to develop a water storage bank on property located in California. The Company invested
$1,059,000 to acquire 10% ownership in the joint venture. The investment was accounted for using
the equity method until June 2003 as the Company exercised significant influence over the joint
venture through a management contract. After June 2003, the investment was accounted for using the
cost method as the management contract terminated and the Company no longer exercised significant
influence over the joint venture. The investment was sold in October 2005 resulting in a gain of
$1,289,000, which was recorded as Other income in the statement of income.
(4) Discontinued Operations
During 2004, the Company sold two businesses and reclassified the results of operations of the
businesses to discontinued operations in accordance with SFAS 144, Accounting for the Impairment
or Disposal of Long-Lived Assets. There were no revenues from the businesses in 2007, 2006 or
2005. Losses from discontinued operations before income taxes for 2006 and 2005 were $2,000 and
$340,000, respectively
41
(5) Goodwill and Other Intangible Assets
Goodwill and other intangible assets consist of the following as of January 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
|
Gross |
|
|
|
|
|
Gross |
|
|
|
|
Carrying |
|
Accumulated |
|
Carrying |
|
Accumulated |
(in thousands) |
|
Amount |
|
Amortization |
|
Amount |
|
Amortization |
|
Goodwill (non tax
deductible) |
|
$ |
65,184 |
|
|
$ |
|
|
|
$ |
57,857 |
|
|
$ |
|
|
|
Other amortizable
intangible assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tradenames |
|
$ |
16,000 |
|
|
$ |
(818 |
) |
|
$ |
16,000 |
|
|
$ |
(204 |
) |
Customer-related |
|
|
332 |
|
|
|
(134 |
) |
|
|
227 |
|
|
|
(34 |
) |
Patents |
|
|
359 |
|
|
|
(160 |
) |
|
|
359 |
|
|
|
(40 |
) |
Non-competition
agreements |
|
|
379 |
|
|
|
(227 |
) |
|
|
379 |
|
|
|
(58 |
) |
Other |
|
|
762 |
|
|
|
(476 |
) |
|
|
730 |
|
|
|
(411 |
) |
|
Total amortizable
intangible assets |
|
$ |
17,832 |
|
|
$ |
(1,815 |
) |
|
$ |
17,695 |
|
|
$ |
(747 |
) |
|
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 $1,068,000, $387,000 and $43,000 in 2007, 2006 and 2005, respectively.
Accumulated amortization expense as of January 31, 2007 was $1,815,000. Amortization expense for
the subsequent five fiscal years is estimated as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
2008 |
|
$ |
1,050 |
|
2009 |
|
|
796 |
|
2010 |
|
|
701 |
|
2011 |
|
|
664 |
|
2012 |
|
|
632 |
|
The carrying amount of goodwill attributed to each operating segment was as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Water and Wastewater |
|
|
|
|
Energy |
|
Infrastructure |
|
Total |
|
Balance, February 1, 2005 |
|
$ |
950 |
|
|
$ |
7,075 |
|
|
$ |
8,025 |
|
Additions |
|
|
|
|
|
|
49,832 |
|
|
|
49,832 |
|
|
Balance, January 31, 2006 |
|
|
950 |
|
|
|
56,907 |
|
|
|
57,857 |
|
Additions |
|
|
|
|
|
|
7,327 |
|
|
|
7,327 |
|
|
Balance, January 31, 2007 |
|
$ |
950 |
|
|
$ |
64,234 |
|
|
$ |
65,184 |
|
|
(6) Other Income (Expense)
Other income (expense) consisted of the following for the years ended January 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2007 |
|
2006 |
|
2005 |
|
Gain (loss) from disposal of
property and equipment |
|
$ |
994 |
|
|
$ |
(295 |
) |
|
$ |
1,744 |
|
Gain on sale of domestic affiliate |
|
|
|
|
|
|
1,289 |
|
|
|
|
|
Gain on sale of mineral concession |
|
|
920 |
|
|
|
|
|
|
|
|
|
Exchange gain (loss) |
|
|
95 |
|
|
|
(290 |
) |
|
|
(342 |
) |
Miscellaneous, net |
|
|
548 |
|
|
|
196 |
|
|
|
(182 |
) |
|
Total |
|
$ |
2,557 |
|
|
$ |
900 |
|
|
$ |
1,220 |
|
|
The gain (loss) from disposal of property and equipment relate to the Companys efforts to monetize
non-strategic assets as well as gains from disposals in the ordinary course of business. In January
2007, the Company sold its interest in a minerals concession for a gain of $920,000. In October
2005, the Company sold its investment in a joint venture to develop a water bank for a gain of
$1,289,000 (see Note 3).
42
(7) Costs and Estimated Earnings on Uncompleted Contracts:
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2007 |
|
2006 |
|
Costs incurred on uncompleted contracts |
|
$ |
711,922 |
|
|
$ |
441,473 |
|
Estimated earnings |
|
|
155,520 |
|
|
|
102,947 |
|
|
|
|
|
867,442 |
|
|
|
544,420 |
|
Less: Billings to date |
|
|
850,474 |
|
|
|
529,244 |
|
|
Total |
|
$ |
16,968 |
|
|
$ |
15,176 |
|
|
Included in accompanying balance sheets
under the following captions: |
|
|
|
|
|
|
|
|
Costs and estimated earnings in excess
of billings on uncompleted contracts |
|
$ |
51,210 |
|
|
$ |
36,538 |
|
Billings in excess of costs and estimated
earnings on uncompleted contracts |
|
|
(34,242 |
) |
|
|
(21,362 |
) |
|
Total |
|
$ |
16,968 |
|
|
$ |
15,176 |
|
|
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, 2007 and 2006, the Company held
unbilled contract retainage amounts of $26,652,000 and $19,350,000, respectively.
(8) Income Taxes
Income (loss) from continuing operations before income taxes is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2007 |
|
2006 |
|
2005 |
|
Domestic |
|
$ |
31,928 |
|
|
$ |
21,039 |
|
|
$ |
13,234 |
|
Foreign |
|
|
16,239 |
|
|
|
6,817 |
|
|
|
5,965 |
|
|
Total |
|
$ |
48,167 |
|
|
$ |
27,856 |
|
|
$ |
19,199 |
|
|
Components of income tax expense are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2007 |
|
2006 |
|
2005 |
|
Currently due: |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
$ |
13,150 |
|
|
$ |
3,536 |
|
|
$ |
438 |
|
State and local |
|
|
2,541 |
|
|
|
462 |
|
|
|
16 |
|
Foreign |
|
|
8,615 |
|
|
|
3,785 |
|
|
|
5,174 |
|
|
|
|
|
24,306 |
|
|
|
7,783 |
|
|
|
5,628 |
|
|
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
|
(941 |
) |
|
|
4,100 |
|
|
|
3,995 |
|
State and local |
|
|
(649 |
) |
|
|
372 |
|
|
|
848 |
|
Foreign |
|
|
(801 |
) |
|
|
866 |
|
|
|
(1,256 |
) |
|
|
|
|
(2,391 |
) |
|
|
5,338 |
|
|
|
3,587 |
|
|
Total |
|
$ |
21,915 |
|
|
$ |
13,121 |
|
|
$ |
9,215 |
|
|
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) |
|
2007 |
|
2006 |
|
|
Assets |
|
Liabilities |
|
Total |
|
Assets |
|
Liabilities |
|
Total |
|
Contract income |
|
$ |
4,372 |
|
|
$ |
|
|
|
$ |
4,372 |
|
|
$ |
3,041 |
|
|
$ |
|
|
|
$ |
3,041 |
|
Inventories |
|
|
1,956 |
|
|
|
(164 |
) |
|
|
1,792 |
|
|
|
1,852 |
|
|
|
(306 |
) |
|
|
1,546 |
|
Accrued insurance |
|
|
2,600 |
|
|
|
|
|
|
|
2,600 |
|
|
|
2,254 |
|
|
|
|
|
|
|
2,254 |
|
Other accrued
liabilities |
|
|
2,382 |
|
|
|
|
|
|
|
2,382 |
|
|
|
1,547 |
|
|
|
|
|
|
|
1,547 |
|
Prepaid expenses |
|
|
|
|
|
|
(619 |
) |
|
|
(619 |
) |
|
|
|
|
|
|
(409 |
) |
|
|
(409 |
) |
Bad debts |
|
|
2,521 |
|
|
|
|
|
|
|
2,521 |
|
|
|
2,243 |
|
|
|
|
|
|
|
2,243 |
|
Employee
compensation |
|
|
3,361 |
|
|
|
|
|
|
|
3,361 |
|
|
|
1,339 |
|
|
|
|
|
|
|
1,339 |
|
Alternative minimum
tax credit |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
474 |
|
|
|
|
|
|
|
474 |
|
Other |
|
|
481 |
|
|
|
(339 |
) |
|
|
142 |
|
|
|
115 |
|
|
|
(174 |
) |
|
|
(59 |
) |
|
Total current |
|
|
17,673 |
|
|
|
(1,122 |
) |
|
|
16,551 |
|
|
|
12,865 |
|
|
|
(889 |
) |
|
|
11,976 |
|
|
Cumulative
translation
adjustment |
|
|
5,088 |
|
|
|
|
|
|
|
5,088 |
|
|
|
5,124 |
|
|
|
|
|
|
|
5,124 |
|
Buildings,
machinery and
equipment |
|
|
126 |
|
|
|
(16,554 |
) |
|
|
(16,428 |
) |
|
|
204 |
|
|
|
(15,509 |
) |
|
|
(15,305 |
) |
Gas transportation
facilities and
equipment |
|
|
|
|
|
|
(2,270 |
) |
|
|
(2,270 |
) |
|
|
|
|
|
|
(1,297 |
) |
|
|
(1,297 |
) |
Mineral interests
and oil and gas
properties |
|
|
|
|
|
|
(11,779 |
) |
|
|
(11,779 |
) |
|
|
|
|
|
|
(7,681 |
) |
|
|
(7,681 |
) |
Intangible assets |
|
|
747 |
|
|
|
(6,072 |
) |
|
|
(5,325 |
) |
|
|
617 |
|
|
|
(6,465 |
) |
|
|
(5,848 |
) |
Tax deductible
goodwill |
|
|
3,448 |
|
|
|
|
|
|
|
3,448 |
|
|
|
3,533 |
|
|
|
|
|
|
|
3,533 |
|
Accrued insurance |
|
|
3,384 |
|
|
|
|
|
|
|
3,384 |
|
|
|
2,723 |
|
|
|
|
|
|
|
2,723 |
|
Pension |
|
|
673 |
|
|
|
(331 |
) |
|
|
342 |
|
|
|
600 |
|
|
|
(1,457 |
) |
|
|
(857 |
) |
Stock-based
compensation |
|
|
633 |
|
|
|
|
|
|
|
633 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Unremitted foreign
earnings |
|
|
|
|
|
|
(1,587 |
) |
|
|
(1,587 |
) |
|
|
|
|
|
|
(1,302 |
) |
|
|
(1,302 |
) |
Other |
|
|
1,430 |
|
|
|
(238 |
) |
|
|
1,192 |
|
|
|
1,577 |
|
|
|
(222 |
) |
|
|
1,355 |
|
|
Total noncurrent |
|
|
15,529 |
|
|
|
(38,831 |
) |
|
|
(23,302 |
) |
|
|
14,378 |
|
|
|
(33,933 |
) |
|
|
(19,555 |
) |
|
Total |
|
$ |
33,202 |
|
|
$ |
(39,953 |
) |
|
$ |
(6,751 |
) |
|
$ |
27,243 |
|
|
$ |
(34,822 |
) |
|
$ |
(7,579 |
) |
|
43
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 $4,500,000 that
expire between 2013 and 2021.
As of January 31, 2007, undistributed earnings of foreign subsidiaries and certain foreign
affiliates included $21,600,000 for which no federal income or foreign withholding taxes have been
provided. These earnings, which are considered to be invested indefinitely, become subject to
income tax if they were remitted as dividends or if the Company were to sell its stock in the
affiliates or subsidiaries. It is not practicable to determine the amount of income or withholding
tax that would be payable upon remittance of these earnings.
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
|
|
|
|
|
Effective |
|
|
|
|
|
Effective |
|
|
|
|
|
Effective |
(in thousands) |
|
Amount |
|
Rate |
|
Amount |
|
Rate |
|
Amount |
|
Rate |
|
Income tax at statutory rate |
|
$ |
16,858 |
|
|
|
35.0 |
% |
|
$ |
9,750 |
|
|
|
35.0 |
% |
|
$ |
6,720 |
|
|
|
35.0 |
% |
State income tax, net |
|
|
1,230 |
|
|
|
2.6 |
|
|
|
542 |
|
|
|
1.9 |
|
|
|
562 |
|
|
|
2.9 |
|
Difference in tax expense
resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nondeductible expenses |
|
|
842 |
|
|
|
1.8 |
|
|
|
593 |
|
|
|
2.1 |
|
|
|
475 |
|
|
|
2.5 |
|
Taxes on foreign
affiliates |
|
|
(774 |
) |
|
|
(1.6 |
) |
|
|
(422 |
) |
|
|
(1.5 |
) |
|
|
(446 |
) |
|
|
(2.3 |
) |
Taxes on foreign
operations |
|
|
3,461 |
|
|
|
7.2 |
|
|
|
2,641 |
|
|
|
9.5 |
|
|
|
2,171 |
|
|
|
11.3 |
|
Other, net |
|
|
298 |
|
|
|
0.5 |
|
|
|
17 |
|
|
|
0.1 |
|
|
|
(267 |
) |
|
|
(1.4 |
) |
|
|
|
$ |
21,915 |
|
|
|
45.5 |
% |
|
$ |
13,121 |
|
|
|
47.1 |
% |
|
$ |
9,215 |
|
|
|
48.0 |
% |
|
The Company has recorded reserves for uncertain tax positions that involve income,
deductions or credits reported in prior year income tax returns that the Company believes were
treated properly. The tax returns are either under current examination or are subject to possible
examination by the Internal Revenue Service or other tax authorities. The ultimate resolution of
these items is uncertain. If the tax positions taken on the returns are ultimately upheld or not
challenged, the resulting tax reserves will be released as tax benefits. If the positions taken on
the returns are determined to be inappropriate, the Company may be required to make cash payments
for taxes, interest and penalties. The reserves have been established using the Companys best
estimates, and are adjusted from time to time based on changing circumstances.
(9) Operating Leases
Future minimum rental payments required under operating leases that have initial or remaining
noncancellable lease terms in excess of one year from January 31, 2007, are as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
2008 |
|
$ |
6,591 |
|
2009 |
|
|
5,044 |
|
2010 |
|
|
2,770 |
|
2011 |
|
|
1,638 |
|
2012 |
|
|
1,249 |
|
Thereafter |
|
|
|
|
Operating leases are primarily for light and medium duty trucks and other equipment. Rent expense
under operating leases (including insignificant amounts of contingent rental payments) was
$22,866,000, $14,603,000 and $11,992,000 in 2007, 2006 and 2005, respectively.
(10) Employee Benefit Plans
The Company sponsors a pension plan covering certain hourly employees not covered by
union-sponsored, multi-employer plans. Benefits are computed based mainly on years of service. The
Company makes annual contributions to the plan substantially equal to the amounts required to
maintain the qualified status of the plan. Contributions are intended to provide for benefits
related to past and current service with the Company. Effective December 31, 2003, the Company
froze the pension plan and recorded a curtailment loss of approximately $20,000. Benefits will no
longer be accrued after December 31, 2003, and no further employees will be added to the Plan. The
Company expects to maintain the assets of the Plan to pay normal benefits accrued through December
31, 2003. Assets of the plan consist primarily of stocks, bonds and government securities.
On January 31, 2007, the Company adopted the recognition and disclosure provisions of SFAS
158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans An
Amendment of FASB Statements 87, 88, 106 and 132(R). SFAS 158 required the Company to recognize
the funded status (i.e., the difference between the fair value of plan assets and the projected
benefit obligations) of its pension plans in the January 31, 2007 balance sheet, with a
corresponding adjustment to accumulated other comprehensive income, net of tax. The adjustment to
accumulated other comprehensive income at adoption represents the net unrecognized actuarial losses
which were previously netted against the plans funded status in the Companys balance sheet
pursuant to the provisions of SFAS 87. These amounts will be subsequently recognized as net
periodic pension cost pursuant to the Companys historical accounting policy for amortizing such
amounts. Further, actuarial gains and losses that arise in subsequent periods and are not
recognized as net periodic
pension costs in the same periods will be recognized as a component of other comprehensive
income. Those
44
amounts will be subsequently recognized as a component of net periodic pension cost
on the same basis as the amounts recognized in accumulated other comprehensive income at adoption
of SFAS 158.
The incremental effects of adopting the provisions of SFAS 158 on the Companys consolidated
balance sheet at January 31, 2007 are presented in the following table. The adoption of SFAS 158
had no effect on the Companys consolidated statement of operations for the year ended January 31,
2007, or for any prior period presented, and it will not effect the Companys operating results in
future periods.
The following table illustrates the effect of applying SFAS 158 as of January 31, 2007 (in
thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plan |
|
|
Prior to |
|
|
|
|
|
Post |
|
|
Adoption |
|
|
|
|
|
Adoption |
|
|
of SFAS |
|
|
|
|
|
of SFAS |
|
|
158 |
|
Adjustments |
|
158 |
|
Other non-current assets |
|
$ |
2,979 |
|
|
$ |
(2,121 |
) |
|
$ |
858 |
|
|
Accumulated other
comprehensive loss
before taxes |
|
$ |
|
|
|
$ |
(2,121 |
) |
|
$ |
(2,121 |
) |
Deferred tax liabilities |
|
|
|
|
|
|
819 |
|
|
|
819 |
|
|
Accumulated other
comprehensive loss |
|
$ |
|
|
|
$ |
(1,302 |
) |
|
$ |
(1,302 |
) |
|
The following table sets forth the plans funded status as of December 31, 2006 and 2005 (the
measurement dates) and the amounts recognized in the Companys Consolidated Balance Sheets at
January 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2007 |
|
2006 |
|
Change in benefit obligation: |
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year |
|
$ |
7,967 |
|
|
$ |
8,087 |
|
Service cost |
|
|
|
|
|
|
|
|
Interest cost |
|
|
452 |
|
|
|
436 |
|
Actuarial gain (loss) |
|
|
164 |
|
|
|
(159 |
) |
Benefits paid |
|
|
(392 |
) |
|
|
(397 |
) |
|
Benefit obligation at end of year |
|
|
8,191 |
|
|
|
7,967 |
|
|
Change in plan assets: |
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year |
|
|
8,108 |
|
|
|
7,050 |
|
Actual return on plan assets |
|
|
833 |
|
|
|
455 |
|
Employer contribution |
|
|
500 |
|
|
|
1,000 |
|
Benefits paid |
|
|
(392 |
) |
|
|
(397 |
) |
|
Fair value of plan assets at end of year |
|
|
9,049 |
|
|
|
8,108 |
|
|
Funded status |
|
|
858 |
|
|
|
141 |
|
Unrecognized actuarial loss |
|
|
|
|
|
|
2,619 |
|
Contributions between measurement
date and year-end |
|
|
|
|
|
|
250 |
|
|
Net amount recognized as other
non-current assets |
|
$ |
858 |
|
|
$ |
3,010 |
|
|
Net periodic pension cost for 2007, 2006 and 2005 includes the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2007 |
|
2006 |
|
2005 |
|
Service cost and expenses |
|
$ |
86 |
|
|
$ |
74 |
|
|
$ |
66 |
|
Interest cost |
|
|
452 |
|
|
|
436 |
|
|
|
438 |
|
Expected return on assets |
|
|
(529 |
) |
|
|
(484 |
) |
|
|
(486 |
) |
Net amortization |
|
|
271 |
|
|
|
278 |
|
|
|
207 |
|
|
Net periodic pension cost |
|
$ |
280 |
|
|
$ |
304 |
|
|
$ |
225 |
|
|
The Company has recognized the full amount of its actuarially determined pension liability.
The estimated net loss for the plan that is expected to be amortized from accumulated other
comprehensive income to net periodic benefit cost during 2008 is $122,000.
The weighted average assumptions used to determine the benefit obligation and the net periodic
pension cost for the years ending January 31, 2007, 2006 and 2005 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
Discount rate |
|
|
5.90 |
% |
|
|
5.67 |
% |
|
|
5.50 |
% |
Expected long-term return
on plan assets |
|
|
7.0 |
% |
|
|
7.0 |
% |
|
|
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 |
|
Smoothed |
|
Smoothed |
|
|
value |
|
value |
|
value |
The estimated long-term rate of return on assets was developed based on the historical returns and
the future expectations for returns for each asset class, as well as the target asset allocation of
the pension portfolio. Benefit level assumptions for 2007, 2006 and 2005 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, |
|
|
2006 |
|
2005 |
|
Equity securities |
|
|
63 |
% |
|
|
68 |
% |
Debt securities |
|
|
35 |
|
|
|
32 |
|
Cash and cash equivalents |
|
|
2 |
|
|
|
|
|
|
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.
45
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, 2007 plan year.
The Company does not expect to make contributions to the plan during the 2007 calendar year.
The estimated benefit payments expected to be paid in each of the next five fiscal years and
in aggregate for the five fiscal years thereafter are as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
2008 |
|
$ |
414 |
|
2009 |
|
|
432 |
|
2010 |
|
|
442 |
|
2011 |
|
|
457 |
|
2012 |
|
|
477 |
|
2013-2017 |
|
|
2,494 |
|
The Company also provides supplemental retirement benefits to its chief executive officer. Benefits
are computed based on the compensation earned during the highest five consecutive years of
employment reduced for a portion of Social Security benefits and an annuity equivalent of the chief
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. The amounts recognized
in the Companys consolidated balance sheets at January 31, 2007 and 2006, were $1,742,000 and
$1,554,000. Net periodic pension cost of the supplemental retirement benefits for 2007, 2006 and
2005 include the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2007 |
|
2006 |
|
2005 |
|
Service cost |
|
$ |
100 |
|
|
$ |
120 |
|
|
$ |
98 |
|
Interest cost |
|
|
88 |
|
|
|
75 |
|
|
|
71 |
|
|
Net periodic pension cost |
|
$ |
188 |
|
|
$ |
195 |
|
|
$ |
169 |
|
|
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 $3,062,000, $2,009,000 and $1,530,000 in
2007, 2006 and 2005, 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 $2,996,000,
$2,588,000 and $2,061,000 in 2007, 2006 and 2005, 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 2007 and 2006
was $1,458,000 and $60,000.
(11) Indebtedness
On July 31, 2003, the Company entered into an agreement (Master Shelf Agreement) whereby it
could issue up to $60,000,000 in unsecured notes. Upon closing, the Company issued $40,000,000 of
notes (Series A Senior Notes) under the Master Shelf Agreement. The Series A Senior Notes bear a
fixed interest rate of 6.05% and are due on July 31, 2010, with annual principal payments of
$13,333,000 beginning July 31, 2008. Proceeds from the issuance were used to refinance borrowings
outstanding under the 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,
46
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 $70,000,000 to $130,000,000, less any outstanding letter of credit commitments
(which are subject to a $30,000,000 sublimit). Approximately $80,000,000 of the facility was used
to pay the cash portion of the acquisition of Reynolds and refinance the outstanding borrowings
under the previous credit agreement. The Credit Agreement was also amended in November 2006,
concurrent with the acquisition of UIG, and the revolving loan commitment was increased to
$200,000,000. The Credit Agreement provides for interest at variable rates equal to, at the
Companys option, a LIBOR rate plus 0.75% to 2.00%, or a base rate, as defined in the Credit
Agreement plus up to 0.50%, depending upon the Companys leverage ratio. The Credit Agreement is
unsecured and is due and payable November 15, 2011. On January 31, 2007, there were letters of
credit of $9,844,000 and borrowings of $91,600,000 outstanding on the Credit Agreement resulting in
available capacity of $98,556,000.
The Master Shelf Agreement and the Credit Agreement contain certain covenants including
restrictions on the incurrence of additional indebtedness and liens, investments, acquisitions,
transfer or sale of assets, transactions with affiliates, payment of dividends and certain
financial maintenance covenants, including among others, fixed charge coverage, maximum debt to
EBITDA and minimum tangible net worth. The Company was in compliance with its covenants as of
January 31, 2007.
Maximum borrowings outstanding under the Companys then-existing credit agreements during 2007
and 2006 were $155,000,000 and $64,000,000, respectively, and the average outstanding borrowings
were $141,850,000 and $50,250,000, respectively. The weighted average interest rates were 6.7% and
5.8%, 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 2007, 2006 and 2005 was $161,000, $96,000 and $61,000,
respectively. Amortization of loan costs is included in interest expense in the consolidated
statements of income.
Debt outstanding as of January 31, 2007 and 2006, whose carrying value approximates fair
market value, was as follows:
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2007 |
|
2006 |
|
Long-term debt: |
|
|
|
|
|
|
|
|
Credit Agreement |
|
$ |
91,600 |
|
|
$ |
68,900 |
|
Senior Notes |
|
|
60,000 |
|
|
|
60,000 |
|
|
Total long-term debt |
|
$ |
151,600 |
|
|
$ |
128,900 |
|
|
As of January 31, 2007, debt outstanding will mature by fiscal years as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
2008 |
|
$ |
|
|
2009 |
|
|
13,333 |
|
2010 |
|
|
20,000 |
|
2011 |
|
|
111,600 |
|
2012 |
|
|
6,667 |
|
Thereafter |
|
|
|
|
(12) 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, 2007, the Company had committed to deliver 3,825,000 million
British Thermal Units (MMBtu) of natural gas through March 2008. The prices on these contracts
range from $7.74 to $10.15 per MMBtu.
The fixed-price physical delivery contracts will result in the physical delivery of natural
gas, and as a result, are exempt from the requirements of SFAS 133 under the normal purchases and
sales exception. Accordingly, the contracts are not reflected in the balance sheet at fair value
and revenues from the contracts are recognized as the natural gas is delivered under the terms of
the contracts. The estimated fair value of such contracts at January 31, 2007 was $1,918,000.
Additionally, the Company has foreign operations that have significant costs denominated in
foreign currencies, and thus is exposed to risks associated with changes in foreign currency
exchange rates. At any point in time, the Company might use various hedge instruments, primarily
foreign currency option contracts, to manage the exposures associated forecasted expatriate labor
costs and purchases of operating supplies. The Company does not enter into foreign currency
derivative financial instruments for speculative or trading purposes.
During the year, the Company held option contracts to hedge the risks associated with
forecasted Australian dollar denominated costs in its African operations. As of January 31, 2007,
the option contracts were no longer outstanding. The contracts settled in various increments
through January 2007 with aggregate losses of $12,000. The hedging losses were recognized during
2007 as the forecasted transactions being hedged occurred and were recorded primarily in cost of
revenues in the Companys Consolidated Statements of Income.
(13) Stock and Stock Option Plans
In October 1998, the Company adopted a Rights Agreement whereby the Company has authorized and
declared a dividend of one preferred share purchase right (Right) for each outstanding common
share of the Company. Subject to limited exceptions, the Rights are exercisable if a person or
group acquires or announces a tender offer for 25% or more of the 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
47
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 stock option and employee incentive plans that provide for the granting of
options to purchase or the issuance of shares of common stock up to an aggregate of 2,600,000
shares of common stock at a price fixed by the Board of Directors or a committee. As of January 31,
2007, there were 513,000 shares available to be granted under the plans. The Company has the
ability to issue shares under the plans either from new issuances or from treasury, although it has
previously always issued new shares and expects to continue to issue new shares in the future.
Significant option groups outstanding at January 31, 2007, and related exercise price and
remaining contractual term follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contractual |
Grant |
|
Options |
|
Options |
|
Exercise |
|
Term |
Date |
|
Outstanding |
|
Exercisable |
|
Price |
|
(Months) |
|
4/97 |
|
|
723 |
|
|
|
723 |
|
|
$ |
11.400 |
|
|
|
3 |
|
2/98 |
|
|
20,900 |
|
|
|
20,900 |
|
|
|
14.000 |
|
|
|
12 |
|
4/98 |
|
|
5,144 |
|
|
|
5,144 |
|
|
|
10.290 |
|
|
|
15 |
|
4/99 |
|
|
9,773 |
|
|
|
9,773 |
|
|
|
4.125 |
|
|
|
27 |
|
4/99 |
|
|
112,375 |
|
|
|
112,375 |
|
|
|
5.250 |
|
|
|
27 |
|
2/00 |
|
|
3,500 |
|
|
|
3,500 |
|
|
|
5.500 |
|
|
|
37 |
|
4/00 |
|
|
14,794 |
|
|
|
14,794 |
|
|
|
3.495 |
|
|
|
39 |
|
8/00 |
|
|
2,500 |
|
|
|
2,500 |
|
|
|
5.125 |
|
|
|
43 |
|
6/04 |
|
|
25,000 |
|
|
|
25,000 |
|
|
|
16.600 |
|
|
|
89 |
|
6/04 |
|
|
216,589 |
|
|
|
81,589 |
|
|
|
16.650 |
|
|
|
90 |
|
6/05 |
|
|
12,000 |
|
|
|
12,000 |
|
|
|
17.540 |
|
|
|
102 |
|
9/05 |
|
|
245,000 |
|
|
|
57,500 |
|
|
|
23.050 |
|
|
|
106 |
|
1/06 |
|
|
210,231 |
|
|
|
52,558 |
|
|
|
27.870 |
|
|
|
109 |
|
6/06 |
|
|
12,000 |
|
|
|
12,000 |
|
|
|
29.290 |
|
|
|
114 |
|
6/06 |
|
|
70,000 |
|
|
|
|
|
|
|
29.290 |
|
|
|
114 |
|
10/06 |
|
|
3,000 |
|
|
|
3,000 |
|
|
|
30.110 |
|
|
|
117 |
|
|
|
|
|
963,529 |
|
|
|
413,356 |
|
|
|
|
|
|
|
|
|
|
All options were granted at an exercise price equal to the fair market value of the 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. Certain option awards provide
for accelerated vesting if there is a change of control (as defined in the plans) and for equitable
adjustments in the event of changes in the Companys equity structure. The Company does not expect
any unvested shares to be forfeited. The fair value of options at date of grant was estimated using
the Black-Scholes model. The weighted average fair value at the date of grant for options granted
during 2007 was $12.679. The fair value was based on an expected life of six years, no dividend
yield, an average interest rate of 4.95% and assumed volatility of 35%.
For purposes of pro forma disclosure, the weighted average fair value at the date of grant for
options granted during 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%.
Transactions for stock options for 2007, 2006 and 2005 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares Under Option |
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
Average |
|
|
Aggregate |
|
|
|
|
|
|
|
Average |
|
|
Remaining |
|
|
Intrinsic |
|
|
|
Number of |
|
|
Exercise |
|
|
Contractual Term |
|
|
Value (in |
|
|
|
Shares |
|
|
Price |
|
|
(years) |
|
|
thousands) |
|
|
Stock Option
Activity Summary: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at February 1, 2004 |
|
|
790,333 |
|
|
$ |
8.118 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable
at February 1, 2004 |
|
|
719,451 |
|
|
|
8.410 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted |
|
|
325,000 |
|
|
|
16.645 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(60,247 |
) |
|
|
5.757 |
|
|
|
|
|
|
$ |
639 |
|
Canceled |
|
|
(16,250 |
) |
|
|
15.959 |
|
|
|
|
|
|
|
49 |
|
Forfeited |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expired |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at January 31, 2005 |
|
|
1,038,836 |
|
|
|
10.800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at January 31, 2005 |
|
|
745,653 |
|
|
|
8.761 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted |
|
|
476,231 |
|
|
|
24.993 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(398,349 |
) |
|
|
8.345 |
|
|
|
|
|
|
|
5,534 |
|
Canceled |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expired |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at January 31, 2006 |
|
|
1,116,718 |
|
|
|
17.728 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at January 31, 2006 |
|
|
455,640 |
|
|
|
10.603 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted |
|
|
87,000 |
|
|
|
29.318 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(237,689 |
) |
|
|
12.656 |
|
|
|
|
|
|
|
4,422 |
|
Canceled |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(2,500 |
) |
|
|
16.650 |
|
|
|
|
|
|
|
30 |
|
Expired |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at January 31, 2007 |
|
|
963,529 |
|
|
$ |
20.028 |
|
|
|
7.41 |
|
|
$ |
14,454 |
|
|
|
|
|
Exercisable at January 31, 2007 |
|
|
413,356 |
|
|
$ |
15.202 |
|
|
|
5.79 |
|
|
$ |
8,196 |
|
|
|
|
|
(14) Contingencies
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
48
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.
(15) Operating Segments and Foreign Operations
The Company is a multinational company that provides sophisticated services and related
products to a variety of markets, as well as being a producer of unconventional natural gas for the
energy market. Management defines the 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 mineral exploration division office performed water well drilling
services, the revenues would be recorded in the mineral exploration division rather than the water
and wastewater infrastructure division. The Companys reportable segments are defined as follows:
Water and Wastewater Infrastructure
This division provides a full line of water-related services and products including
hydrological studies, site selection, well design, drilling and development, pump installation, and
well rehabilitation. The divisions offerings include the design and construction of water
treatment facilities and the provision of filter media and membranes to treat volatile organics and
other contaminants such as nitrates, iron, manganese, arsenic, radium and radon in groundwater. The
division also offers environmental services to assess and monitor groundwater contaminants. With
the acquisition of Reynolds in September 2005, CWI in June 2006 and UIG in November 2006, the
division expanded its capabilities in the area of the design and build of water and wastewater
treatment plants, Ranney collector wells, sewer rehabilitation and water and wastewater
transmission lines.
Mineral Exploration Division
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.
Energy Division
This division focuses on the exploration and production of unconventional gas properties. To
date this division has been concentrated on projects in the mid-continent region of the United
States.
Other
Other includes two small specialty energy service companies and any other specialty operations
not included in one of the their divisions.
49
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. 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, |
|
2007 |
|
2006 |
|
2005 |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Water and wastewater infrastructure |
|
$ |
531,916 |
|
|
$ |
320,996 |
|
|
$ |
233,111 |
|
Mineral exploration |
|
|
148,911 |
|
|
|
124,206 |
|
|
|
104,299 |
|
Energy |
|
|
27,081 |
|
|
|
12,536 |
|
|
|
3,821 |
|
Other |
|
|
14,860 |
|
|
|
5,277 |
|
|
|
2,231 |
|
|
Total revenues |
|
$ |
722,768 |
|
|
$ |
463,015 |
|
|
$ |
343,462 |
|
|
Equity in earnings of affiliates |
|
|
|
|
|
|
|
|
|
|
|
|
Water and wastewater infrastructure |
|
$ |
|
|
|
$ |
839 |
|
|
$ |
(127 |
) |
Mineral exploration |
|
|
4,452 |
|
|
|
3,506 |
|
|
|
2,764 |
|
|
Total equity in earnings of affiliates |
|
$ |
4,452 |
|
|
$ |
4,345 |
|
|
$ |
2,637 |
|
|
Income from continuing operations before income
taxes and minority interests |
|
|
|
|
|
|
|
|
|
|
|
|
Water and wastewater infrastructure |
|
$ |
35,000 |
|
|
$ |
28,255 |
|
|
$ |
26,393 |
|
Mineral exploration |
|
|
26,557 |
|
|
|
13,947 |
|
|
|
11,791 |
|
Energy |
|
|
10,680 |
|
|
|
2,891 |
|
|
|
(1,993 |
) |
Other |
|
|
4,094 |
|
|
|
1,307 |
|
|
|
(43 |
) |
Unallocated corporate expenses |
|
|
(18,383 |
) |
|
|
(12,771 |
) |
|
|
(13,728 |
) |
Interest |
|
|
(9,781 |
) |
|
|
(5,773 |
) |
|
|
(3,221 |
) |
|
Total income from continuing operations
before income taxes and minority interests |
|
$ |
48,167 |
|
|
$ |
27,856 |
|
|
$ |
19,199 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in affiliates |
|
|
|
|
|
|
|
|
|
|
|
|
Water and wastewater infrastructure |
|
$ |
|
|
|
$ |
411 |
|
|
$ |
1,041 |
|
Mineral exploration |
|
|
24,280 |
|
|
|
21,330 |
|
|
|
19,517 |
|
|
Total investment in affiliates |
|
$ |
24,280 |
|
|
$ |
21,741 |
|
|
$ |
20,558 |
|
|
Total assets |
|
|
|
|
|
|
|
|
|
|
|
|
Water and wastewater infrastructure |
|
$ |
321,406 |
|
|
$ |
297,928 |
|
|
$ |
115,659 |
|
Mineral exploration |
|
|
89,826 |
|
|
|
85,110 |
|
|
|
77,873 |
|
Energy |
|
|
91,552 |
|
|
|
55,080 |
|
|
|
32,178 |
|
Other |
|
|
4,112 |
|
|
|
1,546 |
|
|
|
1,210 |
|
Corporate |
|
|
40,268 |
|
|
|
9,671 |
|
|
|
18,460 |
|
|
Total assets |
|
$ |
547,164 |
|
|
$ |
449,335 |
|
|
$ |
245,380 |
|
|
Capital expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
Water and wastewater infrastructure |
|
$ |
23,777 |
|
|
$ |
10,640 |
|
|
$ |
9,755 |
|
Mineral exploration |
|
|
11,607 |
|
|
|
13,525 |
|
|
|
5,325 |
|
Energy |
|
|
40,737 |
|
|
|
24,639 |
|
|
|
15,509 |
|
Other |
|
|
483 |
|
|
|
69 |
|
|
|
305 |
|
Corporate |
|
|
196 |
|
|
|
193 |
|
|
|
180 |
|
|
Total capital expenditures |
|
$ |
76,800 |
|
|
$ |
49,066 |
|
|
$ |
31,074 |
|
|
Depreciation, depletion and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
Water and wastewater infrastructure |
|
$ |
17,691 |
|
|
$ |
10,604 |
|
|
$ |
6,618 |
|
Mineral exploration |
|
|
8,260 |
|
|
|
6,306 |
|
|
|
6,193 |
|
Energy |
|
|
6,531 |
|
|
|
2,703 |
|
|
|
1,228 |
|
Other |
|
|
229 |
|
|
|
273 |
|
|
|
258 |
|
Corporate |
|
|
142 |
|
|
|
138 |
|
|
|
144 |
|
|
Total depreciation, depletion and amortization |
|
$ |
32,853 |
|
|
$ |
20,024 |
|
|
$ |
14,441 |
|
|
50
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
As of and for the Year Ended January 31, |
|
2007 |
|
2006 |
|
2005 |
|
Geographic information: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
595,959 |
|
|
$ |
356,899 |
|
|
$ |
254,093 |
|
Australia/Africa |
|
|
78,640 |
|
|
|
71,594 |
|
|
|
67,294 |
|
Mexico |
|
|
32,749 |
|
|
|
22,345 |
|
|
|
13,744 |
|
Other foreign |
|
|
15,420 |
|
|
|
12,177 |
|
|
|
8,331 |
|
|
Total revenues |
|
$ |
722,768 |
|
|
$ |
463,015 |
|
|
$ |
343,462 |
|
|
Property and equipment, net |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
191,797 |
|
|
$ |
137,162 |
|
|
$ |
74,095 |
|
Africa/Australia |
|
|
16,655 |
|
|
|
17,486 |
|
|
|
13,017 |
|
Mexico |
|
|
5,279 |
|
|
|
3,104 |
|
|
|
2,033 |
|
Other foreign |
|
|
786 |
|
|
|
373 |
|
|
|
311 |
|
|
Total property and equipment, net |
|
$ |
214,517 |
|
|
$ |
158,125 |
|
|
$ |
89,456 |
|
|
(16) New Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board (the FASB) issued Statement of
Financial Accounting Standards 123(R), Share Based Payment (SFAS 123(R)), which became
effective for the Company February 1, 2006. See Note 1 for a discussion of the impact of adopting
SFAS 123(R).
In April 2006, the FASB issued FASB Staff Position FIN 46(R)-6, Determining the Variability
to Be Considered in Applying FASB Interpretation 46(R) (FSP FIN 46(R)-6), which became effective
for the Company in the second quarter of 2007. FSP FIN 46(R)-6 clarifies that the variability to be
considered in applying FASB Interpretation 46(R) shall be based on an analysis of the design of the
variable interest entity. The adoption of this interpretation did not have a material effect on the
Companys consolidated financial statements.
In June 2006, the FASB ratified Emerging Issues Task Force Issue 06-3, How Taxes Collected
from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement
(That Is, Gross Versus Net Presentation) (EITF 06-3), which the Company adopted in the fourth
quarter of the fiscal year ending January 31, 2007. EITF 06-3 requires that companies disclose
their accounting policy regarding the gross or net presentation of certain taxes. Taxes within the
scope of EITF 06-3 are any tax assessed by a governmental authority that is directly imposed on a
revenue-producing transaction between a seller and a customer and may include, but is not limited
to, sales, use, value added and some excise taxes. The Company presents these transactions on a net
basis and intends to continue this presentation in the future; therefore the adoption of this
standard had no impact on the consolidated financial statements.
In July 2006, the FASB released FASB Interpretation 48, Accounting for Uncertainty in Income
Taxes, an Interpretation of FASB Statement 109 (FIN 48). FIN 48 establishes a comprehensive
model for the financial statement recognition, measurement, presentation and disclosure of
uncertain tax positions taken or expected to be taken in income tax returns. This interpretation
will be effective for the Company as of February 1, 2007. The Company has not yet completed its
evaluation of the impact of adoption on the Companys financial position or results of operations.
In September 2006, the Securities and Exchange Commission (SEC) issued Staff Accounting
Bulletin 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements
in Current Year Financial Statements (SAB 108), which states that registrants should use both a
balance sheet (iron curtain) approach and an income statement (rollover) approach when
quantifying and evaluating the materiality of a misstatement. SAB 108 also provides guidance on
correcting errors under this dual approach as well as transition guidance for correcting previously
immaterial errors that are now considered material based on the approach in the bulletin. The
Company adopted this bulletin in the fourth quarter of the fiscal year ending January 31, 2007. The
adoption of this statement did not have a material impact on the consolidated financial statements.
In September 2006, the FASB issued SFAS 157, Fair Value Measurements (SFAS 157), which
defines fair value, establishes a framework for measuring fair value in generally accepted
accounting principles, and expands disclosures about fair value measurements. SFAS 157 does not
require any new fair value measurements, but provides guidance on how to measure fair value by
providing a fair value hierarchy used to classify the source of the information. The Company will
be required to adopt this standard in the first quarter of the fiscal year ending January 31, 2009.
The Company does not anticipate that adoption of this statement will have a material impact on the
consolidated financial statements.
In September 2006, the FASB issued SFAS 158, Employers Accounting for Defined Benefit
Pension and Other Postretirement Plans (SFAS 158), which requires a company that sponsors a
postretirement benefit plan to fully recognize, as an asset or liability, the overfunded or
underfunded status of its benefit plan(s) in its year-end balance sheet. These provisions of SFAS
158 were effective for the Companys fiscal year ended January 31, 2007. The impact of adopting
SFAS 158 is shown in Note 10. In addition, SFAS 158 also generally requires a company to measure
its plan assets and benefit obligations as of its fiscal year-end balance sheet date. The Company
will be required to adopt these provisions of the standard in the fiscal year ending January 31,
2009. The adoption of these measurement provisions is not expected to have a material impact on the
consolidated financial statements.
In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and
Financial Liabilities (SFAS 159). SFAS 159 permits the measurement of specified financial
instruments and warranty and insurance contracts at
51
fair value on a contract-by-contract basis, with changes in fair value recognized in earnings
each reporting period. The Company will be required to adopt this standard in the first quarter of
the fiscal year ending January 31, 2009. The Company does not anticipate that adoption of this
statement will have a material impact on the consolidated financial statements.
(17) Quarterly Results (Unaudited)
Unaudited quarterly financial data are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands of dollars, except per share data) |
|
|
|
|
|
|
|
|
2007: |
|
First |
|
Second |
|
Third |
|
Fourth |
|
Revenues |
|
$ |
156,717 |
|
|
$ |
187,146 |
|
|
$ |
185,824 |
|
|
$ |
193,081 |
|
Net income from continuing operations |
|
|
4,642 |
|
|
|
7,192 |
|
|
|
7,762 |
|
|
|
6,656 |
|
Net income |
|
|
4,642 |
|
|
|
7,192 |
|
|
|
7,762 |
|
|
|
6,656 |
|
Basic net income per share from continuing
operations |
|
|
0.30 |
|
|
|
0.47 |
|
|
|
0.05 |
|
|
|
0.43 |
|
Diluted net income per share from continuing
operations |
|
|
0.30 |
|
|
|
0.47 |
|
|
|
0.50 |
|
|
|
0.42 |
|
Basic net income per share |
|
|
0.30 |
|
|
|
0.47 |
|
|
|
0.51 |
|
|
|
0.43 |
|
Diluted net income per share |
|
|
0.30 |
|
|
|
0.47 |
|
|
|
0.50 |
|
|
|
0.42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006: |
|
First |
|
Second |
|
Third |
|
Fourth |
|
Revenues |
|
$ |
96,658 |
|
|
$ |
106,102 |
|
|
$ |
113,526 |
|
|
$ |
146,729 |
|
Net income from continuing operations |
|
|
2,754 |
|
|
|
4,534 |
|
|
|
4,281 |
|
|
|
3,116 |
|
Net income |
|
|
2,753 |
|
|
|
4,526 |
|
|
|
4,286 |
|
|
|
3,116 |
|
Basic net income per share from
continuing operations |
|
|
0.22 |
|
|
|
0.36 |
|
|
|
0.31 |
|
|
|
0.20 |
|
Diluted net income per share from
continuing operations |
|
|
0.21 |
|
|
|
0.35 |
|
|
|
0.31 |
|
|
|
0.20 |
|
Basic net income per share |
|
|
0.22 |
|
|
|
0.36 |
|
|
|
0.31 |
|
|
|
0.20 |
|
Diluted net income per share |
|
|
0.21 |
|
|
|
0.35 |
|
|
|
0.31 |
|
|
|
0.20 |
|
Supplemental Information on Oil and 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, 2007, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2007 |
|
2006 |
|
2005 |
|
Oil and gas properties |
|
$ |
58,458 |
|
|
$ |
34,308 |
|
|
$ |
20,573 |
|
Mineral interest in oil
and gas properties |
|
|
12,515 |
|
|
|
8,430 |
|
|
|
3,671 |
|
|
|
|
|
70,973 |
|
|
|
42,738 |
|
|
|
24,244 |
|
Accumulated depreciation
and depletion |
|
|
(7,848 |
) |
|
|
(2,931 |
) |
|
|
(910 |
) |
|
Total |
|
$ |
63,125 |
|
|
$ |
39,807 |
|
|
$ |
23,334 |
|
|
Unproved oil and gas property and mineral interest costs at January 31, 2007 totaled $3,631,000 and
$4,153,000, respectively. Unevaluated mineral interest costs excluded from depreciation, depletion
and amortization at January 31, 2007 and 2006 totaled $4,153,000 and $2,926,000, respectively.
Capitalized costs and associated depreciation relating to gas transportation facilities and
equipment were as follows at January 31, 2007, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2007 |
|
2006 |
|
2005 |
|
Gas transportation facilities
and equipment |
|
$ |
24,939 |
|
|
$ |
12,526 |
|
|
$ |
6,413 |
|
Accumulated depreciation |
|
|
(2,353 |
) |
|
|
(883 |
) |
|
|
(287 |
) |
|
Total |
|
$ |
22,586 |
|
|
$ |
11,643 |
|
|
$ |
6,126 |
|
|
Cost Incurred in Oil and Gas Producing Activities
Capitalized costs incurred in oil and gas producing activities were as follows during 2007,
2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2007 |
|
2006 |
|
2005 |
|
Acquisition |
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
$ |
4,249 |
|
|
$ |
4,751 |
|
|
$ |
4,498 |
|
Unproved |
|
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
|
25 |
|
|
|
64 |
|
|
|
66 |
|
Development |
|
|
23,719 |
|
|
|
13,454 |
|
|
|
7,696 |
|
|
|
|
|
27,993 |
|
|
|
18,269 |
|
|
|
12,260 |
|
Asset retirement costs |
|
|
243 |
|
|
|
224 |
|
|
|
167 |
|
|
Total |
|
$ |
28,236 |
|
|
$ |
18,493 |
|
|
$ |
12,427 |
|
|
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.
52
Capitalized costs incurred in gas transportation facilities and equipment during 2007, 2006
and 2005 totaled $14,401,000, $6,570,000 and $3,014,000, 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, 2007, 2006 and 2005 and includes only revenues and
operating costs directly attributable to oil and gas producing activities. Results of operations
from gas transportation facilities and equipment activities, general corporate overhead and other
non oil and gas producing activities are excluded. Production from the natural gas wells is sold to
the 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.
Proved Oil and Gas Reserve Quantities
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per Mcf) |
|
2007 |
|
2006 |
|
2005 |
|
Revenues |
|
$ |
14,014 |
|
|
$ |
8,554 |
|
|
$ |
2,481 |
|
Operating costs: |
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes |
|
|
552 |
|
|
|
345 |
|
|
|
112 |
|
Lease operating expenses |
|
|
5,051 |
|
|
|
2,753 |
|
|
|
1,446 |
|
Depreciation and depletion |
|
|
4,917 |
|
|
|
2,021 |
|
|
|
880 |
|
Asset retirement accretion expense |
|
|
43 |
|
|
|
27 |
|
|
|
12 |
|
Income tax expense |
|
|
1,286 |
|
|
|
1,271 |
|
|
|
12 |
|
|
Total
operating costs |
|
|
11,849 |
|
|
|
6,417 |
|
|
|
2,462 |
|
|
Results of
operations |
|
$ |
2,165 |
|
|
$ |
2,137 |
|
|
$ |
19 |
|
|
Depletion per Mcf |
|
$ |
1.46 |
|
|
$ |
1.44 |
|
|
$ |
1.57 |
|
|
Proved gas reserve quantities as of January 31, 2007 and 2006 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): |
|
2007 |
|
2006 |
|
Balance, beginning of year |
|
|
45,120 |
|
|
|
26,589 |
|
Revisions of previous estimates |
|
|
(5,627 |
) |
|
|
(4,925 |
) |
Extensions, discoveries and other additions |
|
|
19,019 |
|
|
|
19,397 |
|
Production |
|
|
(3,250 |
) |
|
|
(1,403 |
) |
Purchases of reserves in place |
|
|
1,816 |
|
|
|
5,462 |
|
|
Balance, end of year |
|
|
57,078 |
|
|
|
45,120 |
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves |
|
|
25,010 |
|
|
|
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. The weighted average
year-end spot price used in estimating future net revenues was $6.89 and $7.31 per Mcf for 2007 and
2006, respectively. Future production and development costs represent the estimated future
expenditures to be incurred in developing and producing the proved reserves, assuming continuation
of existing economic conditions. Future income tax expense was computed by applying statutory rates
to pre-tax cash flows relating to the 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) |
|
2007 |
|
2006 |
|
Future cash inflows |
|
$ |
393,153 |
|
|
$ |
329,664 |
|
Future production costs |
|
|
(144,511 |
) |
|
|
(102,165 |
) |
Future development costs |
|
|
(49,073 |
) |
|
|
(35,264 |
) |
Future income taxes |
|
|
(59,098 |
) |
|
|
(63,700 |
) |
|
Future net cash flows |
|
|
140,471 |
|
|
|
128,535 |
|
10% discount to reflect timing of cash flows |
|
|
(51,459 |
) |
|
|
(48,924 |
) |
|
Standardized measure of discounted cash flows |
|
$ |
89,012 |
|
|
$ |
79,611 |
|
|
The principal sources of change in the standardized measure of discounted future net cash flows
were:
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2007 |
|
2006 |
|
Balance, beginning of year |
|
$ |
79,611 |
|
|
$ |
29,949 |
|
Sales of gas produced, net of production costs |
|
|
(11,687 |
) |
|
|
(7,608 |
) |
Net changes in prices and production costs |
|
|
(16,568 |
) |
|
|
31,461 |
|
Extensions and discoveries, less related costs |
|
|
37,431 |
|
|
|
45,683 |
|
Revisions of quantity estimates |
|
|
(14,420 |
) |
|
|
(13,110 |
) |
Purchases of reserves in place |
|
|
3,729 |
|
|
|
15,202 |
|
Change in future development |
|
|
(34,038 |
) |
|
|
(16,504 |
) |
Accretion of discount |
|
|
12,998 |
|
|
|
5,392 |
|
Net change in income taxes |
|
|
3,075 |
|
|
|
(25,099 |
) |
Development costs incurred |
|
|
28,881 |
|
|
|
14,244 |
|
Asset retirement obligation and other |
|
|
|
|
|
|
1 |
|
|
Net change |
|
|
9,401 |
|
|
|
49,662 |
|
Balance, end of year |
|
$ |
89,012 |
|
|
$ |
79,611 |
|
|
53
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, 2005 |
|
$ |
4,104 |
|
|
$ |
575 |
|
|
$ |
512 |
|
|
$ |
(1,085 |
) |
|
$ |
4,106 |
|
Fiscal year ended
January 31, 2006 |
|
|
4,106 |
|
|
|
1,496 |
|
|
|
709 |
|
|
|
(738 |
) |
|
|
5,573 |
|
Fiscal year ended
January 31, 2007 |
|
|
5,573 |
|
|
|
1,700 |
|
|
|
666 |
|
|
|
(919 |
) |
|
|
7,020 |
|
Reserves for inventories: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal year ended
January 31, 2005 |
|
$ |
6,242 |
|
|
$ |
695 |
|
|
$ |
|
|
|
$ |
(725 |
) |
|
$ |
6,212 |
|
Fiscal year ended
January 31, 2006 |
|
|
6,212 |
|
|
|
318 |
|
|
|
|
|
|
|
(1,567 |
) |
|
|
4,963 |
|
Fiscal year ended
January 31, 2007 |
|
|
4,963 |
|
|
|
(26 |
) |
|
|
|
|
|
|
(99 |
) |
|
|
4,838 |
|
54
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, 2007 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 accumulated and communicated to the
Companys management (including the Principal Executive Officer and the Principal Financial
Officer) to allow timely decisions regarding required disclosure, and is recorded, processed,
summarized and reported within the time periods specified in Securities and Exchange Commission
rules and forms.
Managements Report on Internal Control over Financial Reporting. Management of Layne Christensen
Company and subsidiaries is responsible for establishing and maintaining adequate internal control
over financial reporting, as such term is defined in Rule 13a-15(f) of the Exchange Act. Under the
supervision and with the participation of the 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, 2007. The Company excluded
from its assessment any changes in internal control over financial reporting at the American Water
Services Underground Infrastructure, Inc. (UIG), which was acquired on November 20, 2006, and
whose financial statements constitute 13% and 6% of net assets and total assets, respectively, 1%
of revenues, and less than 1% of net income of the related consolidated financial statement amounts
as of and for the year ended January 31, 2007. The Company will include UIG in its evaluation of
the design and effectiveness of internal control over financial reporting as of January 31, 2008.
The 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, 2007. 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 2007.
55
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, 2007, based on criteria established in Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in
Managements Report on Internal Control over Financial Reporting, management excluded from its
assessment the internal control over financial reporting at American Water Services Underground
Infrastructure, Inc., which was acquired on November 20, 2006, and whose financial statements
constitute 13% and 6% of net and total assets, respectively, 1% of revenue, and less than 1% of net
income of the consolidated financial statement amounts as of and for the year ended January 31,
2007. Accordingly, our audit did not include the internal control over financial reporting at
American Water Services Underground Infrastructure, Inc. The 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, 2007, is fairly stated, in all material respects, based on
the criteria established in Internal Control-Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained,
in all material respects, effective internal control over financial reporting as of January 31,
2007, based on the criteria established in Internal Control-Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated financial statements and financial statement schedule as of
and for the year ended January 31, 2007, of the Company and our
report dated April 16, 2007
expressed an unqualified opinion on those financial statements and financial statement schedule and
included an explanatory paragraph relating to changes in accounting principles.
/s/Deloitte & Touche LLP
Kansas City, Missouri
April 16, 2007
56
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 7, 2007, (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 7, 2007, will contain, under the caption Executive Compensation and
Other Information, the information required by Item 11 of Form 10-K and such information is
incorporated herein by this reference (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 7, 2007, will contain, under the captions Ownership of Layne
Christensen Common Stock, and Equity Compensation Plan Information, the information required by
Item 12 of Form 10-K and such information is incorporated herein by this reference.
Item 13. Certain Relationships and Related Transactions
The Registrants Proxy Statement to be used in connection with the Annual Meeting of
Stockholders to be held on June 7, 2007, will contain, under the captions Executive Compensation
and Other InformationCertain 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 7, 2007, will contain, under the caption Principal Accounting Fees
and Services, the information required by Item 14 of Form 10-K and such information is
incorporated herein by this reference.
57
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)-
|
|
Certificate of Designations of Series A Junior Participating Preferred Stock of Layne Christensen
Company |
|
|
|
4(3)-
|
|
Amended and Restated Bylaws of the Registrant (filed as Exhibit 99.2 to the Registrants Form 8-K
dated December 5, 2003 and incorporated herein by reference) |
|
|
|
4(4)-
|
|
Certificate of Amendment of Certificate of Incorporation of Layne Christensen Company |
|
|
|
4(5)-
|
|
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(6)-
|
|
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(7)-
|
|
Amendment No. 1 to Amended and Restated Loan Agreement, dated June 16, 2006, by and among Layne
Christensen Company and LaSalle Bank National Association (LaSalle) as Administrative Agent, and
LaSalle and the other Lenders a party thereto (filed as Exhibit 10(1) to the Companys Form 10-Q for
the quarter ended July 31, 2006 and incorporated herein by this reference). |
|
|
|
4(8)-
|
|
Amendment No. 2 to the Amended and Restated Loan Agreement, dated as of November 20, 2006, by and
among Layne Christensen Company and LaSalle, as Administrative Agent, and LaSalle and the other
Lenders a party thereto (filed as Exhibit 4(1) to the Companys Form 8-K, dated November 20, 2006, and
incorporated herein by this reference). |
|
|
|
4(9)-
|
|
Master Shelf Agreement, dated as of July 31, 2003, by and among Layne Christensen Company, Prudential
Investment Management, Inc., The Prudential Insurance Company of America, Pruco Life Insurance
Company, Security Life of Denver Insurance Company and such other Purchasers of the Notes as may be
named in the Master Shelf Agreement from time to time (filed with the Registrants 10-Q for the
quarter ended July 31, 2003 (File No. 0-20578) as Exhibit 4(5) and incorporated herein by reference) |
|
|
|
4(10)-
|
|
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 (filed as
Exhibit 4(6) to the Companys Form 10-K for the fiscal year ended January 31, 2006, and incorporated
herein by this reference) |
|
|
|
4(11)-
|
|
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) |
58
Item 15. Exhibits and Financial Statement Schedules. (continued)
|
|
|
Exhibit |
|
|
Number |
|
Description |
4(12)-
|
|
Letter Amendment No. 3 to Master Shelf Agreement, dated as of June 16, 2006, 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 10(2) to the Companys Form 10-Q for the quarter ended July 31, 2006 and incorporated herein
by this reference) |
|
|
|
4(13)
|
|
Letter Amendment No. 4 to Master Shelf Agreement, dated as of November 20, 2006, 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 November 20, 2006, 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) |
|
|
|
10(2.2)-
|
|
Second Modification and Ratification of Lease Agreement between Parkway Partners, L.L.C. and Layne
Christensen Company dated April 28, 1997 (filed with the 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) |
|
|
|
10(2.3)-
|
|
Third Modification and Extension Agreement between Parkway Partners, L.L.C. and Layne Christensen
Company dated November 3, 1998 (filed with the Companys 10-Q for the quarter ended October 31, 1998
(File No. 0-20578) as Exhibit 10(1) and incorporated herein by reference) |
|
|
|
10(2.4)-
|
|
Fourth Modification and Extension Agreement between Parkway Partners, L.L.C. and Layne Christensen
Company executed May 17, 2000, effective as of December 29, 1998 (filed with the Companys 10-Q for
the quarter ended July 31, 2000 (File No. 0-20578) as Exhibit 10.1 and incorporated herein by
reference) |
|
|
|
10(2.5)-
|
|
Fifth Modification and extension Agreement between Parkway Partners, L.L.C. and Layne Christensen
Company dated March 1, 2003 (filed as Exhibit 10(2.5) to the 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) |
|
|
|
**10(3)-
|
|
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) |
|
|
|
10(4)-
|
|
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) |
|
|
|
10(5)-
|
|
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) |
|
|
|
**10(6)-
|
|
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) |
|
|
|
**10(7)-
|
|
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) |
|
|
|
**10(8)-
|
|
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) |
|
|
|
**10(9)-
|
|
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) |
59
Item 15. Exhibits and Financial Statement Schedules. (continued)
|
|
|
Exhibit |
|
|
Number |
|
Description |
10(10)-
|
|
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) |
|
|
|
**10(11)-
|
|
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) |
|
|
|
**10(12)-
|
|
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) |
|
|
|
**10(13)-
|
|
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) |
|
|
|
**10(14)-
|
|
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) |
|
|
|
10(15)-
|
|
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) |
|
|
|
**10(16)-
|
|
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) |
|
|
|
10(17)-
|
|
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) |
|
|
|
**10(18)
|
|
Layne Christensen Company 2006 Equity Incentive Plan, as amended (filed as Exhibit 10.1 to the
Companys Form 8-K, filed June 14, 2006, and incorporated herein by this reference) |
|
|
|
**10(19)
|
|
Form of Incentive Stock Option Agreement between the Company and management of the Company for use
with the 2006 Equity Incentive Plan (filed as Exhibit 4(e) to the Companys Form S-8 (File No.
333-135683), filed July 10, 2006, and incorporated herein by this reference) |
|
|
|
**10(20)
|
|
Form of Nonqualified Stock Option Agreement between the Company and management of the Company for use
with the 2006 Equity Incentive Plan (filed as Exhibit 4(f) to the Companys Form S-8 (File No.
333-135683), filed July 10, 2006, and incorporated herein by this reference) |
|
|
|
**10(21)
|
|
Form of Nonqualified Stock Option Agreement between the Company and non-employee directors of the
Company for use with the 2006 Equity Incentive Plan (filed as Exhibit 4(g) to the Companys Form S-8
(File No. 333-135683), filed July 10, 2006, and incorporated herein by this reference) |
|
|
|
**10(22)
|
|
Form of Restricted Stock Award Agreement between the Company and management of the Company for use
with the 2006 Equity Incentive Plan (filed as Exhibit 10(7) to the Companys Form 10-Q for the quarter
ended July 31, 2006 and incorporated herein by this reference) |
|
|
|
**10(23)
|
|
Layne Christensen Company Water and Wastewater Infrastructure Group Incentive Compensation Plan (filed
as Exhibit 10.1 to the Companys Form 8-K, filed August 28, 2006, and incorporated herein by this
reference) |
|
|
|
**10(24)-
|
|
Summary of 2007 Salaries of Named Executive Officers |
|
|
|
10(25)-
|
|
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) |
60
Item 15. Exhibits and Financial Statement Schedules. (continued)
|
|
|
Exhibit |
|
|
Number |
|
Description |
**10(26)-
|
|
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) |
|
|
|
**10(27)-
|
|
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) |
|
|
|
10(28)-
|
|
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) |
|
|
|
21(1)-
|
|
List of Subsidiaries |
|
|
|
23(1)-
|
|
Consent of Deloitte & Touche LLP |
|
|
|
23(2)-
|
|
Consent of Cawley, Gillespie & Associates, Inc. |
|
|
|
31(1)-
|
|
Section 302 Certification of Principal Executive Officer of the Company |
|
|
|
31(2)-
|
|
Section 302 Certification of Principal Financial Officer of the Company |
|
|
|
32(1)-
|
|
Section 906 Certification of Principal Executive Officer of the Company |
|
|
|
32(2)-
|
|
Section 906 Certification of Principal Financial Officer of the Company |
** |
|
Management contracts or compensatory plans or arrangements required to be identified by Item 14(a)(3). |
|
(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). |
61
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
|
|
|
|
|
|
|
|
|
Layne Christensen Company |
|
|
|
|
|
|
|
By
|
|
/s/ A. B. Schmitt |
|
|
|
|
Andrew B. Schmitt |
|
|
|
|
President and Chief Executive Officer: |
|
|
|
|
|
|
|
|
|
Dated April 16, 2007 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed
below by the following persons on behalf of the registrant and in the capacities and on the dates
indicated:
|
|
|
Signature and Title |
|
Date |
|
|
|
/s/ A. B. Schmitt
|
|
April 16, 2007 |
|
|
|
President, Chief Executive Officer |
|
|
and Director (Principal Executive Officer) |
|
|
|
|
|
/s/ Jerry W. Fanska
|
|
April 16, 2007 |
|
|
|
Senior Vice President-Finance and Treasurer |
|
|
(Principal Financial and Accounting Officer) |
|
|
|
|
|
/s/ Jeff Reynolds
|
|
April 16, 2007 |
|
|
|
Director |
|
|
|
|
|
/s/ Donald K. Miller
|
|
April 16, 2007 |
|
|
|
Director |
|
|
|
|
|
/s/ David A. B. Brown
|
|
April 16, 2007 |
|
|
|
Director |
|
|
|
|
|
/s/ J. Samuel Butler
|
|
April 16, 2007 |
|
|
|
Director |
|
|
|
|
|
/s/ Anthony B. Helfet
|
|
April 16, 2007 |
|
|
|
Director |
|
|
|
|
|
/s/ John J. Quicke
|
|
April 16, 2007 |
|
|
|
Director |
|
|
|
|
|
/s/ Nelson Obus
|
|
April 16, 2007 |
|
|
|
Director |
|
|
62