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
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For the Fiscal Year Ended January 31, 2008
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Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
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For the transition period from
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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
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of incorporation or organization)
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Identification No.)
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1900 Shawnee Mission Parkway,
Mission Woods, Kansas 66205
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(Address of principal executive
offices) (Zip Code)
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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
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No
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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
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No
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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
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No
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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.
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
a non-accelerated filer, or a smaller reporting company.
See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer
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Accelerated filer
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Non-accelerated filer
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(Do not check if a smaller reporting company)
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Smaller reporting company
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Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes
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No
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The aggregate market value of the 14,850,045 shares of Common Stock of the registrant held by
non-affiliates of the registrant on July 31, 2007, 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 $670,776,533.
At March 31, 2008, there were 19,161,452 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 2008 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 infrastructure and mineral exploration, as well as being a
producer of unconventional natural gas for the energy market. We operate throughout North America,
as well as Africa, Australia, Europe and, through our affiliates, in South America. Layne
Christensens customers include municipalities, investor-owned water utilities, industrial
companies, global mining companies, consulting engineering firms, heavy civil construction
contractors, oil and gas companies and, to a lesser extent, agribusiness.
We maintain our executive offices at 1900 Shawnee Mission Parkway, Mission Woods, Kansas
66205. Our telephone number is (913) 362-0510 and our web site address is
www.laynechristensen.com
. Our periodic and current reports are available, free of charge,
on our Web site 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 we operate are described below. See Note 15
to the Consolidated Financial Statements for certain financial information about our operating
segments and foreign operations.
Water Infrastructure
Water well drilling services demand is driven by the need to access the vital natural resource of
groundwater, which is drawn from the earth for drinking water, irrigation and industrial use, and
which in many areas globally is the only reliable source of potable water. Main drivers of drilling
services include shifting demographics and regional expansion, deteriorating water quality,
increasing water demand at industrial facilities, limited availability of surface water and new
housing developments. The U.S. water well drilling industry is highly fragmented, consisting of
several thousand regionally and locally based contractors. We believe that a majority of these
contractors are primarily involved in drilling low-volume water wells for agricultural and
residential customers, markets in which we do not generally choose to compete.
Well and pump rehabilitation demand depends on the age and application of the equipment, the
quality of material and workmanship applied in the original well construction and changes in depth
and quality of the groundwater. Rehabilitation work is often required on an emergency basis or
within a relatively short period of time after a performance decline is recognized. Scheduling
flexibility and a broad national footprint combined with technical expertise and equipment, are
critical for a repair and maintenance service provider. Like the water well drilling market, the
market for rehabilitation is highly fragmented.
Water and wastewater treatment services demand continues to grow. Increasingly stringent water
quality and treatment regulations are being adopted by a variety of governing agencies. As
demographic shifts occur to more water-challenged areas and the number and allowable level of
regulated contaminants and impurities becomes more strict, the demand for water recycling and
conservation services, as well as new specialized treatment media and filtration methods, is
expected to remain strong.
Wastewater treatment and pipeline construction demand is driven by many of the same factors
that affect demand for water well drilling services. Sewer rehabilitation demand is largely a
function of deteriorating urban infrastructure and pressure from population growth. Additionally,
the EPA and state health boards are forcing municipalities and industry to address pollution
resulting from infiltration of damaged or leaking lines.
Mineral Exploration
Growth in demand for mineral exploration drilling is driven by the need to identify, define and
develop underground base and precious mineral deposits. Factors influencing the demand for
mineral-related drilling services include commodity prices, growth in the economies of developing
countries, international political conditions, inflation, foreign exchange levels, the economic
feasibility of mineral exploration and production, the discovery rate of new mineral reserves and
the ability of mining companies to access capital for their activities.
Global consumption of raw materials has been driven by the rapid industrialization and
urbanization of countries such as China, India, Brazil and Russia. These developing countries
generate significant demand as their populations consume increasing amounts of base and precious
metals for housing, automobiles, electronics and other durable and consumer items. This demand,
coupled with a prolonged period of underinvestment in supply by mining companies in the late 1990s,
has produced a significant supply shortage. Addressing this supply shortage also has been
complicated by a lack of equipment, labor and services such as those that we provide. Robust
commodity prices and continued demand have led to growth in capital allocated by global mining
companies to exploration. Given the strong current commodities pricing environment, we expect that
global mining companies will continue to invest in new exploration and production. Based on this
supply and demand imbalance and the expected above-average growth from developing economies,
discussions have emerged in the mineral exploration marketplace about the possibility of a stronger
commodities cycle for a longer period of time, sometimes referred to as a super-cycle.
As mineral resources in developed countries are exhausted and new discoveries begin to slow,
mining companies have focused attention overseas as an important source of future production. South
America and Africa are key markets for future global growth. Mining service companies with
operating expertise in challenging regions should be well-positioned to capture an increasing
amount of these new projects. In addition to new mine development, technological advancements in
drilling and
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processing allow development of mineral resources previously regarded as uneconomical and
should benefit the largest drilling services companies that are leading technical innovation in the
mineral exploration marketplace.
Energy
The unconventional natural gas market generally is categorized as a subset of the natural gas
market and includes natural gas sourced from coalbeds, shale and tight sands. Large amounts of
methane-rich natural gas are generated and stored in coalbeds and surrounding shales and sandstones
during the coalification process, when plant material progressively is converted to coal.
Production of unconventional natural gas is often accompanied by significant environmental and
operational challenges, including disposal of large quantities of water, sometimes saline, that are
unavoidably produced with the natural gas. According to data from the Energy Information
Administration (EIA), unconventional natural gas production increased from 15% of all U.S.
natural gas production in 1990 to 44% of U.S. natural gas production in 2006. As important,
unconventional natural gas contribution is forecasted to grow to 50% of U.S. natural gas production
by 2030 based on EIA projections. Factors influencing the demand for unconventional natural gas
include increasing consumption, decreasing access to natural gas domestically and commodity prices.
The exploration and production of unconventional natural gas domestically is driven by the
production and use imbalance of natural gas in the U.S. and the economic feasibility from continued
advances in drilling completion and production technology. Currently, according to EIA data, the
U.S. produces approximately 81% of the natural gas that it consumes each year, with the balance
coming from imported natural gas from Canada and from imported liquefied natural gas.
Unconventional natural gas is widely accepted to be a primary future source of domestic supply. Our
approximately 211,000 gross acres within the Cherokee Basin, which has an estimated 6 trillion
cubic feet of natural gas resource potential according to the Kansas Geological Survey, positions
us well to provide natural gas to the domestic market.
Business Strategy
Our growth strategy
Our growth strategy is to expand our current product and service offerings and build attractive
extensions of our current divisions driven by our core competencies. The key elements of this
strategy include:
Expand our turnkey service capabilities and geographic platform and focus on industrial end-markets
for water and wastewater treatment facilities
We expect to continue to expand our presence in the water well drilling and development, pump
installation and well rehabilitation markets by executing our proven operating strategies that we
believe have made us the leader in each of these fragmented markets. We believe the growth in these
market sectors will be driven by bundling products and services and marketing these offerings to
users of treatment and distribution facilities such as municipalities, investor-owned water
utilities, industrial companies and developers. By offering these services on a turnkey basis, we
believe we can enable our customers to expedite the typical design and build project and achieve
economies and efficiencies over traditional unbundled services, as well as expand our market share
among our existing customer base.
In addition, we are aggressively seeking to expand turnkey water infrastructure penetration
across the U.S. by combining the service offerings provided by our recent acquisitions with our
well-established water well drilling relationships. Cross-selling broad service offerings into our
existing base of traditional water well drilling customers should enable us to expand our market
share in the water infrastructure market. We intend to continue our geographic penetration through
organic and acquisition growth. Additionally, extending the geographical reach of our services
internationally represents an attractive long-term growth opportunity.
We believe that our leading position as a provider of water and wastewater treatment services
for small- to medium-sized plants for the municipal end-market enhances our ability to provide
complementary services to industrial end-markets. We intend to market our water and wastewater
infrastructure service offerings aggressively to customers in the power generation,
pharmaceuticals, food and beverage and other key industrial segments. These end-markets represent
large, growing and profitable opportunities that allow us to leverage our existing municipal
expertise. One of our primary focus areas is the power generation segment, including coal, natural
gas and nuclear power, which is projected to add approximately 10% of new capacity annually over
the next five years, according to EIA data. Increased water management systems, including boiler
water treatment and scrubber wastewater treatment, will be essential to support this generation
capacity growth. We expect to leverage our nationwide presence and brand recognition in water
infrastructure in marketing our services to these customers.
Continue to take advantage of robust market conditions in mineral exploration
We believe that we are well-positioned in many of the strategic geographic locations around the
world, particularly in Africa and South America, to take advantage of the robust market conditions
in mineral exploration created by the increased price of precious and base metals. Our ability to
maximize this opportunity is created in part by utilizing our local market expertise and technical
competence, combined with access to transferable drilling equipment and employee training and
safety programs. We intend to focus on maintenance and efficiency, as well as increased scale of
our operations, to improve profitability. We plan to add new rigs and replace existing rigs with
more efficient equipment that will increase our capacity to grow revenue and profitability. Our
improved efficiency should also help enhance margins for our services. We may also seek to increase
our market share through strategic acquisitions, as we believe nearly half of the mineral
exploration market is controlled by small regional competitors that are less able to withstand
fluctuations in demand.
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Develop existing unconventional natural gas opportunities and expand presence in the upstream
energy market
We are aggressively developing and expanding our existing unconventional natural gas properties in
the Cherokee Basin as well as seeking opportunities in other areas. Concurrent with the development
of our unconventional natural gas properties, we continue to build pipeline and natural gas
gathering system infrastructure enhancing our ability to transport natural gas to market. We will
continue to grow our unconventional natural gas projects by leveraging our internal resources,
engineering and geological expertise and experience in large scale developmental drilling, well
completion, exploratory drilling and infrastructure engineering and operations.
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 drilling is used primarily in water well
applications for drilling large diameter wells and employs 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.
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Water Infrastructure
We are a leading provider of groundwater systems and potable water treatment facilities. We offer,
on a turnkey basis, a comprehensive range of design, construction and maintenance services for
municipal, industrial and agricultural water systems. We believe our water infrastructure division
is the market leader in the water well drilling industry and provides a full line of water-related
products and services.
The primary services we provide in the water infrastructure division are:
Water Systems
We offer our customers every aspect of a water system, including test hole
drilling, well construction, well development and testing, pump selection, equipment installation
and pipeline construction. In fiscal 2008, these services and products generated approximately 50%
of revenue in the water infrastructure division. The division provides water well drilling services
in most regions of the U.S. Our target groundwater drilling market consists of high-volume water
wells drilled principally for municipal and industrial customers. These wells have more stringent
design specifications and are typically deeper and larger in diameter than low-volume residential
and agricultural wells. We have strong technical expertise, an in-depth knowledge of local geology
and hydrology, a well-maintained modern fleet of appropriately sized drilling equipment and a
demonstrated ability to procure sizable performance bonds often required for water related
projects.
Water supply development mainly requires the integration of hydrogeology and engineering with
proven knowledge of drilling techniques. The drilling methods and size and type of equipment depend
upon the depth of the wells and the geological formations encountered at the project site. We have
extensive well archives in addition to technical personnel to determine geological conditions and
aquifer characteristics. We provide feasibility studies using complex geophysical survey methods
and have the expertise to analyze the survey results and define the source, depth and magnitude of
an aquifer. We can then estimate recharge rates, specify required well design features, plan well
field design and develop water management plans. To conduct these services, we maintain a staff of
professional employees, including geological engineers, geologists, hydrogeologists and
geophysicists. These attributes enable us to locate suitable water-bearing formations to meet a
wide variety of customer requirements.
Well and Pump Rehabilitation
We believe we are the leader in the rehabilitation of wells and well
equipment. Our involvement in the initial drilling of a well positions us to win follow-up
rehabilitation business, which is generally a higher margin business than well drilling. Such
rehabilitation is required periodically during the life of a well. For instance, in locations where
the groundwater contains bacteria, iron, or high mineral content, screen openings may become
blocked, reducing the capacity and productivity of the well.
We offer complete diagnostic and rehabilitation services for existing wells, pumps and related
equipment through a network of local offices throughout our geographic markets in the U.S. In
addition to our well service rigs, we have equipment capable of conducting downhole closed circuit
televideo inspections, one of the most effective methods for investigating water well problems,
enabling us to effectively diagnose and respond quickly to well and pump performance problems. Our
trained and experienced personnel can perform a variety of well rehabilitation techniques, both
chemical and mechanical methods, and can perform bacteriological well evaluation and water
chemistry analyses. We also have the capability and inventory to repair, in our own machine shops,
most water well pumps,
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regardless of manufacturer, as well as to repair well screens, casings and related equipment
such as chlorinators, aerators and filtration systems.
Water and Wastewater Treatment and Plant Construction
We believe we are well-positioned to be an
important provider of municipal water treatment services, as continued population growth in
water-challenged regions and more stringent regulatory requirements lead to increasing needs to
conserve water resources and control contaminants and impurities. For the design and construction
of integrated water treatment facilities and the provision of filter media and membranes, we focus
on our traditional customer base served in our water well service businesses. We offer complete
water treatment solutions for various groundwater contaminants and impurities, such as volatile
organics, nitrates, iron, manganese, arsenic, radium and radon. These design and construction
solutions typically involve proprietary treatment media and filtration methods, as well as
treatment equipment installed at or near the wellhead, including chlorinators, aerators, filters
and controls. These services are provided in connection with surface water intakes, pumping
stations and well houses. In addition to our traditional treatment equipment and filtration media,
we are actively expanding our offerings and expertise in membrane filtration technologies. We
believe our proprietary technology, expertise and reputation in the industry will set us apart from
competitors in this market.
Sewer Rehabilitation
We have the capability to provide a full range of rehabilitation services
through traditional pipeline replacement or trenchless, cured-in-place pipe (CIPP) technologies
through our Inliner product line. CIPP is a rehabilitation method that allows existing sewer
pipelines to be repaired without the need for extensive excavation and the resultant disruption of
traffic flow and other services. We intend to continue to explore new rehabilitation processes and
technology.
Environmental Assessment Drilling
Customers use our environmental drilling services to assist in
assessing, investigating, monitoring and characterizing water quality and aquifer parameters. The
customers are typically national and regional consulting firms engaged by federal and state
agencies, as well as industrial companies that need to assess, define or clean up groundwater
contamination sources. We offer a wide range of environmental drilling services including:
investigative drilling, installation and testing of monitoring wells to assist the customer in
determining the extent of groundwater contamination, installation of recovery wells that extract
contaminated groundwater for treatment, which is known as pump and treat remediation, and
specialized site safety programs associated with drilling at contaminated sites. In our
environmental health sciences department, we employ a full-time staff qualified to prepare site
specific health and safety plans for hazardous waste cleanup sites as required by OSHA and MSHA.
Mineral Exploration
Together with our Latin American affiliates, we are one of the three largest providers of drilling
services for the global mineral exploration industry. Global mining companies hire us to extract
samples from a site that the mining companies analyze for mineral content before investing heavily
in development. Our drilling services require a high level of expertise and technical competence
because the samples extracted must be free of contamination and accurately reflect the underlying
mineral deposit.
Our mineral exploration division conducts aboveground and underground drilling activities,
including all phases of core drilling, diamond, reverse circulation, dual tube, hammer and rotary
air-blast methods. Our service offerings include both exploratory and definitional drilling.
Exploratory drilling is conducted to determine if there is a minable mineral deposit, which is
known as an orebody, on the site. Definitional drilling is typically conducted at a site to assess
whether it would be economical to mine and to assist in mapping the mine layout. The demand for our
definitional drilling services has increased in recent years as new and less expensive mining
techniques have made it feasible to mine previously uneconomical orebodies.
Our services are used primarily by major gold and copper producers and to a lesser extent,
other base metal producers. Work for gold mining customers generates approximately half of the
business in our mineral exploration division. The success of our mineral exploration division is
closely tied to global commodity prices and demand for our global mining customers products, and
we benefit significantly from the currently strong precious and base metals markets. Our primary
markets are in the western U.S., Alaska, Mexico, Australia and Africa. We also have ownership
interests in foreign affiliates operating in Latin America that form our primary presence in this
market.
Energy
In 2002, we entered the energy business in the midwestern U.S. We expect to continue to
substantially grow this business. Our main energy operations include the exploration for, and
acquisition, development, and production of, unconventional natural gas.
According to the EIA, the production rate of conventional natural gas is declining, while
consumption of natural gas and other cleaner-burning fuels is increasing. We therefore expect the
fundamentals for unconventional natural gas to be positive over the coming years. Unconventional
natural gas burns with essentially the same efficiency as natural gas, and we believe it is an
attractive substitute fuel source in the marketplace for conventional resources. Because
unconventional natural gas wells in our operating market generally take 18-24 months to reach full
capacity, we anticipate significant growth, for at least the next five years, in revenue and
operating income from our exploration and development activities as previously drilled wells
achieve maximum production and new wells are brought online.
We have developed expertise in the complex geology and engineering techniques needed to
effectively develop multi-zone wells in the midwestern U.S., primarily the Cherokee Basin. As of
January 31, 2008, we had approximately 260,000 gross acres under lease and over 466 gross producing
wells. Production from these wells increases more slowly than conventional natural gas wells, but
their life span is significantly longer than conventional natural gas wells. We estimate that the
average life span of our current wells is approximately
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15-20 years. Additionally, we continue to lease acreage for purposes of expanding our development
potential. We believe the increasing demand for cleaner-burning fuels and increasingly stringent
regulatory limitations to ensure air quality will have a favorable impact on the price for such
fuels. We generally enter into fixed-price physical delivery contracts for a portion of our
production to cushion against declines in market prices. The energy division became profitable in
fiscal 2006 as production continued to increase. Energy is currently our smallest division;
however, assuming no significant decline in market prices for natural gas, we expect this can be
our fastest growing division.
We use derivative financial instruments to manage price fluctuation associated with our
production of unconventional natural gas and achieve a more predictable cash flow. These
instruments limit our exposure to declines in prices, but also limit the benefits if prices
increase. These instruments would not fully protect us from a decline in natural gas prices.
Operations
We operate 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, our foreign affiliates operate out of locations in South America and Mexico.
We are primarily organized around division presidents responsible for water 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 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, we learn of and are in a position to
compete for proposed projects. In addition, water infrastructure personnel monitor industry
publications for upcoming bid opportunities.
In our foreign affiliates, where we do not have majority ownership or operating control,
day-to-day operating decisions are made by local management. We manage our interests in our foreign
affiliates through regular management meetings and analysis of comprehensive operating and
financial information. For our significant foreign affiliates, we have entered into shareholder
agreements that give us limited board representation rights and require super-majority votes in
certain circumstances.
Customers and Contracts
Each of our 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, we negotiate our service contracts with industrial and mining companies and other
private entities, while our service contracts with municipalities are generally awarded on a bid
basis. Our 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 infrastructure division, our customers are typically municipalities and local
operations of industrial businesses. Of our water infrastructure revenues in fiscal 2008,
approximately 66% were derived from municipalities and approximately 15% 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, we target customers that
require compliance with detailed and demanding specifications and regulations and that often
require bonding and insurance, areas in which we believe we have competitive advantages due to our
drilling expertise and financial resources.
Customers for our mineral exploration services in the United States, Mexico, Australia, Africa
and South America are primarily gold and copper producers. Our largest customers in our mineral
exploration drilling business are multi-national corporations headquartered primarily in the United
States, Europe and Canada.
We market our unconventional gas production to large energy pipeline companies and local
industrial customers.
Backlog
We track backlog only in our water infrastructure division. Our backlog consists of the expected
gross revenues associated with executed contracts, or portions thereof, not yet performed by the
Company. We do not believe that backlog has any significance for our business other than as a
short-term business indicator, particularly outside of the water infrastructure division. This is
because substantially all of the contracts comprising the backlog are cancelable for, among other
reasons, the convenience of the customer. Our backlog for the water infrastructure division was
$408,404,000 at January 31, 2008, compared to $349,200,000 at January 31, 2007. Our backlog as of
year-end is generally completed within the following 12 to 24 months.
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Competition
Our competition for our water infrastructure divisions turnkey construction services are primarily
local and national specialty general contractors. Our competition in the water well drilling
business consists primarily of small, local water well drilling operations and some regional
competitors. Oil and conventional natural gas well drillers generally do not compete in the water
well drilling business because the typical well depths are greater for oil and conventional natural
gas and, to a lesser extent, the technology and equipment utilized in these businesses are
different. Only a small percentage of all companies that perform water well drilling services have
the technical competence and drilling expertise to compete effectively for high-volume municipal
and industrial projects, which typically are more demanding than projects in the agricultural or
residential well markets. In addition, smaller companies often do not have the financial resources
or bonding capacity to compete for large projects. However, there are no proprietary technologies
or other significant factors which prevent other firms from entering these local or regional
markets or from consolidating into larger companies more comparable in size to us. Water well
drilling work is usually obtained on a competitive bid basis for municipalities, while work for
industrial customers is obtained on a negotiated or informal bid basis.
As is the case in the water well drilling business, the well and pump rehabilitation business
is characterized by a large number of relatively small competitors. We believe only a small
percentage of the companies performing these services have the technical expertise necessary to
diagnose complex problems, perform many of the sophisticated rehabilitation techniques we offer or
repair a wide range of pumps in their own facilities. In addition, many of these companies have
only a small number of pump service rigs. Rehabilitation projects are typically negotiated at the
time of repair or contracted for in advance depending upon the lead time available for the repair
work. Since well and pump rehabilitation work is typically negotiated on an emergency basis or
within a relatively short period of time, those companies with available rigs and the requisite
expertise have a competitive advantage by being able to respond quickly to repair requests.
Our mineral exploration division competes with a number of drilling companies as well as
vertically integrated mining companies that conduct their own exploration drilling activities, and
some of these competitors have greater capital and other resources than we have. In the mineral
exploration drilling market, we compete based on price, technical expertise and reputation. We
believe we have a well-recognized reputation for expertise and performance in this market. Mineral
exploration drilling work is typically performed on a negotiated basis.
In the natural gas energy production market, we compete for leases, assets, services and
pipeline capacity with numerous upstream oil and natural gas production companies, many of which
have greater capital and other resources than us. In our current operations, we are not constrained
by the availability of a market for our production, but do compete with other exploration and
production companies for mineral leases and rights-of-way in our areas of interest.
Regulation
The services we provide are subject to various licensing, permitting, approval and reporting
requirements imposed by federal, state, local and foreign laws. Our operations are subject to
inspection and regulation by various governmental agencies, including the Department of
Transportation, OSHA and MSHA in the U.S. as well as their counterparts in foreign countries. In
addition, our activities are subject to regulation under various environmental laws regarding
emissions to air, discharges to water and management of wastes and hazardous substances. To the
extent we fail to comply with these various regulations, we could be subject to monetary fines,
suspension of operations and other penalties. In addition, these and other laws and regulations
affect our mineral exploration customers and influence their determination whether to conduct
mineral exploration and development.
Many localities require well operating licenses which typically specify that wells be
constructed in accordance with applicable regulations. Various state, local and foreign laws
require that water wells and monitoring wells be installed by licensed well drillers. We maintain
well drilling and contractors licenses in those jurisdictions in which we operate and in which
such licenses are required. In addition, we employ licensed engineers, geologists and other
professionals necessary to the conduct of our business. In those circumstances in which we do not
have a required professional license, we subcontract that portion of the work to a firm employing
the necessary professionals.
Applicable Legislation
There are a number of complex foreign, federal, state and local environmental laws which impact the
demand for our environmental drilling services. For example, we currently provide a variety of
services for individuals and entities that have either been ordered by the EPA or a comparable
state agency to clean up certain contaminated property, or are investigating whether a particular
piece of property contains any contaminants. These services include soil and groundwater testing
done in connection with environmental audits, investigative drilling to determine the presence of
hazardous substances, monitoring wells to detect the extent of contamination present in the
groundwater and recovery wells to recover certain contaminants from the groundwater. A change in
these laws, or changes in governmental policies regarding the funding, implementation or
enforcement of the laws, could have a material effect on us.
Employees
At January 31, 2008, we had approximately 4,300 employees, approximately 420 of whom were members
of collective bargaining units represented by locals affiliated with major labor unions in the U.S.
We believe that our relationship with our employees is satisfactory. In all of our service lines,
an important competitive factor is technical expertise. As a result, we emphasize the training and
development of our personnel. Periodic technical training is provided for senior field employees
covering such areas as pump installation, drilling technology
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and electrical troubleshooting. In addition, we emphasize strict adherence to all health and safety
requirements and offer incentive pay based upon achievement of specified safety goals. This
emphasis encompasses developing site-specific safety plans, ensuring regulatory compliance and
training employees in regulatory compliance and good safety practices. Training includes an
OSHA-mandated 40-hour hazardous waste and emergency response training course as well as the
required annual eight-hour updates. We have a safety department staff which allows us to offer such
training in-house. This staff also prepares health and safety plans for specific sites and provides
input and analysis for the health and safety plans prepared by others.
On average, our field supervisors and drillers have 18 and 13 years, respectively, of
experience with us. Many of our professional employees have advanced academic backgrounds in
agricultural, chemical, civil, industrial, geological and mechanical engineering, geology,
geophysics and metallurgy. We believe that our size and reputation allow us to compete effectively
for highly qualified professionals.
Legal Proceedings
We are involved in various matters of litigation, claims and disputes which have arisen in the
ordinary course of our business. As of the date of this annual report, there are no pending
material legal proceedings to which we are a party or to which our property is subject.
Item 1A. Risk Factors
Investing in our common stock involves a high degree of risk. You should carefully consider the
risks described below with all of the other information contained or incorporated by reference in
this annual report before deciding to invest in our common stock. If any of the following risks
actually occur, they may materially harm our business and our financial condition and results of
operations. In this event, the market price of our common stock could decline, and you could lose
part or all of your investment.
Risks Relating To Our Business And Industry
A decline in municipal spending on water treatment and wastewater infrastructure could reduce our
revenue.
For the fiscal year ended January 31, 2008, approximately 66% of our water infrastructure division
revenue was derived from contracts with governmental entities or agencies. Reduced tax revenue in
certain regions may limit spending and new development by local municipalities, which in turn may
adversely affect the demand for our services in these regions. Reductions in spending by
municipalities or local governmental agencies could reduce demand for our services and reduce our
revenue.
A reduction in demand for our mineral exploration and development services could reduce our
revenue.
Demand for our mineral exploration services depends in significant part upon the level of mineral
exploration and development activities conducted by mining companies, particularly with respect to
gold and copper. Mineral exploration is highly speculative and is influenced by a variety of
factors, including the prevailing prices for various metals, which often fluctuate widely. In
addition, the price of gold is affected by numerous factors, including international economic
trends, currency exchange fluctuations, expectations for inflation, speculative activities,
consumption patterns, purchases and sales of gold bullion holdings by central banks and others,
world production levels and political events. In addition to prevailing prices for minerals,
mineral exploration activity is influenced by the following factors:
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global and domestic economic considerations;
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the economic feasibility of mineral exploration and production;
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the discovery rate of new mineral reserves;
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national and international political conditions; and
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the ability of mining companies to access or generate sufficient funds to finance capital
expenditures for their activities.
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We cannot guarantee that overall demand for our mineral exploration services will increase or
stay the same in the future. A material decrease in the rate of mineral exploration and development
would reduce the revenue generated by our mineral exploration division.
Because our businesses are seasonal, our results can fluctuate significantly which could make it
difficult to evaluate our business and could cause instability in the market price of our common
stock.
We periodically have experienced fluctuations in our quarterly results arising from a number of
factors, including the following:
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the timing of the award and completion of contracts;
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the recording of related revenue; and
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unanticipated additional costs incurred on projects.
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In addition, adverse weather conditions, natural disasters, force majeure and other similar events
can curtail our operations in various regions of the world throughout the year, resulting in
performance delays and increased costs. Moreover, our domestic activities and related revenue and
earnings tend to decrease in the winter months when adverse weather conditions interfere with
access to drilling or other construction sites. As a result, our revenue and earnings in the second
and third quarters tend to be higher than revenue and earnings in the first and fourth quarters.
Accordingly, as a result of the foregoing as well as other factors, our quarterly results should
not be considered indicative of results to be expected for any other quarter or for any full fiscal
year.
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Our use of the percentage-of-completion method of accounting could result in a reduction or
reversal of previously recorded results.
Our revenue on large water infrastructure contracts is recognized on a percentage-of-completion
basis for individual contracts based upon the ratio of costs incurred to total estimated costs at
completion. Contract price and cost estimates are reviewed periodically as work progresses and
adjustments proportionate to the percentage of completion are reflected in contract revenue in the
reporting period when such estimates are revised. Changes in job performance, job conditions and
estimated profitability, including those arising from contract penalty provisions, and final
contract settlements may result in revisions to costs and income and are recognized in the period
in which the revisions are determined.
We may experience cost overruns on our fixed-price contracts, which could reduce our profitability.
A significant number of our contracts contain fixed prices and generally assign responsibility to
us for cost overruns for the subject projects. Under such contracts, prices are established in part
on cost and scheduling estimates, which are based on a number of assumptions, including assumptions
about future economic conditions, prices and availability of materials, labor and other
requirements. Inaccurate estimates, or changes in other circumstances, such as unanticipated
technical problems, difficulties obtaining permits or approvals, changes in local laws or labor
conditions, weather delays, cost of raw materials, or our suppliers or subcontractors inability
to perform, could result in substantial losses. As a result, cost and gross margin may vary from
those originally estimated and, depending upon the size of the project, variations from estimated
contract performance could affect our operating results for a particular quarter. Many of our
contracts also are subject to cancellation by the customer upon short notice with limited damages
payable to us.
We have indebtedness and other contractual commitments that could limit our operating flexibility,
and in turn, hinder our ability to make payments on the obligations, lessen our ability to make
capital expenditures and/or increase the cost of obtaining additional financing.
As of January 31, 2008, our total indebtedness was $60 million, our total liabilities were $274
million and our total assets were $697 million. The level of our indebtedness could have important
consequences to stockholders, 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 portion of our cash flow must be dedicated to the payment of principal and interest on
our indebtedness and other obligations and will not be available for use in our business;
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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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a high degree of indebtedness and other liabilities could 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.
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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 earnings is generated from our operations, and those of our
affiliates, in foreign countries, and political and economic risks in those countries could reduce
or eliminate the earnings we derive from those operations.
Our earnings are significantly impacted by the results of our operations in foreign countries,
including Chile, Mexico, Peru, Italy, Australia and several countries in Africa. 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 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.
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Some of our contracts are not denominated in dollars, and, other than on a selected basis, we
do not engage in foreign currency hedging transactions. An exchange rate fluctuation between the
U.S. dollar and other currencies may have an adverse effect on our results of operations and
financial condition.
We perform work at mining operations in countries such as Tanzania, Guinea, the Democratic
Republic of the Congo, Chile, Peru and Mexico, which have experienced instability in the past, or
may experience instability in the future. The mining industry is subject to regulation by
governments around the world, including the regions in which we have operations, relating to
matters such as environmental protection, controls and restrictions on production, and,
potentially, nationalization, expropriation or cancellation of contract rights, as well as
restrictions on conducting business in such countries. In addition, in our foreign operations we
face operating difficulties, including political instability, workforce instability, harsh
environmental conditions and remote locations. We do not maintain political risk insurance. Adverse
events beyond our control in the areas of our foreign operations could reduce the revenue derived
from our foreign operations to the extent that contractual provisions and bilateral agreements
between countries may not be sufficient to guard our interests.
Reductions in the market price of gold could significantly reduce our profit.
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World gold prices historically have fluctuated widely and are affected by numerous factors beyond
our control, including;
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the strength of the U.S. 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 U.S. dollar and other currencies;
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expectations with respect to the rate of inflation;
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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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Any material decrease in the market price of gold could reduce the demand for our mineral
exploration services and reduce our profits.
Reductions in natural gas prices could reduce our revenue and profit and curtail our future growth.
Our revenue, profitability and future growth and the carrying value of our natural gas properties
depend to a large degree on prevailing natural gas prices. Prices for natural gas are subject to
large fluctuations in response to relatively minor changes in the supply and demand for natural
gas, uncertainties within the market and a variety of other factors beyond our control. These
factors include weather conditions in the U.S., the condition of the U.S. economy, governmental
regulation and the availability of alternative fuel sources.
A sharp decline in the price of natural gas would result in a commensurate reduction in our
revenue, income and cash flow from the production of unconventional natural gas and could have a
material adverse effect on the carrying value of our natural gas properties and the amount of our
natural gas reserves. In the event prices fall substantially, we may not be able to realize a
profit from our production. In recent decades, there have been periods of both worldwide
overproduction and underproduction of hydrocarbons and periods of both increased and relaxed energy
conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced
demand for natural gas. These periods have been followed by periods of short supply of, and
increased demand for, natural gas.
Lower natural gas prices may not only decrease our revenue, profitability and cash flow, but
also reduce the amount of natural gas that we can produce economically. This may result in our
having to make substantial downward adjustments to our estimated proved reserves. Substantial
decreases in natural gas prices would render a significant number of our planned exploitation
projects uneconomical. If this occurs, or if our estimates of development costs increase,
production data factors change or drilling results deteriorate, we may be required to write down
the carrying value of our natural gas properties for impairments as a non-cash charge to earnings.
We perform impairment tests on our assets periodically and whenever events or changes in
circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the
estimated useful life or estimated future cash flow of our assets, the carrying value may not be
recoverable and may, therefore, require a write-down of such carrying value. We may incur
impairment charges in the future, which could reduce net income in the period incurred.
Our derivative financial instruments may not fully protect us from changes in natural gas prices.
We are exposed to fluctuations in the price of natural gas and have entered into fixed-price
physical delivery contracts to manage natural gas price risk for a portion of our production. The
prices at which we enter into derivative financial instruments covering our production in the
future will be dependent upon commodity prices at the time we enter into these transactions, which
may be substantially lower than current natural gas prices. Accordingly, our commodity price risk
management strategy will not protect us from significant and sustained declines in natural gas
prices received for our future production. Conversely, our commodity price risk management strategy
may limit our ability to realize cash flow from commodity price increases. As of January 31, 2008,
we had committed to deliver 4,190,000 MMBtu of natural gas through March 2010 at prices ranging
from $7.49 to $9.05 per MMBtu through March 2008, and $7.64 per MMBtu from April 2008 through March
2010.
The development of unconventional natural gas properties is capital intensive and involves
assumptions and speculation that may result in a total loss of investment.
The business of exploring for and, to a lesser extent, developing and operating unconventional
natural gas properties involves a high degree of business and financial risk that even a
combination of experience, knowledge and careful evaluation may not be able to overcome. We intend
to make additional investments in our energy division and intend to develop aggressively our
existing properties and seek opportunities to lease additional areas in the Cherokee Basin and
other areas. Such expansion will require significant capital expenditure. We may drill wells that
are unproductive or, although productive, do not produce natural gas in economic quantities.
Acquisition and well completion decisions generally are based on subjective judgments and
assumptions that are speculative. It is impossible to predict with certainty the production
potential of a particular property or well. Furthermore, a successful completion of a well does not
ensure a profitable return on the investment. A variety of geological, operational, or
market-related factors, including unusual or unexpected geological formations, pressures, equipment
failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental
risks, shortages or delays in the availability of drilling rigs and the delivery of equipment,
inability to renew leases relating to producing properties, loss of circulation of drilling fluids
or other conditions may substantially delay or prevent completion of any well, or otherwise prevent
a property or well from being profitable.
If we are unable to find, develop and acquire additional unconventional natural gas reserves that
will be commercially viable for production, our reserves and revenue from our energy division would
decline.
The rate of production from unconventional natural gas properties declines as reserves are
depleted. As a result, we must
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locate and develop or acquire new reserves to replace those being depleted by production. Without
successful development or acquisition activities, our reserves and revenue from our energy division
will decline. Some of our competitors in the energy business are larger, more established companies
with substantially greater resources, and in many instances they have been engaged in the
unconventional natural gas extraction business for longer than we have. These companies may have
acquisition and development strategies that are more aggressive than ours and may be able to
acquire more unconventional natural gas properties or develop their existing properties much faster
than we can. We endeavor to discover new economically feasible natural gas reserves at least
commensurate with the depletion of our existing reserves through production. Our inability to
acquire larger reserves of unconventional natural gas and potential delays in the expansion of our
unconventional natural gas division may prevent us from gaining market share and reduce our revenue
and profitability. We may not be able to find and develop or acquire additional reserves at an
acceptable cost or have necessary financing for these activities in the future. In addition,
drilling activity within a particular area that we lease may be unsuccessful and exploration
activities may not lead to commercial discoveries of unconventional natural gas. Further, we may
also have to venture into more hostile environments, both politically and geographically, where
exploration, development and production of unconventional natural gas will be more technologically
challenging and expensive.
Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any
material inaccuracies in these reserve estimates or underlying assumptions could materially reduce
the quantities and present value of our reserves.
It is not possible to measure underground accumulations of natural gas in an exact way. Natural gas
reserve engineering requires subjective estimates of underground accumulations of natural gas and
assumptions concerning future natural gas prices, production levels and operating and development
costs. In estimating our level of natural gas reserves, we and our independent reserve engineers
make certain assumptions that may prove to be incorrect, including assumptions relating to:
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a constant level of future natural gas prices;
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operating and development costs;
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the effects of regulation; and
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If these assumptions prove to be incorrect, our estimates of proved reserves, the economically
recoverable quantities of natural gas attributable to any particular group of properties, the
classifications of reserves based on risk of recovery and our estimates of the future net cash flow
from our reserves could change significantly. For example, if natural gas prices at January 31,
2008, had been $1.00 less per Mcf, then the standardized measure of our proved reserves as of that
date would have decreased by $18 million, from $86 million to $68 million, and our estimated net
proved reserves would have decreased by 1.5 Bcfe, from 50.1 Bcfe to 48.6 Bcfe.
The standardized measure of discounted cash flow is the present value of estimated future net
revenue to be generated from the production of proved reserves, determined in accordance with the
rules and regulations of the SEC (using prices and costs in effect as of the date of estimation),
less future development, production and income tax expenses, and discounted at 10% per annum to
reflect the timing of future net revenue. Over time, we may make material changes to reserve
estimates to take into account changes in our assumptions and the results of actual drilling and
production.
The present value of future net cash flow from our estimated proved reserves is not
necessarily the same as the current market value of our estimated proved reserves. We base the
estimated discounted future net cash flow from our estimated proved reserves on prices and costs in
effect on the day of estimate. However, actual future net cash flow from our natural gas properties
also will be affected by factors such as:
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the actual prices we receive for natural gas;
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our actual operating costs in producing natural gas;
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the amount and timing of actual production
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the amount and timing of our capital expenditures;
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supply of and demand for natural gas; and
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changes in governmental regulations or taxation.
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The timing of both our production and our incurrence of expenses in connection with the
development and production of natural gas properties will affect the timing of actual future net
cash flow from proved reserves, and thus their actual present value. In addition, the 10% discount
factor we use when calculating discounted future net cash flow in compliance with the Financial
Accounting Standards Boards Statement of Financial Accounting Standards No. 69, Disclosures about
Oil and Gas Producing Activities, may not be the most appropriate discount factor based on interest
rates in effect from time to time and risks associated with us or the natural gas industry in
general.
If we are unable to obtain bonding at acceptable rates, our operating costs could increase.
A significant portion of our projects require us to procure a bond to secure performance. With a
decreasing number of insurance providers in that market, it may be difficult to find sureties who
will continue to provide contract required bonding at acceptable rates. With respect to our joint
ventures, our ability to obtain a bond may also depend on the credit and performance risks of our
joint venture partners, some of whom may not be as financially strong as we are. Our inability to
obtain bonding on favorable terms or at all would increase our operating costs and inhibit our
ability to execute projects.
Fluctuations in the prices of raw materials could increase our operating costs.
The manufacture of materials used in our rehabilitation business is dependent upon the availability
of resin, a petroleum-based
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product. Resin prices have fluctuated on the basis of the prevailing prices of oil and we
anticipate that prices will continue to be heavily influenced by the events affecting the oil
market. We also purchase a significant amount of steel for use in connection with all of our
businesses. In addition, we purchase a significant volume of fuel to operate our trucks and
equipment. At present, we do not engage in any type of hedging activities to mitigate the risks of
fluctuating market prices for oil, steel or fuel and increases in the price of these materials may
increase our operating costs.
The dollar amount of our backlog, as stated at any given time, is not necessarily indicative of our
future earnings.
As of January 31, 2008, the backlog in our water infrastructure division was approximately $408
million. This consists of the expected gross revenue associated with executed contracts, or
portions thereof, not yet performed by us. We cannot assure you that the revenue projected in our
backlog will be realized or, if realized, will result in profit. Further, project terminations,
suspensions or adjustments in scope may occur with respect to contracts reflected in our backlog.
Reductions in backlog due to cancellation by a customer or scope adjustments adversely affect,
potentially to a material extent, the revenue and profit we actually receive from such backlog. We
may be unable to complete some projects included in our backlog in the estimated time and, as a
result, such projects could remain in the backlog for extended periods of time. Estimates are
reviewed periodically and appropriate adjustments are made to the amounts included in backlog. Our
backlog as of year end is generally completed within the following 12 to 24 months. Our backlog
does not include any awards for work expected to be performed more than three years after the date
of our financial statements. The amount of future actual awards may be more or less than our
estimates.
Our failure to meet the schedule or performance requirements of our contracts could harm our
reputation, reduce our client base and curtail our future operations.
In certain circumstances, we guarantee contract completion by a scheduled acceptance date. Failure
to meet any such schedule could result in additional costs, and the amount of such additional costs
could exceed projected profit margins. These additional costs include liquidated damages paid under
contractual penalty provisions, which can be substantial and can accrue on a daily basis. In
addition, our actual costs could exceed our projections. Performance problems for existing and
future contracts could increase the anticipated costs of performing those contracts and cause us to
suffer damage to our reputation within our industry and our client base, which would harm our
future business.
If we cannot obtain third-party subcontractors at reasonable rates, or if their performance is
unsatisfactory, our profit could be reduced.
We rely on third-party subcontractors to complete some of our projects. To the extent that we
cannot engage subcontractors, our ability to complete a project in a timely fashion or at a profit
may be impaired. If the amount we are required to pay for subcontracted services exceeds the amount
we have estimated in bidding for fixed-price work, we could experience losses in the performance of
these contracts. In addition, if a subcontractor is unable to deliver its services according to the
negotiated terms for any reason, including the deterioration of its financial condition, we may be
required to purchase the services from another source at a higher price, which could reduce the
profit to be realized or result in a loss on a project for which the services were needed.
Professional liability, product liability, warranty and other claims against us could reduce our
revenue.
Any accidents or system failures in excess of insurance limits at locations that we engineer or
construct or where our products are installed or where we perform services could result in
significant professional liability, product liability, warranty and other claims against us.
Further, the construction projects we perform expose us to additional risks, including cost
overruns, equipment failures, personal injuries, property damage, shortages of materials and labor,
work stoppages, labor disputes, weather problems and unforeseen engineering, architectural,
environmental and geological problems. In addition, once our construction is complete, we may face
claims with respect to the work performed.
If our joint venture partners default on their performance obligations, we could be required to
complete their work under our joint venture arrangements, which could reduce our profit or result
in losses.
We enter into contractual joint ventures in order to develop joint bids on contracts. The success
of these joint ventures depends largely on the satisfactory performance of our joint venture
partners of their obligations under the joint venture. Under these joint venture arrangements, we
may be required to complete our joint venture 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 profit or, in some cases, significant losses for us with
respect to the joint venture.
Our business is subject to numerous operating hazards, logistical limitations and force majeure
events that could significantly reduce our liquidity, suspend our operations and reduce our revenue
and future business.
Our drilling and other construction activities involve operating hazards that can result in
personal injury or loss of life, damage or destruction of property and equipment, damage to the
surrounding areas, release of hazardous substances or wastes and other harm to the environment. To
the extent that the insurance protection we maintain is insufficient or ineffective against claims
resulting from the operating hazards to which our business is subject, our liquidity could be
significantly reduced.
In addition, our operations are subject to delays in obtaining equipment and supplies and the
availability of transportation for the purpose of mobilizing rigs and other equipment, particularly
where rigs or mines are located in remote areas with limited
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infrastructure support. Our business operations are also subject to force majeure events such
as adverse weather conditions, natural disasters and mine accidents or closings. If our drill site
or mineral exploration operations are interrupted or suspended as a result of any such events, we
could incur substantial losses of revenue and future business.
If we are unable to retain skilled workers, or if a work stoppage occurs as a result of disputes
relating to collective bargaining agreements, our ability to operate our business could be limited
and our revenue could be reduced.
Our ability to remain productive, profitable and competitive depends substantially on our ability
to retain and attract skilled workers with expert geological and other engineering knowledge and
capabilities. The demand for these workers is high and the supply is limited. An inability to
attract and retain trained drillers and other skilled employees could limit our ability to operate
our business and reduce our revenue.
As of January 31, 2008, approximately 10% of our U.S. workforce was unionized and two of our
33 collective bargaining agreements were scheduled to expire within the next 12 months. To the
extent that disputes relating to existing or future collective bargaining agreements arise, a work
stoppage could occur. If protracted, a work stoppage could substantially reduce or suspend our
operations and reduce our revenue.
If we are not able to demonstrate our technical competence, competitive pricing and reliable
performance to potential customers we will lose business to competitors, which would reduce our
profit.
We face significant competition and a large part of our business is dependent upon obtaining work
through a competitive bidding process. In our water infrastructure division, we compete with many
smaller firms on a local or regional level. There are few proprietary technologies or other
significant factors which prevent other firms from entering these local or regional markets or from
consolidating together into larger companies more comparable in size to our company. Our
competitors for our turnkey construction services are primarily local and national specialty
general contractors. In our mineral exploration division, we compete with a number of drilling
companies, the largest being Boart Longyear Group, an Australian public company, and Major
Drilling, a Canadian public company. Competition also places downward pressure on our contract
prices and profit margins. Intense competition is expected to continue in these markets, and we
face challenges in our ability to maintain strong growth rates. If we are unable to meet these
competitive challenges, we could lose market share to our competitors and experience an overall
reduction in our profit. Additional competition could reduce our profit.
The cost of complying with complex governmental regulations applicable to our business, sanctions
resulting from non-compliance or reduced demand resulting from increased regulations could increase
our operating costs and reduce our profit.
Our drilling and other construction services are subject to various licensing, permitting, approval
and reporting requirements imposed by federal, state, local and foreign laws. Our operations are
subject to inspection and regulation by various governmental agencies, including the Department of
Transportation, Occupational and Safety Health Administration (OSHA) and the Mine Safety and
Health Administration (MSHA) of the Department of Labor in the U.S., as well as their
counterparts in foreign countries. A major risk inherent in drilling and other construction is the
need to obtain permits from local authorities. Delays in obtaining permits, the failure to obtain a
permit for a project or a permit with unreasonable conditions or costs could limit our ability to
effectively provide our services.
In addition, these regulations also affect our mining customers and may influence their
determination to conduct mineral exploration and development. Future changes in these laws and
regulations, domestically or in foreign countries, could cause our customers to incur additional
expenses or result in significant restrictions to their operations and possible expansion plans,
which could reduce our profit.
Our water treatment business is impacted by legislation and municipal requirements that set
forth discharge parameters, constrain water source availability and set quality and treatment
standards. The success of our groundwater treatment services depends on our ability to comply with
the stringent standards set forth by the regulations governing the industry and our ability to
provide adequate design and construction solutions cost-effectively.
Presently, the exploration, development and production of unconventional natural gas is
subject to various types of regulation by local, state, foreign and federal agencies, including
laws relating to the environment and pollution. We incur certain capital costs to comply with such
regulations and expect to continue to make capital expenditures to comply with these regulatory
requirements. In addition, these requirements may prevent or delay the commencement or continuance
of a given operation and have a substantial impact on the growth of our energy division.
Legislation affecting the natural gas industry is under constant review for amendment and expansion
of scope and future changes to legislation may impose significant financial and operational burdens
on our business. Also, numerous departments and agencies, both federal and state, are authorized by
statute to issue and have issued rules and regulations binding on the natural gas industry and its
individual members, some of which carry substantial penalties and other sanctions for failure to
comply. Any increases in the regulatory burden on the natural gas industry created by new
legislation would increase our cost of doing business and, consequently, lower our profitability.
Our activities are subject to environmental regulation that could increase our operating costs or
suspend our ability to operate our business.
We are required to comply with foreign, federal, state and local laws and regulations regarding
health and safety and the protection of the environment, including those governing the storage,
use, handling, transportation, discharge and disposal of hazardous substances in the ordinary
course of our operations. We are also required to obtain and comply with various permits under
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current environmental laws and regulations, and new laws and regulations may require us to obtain
and comply with additional permits. We may be unable to obtain or comply with, and could be subject
to revocation of, permits necessary to conduct our business. The costs of complying with
environmental laws, regulations and permits may be substantial and any failure to comply could
result in fines, penalties or other sanctions.
Various foreign, federal, state and local environmental laws and regulations may impose
liability on us with respect to conditions at our current or former facilities, sites at which we
conduct or have conducted operations or activities or any third- party waste disposal site to which
we send hazardous wastes. The costs of investigation or remediation at these sites may be
substantial. Environmental laws are complex, change frequently and have tended to become more
stringent over time. Compliance with, and liability under, current and future environmental laws,
as well as more vigorous enforcement policies or discovery of previously unknown conditions
requiring remediation, could increase our operating costs and reduce our revenue.
If our health insurance, liability insurance or workers compensation insurance is insufficient to
cover losses resulting from claims or hazard, if we are unable to cover our deductible obligations
or if we are unable to obtain insurance at reasonable rates, our operating costs could increase and
our profit could decline.
Although we maintain insurance protection that we consider economically prudent for major losses,
we have high deductible amounts for each claim under our health insurance, workers compensation
insurance and liability insurance. Our current individual claim deductible amount is $200,000 for
health insurance, $500,000 for liability insurance and $500,000 for workers compensation. We
cannot assure you that we will have adequate funds to cover our deductible obligations or that our
insurance will be sufficient or effective under all circumstances or against all claims or hazards
to which we may be subject or that we will be able to continue to obtain such insurance protection.
In addition, we may not be able to maintain insurance of the types or at levels we deem necessary
or adequate or at rates we consider reasonable. A successful claim or damage resulting from a
hazard for which we are not fully insured could increase our operating costs and reduce our profit.
Our actual results could differ if the estimates and assumptions that we use to prepare our
financial statements are inaccurate.
To prepare financial statements in conformity with generally accepted accounting principles in the
U.S., we are required to make estimates and assumptions, as of the date of the financial statements
that affect the reported values of assets, liabilities, revenue, expenses and disclosures of
contingent assets and liabilities. Areas in which we must make significant estimates include:
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contract costs and profit 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;
|
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|
accruals for estimated liabilities; including litigation and insurance reserves; and
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calculation of estimated gas reserves.
|
If these estimates are inaccurate, our actual results could differ.
The cost of defending litigation or successful claims against us could reduce our profit or
significantly limit our liquidity and impair our operations.
We have been and from time to time may be named as a defendant in legal actions claiming damages in
connection with drilling or other construction projects and other matters. These are typically
actions that arise in the normal course of business, including employment-related claims and
contractual disputes or claims for personal injury or property damage that occur in connection with
drilling or construction site services. To the extent that defending litigation or successful
claims against us are not covered by insurance, our profit could decline, our liquidity could be
significantly reduced and our operations could be impaired.
If we must write off a significant amount of intangible assets or long-lived assets, our earnings
will be reduced.
Because we have grown in part through acquisitions, goodwill and other acquired intangible assets
represent a substantial portion of our assets. Goodwill was approximately $86 million as of January
31, 2008. 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 $268 million as of January 31, 2008, that are reviewed
for impairment annually or whenever events or circumstances indicate the carrying amount of an
asset may not be recoverable. If a determination that a significant impairment in value of our
unamortized intangible assets or long-lived assets occurs, such determination would require us to
write off a substantial portion of our assets, which would reduce our earnings.
Difficulties integrating our acquisitions could lower our profit.
From time to time, we have made acquisitions to pursue market opportunities, increase our existing
capabilities and expand into new areas of operation. We plan to pursue select acquisitions in the
future. If we are unable to identify and complete such acquisitions, our growth strategy could be
impaired. In addition, we may encounter difficulties integrating our acquisitions and in
successfully managing the growth we expect from the acquisitions. Furthermore, expansion into new
businesses may expose us to additional business risks that are different from those we
14
have traditionally experienced. Because we may pursue acquisitions around the world and may
actively pursue a number of opportunities simultaneously, we may encounter unforeseen expenses,
complications and delays, including difficulties in employing sufficient staff and maintaining
operational and management oversight. To the extent we encounter problems in identifying
acquisition risks or integrating our acquisitions, our operations could be impaired as a result of
business disruptions and lost management time, which could reduce our profit.
If we are unable to protect our intellectual property adequately, the value of our patents and
trademarks and our ability to operate our business could be harmed.
We rely on a combination of patents, trademarks, trade secrets and similar intellectual property
rights to protect the proprietary technology and other intellectual property that are instrumental
to our water infrastructure, mineral exploration and energy operations. We may not be able to
protect our intellectual property adequately, and our use of this intellectual property could
result in liability for patent or trademark infringement or unfair competition. Further, through
acquisitions of third parties, we may acquire intellectual property that is subject to the same
risks as the intellectual property we currently own.
We may be required to institute litigation to enforce our patents, trademarks or other
intellectual property rights, or to protect our trade secrets from time to time. Such litigation
could result in substantial costs and diversion of resources and could reduce our profit or disrupt
our business, regardless of whether we are able to successfully enforce our rights.
RISKS RELATED TO OUR COMMON STOCK
The market price of our common stock could be lowered by future sales of our common stock.
Sales by us or our stockholders of a substantial number of shares of our common stock in the public
market, or the perception that these sales might occur, could cause the market price of our common
stock to decline or could impair our ability to raise capital through a future sale of, or pay for
acquisitions using, our equity securities.
In addition to outstanding shares eligible for future sale, as of January 31, 2008, 849,950
shares of our common stock were issuable under currently outstanding stock options granted to
several officers, directors and employees under our stock option and employee incentive plans.
Future sales of these shares of our common stock could decrease our stock price.
Provisions in our organizational documents and Delaware law could prevent or frustrate attempts by
stockholders to replace our current management or effect a change of control of our company.
Our certificate of incorporation, bylaws and the Delaware General Corporation Law contain
provisions that could make it more difficult for a third party to acquire us without consent of our
board of directors. In addition, under our certificate of incorporation, our board of directors may
issue shares of preferred stock and determine the terms of those shares of stock without any
further action by our stockholders. Our issuance of preferred stock could make it more difficult
for a third party to acquire a majority of our outstanding voting stock and thereby effect a change
in the composition of our board of directors. Our certificate of incorporation also provides that
our stockholders may not take action by written consent. Our bylaws require advance notice of
stockholder proposals and nominations, and permit only our board of directors, or authorized
committee designated by our board of directors, to call a special stockholder meeting. These
provisions may have the effect of preventing or hindering attempts by our stockholders to replace
our current management. In addition, Delaware law prohibits us from engaging in a business
combination with any holder of 15% or more of our capital stock until the holder has held the stock
for three years unless, among other possibilities, our board of directors approves the transaction.
Our board may use this provision to prevent changes in our management. Also, under applicable
Delaware law, our board of directors may adopt additional anti-takeover measures in the future.
We have approved a stockholders rights agreement between us and National City Bank, as rights
agent. Pursuant to this agreement, holders of our common stock are entitled to purchase one
one-hundredth (1/100) of a share of Series A junior participating preferred stock at a price of $45
per share of preferred stock upon certain events. The purchase price is subject to appropriate
adjustment for stock splits and other similar events. Generally, in the event a person or entity
acquires, or initiates a tender offer to acquire, at least 25% of our then outstanding common
stock, the rights will become exercisable for common stock having a value equal to two times the
purchase price of the right. The existence of the Rights Agreement may discourage, delay or prevent
a third party from effecting a change of control or takeover of our company that our management and
board of directors oppose.
In addition, provisions of Delaware law may also discourage, delay or prevent a third party
from acquiring or merging with us or obtaining control of our company.
Because we are a relatively small company, we are disproportionately negatively impacted by changes
in federal securities laws and regulations, which are likely to increase our costs and require
additional management resources.
The Sarbanes-Oxley Act of 2002, which became law in July 2002, has required changes in some of
our corporate governance, securities disclosure and compliance practices. In response to the
requirements of the Sarbanes-Oxley Act, the SEC and Nasdaq have promulgated new rules and listing
standards covering a variety of subjects. Compliance with these new rules and listing standards has
significantly increased our legal and financial and accounting costs, and we expect these increased
costs to continue. In addition, the requirements have taken a significant amount of our time and
resources. Likewise, these developments may make it more difficult for us to attract and retain
qualified members of our board of directors, particularly independent directors, or qualified
executive officers. Because
15
we are a relatively small company, we may be disproportionately impacted by these changes in
federal securities laws and regulations.
As directed by the Sarbanes-Oxley Act, the SEC adopted rules requiring public companies,
including us, 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 our internal controls over financial reporting. In addition, the public accounting
firm auditing our financial statements must report on the effectiveness of our internal controls
over financial reporting. If we are unable to conclude that we have effective internal controls
over financial reporting or, if our independent registered public accounting firm is unable to
provide us with an unqualified report as to the effectiveness of our internal controls over
financial reporting as of each fiscal year end, investors could lose confidence in the reliability
of our financial statements, which could lower our stock price.
We are restricted from paying dividends.
We have not paid any cash dividends on our common stock since our initial public offering in 1992,
and we do not anticipate paying any cash dividends in the foreseeable future. In addition, our
current credit arrangements restrict our ability to pay cash dividends.
Our share price could be volatile and could decline, resulting in a substantial or complete loss of
your investment. Because the trading of our common stock is characterized by low trading volume, it
could be difficult for you to sell the shares of our common stock that you may hold.
The stock markets, including the NASDAQ Global Select Market, on which we list our common stock,
have experienced significant price and volume fluctuations. As a result, the market price of our
common stock could be similarly volatile, and you may experience a decrease in the value of the
shares of our common stock that you may hold, including decreases unrelated to our operating
performance or prospects. In addition, the trading of our common stock has historically been
characterized by relatively low trading volume, and the volatility of our stock price could be
exacerbated by such low trading volumes. The market price of our common stock could be subject to
significant fluctuations in response to various factors or events, including among other things:
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our operating performance and the performance of other similar companies;
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actual or anticipated differences in our operating results;
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changes in our revenue or earnings estimates or recommendations by securities analysts;
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publication of research reports about us or our industry by securities analysts;
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additions and departures of key personnel;
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strategic decisions by us or our competitors, such as acquisitions, divestments, spin-offs,
joint ventures, strategic investments or changes in business strategy;
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the passage of legislation or other regulatory developments that adversely affect us or our
industry;
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speculation in the press or investment community;
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actions by institutional stockholders;
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changes in accounting principles;
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terrorist acts; and
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general market conditions, including factors unrelated to our performance.
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These factors may lower the trading price of our common stock, regardless of our actual
operating performance, and could prevent you from selling your common stock at or above the
offering price to the public. In addition, the stock markets, from time to time, experience extreme
price and volume fluctuations that may be unrelated or disproportionate to the operating
performance of companies. These broad fluctuations may lower the market price of our common stock.
Item 1B. Unresolved Staff Comments
We have no unresolved comments from the Securities and Exchange Commission staff.
Item 2. Properties and Equipment
Our corporate headquarters are located in Mission Woods, Kansas (a suburb of Kansas City,
Missouri), in approximately 46,000 square feet of office space leased by the Company pursuant to a
written lease agreement which expires December 31, 2008. Subsequent to January 31, the lease was
renewed to December 31, 2013.
As of January 31, 2008, we (excluding foreign affiliates) owned or leased approximately 596
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, 2008, our foreign affiliates owned or leased
approximately 151 drill rigs.
Our coalbed methane projects consist of working interests in developed and undeveloped
properties primarily located in the Cherokee Basin in the midwestern U.S. We also own the gas
transportation facilities and equipment that transport the gas produced from our wells.
Natural Gas Reserves
The estimate of natural gas reserves is complex and requires significant judgment in the evaluation
of geological, engineering and economic data. The reserve estimates may change substantially over
time as a result of additional development activity, market price, production history and viability
of production under varying economic conditions. Consequently, significant changes in estimates of
existing reserves could occur. Our reserve and standardized measure estimates are based on
independent engineering evaluations prepared by Cawley, Gillespie & Associates, Inc.
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2008
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2007
|
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Proved developed (MMcf)
|
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22,794
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|
|
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25,010
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Proved undeveloped (MMcf)
|
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27,258
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|
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32,068
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Total proved reserves (MMcf)
|
|
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50,052
|
|
|
|
57,078
|
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Standardized measure of discounted
cash flow (in thousands)
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$
|
86,484
|
|
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$
|
89,012
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16
The standardized measure of discounted cash flow is the present value of estimated future net
revenue to be generated from the production of proved reserves, determined in accordance with the
rules and regulations of the SEC (using prices and costs in effect as of the date of estimation),
less future development, production and income tax expenses, and discounted at 10% per annum to
reflect the timing of future net revenue. The weighted
average year-end spot price used in estimating future net revenue was $7.53 and $6.89 per Mcf for
fiscal 2008 and 2007, respectively. The standardized measure shown should not be construed as the
current market value of the reserves. The 10% discount factor used to calculate present value,
which is required by FASB pronouncements, is not intended to reflect current market conditions. The
present value, no matter what discount rate is used, is materially affected by assumptions as to
timing of future production, which may prove to be inaccurate. See the supplemental oil and gas
disclosures included in the Consolidated Financial Statements for additional information pertaining
to the Companys natural gas reserves and related information. During 2008, we filed estimates of
our natural gas and oil reserves for the year 2007 with the Energy Information Administration of
the U. S. Department of Energy on
Form EIA-23L. The data on Form EIA-23L was presented on
a different basis, and included 100% of the natural gas and oil volumes from our operated
properties only, regardless of our net interest. The difference between the natural gas and oil
reserves reported on Form EIA-23L and those reported in this report exceeds 5%.
Productive Wells, Production and Acreage
As of January 31, 2008, the Company had 466 gross producing wells and 465 net producing wells. The
following table sets forth revenues from sales of gas and production costs per Mcf. Revenues are
presented net of third party interests.
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Fiscal Years Ended January 31,
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2008
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2007
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2006
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Revenues
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$
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6.45
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$
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5.95
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$
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8.52
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Lease operating expenses
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1.71
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1.46
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1.94
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Transportation costs
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2.06
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1.88
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2.57
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Production and property taxes
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0.18
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0.16
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0.24
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The gross and net acreage on leases expiring in each of the following five fiscal years and
thereafter were as follows:
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Gross
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Net
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Acres
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Acres
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2009
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29,220
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|
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29,220
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2010
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24,497
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|
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24,497
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2011
|
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35,046
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|
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35,046
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2012
|
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18,985
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18,985
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2013
|
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63,096
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|
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63,096
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Thereafter
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|
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212
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212
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Gross and net developed and undeveloped acreage as of the end of our last two fiscal years were as
follows:
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Acres
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Fiscal Years Ended January 31,
|
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2008
|
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2007
|
|
Gross developed
|
|
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66,044
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|
|
|
63,973
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Net developed
|
|
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65,836
|
|
|
|
50,159
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Gross undeveloped
|
|
|
192,473
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|
|
|
161,301
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Net undeveloped
|
|
|
192,473
|
|
|
|
161,301
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Drilling Activity
As of January 31, 2008, we had 11 gross and net wells awaiting completion. The table below sets
forth the number of wells completed at any time during the period, regardless of when drilling was
initiated. Most of the wells expected to be drilled in the next year will be of the development
category and in the vicinity of our existing or planned construction pipeline network. Our
drilling, abandonment, and acquisition activities for the periods indicated are shown below:
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|
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|
|
|
|
|
|
|
|
|
|
|
Fiscal Years Ended January 31,
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2008
|
|
2007
|
|
2006
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
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|
Exploratory wells:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capable of production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dry
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
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|
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Development wells:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capable of production
|
|
|
92
|
|
|
|
104
|
|
|
|
148
|
|
|
|
147
|
|
|
|
111
|
|
|
|
111
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|
Dry
|
|
|
|
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|
|
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|
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|
Wells abandoned
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|
|
|
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|
|
|
|
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|
|
|
|
|
|
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|
Acquired wells
|
|
|
|
|
|
|
|
|
|
|
14
|
|
|
|
13
|
|
|
|
4
|
|
|
|
40
|
|
|
Net increase in capable wells
|
|
|
92
|
|
|
|
104
|
|
|
|
162
|
|
|
|
160
|
|
|
|
115
|
|
|
|
151
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|
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The amounts shown as gross and net development wells in 2008 are net of 18 gross and
six net wells which were disposed of during the year in exchange for an overriding royalty
interest. The amount shown as net acquired wells in 2006 includes a
number of pre-existing gross
wells in which we acquired an additional interest during the year.
17
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, 2008.
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.
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Name
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Age
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Position
|
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Andrew B. Schmitt
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|
|
59
|
|
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President, Chief Executive Officer and Director
|
Jeffrey J. Reynolds
|
|
|
41
|
|
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Executive Vice President and Director
|
Gregory F. Aluce
|
|
|
52
|
|
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Senior Vice President and
Division President Water Resources
|
Eric R. Despain
|
|
|
59
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|
|
Senior Vice President and
Division President Mineral Exploration
|
Steven F. Crooke
|
|
|
51
|
|
|
Senior Vice President, Secretary and
General Counsel
|
Jerry W. Fanska
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|
|
59
|
|
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Senior Vice President-Finance and Treasurer
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The business experience of each of the executive officers 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 infrastructure division, and is responsible for the Companys groundwater supply, well
and pump rehabilitation and potable water treatment services. Mr. Aluce has over 24 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.
18
PART II
Item 5. Market for Registrants Common Equity and Related Stockholder Matters
The Companys common stock is traded in the over-the-counter market through the Nasdaq National
Market System under the symbol LAYN. The stock has been traded in this market since the Company
became a publicly held company on August 20, 1992. The Company has not repurchased any of its
common stock during fiscal 2008. The following table sets forth the range of high and low sales
prices of the Companys stock by quarter for fiscal 2008 and 2007, as reported by the Nasdaq Stock
Market. These quotations represent prices between dealers and do not include retail mark-up,
mark-down or commissions.
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|
|
|
|
|
|
Fiscal Year 2008
|
|
High
|
|
Low
|
|
First Quarter
|
|
$
|
41.81
|
|
|
$
|
30.21
|
|
Second Quarter
|
|
|
46.17
|
|
|
|
36.36
|
|
Third Quarter
|
|
|
59.19
|
|
|
|
38.09
|
|
Fourth Quarter
|
|
|
58.49
|
|
|
|
33.83
|
|
|
|
|
|
|
|
|
|
|
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
|
|
At March 31, 2008, there were 108 owners of record of the Companys common stock.
The Company has not paid any cash dividends on its common stock. Moreover, the Board of
Directors of the Company does not anticipate paying any cash dividends in the foreseeable future.
The Companys future dividend policy will depend on a number of factors including future earnings,
capital requirements, financial condition and prospects of the Company and such other factors as
the Board of Directors may deem relevant, as well as restrictions under the Credit Agreement
between the Company and LaSalle Bank National Association, as administrative agent for a group of
banks, the Master Shelf Agreement between the Company and Prudential Investment Management, Inc.,
The Prudential Insurance Company of America, Pruco Life Insurance Company and Security Life of
Denver Insurance Company, and other restrictions which may exist under other credit arrangements
existing from time to time. The Credit Agreement and the Master Shelf Agreement limit the cash
dividends payable by the Company.
19
Item 6. Selected Financial Data
The following selected historical financial information as of and for each of the five fiscal years
ended January 31, 2008, 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.
The Company sold various operating companies during 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,
|
|
2008
|
|
2007
|
|
2006
|
|
2005
|
|
2004
|
|
Income Statement Data (in thousands, except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
868,274
|
|
|
$
|
722,768
|
|
|
$
|
463,015
|
|
|
$
|
343,462
|
|
|
$
|
272,053
|
|
Cost of revenues (exclusive of depreciation, depletion and amortization
shown below)
|
|
|
638,003
|
|
|
|
536,373
|
|
|
|
344,628
|
|
|
|
250,244
|
|
|
|
196,462
|
|
Selling, general and administrative expense
|
|
|
119,937
|
|
|
|
102,603
|
|
|
|
69,979
|
|
|
|
60,214
|
|
|
|
53,920
|
|
Depreciation, depletion and amorization
|
|
|
43,620
|
|
|
|
32,853
|
|
|
|
20,024
|
|
|
|
14,441
|
|
|
|
11,877
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of affiliates
|
|
|
8,076
|
|
|
|
4,452
|
|
|
|
4,345
|
|
|
|
2,637
|
|
|
|
1,398
|
|
Interest
|
|
|
(8,730
|
)
|
|
|
(9,781
|
)
|
|
|
(5,773
|
)
|
|
|
(3,221
|
)
|
|
|
(2,604
|
)
|
Debt extinguishment costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,320
|
)
|
Other, net
|
|
|
1,229
|
|
|
|
2,557
|
|
|
|
900
|
|
|
|
1,220
|
|
|
|
358
|
|
|
Income from continuing operations before income taxes
and minority interest
|
|
|
67,289
|
|
|
|
48,167
|
|
|
|
27,856
|
|
|
|
19,199
|
|
|
|
6,626
|
|
Income tax expense
|
|
|
30,178
|
|
|
|
21,915
|
|
|
|
13,121
|
|
|
|
9,215
|
|
|
|
4,265
|
|
Minority interest
|
|
|
145
|
|
|
|
|
|
|
|
(50
|
)
|
|
|
(17
|
)
|
|
|
|
|
|
Net income from continuing operations before discontinued operations
|
|
|
37,256
|
|
|
|
26,252
|
|
|
|
14,685
|
|
|
|
9,967
|
|
|
|
2,361
|
|
Gain (loss) from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
|
|
(213
|
)
|
|
|
(1,456
|
)
|
Gain (loss) on sale of discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,746
|
|
|
Net income
|
|
$
|
37,256
|
|
|
$
|
26,252
|
|
|
$
|
14,681
|
|
|
$
|
9,754
|
|
|
$
|
2,651
|
|
|
Basic income per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations before discontinued
operations
|
|
$
|
2.23
|
|
|
$
|
1.71
|
|
|
$
|
1.08
|
|
|
$
|
0.79
|
|
|
$
|
0.20
|
|
Income (loss) from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.01
|
)
|
|
|
0.02
|
|
|
Net income per share
|
|
$
|
2.23
|
|
|
$
|
1.71
|
|
|
$
|
1.08
|
|
|
$
|
0.78
|
|
|
$
|
0.22
|
|
|
Diluted income per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations before discontinued
operations
|
|
$
|
2.20
|
|
|
$
|
1.68
|
|
|
$
|
1.05
|
|
|
$
|
0.77
|
|
|
$
|
0.19
|
|
Income (loss) from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.02
|
)
|
|
|
0.02
|
|
|
Net income per share
|
|
$
|
2.20
|
|
|
$
|
1.68
|
|
|
$
|
1.05
|
|
|
$
|
0.75
|
|
|
$
|
0.21
|
|
|
Balance Sheet Data (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working capital, including current maturities of debt
|
|
$
|
127,696
|
|
|
$
|
66,989
|
|
|
$
|
69,996
|
|
|
$
|
54,455
|
|
|
$
|
52,406
|
|
Total assets
|
|
|
696,955
|
|
|
|
547,164
|
|
|
|
449,335
|
|
|
|
245,380
|
|
|
|
217,327
|
|
Total long term debt, excluding current maturities
|
|
|
46,667
|
|
|
|
151,600
|
|
|
|
128,900
|
|
|
|
60,000
|
|
|
|
42,000
|
|
Total stockholders equity
|
|
|
423,372
|
|
|
|
205,034
|
|
|
|
171,626
|
|
|
|
104,697
|
|
|
|
93,685
|
|
20
Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of financial condition and results of operations should be
read in conjunction with the Companys Consolidated Financial Statements and Notes thereto under
Item 8.
Cautionary Language Regarding Forward-Looking Statements
This Form 10-K may contain forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Exchange Act of 1934. Such statements may include,
but are not limited to, statements of plans and objectives, statements of future economic
performance and statements of assumptions underlying such statements, and statements of
managements intentions, hopes, beliefs, expectations or predictions of the future. Forward-looking
statements can often be identified by the use of forward-looking terminology, such as should,
intended, continue, believe, may, hope, anticipate, 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 infrastructure division. The Companys reportable segments are
defined as follows:
Water 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.
Through internal growth and several recent acquisitions, 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, water treatment product research and development, sewer rehabilitation and
water and wastewater transmission lines.
The divisions operations rely heavily on the municipal sector as approximately 66% of the
divisions fiscal 2008 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 35% of total division revenues
were generated for fiscal 2008. 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.
21
Energy Division
This division focuses on the exploration and production of unconventional gas properties. This
division has primarily been concentrated on projects in the mid-continent region of the United
States; however, in fiscal 2008, it began an exploration project in Chile.
The expansion of the Companys energy segment is contingent upon significant cash investments
to develop the Companys unproved acreage. As of January 31, 2008, the Company has invested
$125,275,000 in oil and gas related assets and expects to spend approximately $25,000,000 in
development activities in fiscal 2009. The production curve for a typical unconventional gas well
in the Companys operating market is generally 15-20 years. Accordingly, the Company expects to
earn a return on its investment through proceeds from gas production over the next 15-20 years.
However, future revenues and profits will be dependent upon a number of factors including
consumption levels for natural gas, commodity prices, the economic feasibility of gas exploration
and production and the discovery rate of new gas reserves. The Company has 465 net producing wells
on-line as of January 31, 2008.
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
|
2008
|
|
2007
|
|
2006
|
|
vs. 2007
|
|
vs. 2006
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Water infrastructure
|
|
|
73.7
|
%
|
|
|
73.6
|
%
|
|
|
69.3
|
%
|
|
|
20.2
|
%
|
|
|
65.7
|
%
|
Mineral exploration
|
|
|
20.5
|
|
|
|
20.6
|
|
|
|
26.8
|
|
|
|
19.9
|
|
|
|
19.9
|
|
Energy
|
|
|
4.6
|
|
|
|
3.7
|
|
|
|
2.7
|
|
|
|
46.8
|
|
|
|
116.0
|
|
Other
|
|
|
1.2
|
|
|
|
2.1
|
|
|
|
1.2
|
|
|
|
(29.6
|
)
|
|
|
181.6
|
|
|
Total revenues
|
|
|
100.0
|
%
|
|
|
100.0
|
%
|
|
|
100.0
|
%
|
|
|
20.1
|
|
|
|
56.1
|
|
Cost of revenues (exclusive of depreciation, depletion and amortization
shown below)
|
|
|
73.5
|
|
|
|
74.2
|
|
|
|
74.4
|
|
|
|
18.9
|
|
|
|
55.6
|
|
Selling, general and administrative expense
|
|
|
13.8
|
|
|
|
14.2
|
|
|
|
15.1
|
|
|
|
16.9
|
|
|
|
46.6
|
|
Depreciation, depletion and amortization
|
|
|
5.0
|
|
|
|
4.5
|
|
|
|
4.3
|
|
|
|
32.8
|
|
|
|
64.1
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of affiliates
|
|
|
0.9
|
|
|
|
0.6
|
|
|
|
0.9
|
|
|
|
81.4
|
|
|
|
2.5
|
|
Interest
|
|
|
(1.0
|
)
|
|
|
(1.4
|
)
|
|
|
(1.3
|
)
|
|
|
(10.7
|
)
|
|
|
69.4
|
|
Other, net
|
|
|
0.2
|
|
|
|
0.3
|
|
|
|
0.2
|
|
|
|
(51.9
|
)
|
|
|
184.1
|
|
|
Income from continuing operations before income taxes and
minority interest
|
|
|
7.8
|
|
|
|
6.6
|
|
|
|
6.0
|
|
|
|
39.7
|
|
|
|
72.9
|
|
Income tax expense
|
|
|
3.5
|
|
|
|
3.0
|
|
|
|
2.8
|
|
|
|
37.7
|
|
|
|
67.0
|
|
Minority interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations
|
|
|
4.3
|
|
|
|
3.6
|
|
|
|
3.2
|
|
|
|
41.9
|
|
|
|
78.8
|
|
|
Loss from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
|
|
*
|
|
Net income
|
|
|
4.3
|
%
|
|
|
3.6
|
%
|
|
|
3.2
|
%
|
|
|
41.9
|
%
|
|
|
78.8
|
%
|
|
* Not
meaningful
Revenues, equity in earnings of affiliates and income from continuing operations before income
taxes pertaining to the Companys operating segments are
presented on the next page. Intersegment revenues, if
any, 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.
22
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,
|
|
2008
|
|
2007
|
|
2006
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Water infrastructure
|
|
$
|
639,584
|
|
|
$
|
531,916
|
|
|
$
|
320,996
|
|
Mineral exploration
|
|
|
178,482
|
|
|
|
148,911
|
|
|
|
124,206
|
|
Energy
|
|
|
39,749
|
|
|
|
27,081
|
|
|
|
12,536
|
|
Other
|
|
|
10,459
|
|
|
|
14,860
|
|
|
|
5,277
|
|
|
Total revenues
|
|
$
|
868,274
|
|
|
$
|
722,768
|
|
|
$
|
463,015
|
|
|
Equity in earnings of affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
Water infrastructure
|
|
$
|
|
|
|
$
|
|
|
|
$
|
839
|
|
Mineral exploration
|
|
|
8,076
|
|
|
|
4,452
|
|
|
|
3,506
|
|
|
Total equity in earnings of affiliates
|
|
$
|
8,076
|
|
|
$
|
4,452
|
|
|
$
|
4,345
|
|
|
Income (loss) from continuing operations before income taxes and minority interest
|
|
|
|
|
|
|
|
|
|
|
|
|
Water infrastructure
|
|
$
|
42,995
|
|
|
$
|
35,000
|
|
|
$
|
28,255
|
|
Mineral exploration
|
|
|
37,452
|
|
|
|
26,557
|
|
|
|
13,947
|
|
Energy
|
|
|
13,075
|
|
|
|
10,680
|
|
|
|
2,891
|
|
Other
|
|
|
3,696
|
|
|
|
4,094
|
|
|
|
1,307
|
|
Unallocated corporate expenses
|
|
|
(21,199
|
)
|
|
|
(18,383
|
)
|
|
|
(12,771
|
)
|
Interest
|
|
|
(8,730
|
)
|
|
|
(9,781
|
)
|
|
|
(5,773
|
)
|
|
Total income from continuing operations before income taxes and minority interest
|
|
$
|
67,289
|
|
|
$
|
48,167
|
|
|
$
|
27,856
|
|
|
23
Comparison of Fiscal 2008 to Fiscal 2007
Revenues for fiscal 2008 increased $145,506,000, or 20.1%, to $868,274,000 compared to $722,768,000
for fiscal 2007. Revenues were up across all divisions. A further discussion of results of
operations by division is presented below.
Selling, general and administrative expenses increased to $119,937,000 for fiscal 2008
compared to $102,603,000 for fiscal 2007 (13.8% and 14.2% of revenues, respectively). The increase,
including increases from acquisitions, was primarily the result of wage and benefit increases of
$7,731,000, in-creased professional fees of $1,474,000, primarily due to several strategic
consulting projects during the year, and additional incentive compensation expense of $1,193,000
from increased profitability.
Depreciation, depletion and amortization increased to $43,620,000 for fiscal 2008 compared to
$32,853,000 for fiscal 2007. The increase was primarily the result of increased depletion of
$3,587,000 resulting from the increase in production of unconventional gas from the Companys
energy operations and increased depreciation from property additions and acquisitions in the other
divisions.
Equity in earnings of affiliates increased to $8,076,000 for fiscal 2008 compared to
$4,452,000 for fiscal 2007. The increase reflects continued strong performance in mineral
exploration by affiliates in Latin America in response to continued high metals pricing.
Interest expense decreased to $8,730,000 for fiscal 2008 compared to $9,781,000 for fiscal
2007. The decrease was primarily a result of debt paid off with proceeds from the Companys stock
offering in October 2007.
Other, net decreased to $1,229,000 for fiscal 2008 from $2,557,000 for fiscal 2007, primarily
due to a non-recurring 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 44.8% for fiscal 2008, compared to 45.5% for fiscal 2007.
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 Infrastructure Division
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
Fiscal Years Ended January 31,
|
|
2008
|
|
2007
|
|
Revenues
|
|
$
|
639,584
|
|
|
$
|
531,916
|
|
Income before income taxes and
minority interest
|
|
|
42,995
|
|
|
|
35,000
|
|
Water infrastructure revenues increased 20.2% to $639,584,000 for fiscal 2008, from
$531,916,000 for fiscal 2007. The increase in revenues was partially attributable to incremental
revenues of $49,313,000 from the Companys acquisitions, including a full years impact from 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. In addition, revenues for fiscal 2008 increased by $16,486,000 from sewer rehabilitation
services with the balance of revenue increases spread throughout the group.
Income for the water infrastructure division increased 22.8% to $42,995,000 for fiscal 2008,
compared to $35,000,000 for fiscal 2007. The increase in income was primarily attributable to
incremental income of approximately $5,144,000 from the Companys acquisitions.
The backlog in the water infrastructure division was $408,404,000 as of January 31, 2008,
compared to $349,200,000 as of
January 31, 2007.
Mineral Exploration Division
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
Fiscal Years Ended January 31,
|
|
2008
|
|
2007
|
|
Revenues
|
|
$
|
178,482
|
|
|
$
|
148,911
|
|
Income before income taxes and
minority interest
|
|
|
37,452
|
|
|
|
26,557
|
|
Mineral exploration revenues increased 19.9% to $178,482,000 for fiscal 2008, compared to revenues
of $148,911,000 for fiscal 2007. The increase in revenues was primarily attributable to continued
strength in worldwide exploration activity as a result of the relatively high gold and base metal
prices.
Income for the mineral exploration division increased 41.0% to $37,452,000 for fiscal 2008,
compared to $26,557,000 for fiscal 2007. The improved income was attributable to continued strong
exploration activity in the Companys markets, especially in North America, and earnings increases
of $3,624,000 by the Companys Latin American affiliates.
Energy Division
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
Fiscal Years Ended January 31,
|
|
2008
|
|
2007
|
|
Revenues
|
|
$
|
39,749
|
|
|
$
|
27,081
|
|
Income before income taxes and
minority interest
|
|
|
13,075
|
|
|
|
10,680
|
|
Energy division revenues increased 46.8% to $39,749,000 for fiscal 2008, compared to revenues
of $27,081,000 for fiscal 2007. The increase in revenues was primarily attributable to increased
production from the Companys unconventional gas properties.
The division income increased 22.4% to $13,075,000 for fiscal 2008, compared to $10,680,000
for fiscal 2007. For the year, increased income was primarily due to the increased production
discussed above, offset by expenses of $947,000 associated with the operations of the Companys
concession in Chile.
Other
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
Fiscal Years Ended January 31,
|
|
2008
|
|
2007
|
|
Revenues
|
|
$
|
10,459
|
|
|
$
|
14,860
|
|
Income before income taxes and
minority interest
|
|
|
3,696
|
|
|
|
4,094
|
|
Included in Other for fiscal 2008 and 2007 were revenues of $4,954,000 and $10,035,000,
respectively, associated with contracts to provide consulting and logistical support for
international projects in Canada and Africa. Excluding the effects of
24
these activities, the remainder of the operations included in this segment were consistent year
over year.
Unallocated Corporate Expenses
Corporate expenses not allocated to individual divisions, primarily included in selling, general
and administrative expenses, were $21,199,000 and $18,383,000 for fiscal 2008 and 2007,
respectively. The increase for the year was primarily due to increases in wage and benefit costs of
$1,028,000 and increased share based compensation to employees of $840,000.
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 CWI acquisition and the acquisition of UIG. A
further discussion of results of operations by division is presented below.
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 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 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 Infrastructure Division
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
Fiscal Years Ended January 31,
|
|
2007
|
|
2006
|
|
Revenues
|
|
$
|
531,916
|
|
|
$
|
320,996
|
|
Income from continuing operations
before income taxes and minority interest
|
|
|
35,000
|
|
|
|
28,255
|
|
Water 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 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.
The backlog in the water infrastructure division was $349,200,000 as of January 31, 2007,
compared to $227,444,000 as of
January 31, 2006.
Mineral Exploration Division
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
Fiscal Years Ended January 31,
|
|
2007
|
|
2006
|
|
Revenues
|
|
$
|
148,911
|
|
|
$
|
124,206
|
|
Income from continuing operations
before income taxes and minority interest
|
|
|
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.
25
Energy
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
Fiscal Years Ended January 31,
|
|
2007
|
|
2006
|
|
Revenues
|
|
$
|
27,081
|
|
|
$
|
12,536
|
|
Income from continuing operations
before income taxes and minority interest
|
|
|
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 and minority interest
|
|
|
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.
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 does not believe that the Companys operations for the periods discussed have been
significantly adversely affected by inflation or changing prices from its suppliers.
Liquidity and Capital Resources
Management exercises discretion regarding the liquidity and capital resource needs of its business
segments. This includes the ability to prioritize the use of capital and debt capacity, to
determine cash management policies and to make decisions regarding capital expenditures. The
Companys primary sources of liquidity have historically been cash from operations, supplemented by
borrowings under its credit facilities.
The Company maintains an agreement (the Master Shelf Agreement) whereby it has $105,000,000
of unsecured notes available to be issued before September 15, 2009. At January 31, 2008, 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). At
January 31, 2008, the Company had letters of credits of $12,716,000 and no borrowings outstanding
under the Credit Agreement resulting in available capacity of $187,284,000. The Company was in
compliance with its financial covenants at January 31, 2008 and expects to remain in compliance
through the foreseeable future.
The Companys working capital as of January 31, 2008, 2007 and 2006, was $127,696,000,
$66,989,000 and $69,996,000, respectively. The increase in working capital in the current year was
attributable to remaining proceeds of the Companys October 2007 stock offering.
The Company believes it will have sufficient cash from operations and access to credit
facilities to meet the Companys
26
operating cash requirements and to fund its budgeted capital
expenditures for fiscal 2009.
Operating Activities
Cash from
operating activities was $80,163,000, $74,676,000 and $40,869,000 for fiscal 2008, 2007
and 2006, respectively. The growth over the last two years was primarily due to increased earnings
and related increases in accounts payable, 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 $70,037,000 for the year ended January 31,
2008, were more heavily weighted toward its water infrastructure and minerals divisions rather than
unconventional gas exploration and production. Expenditures were made in those two divisions
during the year to sustain capacity and improve efficiency of the equipment. Unconventional gas
expenditures declined to $29,193,000 as the Company maintained its U.S. operations while carefully
considering its expansion efforts on its exploration concession in Chile. Also, during the year,
the Company spent $20,470,000 to complete two acquisitions to complement its water infrastructure
division.
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).
Financing Activities
In October 2007, the Company completed a public offering of its common stock. The offering
produced net proceeds of approximately $160 million, which were used to repay the then outstanding
borrowings on the Companys revolving bank credit facility and to build funds for potential future
acquisitions and general corporate purposes.
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.
27
Contractual Obligations and Commercial Commitments
The Companys contractual obligations and commercial commitments as of January 31, 2008, 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 principal payments
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Senior Notes principal payments
|
|
|
60,000
|
|
|
|
13,333
|
|
|
|
40,000
|
|
|
|
6,667
|
|
|
|
|
|
Interest payments
|
|
|
10,011
|
|
|
|
3,500
|
|
|
|
5,791
|
|
|
|
720
|
|
|
|
|
|
Operating leases
|
|
|
28,387
|
|
|
|
10,543
|
|
|
|
15,067
|
|
|
|
2,777
|
|
|
|
|
|
Mineral interest obligations
|
|
|
613
|
|
|
|
109
|
|
|
|
345
|
|
|
|
146
|
|
|
|
13
|
|
Income tax
uncertainties
|
|
|
1,200
|
|
|
|
1,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash contractual obligations
|
|
|
100,211
|
|
|
|
28,685
|
|
|
|
61,203
|
|
|
|
10,310
|
|
|
|
13
|
|
Standby letters of credit
|
|
|
12,716
|
|
|
|
12,716
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
|
1,043
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,043
|
|
|
Total contractual obligations and
commercial commitments
|
|
$
|
113,970
|
|
|
$
|
41,401
|
|
|
$
|
61,203
|
|
|
$
|
10,310
|
|
|
$
|
1,056
|
|
|
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. 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). Interest payments have been included in the table above based
only on outstanding balances and interest rates as of January 31, 2008.
The
Company has income tax uncertainties in the amount of $5,997,000 at
January 31, 2008, that are classified as non-current on
the Companys balance sheet as resolution of these matters is
expected to take more than a year. The ultimate timing of resolution
of these items is uncertain, and accordingly the amounts have not
been included in the table above.
The Company incurs additional obligations in the ordinary course of operations. These
obligations, including but not limited to, income tax payments 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.
28
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. Separate full-cost pools are established for each country in which the
Company has exploration activities.
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
29
based on actuarially determined projections of future payments under
these programs. Should a greater amount of claims occur compared to what was estimated or medical
costs increase beyond what was anticipated, reserves recorded may not be sufficient and additional
costs to the consolidated financial statements could be required.
Costs estimated to be incurred in the future for employee health and welfare benefits,
property, workers compensation and casualty insurance programs resulting from claims which have
occurred are accrued currently. Under the terms of 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, 2008, an instantaneous
change in interest rates of one percentage point would not change the Companys annual interest
expense as we have no variable rate debt outstanding.
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, 2008, 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 $511,000, $416,000 and $276,000 for the
years ended January 31, 2008, 2007 and 2006, 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, 2008, 2007 and 2006, were ($430,000), $95,000 and
($290,000), 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, 2008, the Company held contracts for physical delivery of 4,190,000 million British Thermal
Units (MMBtu) of natural gas through March 31, 2010, at prices ranging from $7.49 to $9.05 per
MMBtu through March 2008, and $7.64 per MMBtu from April 2008 through March 2010. The estimated
fair value of such contracts at January 31, 2008, was a loss of $99,000. 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 $1,350,000 for the year ended January 31,
2008.
30
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
|
|
|
32
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|
|
|
|
|
|
Report of Independent Registered Public Accounting Firm
|
|
|
33
|
|
|
|
|
|
|
Financial Statements:
|
|
|
|
|
|
|
|
|
|
Consolidated Balance Sheets as of January 31, 2008 and 2007
|
|
|
34
|
|
|
|
|
|
|
Consolidated Statements of Income for the Years Ended January 31, 2008, 2007 and 2006
|
|
|
35
|
|
|
|
|
|
|
Consolidated Statements of Stockholders Equity for the Years Ended January 31, 2008, 2007 and 2006
|
|
|
36
|
|
|
|
|
|
|
Consolidated Statements of Cash Flows for the Years Ended January 31, 2008, 2007 and 2006
|
|
|
37
|
|
|
|
|
|
|
Notes to Consolidated Financial Statements
|
|
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38
|
|
|
|
|
|
|
Supplemental Information on Oil and Gas Producing Activities
|
|
|
58
|
|
|
|
|
|
|
Financial Statement Schedule II Valuation and Qualifying Accounts
|
|
|
60
|
|
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.
31
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
|
|
Senior Vice President and
|
Chief Executive Officer
|
|
Chief Financial Officer
|
32
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, 2008 and 2007, and the related consolidated
statements of income, stockholders equity, and cash flows for each of the three years in the
period ended January 31, 2008. 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, 2008
and 2007, and the results of their operations and their cash flows for each of the three years in
the period ended January 31, 2008, in conformity with accounting principles generally accepted in
the United States of America. Also, in our opinion, such financial statement schedule, when
considered in relation to the basic consolidated financial statements taken as a whole, present
fairly, in all material respects, the information set forth therein.
As
discussed in Note 8 to the consolidated financial statements, the Company adopted the
provisions of Financial Accounting Standards Board (FASB) Interpretation No. 48,
Accounting for
Uncertainty in Income Taxes an Interpretation of FASB Statement No. 109
, on February 1, 2007.
Additionally, as discussed in Note 1 to the consolidated financial statements, the Company changed
its method of accounting for share-based compensation upon the adoption of Statement of Financial
Accounting Standards (SFAS) No. 123(R),
Share-Based Payments
, on February 1, 2006 and 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 Companys internal control over financial reporting as of
January 31, 2008, 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 15, 2008 expressed an unqualified opinion on the Companys internal control over financial
reporting.
/s/Deloitte & Touche LLP
Kansas City, Missouri
April 15, 2008
33
Layne Christensen Company and Subsidiaries
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
ASSETS
|
|
|
|
|
January 31,
|
|
2008
|
|
2007
|
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
73,068
|
|
|
$
|
13,007
|
|
Customer receivables, less allowance of $7,571 and $7,020, respectively
|
|
|
125,091
|
|
|
|
109,615
|
|
Costs and estimated earnings in excess of billings on uncompleted contracts
|
|
|
60,796
|
|
|
|
51,210
|
|
Inventories
|
|
|
21,020
|
|
|
|
18,456
|
|
Deferred income taxes
|
|
|
18,711
|
|
|
|
16,551
|
|
Income taxes receivable
|
|
|
866
|
|
|
|
521
|
|
Restricted cash current
|
|
|
500
|
|
|
|
8,270
|
|
Other
|
|
|
5,288
|
|
|
|
5,578
|
|
|
Total current assets
|
|
|
305,340
|
|
|
|
223,208
|
|
|
Property and equipment:
|
|
|
|
|
|
|
|
|
Land
|
|
|
8,643
|
|
|
|
8,180
|
|
Buildings
|
|
|
21,868
|
|
|
|
21,457
|
|
Machinery and equipment
|
|
|
299,642
|
|
|
|
263,049
|
|
Gas transportation facilities and equipment
|
|
|
30,266
|
|
|
|
24,939
|
|
Oil and gas properties
|
|
|
76,844
|
|
|
|
58,458
|
|
Mineral interests in oil and gas properties
|
|
|
18,165
|
|
|
|
12,515
|
|
|
|
|
|
455,428
|
|
|
|
388,598
|
|
Less accumulated depreciation and depletion
|
|
|
(208,061
|
)
|
|
|
(174,081
|
)
|
|
Net property and equipment
|
|
|
247,367
|
|
|
|
214,517
|
|
|
Other assets:
|
|
|
|
|
|
|
|
|
Investment in affiliates
|
|
|
29,835
|
|
|
|
24,280
|
|
Goodwill
|
|
|
85,706
|
|
|
|
65,184
|
|
Other intangible assets, net
|
|
|
20,930
|
|
|
|
16,017
|
|
Restricted cash long term
|
|
|
505
|
|
|
|
|
|
Other
|
|
|
7,272
|
|
|
|
3,958
|
|
|
Total other assets
|
|
|
144,248
|
|
|
|
109,439
|
|
|
|
|
$
|
696,955
|
|
|
$
|
547,164
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
67,777
|
|
|
$
|
52,156
|
|
Current maturities of long term debt
|
|
|
13,333
|
|
|
|
|
|
Accrued compensation
|
|
|
36,763
|
|
|
|
29,616
|
|
Cash purchase price adjustments
|
|
|
|
|
|
|
240
|
|
Accrued insurance expense
|
|
|
8,158
|
|
|
|
7,303
|
|
Other accrued expenses
|
|
|
15,222
|
|
|
|
14,222
|
|
Acquisition escrow obligation current
|
|
|
550
|
|
|
|
9,395
|
|
Income taxes payable
|
|
|
4,200
|
|
|
|
9,045
|
|
Billings in excess of costs and estimated earnings on uncompleted contracts
|
|
|
31,641
|
|
|
|
34,242
|
|
|
Total current liabilities
|
|
|
177,644
|
|
|
|
156,219
|
|
|
Noncurrent and deferred liabilities:
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
46,667
|
|
|
|
151,600
|
|
Accrued insurance expense
|
|
|
9,736
|
|
|
|
8,160
|
|
Deferred income taxes
|
|
|
28,329
|
|
|
|
23,302
|
|
Acquisition escrow obligation long term
|
|
|
505
|
|
|
|
|
|
Minority interest
|
|
|
398
|
|
|
|
|
|
Other
|
|
|
10,304
|
|
|
|
2,849
|
|
|
Total noncurrent and deferred liabilities
|
|
|
95,939
|
|
|
|
185,911
|
|
|
Contingencies
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Common stock, par value $.01 per share, 30,000,000 shares authorized,
19,160,716 and 15,517,724 shares issued and outstanding, respectively
|
|
|
192
|
|
|
|
155
|
|
Capital in excess of par value
|
|
|
328,301
|
|
|
|
149,187
|
|
Retained earnings
|
|
|
101,866
|
|
|
|
64,145
|
|
Accumulated other comprehensive loss
|
|
|
(6,987
|
)
|
|
|
(8,453
|
)
|
|
Total stockholders equity
|
|
|
423,372
|
|
|
|
205,034
|
|
|
|
|
$
|
696,955
|
|
|
$
|
547,164
|
|
|
See Notes to Consolidated Financial Statements.
34
Layne Christensen Company and Subsidiaries
Consolidated Statements of Income
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per share data)
|
|
|
|
|
|
|
Years Ended January 31,
|
|
2008
|
|
2007
|
|
2006
|
|
Revenues
|
|
$
|
868,274
|
|
|
$
|
722,768
|
|
|
$
|
463,015
|
|
Cost of revenues (exclusive of depreciation, depletion and amortization shown below)
|
|
|
638,003
|
|
|
|
536,373
|
|
|
|
344,628
|
|
Selling, general and administrative expense
|
|
|
119,937
|
|
|
|
102,603
|
|
|
|
69,979
|
|
Depreciation, depletion and amortization
|
|
|
43,620
|
|
|
|
32,853
|
|
|
|
20,024
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of affiliates
|
|
|
8,076
|
|
|
|
4,452
|
|
|
|
4,345
|
|
Interest
|
|
|
(8,730
|
)
|
|
|
(9,781
|
)
|
|
|
(5,773
|
)
|
Other, net
|
|
|
1,229
|
|
|
|
2,557
|
|
|
|
900
|
|
|
Income from continuing operations before income taxes and minority interest
|
|
|
67,289
|
|
|
|
48,167
|
|
|
|
27,856
|
|
Income tax expense
|
|
|
30,178
|
|
|
|
21,915
|
|
|
|
13,121
|
|
Minority interest
|
|
|
145
|
|
|
|
|
|
|
|
(50
|
)
|
|
Net income from continuing operations before discontinued operations
|
|
|
37,256
|
|
|
|
26,252
|
|
|
|
14,685
|
|
Loss from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
|
Net income
|
|
$
|
37,256
|
|
|
$
|
26,252
|
|
|
$
|
14,681
|
|
|
Basic income per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations
|
|
$
|
2.23
|
|
|
$
|
1.71
|
|
|
$
|
1.08
|
|
Loss from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share
|
|
$
|
2.23
|
|
|
$
|
1.71
|
|
|
$
|
1.08
|
|
|
Diluted income per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations
|
|
$
|
2.20
|
|
|
$
|
1.68
|
|
|
$
|
1.05
|
|
Loss from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share
|
|
$
|
2.20
|
|
|
$
|
1.68
|
|
|
$
|
1.05
|
|
|
Weighted average shares outstanding basic
|
|
|
16,670
|
|
|
|
15,320
|
|
|
|
13,550
|
|
Dilutive stock options
|
|
|
268
|
|
|
|
311
|
|
|
|
477
|
|
|
Weighted average shares outstanding diluted
|
|
|
16,938
|
|
|
|
15,631
|
|
|
|
14,027
|
|
|
See Notes to Consolidated Financial Statements.
35
Layne Christensen Company and Subsidiaries
Consolidated Statements of Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital In
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
Common Stock
|
|
Excess of
|
|
Retained
|
|
Comprehensive
|
|
Unearned
|
|
|
(in thousands, except share data)
|
|
Shares
|
|
Amount
|
|
Par Value
|
|
Earnings
|
|
Income (Loss)
|
|
Compensation
|
|
Total
|
|
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
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37,256
|
|
|
|
|
|
|
|
|
|
|
|
37,256
|
|
Other comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustments,
net of income tax expense of $424
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
760
|
|
|
|
|
|
|
|
760
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38,016
|
|
|
Issuance of unvested shares
|
|
|
73,863
|
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of adoption of FIN 48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
465
|
|
|
|
|
|
|
|
|
|
|
|
465
|
|
Change in
unrecognized pension liability,
net of income tax expense of $445
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
706
|
|
|
|
|
|
|
|
706
|
|
Proceeds from public offering, net
|
|
|
3,105,000
|
|
|
|
31
|
|
|
|
159,848
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
159,879
|
|
Issuance of stock upon acquisition of business
|
|
|
249,023
|
|
|
|
3
|
|
|
|
10,979
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,982
|
|
Issuance of stock upon exercise of options
|
|
|
215,106
|
|
|
|
2
|
|
|
|
2,902
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,904
|
|
Income tax benefit on exercise of options
|
|
|
|
|
|
|
|
|
|
|
2,360
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,360
|
|
Share-based compensation
|
|
|
|
|
|
|
|
|
|
|
3,026
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,026
|
|
|
Balance, January 31, 2008
|
|
|
19,160,716
|
|
|
$
|
192
|
|
|
$
|
328,301
|
|
|
$
|
101,866
|
|
|
$
|
(6,987
|
)
|
|
$
|
|
|
|
$
|
423,372
|
|
|
See Notes to Consolidated Financial Statements.
36
Layne Christensen Company and Subsidiaries
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
Years Ended January 31,
|
|
2008
|
|
2007
|
|
2006
|
|
Cash flow from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
37,256
|
|
|
$
|
26,252
|
|
|
$
|
14,681
|
|
Adjustments to reconcile net income to cash from operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
4
|
|
Depreciation, depletion and amortization
|
|
|
43,620
|
|
|
|
32,853
|
|
|
|
20,024
|
|
Deferred income taxes
|
|
|
2,364
|
|
|
|
(2,985
|
)
|
|
|
6,540
|
|
Equity in earnings of affiliates
|
|
|
(8,076
|
)
|
|
|
(4,452
|
)
|
|
|
(4,345
|
)
|
Dividends received from affiliates
|
|
|
2,521
|
|
|
|
1,502
|
|
|
|
1,693
|
|
Minority interest
|
|
|
(145
|
)
|
|
|
|
|
|
|
50
|
|
(Gain) loss on disposal of property and equipment
|
|
|
(671
|
)
|
|
|
(994
|
)
|
|
|
295
|
|
Gain on sale of domestic affiliate
|
|
|
|
|
|
|
|
|
|
|
(1,289
|
)
|
Gain on sale of mineral concession
|
|
|
|
|
|
|
(920
|
)
|
|
|
|
|
Share-based compensation
|
|
|
3,026
|
|
|
|
2,240
|
|
|
|
|
|
Share-based compensation excess tax benefits
|
|
|
(2,313
|
)
|
|
|
(1,382
|
)
|
|
|
|
|
Changes in current assets and liabilities, (exclusive of effects of acquisitions and disposals):
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in customer receivables
|
|
|
(9,616
|
)
|
|
|
(7,691
|
)
|
|
|
(3,139
|
)
|
Increase in costs and estimated earnings in excess of
billings on uncompleted contracts
|
|
|
(9,205
|
)
|
|
|
(10,044
|
)
|
|
|
(432
|
)
|
(Increase) decrease in inventories
|
|
|
(1,788
|
)
|
|
|
462
|
|
|
|
3,682
|
|
(Increase) decrease in other current assets
|
|
|
602
|
|
|
|
598
|
|
|
|
(866
|
)
|
Increase in accounts payable and accrued expenses
|
|
|
27,512
|
|
|
|
27,522
|
|
|
|
1,594
|
|
Increase (decrease) in billings in excess of costs and estimated
earnings on uncompleted contracts
|
|
|
(2,648
|
)
|
|
|
12,312
|
|
|
|
3,534
|
|
Other, net
|
|
|
(2,276
|
)
|
|
|
(597
|
)
|
|
|
(1,185
|
)
|
|
Cash from continuing operations
|
|
|
80,163
|
|
|
|
74,676
|
|
|
|
40,841
|
|
Cash from discontinued operations
|
|
|
|
|
|
|
|
|
|
|
28
|
|
|
Cash from operating activities
|
|
|
80,163
|
|
|
|
74,676
|
|
|
|
40,869
|
|
|
Cash flow used in investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to property and equipment
|
|
|
(44,177
|
)
|
|
|
(36,150
|
)
|
|
|
(24,427
|
)
|
Additions to gas transportation facilities and equipment
|
|
|
(5,327
|
)
|
|
|
(12,413
|
)
|
|
|
(5,125
|
)
|
Additions to oil and gas properties
|
|
|
(18,216
|
)
|
|
|
(23,075
|
)
|
|
|
(11,084
|
)
|
Additions to mineral interests in oil and gas properties
|
|
|
(5,650
|
)
|
|
|
(3,174
|
)
|
|
|
(2,281
|
)
|
Payment of cash purchase price adjustment on prior year acquisition
|
|
|
(2,270
|
)
|
|
|
(6,120
|
)
|
|
|
|
|
Proceeds from disposal of property and equipment
|
|
|
3,333
|
|
|
|
4,646
|
|
|
|
892
|
|
Proceeds from sale of domestic affiliate
|
|
|
|
|
|
|
|
|
|
|
2,355
|
|
Proceeds from sale of mineral concession
|
|
|
|
|
|
|
920
|
|
|
|
|
|
Acquisition of businesses, net of cash acquired
|
|
|
(20,470
|
)
|
|
|
(31,305
|
)
|
|
|
(61,542
|
)
|
Acquisition of gas transportation facilities and equipment
|
|
|
|
|
|
|
|
|
|
|
(1,445
|
)
|
Acquisition of oil and gas properties and mineral interests
|
|
|
|
|
|
|
(1,988
|
)
|
|
|
(4,704
|
)
|
Deposit of cash into restricted accounts
|
|
|
(2,075
|
)
|
|
|
(4,473
|
)
|
|
|
|
|
Release of cash from restricted accounts
|
|
|
9,627
|
|
|
|
5,597
|
|
|
|
|
|
Distribution of restricted cash for prior year acquisition
|
|
|
(9,627
|
)
|
|
|
|
|
|
|
|
|
Return of capital from (investment in) affiliates
|
|
|
|
|
|
|
411
|
|
|
|
(69
|
)
|
|
Cash used in investing activities
|
|
|
(94,852
|
)
|
|
|
(107,124
|
)
|
|
|
(107,430
|
)
|
|
Cash flow from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings under revolving credit facilities
|
|
|
483,800
|
|
|
|
425,925
|
|
|
|
335,155
|
|
Repayments under revolving credit facilities
|
|
|
(575,400
|
)
|
|
|
(403,225
|
)
|
|
|
(266,255
|
)
|
Debt issuance costs
|
|
|
|
|
|
|
|
|
|
|
(605
|
)
|
Payments on promissory note
|
|
|
|
|
|
|
|
|
|
|
(1,080
|
)
|
Proceeds from public offering of common stock, net of issuance costs
|
|
|
159,879
|
|
|
|
|
|
|
|
|
|
Issuances of common stock
|
|
|
2,904
|
|
|
|
3,010
|
|
|
|
3,324
|
|
Excess tax benefit on exercise of share-based instruments
|
|
|
2,313
|
|
|
|
1,382
|
|
|
|
|
|
Contribution by minority interest
|
|
|
543
|
|
|
|
|
|
|
|
|
|
|
Cash from financing activities
|
|
|
74,039
|
|
|
|
27,092
|
|
|
|
70,539
|
|
|
Effects of exchange rate changes on cash
|
|
|
711
|
|
|
|
380
|
|
|
|
(403
|
)
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
60,061
|
|
|
|
(4,976
|
)
|
|
|
3,575
|
|
Cash and cash equivalents at beginning of year
|
|
|
13,007
|
|
|
|
17,983
|
|
|
|
14,408
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
73,068
|
|
|
$
|
13,007
|
|
|
$
|
17,983
|
|
|
See Notes to Consolidated Financial Statements.
37
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
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 2008, 2007 and 2006 were ($430,000),
$95,000 and ($290,000), 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 $33,933,000, $26,825,000 and $17,589,000
in 2008, 2007 and 2006, respectively. The lives used for the items within each property
classification are as follows:
|
|
|
|
|
|
|
Years
|
|
Buildings
|
|
|
1535
|
Machinery and equipment
|
|
|
310
|
Gas transportation facilities and equipment
|
|
|
15
|
38
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. Separate full-cost pools are established for each country in which the
Company has exploration activities. Depletion expense was $8,504,000, $4,917,000 and $2,021,000 in
2008, 2007 and 2006, 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 acquisitions as
described in Note 2 of the Notes to Consolidated Financial Statements.
39
Accrued Insurance Expense
Costs estimated to be incurred in the future for employee health and
welfare benefits, workers compensation, property and casualty insurance programs resulting from
claims which have been incurred are accrued currently. Under the terms of the 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, 2008 and 2007, 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 forecast 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)
|
|
2008
|
|
2007
|
|
2006
|
|
Income taxes
|
|
$
|
20,704
|
|
|
$
|
15,489
|
|
|
$
|
7,399
|
|
Interest
|
|
|
8,721
|
|
|
|
9,564
|
|
|
|
5,547
|
|
Supplemental Non-cash Transactions
The Company had earnings on restricted cash of $287,000 and
$252,000 for 2008 and 2007, which was treated as a non-cash item as it was restricted for the
account of the escrow beneficiaries.
In connection with the Reynolds acquisition (see Note 2), the company settled the Earnout
Amount on a discounted basis for $13,252,000, consisting of $2,270,000 in cash and 249,023 shares
of common stock (valued at $10,982,000) during the year ended January 31, 2008.
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.
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 3,000, 3,000 and 460,231 shares have been excluded from weighted average shares
in 2008, 2007 and 2006, respectively, as their effect was antidilutive.
40
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 adopted the standard using the Modified Prospective Method which required
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, income before income taxes was $2,186,000 lower for the year ended January 31,
2007, and net income was $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 had no financial impact on prior fiscal years. As
of January 31, 2008, the Company had unrecognized compensation expense of $4,813,000 to be
recognized over a weighted average period of 2.36 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 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, determined as if the SFAS 123 Method has
been applied, is presented in the following table:
|
|
|
|
|
(in thousands, except per share amounts)
|
|
2006
|
|
Net income, as reported
|
|
$
|
14,681
|
|
Deduct:
|
|
|
|
|
Total stock-based employee
compensation determined under
fair value based method for all
awards, net of income taxes of
$428
|
|
|
(681
|
)
|
|
Pro forma net income
|
|
$
|
14,000
|
|
|
Net income per share:
|
|
|
|
|
Basic as reported
|
|
$
|
1.08
|
|
|
Basic pro forma
|
|
$
|
1.03
|
|
|
Diluted as reported
|
|
$
|
1.05
|
|
|
Diluted proforma
|
|
$
|
1.00
|
|
|
Unearned Compensation
Unearned compensation expense associated with the issuance of unvested
shares is amortized on a straight-line basis as the restrictions on the stock expire. As required
by SFAS 123R, unearned compensation of $44,000, which was previously reflected as a reduction to
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, January 31, 2006
|
|
$
|
(7,442
|
)
|
|
$
|
|
|
|
$
|
(7,442
|
)
|
Period change
|
|
|
291
|
|
|
|
(1,302
|
)
|
|
|
(1,011
|
)
|
|
Balance, January 31, 2007
|
|
$
|
(7,151
|
)
|
|
$
|
(1,302
|
)
|
|
$
|
(8,453
|
)
|
Period change
|
|
|
760
|
|
|
|
706
|
|
|
|
1,466
|
|
|
Balance, January 31, 2008
|
|
$
|
(6,391
|
)
|
|
$
|
(596
|
)
|
|
$
|
(6,987
|
)
|
|
41
(2) Acquisitions
On December 31, 2007 (the Tierdael Closing Date), the Company acquired certain assets and
liabilities of Tierdael Construction (Tierdael), a pipeline and utility construction contractor
in Denver which was combined with a similar service line acquired in the acquisition of Reynolds,
Inc. The purchase price for Tierdael was $7,110,000, consisting of cash of $6,646,000, assumed
liabilities of $226,000 and costs of $238,000. The cash portion of the purchase price is subject to
certain adjustments based on the value of working capital at the closing date, settlement of which
is expected in April 2008. Any adjustment will be treated as an adjustment of the total purchase
price.
The preliminary purchase price has been allocated based on the fair value of the assets and
liabilities acquired, determined based on the Companys internal operational assessments and other
analyses. Such amounts may be subject to revision as Tierdael 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
|
|
$
|
3,983
|
|
Property and equipment
|
|
|
3,127
|
|
|
Total purchase price
|
|
$
|
7,110
|
|
|
The results of operations of Tierdael have been included in the Companys consolidated statements
of income commencing with the Tierdael Closing Date. Assuming Tierdael had been acquired as of the
beginning of each period, the unaudited pro forma consolidated revenues, net income and net income
per share would be as follows:
|
|
|
|
|
|
|
|
|
(in thousands, except per share data)
|
|
2008
|
|
2007
|
|
Revenues
|
|
$
|
890,755
|
|
|
$
|
758,310
|
|
Net income
|
|
|
38,052
|
|
|
|
28,250
|
|
Basic earnings per share
|
|
$
|
2.28
|
|
|
$
|
1.84
|
|
|
Diluted earnings per share
|
|
$
|
2.25
|
|
|
$
|
1.81
|
|
|
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.
On November 30, 2007 (the SolmeteX Closing Date), the Company acquired certain assets and
liabilities of SolmeteX, Inc. (SolmeteX), a water and wastewater research and development
business and a supplier of wastewater filtration products to the dental market. The purchase price
for SolmeteX was $13,586,000, consisting of cash of $13,500,000 and costs of $86,000. In addition,
there is contingent consideration up to a maximum of $1,000,000 (the SolmeteX Earnout Amount),
which is based on a percentage of the amount of SolmeteXs revenues during the 36 months following
the acquisition. Any portion of the SolmeteX Earnout Amount that 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 the Companys internal operational assessments, appraisals and other
analyses. Such amounts may be subject to revision as SolmeteX is integrated into the Company and
the revisions may be significant and will be recorded by the Company as further adjustments to
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
|
|
$
|
64
|
|
Property and equipment
|
|
|
115
|
|
Goodwill
|
|
|
7,270
|
|
Tradenames
|
|
|
2,962
|
|
Patents
|
|
|
2,543
|
|
Other intangible assets
|
|
|
551
|
|
Deferred income taxes
|
|
|
81
|
|
|
Total purchase price
|
|
$
|
13,586
|
|
|
Of
the $6,056,000 of acquired intangible assets, $21,000 was assigned to research and
development assets that were written off in selling, general and administrative expenses at the
date of acquisition in accordance with FASB Interpretation No. 4,
Applicability of FASB Statement
No. 2 to Business Combinations Accounted for by the Purchase
Method.
The remaining $6,035,000 of
acquired intangible assets have a weighted-average useful life of
approximately 15.4 years,
comprised of tradenames (15-year weighted-average useful life), patents (15-year weighted-average
useful life), and other assets (20-year average useful life). The $7,270,000 of goodwill was
assigned to the water infrastructure segment. Of that total amount, $7,053,000 is expected to be
deductible for tax purposes.
The results of operations of SolmeteX have been included in the Companys consolidated
statements of income commencing with the SolmeteX Closing Date. Assuming SolmeteX had been acquired
as of the beginning of each period, the unaudited pro forma consolidated revenues, net income and
net income per share would be as follows:
|
|
|
|
|
|
|
|
|
(in thousands, except per share data)
|
|
2008
|
|
|
2007
|
|
|
Revenues
|
|
$
|
872,427
|
|
|
$
|
726,575
|
|
Net income
|
|
|
36,307
|
|
|
|
25,211
|
|
Basic earnings per share
|
|
$
|
2.18
|
|
|
$
|
1.65
|
|
|
Diluted earnings per share
|
|
$
|
2.14
|
|
|
$
|
1.61
|
|
|
The pro forma information provided above is not necessarily indicative of the results of operations
that would actually have resulted if the acquisition was made as of those dates or of results that
may occur in the future. Pro forma results include adjustments for interest expense on the cash
purchase price.
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 storm water systems and was 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
42
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.
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
|
|
$
|
11,723
|
|
Property and equipment
|
|
|
13,602
|
|
Goodwill (non tax deductible)
|
|
|
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 November 20, 2006. 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 was combined with a similar service line acquired in the
acquisition of Reynolds, Inc. The purchase price for CWI was $5,442,000, consisting of $3,150,000
cash, 45,563 shares of Layne common stock (valued at $1,263,000), cash purchase price adjustments
and costs of $1,029,000 ($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.
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
|
|
$
|
1,016
|
|
Property and equipment
|
|
|
1,580
|
|
Goodwill (non tax deductible)
|
|
|
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 Reynolds 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 infrastructure division. Reynolds primary service lines
include design and building of water and wastewater treatment plants, water and wastewater
transmission lines, cured-in-place pipe (CIPP) services for sewer rehabilitation, water supply
wells and Ranney collector wells.
The purchase price for Reynolds was $112,356,000, consisting of $60,000,000 cash, 2,222,216
shares of Layne common stock (valued at $45,053,000), cash purchase price adjustments of $6,120,000
(paid in 2007) and costs of $1,183,000. Layne common stock was valued in the transaction based upon
a five-day average of the closing price of the stock two days before and two days after the terms
of the 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).
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 April and June 2007. The remainder of the Escrow Fund
was released to the Reynolds shareholders on September 30, 2007.
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.
43
Based on the Companys allocation of the purchase price, the acquisition had the following
effect on the Companys consolidated financial position as of January 31, 2006:
|
|
|
|
|
(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 $16,586,000 of acquired intangible assets have a weighted-average useful life of
approximately 30.1 years, comprised of tradenames (32-year weighted-average useful life) and other
assets (2.7-year weighted-average useful life). The $49,832,000 of goodwill was assigned to the
water infrastructure segment and is not deductible for tax purposes.
The results of operations of Reynolds have been included in the Companys consolidated
statements of income commencing with the Reynolds Closing Date. Assuming Reynolds had been acquired
as of the beginning of the year of acquisition, 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
|
|
Revenues
|
|
$
|
600,781
|
|
Net income
from continuing operations
|
|
|
17,945
|
|
Net income
|
|
|
17,941
|
|
Basic earnings per share
from continuing operations
|
|
$
|
1.19
|
|
|
Diluted earnings per share
from continuing operations
|
|
$
|
1.16
|
|
|
Basic earnings per share
|
|
$
|
1.19
|
|
|
Diluted earnings per share
|
|
$
|
1.16
|
|
|
The pro forma information provided above is not necessarily indicative of the results of operations
that would actually have resulted if the acquisition were made as of those dates or of results that
may occur in the future. Pro forma results include adjustments for interest expense on the cash
purchase price, depreciation and amortization expense on the acquisition adjustments to property
and equipment and other intangible assets and for the additional shares outstanding.
Under the terms of the purchase, there was contingent consideration up to a maximum of
$15,000,000 (the Earnout Amount), which was based on Reynolds operating performance over a period
of 36 months following the Reynolds Closing Date (the Earnout Period). During July 2007, the
Company determined that it was probable that the maximum consideration would be achieved and agreed
to settle the Earnout Amount on a discounted basis for $13,252,000, consisting of $2,270,000 in
cash and $10,982,000 of Layne common stock, valued based on the average closing price of the five
trading days ending July 31, 2007. The Company paid the cash portion of the settlement on July 31,
2007, and issued 249,023 shares of Layne common stock in August 2007 in payment of the stock
portion. The Earnout Amount has been accounted for as additional purchase consideration, and
accordingly the Company recorded $13,252,000 of additional Goodwill in July 2007.
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
|
|
|
(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, 2008:
|
|
|
|
|
|
|
Percentage
|
|
|
Owned
|
|
Christensen Chile, S.A. (Chile)
|
|
|
50.00
|
%
|
Christensen Commercial, S.A. (Chile)
|
|
|
50.00
|
|
Geotec Boyles Bros., S.A. (Chile)
|
|
|
50.00
|
|
Boyles Bros. Diamantina, S.A. (Peru)
|
|
|
29.49
|
|
Christensen Commercial, S.A. (Peru)
|
|
|
35.38
|
|
Geotec, S.A. (Peru)
|
|
|
35.38
|
|
Boytec, S.A. (Panama)
|
|
|
50.00
|
|
Plantel Industrial S.A. (Chile)
|
|
|
50.00
|
|
Boytec Sondajes de Mexico, S.A. de C.V. (Mexico)
|
|
|
50.00
|
|
Geoductos Chile, S.A. (Chile)
|
|
|
50.00
|
|
Mining Drilling Fluids (Panama)
|
|
|
25.00
|
|
Diamantina Christensen Trading (Panama)
|
|
|
42.69
|
|
Boyles Bros. do Brasil Ltd. (Brazil)
|
|
|
40.00
|
|
Boytec, S.A. (Columbia)
|
|
|
50.00
|
|
44
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, 2008, 2007 and 2006,
and for the years then ended, was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
Current assets
|
|
$
|
78,165
|
|
|
$
|
42,584
|
|
|
$
|
36,937
|
|
Noncurrent assets
|
|
|
42,682
|
|
|
|
29,696
|
|
|
|
28,866
|
|
Current liabilities
|
|
|
48,496
|
|
|
|
19,857
|
|
|
|
17,178
|
|
Noncurrent liabilities
|
|
|
9,373
|
|
|
|
4,755
|
|
|
|
5,211
|
|
Revenues
|
|
|
202,649
|
|
|
|
130,090
|
|
|
|
103,735
|
|
Gross profit
|
|
|
36,234
|
|
|
|
23,274
|
|
|
|
18,003
|
|
Operating income
|
|
|
24,074
|
|
|
|
14,319
|
|
|
|
10,828
|
|
Net income
|
|
|
18,762
|
|
|
|
10,862
|
|
|
|
9,452
|
|
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, 2008, 2007 and
2006, and for the years then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
Accounts Receivable
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Revenues
|
|
|
17
|
|
|
|
3
|
|
|
|
302
|
|
Undistributed equity in earnings of the affiliates totaled $15,190,000, $9,635,000 and $7,096,000
as of January 31, 2008, 2007 and 2006, 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 2008, 2007 or
2006. Losses from discontinued operations before income taxes for 2006 were $2,000.
45
(5) Goodwill and Other Intangible Assets
Goodwill and other intangible assets consisted of the following as of January 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
|
Gross
|
|
|
|
|
|
Gross
|
|
|
|
|
Carrying
|
|
Accumulated
|
|
Carrying
|
|
Accumulated
|
(in thousands)
|
|
Amount
|
|
Amortization
|
|
Amount
|
|
Amortization
|
|
Goodwill
|
|
$
|
85,706
|
|
|
$
|
|
|
|
$
|
65,184
|
|
|
$
|
|
|
|
Amortizable intangible assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tradenames
|
|
$
|
18,962
|
|
|
$
|
(1,464
|
)
|
|
$
|
16,000
|
|
|
$
|
(818
|
)
|
Customer-related
|
|
|
332
|
|
|
|
(340
|
)
|
|
|
332
|
|
|
|
(134
|
)
|
Patents
|
|
|
2,902
|
|
|
|
(307
|
)
|
|
|
359
|
|
|
|
(160
|
)
|
Non-competition agreements
|
|
|
379
|
|
|
|
(273
|
)
|
|
|
379
|
|
|
|
(227
|
)
|
Other
|
|
|
1,292
|
|
|
|
(553
|
)
|
|
|
762
|
|
|
|
(476
|
)
|
|
Total amortizable intangible assets
|
|
$
|
23,867
|
|
|
$
|
(2,937
|
)
|
|
$
|
17,832
|
|
|
$
|
(1,815
|
)
|
|
Amortizable intangible assets are being amortized over their estimated useful lives of two to 40
years with a weighted average amortization period of 26 years. Total amortization expense for other
intangible assets was $1,123,000, $1,068,000 and $387,000 in 2008, 2007 and 2006, respectively.
Amortization expense for the subsequent five fiscal years is estimated as follows:
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
2009
|
|
$
|
1,181
|
|
2010
|
|
|
1,095
|
|
2011
|
|
|
1,057
|
|
2012
|
|
|
1,028
|
|
2013
|
|
|
1,020
|
|
Of the total goodwill as of January 31, 2008 and 2007, $13,578,000 and $6,526,000,
respectively, is expected to be tax deductible.
The carrying amount of goodwill attributed to each operating segment was as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Water
|
|
|
|
|
Energy
|
|
Infrastructure
|
|
Total
|
|
Balance, February 1, 2006
|
|
$
|
950
|
|
|
$
|
56,907
|
|
|
$
|
57,857
|
|
Additions
|
|
|
|
|
|
|
7,327
|
|
|
|
7,327
|
|
|
Balance, January 31, 2007
|
|
|
950
|
|
|
|
64,234
|
|
|
|
65,184
|
|
Additions
|
|
|
|
|
|
|
20,522
|
|
|
|
20,522
|
|
|
Balance, January 31, 2008
|
|
$
|
950
|
|
|
$
|
84,756
|
|
|
$
|
85,706
|
|
|
46
(6) Other Income (Expense)
Other income (expense) consisted of the following for the years ended January 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
Gain (loss) from disposal of
property and equipment
|
|
$
|
671
|
|
|
$
|
994
|
|
|
$
|
(295
|
)
|
Gain on sale of domestic affiliate
|
|
|
|
|
|
|
|
|
|
|
1,289
|
|
Gain on sale of mineral concession
|
|
|
|
|
|
|
920
|
|
|
|
|
|
Interest income
|
|
|
953
|
|
|
|
187
|
|
|
|
133
|
|
Exchange gain (loss)
|
|
|
(430
|
)
|
|
|
95
|
|
|
|
(290
|
)
|
Miscellaneous, net
|
|
|
35
|
|
|
|
361
|
|
|
|
63
|
|
|
Total
|
|
$
|
1,229
|
|
|
$
|
2,557
|
|
|
$
|
900
|
|
|
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).
(7) Costs and Estimated Earnings on Uncompleted Contracts:
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2008
|
|
2007
|
|
Costs incurred on uncompleted contracts
|
|
$
|
586,459
|
|
|
$
|
711,922
|
|
Estimated earnings
|
|
|
147,796
|
|
|
|
155,520
|
|
|
|
|
|
734,255
|
|
|
|
867,442
|
|
Less: Billings to date
|
|
|
705,100
|
|
|
|
850,474
|
|
|
Total
|
|
$
|
29,155
|
|
|
$
|
16,968
|
|
|
Included in accompanying balance sheets
under the following captions:
|
|
|
|
|
|
|
|
|
Costs and estimated earnings in excess
of billings on uncompleted
contracts
|
|
$
|
60,796
|
|
|
$
|
51,210
|
|
Billings in excess of costs and estimated
earnings on uncompleted contracts
|
|
|
(31,641
|
)
|
|
|
(34,242
|
)
|
|
Total
|
|
$
|
29,155
|
|
|
$
|
16,968
|
|
|
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, 2008 and 2007, the Company held unbilled contract
retainage amounts of $33,201,000 and $26,652,000, respectively.
(8) Income Taxes
Income (loss) from continuing operations before income taxes is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
Domestic
|
|
$
|
46,649
|
|
|
$
|
31,928
|
|
|
$
|
21,039
|
|
Foreign
|
|
|
20,640
|
|
|
|
16,239
|
|
|
|
6,817
|
|
|
Total
|
|
$
|
67,289
|
|
|
$
|
48,167
|
|
|
$
|
27,856
|
|
|
Components of income tax expense are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
Currently due:
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal
|
|
$
|
17,226
|
|
|
$
|
13,150
|
|
|
$
|
3,536
|
|
State and local
|
|
|
3,125
|
|
|
|
2,541
|
|
|
|
462
|
|
Foreign
|
|
|
7,099
|
|
|
|
8,615
|
|
|
|
3,785
|
|
|
|
|
|
27,450
|
|
|
|
24,306
|
|
|
|
7,783
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal
|
|
|
1,632
|
|
|
|
(941
|
)
|
|
|
4,100
|
|
State and local
|
|
|
288
|
|
|
|
(649
|
)
|
|
|
372
|
|
Foreign
|
|
|
808
|
|
|
|
(801
|
)
|
|
|
866
|
|
|
|
|
|
2,728
|
|
|
|
(2,391
|
)
|
|
|
5,338
|
|
|
Total
|
|
$
|
30,178
|
|
|
$
|
21,915
|
|
|
$
|
13,121
|
|
|
47
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)
|
|
2008
|
|
2007
|
|
|
Assets
|
|
Liabilities
|
|
Total
|
|
Assets
|
|
Liabilities
|
|
Total
|
|
Contract income
|
|
$
|
4,545
|
|
|
$
|
|
|
|
$
|
4,545
|
|
|
$
|
4,372
|
|
|
$
|
|
|
|
$
|
4,372
|
|
Inventories
|
|
|
2,125
|
|
|
|
(271
|
)
|
|
|
1,854
|
|
|
|
1,956
|
|
|
|
(164
|
)
|
|
|
1,792
|
|
Accrued insurance
|
|
|
2,809
|
|
|
|
|
|
|
|
2,809
|
|
|
|
2,600
|
|
|
|
|
|
|
|
2,600
|
|
Other accrued liabilities
|
|
|
2,234
|
|
|
|
|
|
|
|
2,234
|
|
|
|
2,382
|
|
|
|
|
|
|
|
2,382
|
|
Prepaid expenses
|
|
|
|
|
|
|
(684
|
)
|
|
|
(684
|
)
|
|
|
|
|
|
|
(619
|
)
|
|
|
(619
|
)
|
Bad debts
|
|
|
2,866
|
|
|
|
|
|
|
|
2,866
|
|
|
|
2,521
|
|
|
|
|
|
|
|
2,521
|
|
Employee compensation
|
|
|
4,905
|
|
|
|
|
|
|
|
4,905
|
|
|
|
3,361
|
|
|
|
|
|
|
|
3,361
|
|
Other
|
|
|
481
|
|
|
|
(299
|
)
|
|
|
182
|
|
|
|
481
|
|
|
|
(339
|
)
|
|
|
142
|
|
|
Total current
|
|
|
19,965
|
|
|
|
(1,254
|
)
|
|
|
18,711
|
|
|
|
17,673
|
|
|
|
(1,122
|
)
|
|
|
16,551
|
|
|
Cumulative translation adjustment
|
|
|
4,665
|
|
|
|
|
|
|
|
4,665
|
|
|
|
5,088
|
|
|
|
|
|
|
|
5,088
|
|
Buildings, machinery and equipment
|
|
|
440
|
|
|
|
(16,251
|
)
|
|
|
(15,811
|
)
|
|
|
126
|
|
|
|
(16,554
|
)
|
|
|
(16,428
|
)
|
Gas transportation facilities and equipment
|
|
|
|
|
|
|
(3,799
|
)
|
|
|
(3,799
|
)
|
|
|
|
|
|
|
(2,270
|
)
|
|
|
(2,270
|
)
|
Mineral interests and oil and gas properties
|
|
|
|
|
|
|
(14,702
|
)
|
|
|
(14,702
|
)
|
|
|
|
|
|
|
(11,779
|
)
|
|
|
(11,779
|
)
|
Intangible assets
|
|
|
744
|
|
|
|
(5,788
|
)
|
|
|
(5,044
|
)
|
|
|
747
|
|
|
|
(6,072
|
)
|
|
|
(5,325
|
)
|
Tax deductible goodwill
|
|
|
2,831
|
|
|
|
|
|
|
|
2,831
|
|
|
|
3,448
|
|
|
|
|
|
|
|
3,448
|
|
Accrued insurance
|
|
|
3,988
|
|
|
|
|
|
|
|
3,988
|
|
|
|
3,384
|
|
|
|
|
|
|
|
3,384
|
|
Pension
|
|
|
781
|
|
|
|
(689
|
)
|
|
|
92
|
|
|
|
673
|
|
|
|
(331
|
)
|
|
|
342
|
|
Stock-based compensation
|
|
|
1,352
|
|
|
|
|
|
|
|
1,352
|
|
|
|
633
|
|
|
|
|
|
|
|
633
|
|
Unremitted foreign earnings
|
|
|
|
|
|
|
(3,036
|
)
|
|
|
(3,036
|
)
|
|
|
|
|
|
|
(1,587
|
)
|
|
|
(1,587
|
)
|
Other
|
|
|
1,230
|
|
|
|
(95
|
)
|
|
|
1,135
|
|
|
|
1,430
|
|
|
|
(238
|
)
|
|
|
1,192
|
|
|
Total noncurrent
|
|
|
16,031
|
|
|
|
(44,360
|
)
|
|
|
(28,329
|
)
|
|
|
15,529
|
|
|
|
(38,831
|
)
|
|
|
(23,302
|
)
|
|
Total
|
|
$
|
35,996
|
|
|
$
|
(45,614
|
)
|
|
$
|
(9,618
|
)
|
|
$
|
33,202
|
|
|
$
|
(39,953
|
)
|
|
$
|
(6,751
|
)
|
|
48
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 $1,300,000 that expire
between 2013 and 2021.
As of January 31, 2008, undistributed earnings of foreign subsidiaries and certain foreign
affiliates included $33,400,000 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
|
|
|
|
|
Effective
|
|
|
|
|
|
Effective
|
|
|
|
|
|
Effective
|
(in thousands)
|
|
Amount
|
|
Rate
|
|
Amount
|
|
Rate
|
|
Amount
|
|
Rate
|
|
Income tax at statutory rate
|
|
$
|
23,551
|
|
|
|
35.0
|
%
|
|
$
|
16,858
|
|
|
|
35.0
|
%
|
|
$
|
9,750
|
|
|
|
35.0
|
%
|
State income tax, net
|
|
|
2,219
|
|
|
|
3.3
|
|
|
|
1,230
|
|
|
|
2.6
|
|
|
|
542
|
|
|
|
1.9
|
|
Difference in tax expense resulting from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nondeductible expenses
|
|
|
1,041
|
|
|
|
1.5
|
|
|
|
842
|
|
|
|
1.8
|
|
|
|
593
|
|
|
|
2.1
|
|
Taxes on foreign affiliates
|
|
|
(1,370
|
)
|
|
|
(2.0
|
)
|
|
|
(774
|
)
|
|
|
(1.6
|
)
|
|
|
(422
|
)
|
|
|
(1.5
|
)
|
Taxes on foreign operations
|
|
|
5,033
|
|
|
|
7.5
|
|
|
|
3,461
|
|
|
|
7.2
|
|
|
|
2,641
|
|
|
|
9.5
|
|
Other, net
|
|
|
(296
|
)
|
|
|
(0.5
|
)
|
|
|
298
|
|
|
|
0.5
|
|
|
|
17
|
|
|
|
0.1
|
|
|
|
|
$
|
30,178
|
|
|
|
44.8
|
%
|
|
$
|
21,915
|
|
|
|
45.5
|
%
|
|
$
|
13,121
|
|
|
|
47.1
|
%
|
|
The Company adopted the provisions of FASB Interpretation No. 48, Accounting for
Uncertainty in Income Taxes, an interpretation of FASB Statement 109 (FIN 48), effective
February 1, 2007. The interpretation clarifies the accounting for uncertainty in income taxes
recognized in an entitys financial statements. FIN 48 prescribes a more-likely-than-not threshold
for financial statement recognition and measurement of a tax position taken or expected to be taken
in a tax return.
The Companys adoption of FIN 48 resulted in a cumulative effect adjustment increasing
retained earnings by $465,000 as of February 1, 2007. Prior to the adoption of FIN 48, the Company
classified income tax uncertainties as current liabilities. Upon adoption of FIN 48, approximately
$4,600,000 was reclassified to non-current liabilities because the resolution of those tax
uncertainties was not expected to be resolved within 12 months.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as
follows:
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
Balance, February 1, 2007
|
|
$
|
6,152
|
|
Additions based on tax
positions related
to current year
|
|
|
3,248
|
|
Additions for tax positions of
prior years
|
|
|
772
|
|
Impact of changes in exchange
rate
|
|
|
79
|
|
Settlements with tax
authorities
|
|
|
(162
|
)
|
Reductions for tax positions
of prior years
|
|
|
(2,995
|
)
|
Reductions due to the lapse of
statute of
limitations
|
|
|
(452
|
)
|
|
Balance, January 31, 2008
|
|
$
|
6,642
|
|
|
Substantially all of the unrecognized tax benefits recorded at January 31, 2008, and February
1, 2007, would affect the effective rate if recognized. It is expected that the amount of
unrecognized tax benefits will change during the next year; however, the Company does not expect
the change to have a significant impact on its results of operations or financial position.
The Company classifies interest and penalties related to income taxes as a component of income
tax expense, which is consistent with the recognition of these items in prior years. As of February
1, 2007, the Company had $1,782,000 of interest and penalties accrued associated with unrecognized
tax benefits. The liability of interest and penalties increased $970,000 during the year ended
January 31, 2008, to $2,752,000.
The Company files income tax returns in the U.S. federal jurisdiction, various state
jurisdictions and certain foreign jurisdictions. The Company settled IRS examinations during the
year ended January 31, 2008, relating to the tax years ended January 31, 1999 through 2003. The
examinations did not result in material adjustments. The statue of limitations expired for the tax
year ended January 31, 2004, during the year ended January 31, 2008. The Company is not currently
under IRS examination for its remaining open tax years, and the statue of limitations will expire
for those years between 2008 through 2010. The Company is not currently under examination by any
state or local jurisdictions. The state and
local tax years open to examination will close between 2008 and 2011.
The Company files tax returns in the foreign jurisdictions where it operates. The returns are
subject to examination and numerous tax audits may be ongoing at any point in time. Tax liabilities
are recorded based on estimates of additional taxes which will be due upon settlement of those
audits. The tax years subject to examination by foreign tax authorities vary by jurisdiction, but
generally the tax years 2003 through 2008 remain open to examination.
49
(9) Operating
Leases and Other Obligations
Future minimum rental payments required under operating leases that have initial or remaining
noncancelable lease terms in excess of one year from January 31, 2008, are as follows:
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
2009
|
|
$
|
10,543
|
|
2010
|
|
|
6,257
|
|
2011
|
|
|
4,870
|
|
2012
|
|
|
3,940
|
|
2013
|
|
|
2,777
|
|
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
$27,977,000, $22,866,000 and $14,603,000 in 2008, 2007 and 2006, respectively.
Asset
retirement obligations consist of the estimated costs of dismantlement, removal, site
reclamation and similar activities associated with our oil and gas properties. An asset retirement
obligation and the related asset retirement cost are recorded when a well is drilled and completed.
The asset retirement cost is determined based on the expected costs to complete the reclamation at
the end of the wells economic life, discounted to its present value using a credit-adjusted
risk-free rate. After initial recording, the liability is increased for the passage of time, with
the increase being reflected in the consolidated statements of income as depreciation, depletion
and amortization. Asset retirement costs are capitalized as part of oil and gas properties and
depleted accordingly. Additions to the asset retirement obligations during the years ended January
31, 2008, 2007 and 2006 were $170,000, $243,000 and $224,000, respectively. Accretion during the
same periods was $60,000, $43,000 and $27,000, respectively. The carrying value of the asset
retirement obligations as of January 31, 2008 was $1,043,000, and is recorded in Other Long Term
Liabilities.
(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, ceased accrual of benefits 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 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 statements of income for any period presented. See Note
16 for discussion of further provisions of SFAS 158 which will be required to be adopted in the
year ended January 31, 2009.
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, 2007 and 2006 (the
measurement dates) and the amounts recognized in the Companys Consolidated Balance Sheets at
January 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2008
|
|
2007
|
|
Change in benefit obligation:
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year
|
|
$
|
8,191
|
|
|
$
|
7,967
|
|
Service cost
|
|
|
|
|
|
|
|
|
Interest cost
|
|
|
450
|
|
|
|
452
|
|
Actuarial gain (loss)
|
|
|
(902
|
)
|
|
|
164
|
|
Benefits paid
|
|
|
(413
|
)
|
|
|
(392
|
)
|
|
Benefit obligation at end of year
|
|
|
7,326
|
|
|
|
8,191
|
|
|
Change in plan assets:
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year
|
|
|
9,049
|
|
|
|
8,108
|
|
Actual return on plan assets
|
|
|
473
|
|
|
|
833
|
|
Employer contribution
|
|
|
|
|
|
|
500
|
|
Benefits paid
|
|
|
(413
|
)
|
|
|
(392
|
)
|
|
Fair value of plan assets at end of year
|
|
|
9,109
|
|
|
|
9,049
|
|
|
Funded status
|
|
|
1,783
|
|
|
|
858
|
|
Contributions between measurement
date and year-end
|
|
|
|
|
|
|
|
|
|
Net amount recognized as other
non-current assets
|
|
$
|
1,783
|
|
|
$
|
858
|
|
|
50
Net periodic pension cost for 2008, 2007 and 2006 includes the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
Service cost and expenses
|
|
$
|
96
|
|
|
$
|
86
|
|
|
$
|
74
|
|
Interest cost
|
|
|
450
|
|
|
|
452
|
|
|
|
436
|
|
Expected return on assets
|
|
|
(536
|
)
|
|
|
(529
|
)
|
|
|
(484
|
)
|
Net amortization
|
|
|
215
|
|
|
|
271
|
|
|
|
278
|
|
|
Net periodic pension cost
|
|
$
|
225
|
|
|
$
|
280
|
|
|
$
|
304
|
|
|
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 2009 is $120,000.
The weighted average assumptions used to determine the benefit obligation and the net periodic
pension cost for the years ending January 31, 2008, 2007 and 2006, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
Discount rate
|
|
|
6.49
|
%
|
|
|
5.90
|
%
|
|
|
5.67
|
%
|
Expected long-term return
on plan assets
|
|
|
7.0
|
%
|
|
|
7.0
|
%
|
|
|
7.0
|
%
|
Rate of compensation increase
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Health care cost trend
on covered charges
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Market-related value of assets
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Expected return on assets
|
|
Smoothed value
|
|
Smoothed value
|
|
Smoothed value
|
The estimated long-term rate of return on assets was developed based on the historical returns and
the future expectations for returns for each asset class, as well as the target asset allocation of
the pension portfolio. Benefit level assumptions for 2008, 2007 and 2006 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,
|
|
|
2007
|
|
2006
|
|
Equity securities
|
|
|
60
|
%
|
|
|
63
|
%
|
Debt securities
|
|
|
13
|
|
|
|
35
|
|
Cash and cash equivalents
|
|
|
27
|
|
|
|
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.
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 10 years)
and a maximum permitted maturity for an individual issue
of 15 years.
|
As of December 31, 2007, in response to changing market conditions, the investment manager
sought to minimize portfolio risk with asset allocations to cash and cash equivalents from debt
securities outside of the established policy range, as allowed by the discretion granted to the
investment by the Company. The percentage of the fair value of total plan assets for each major
category of plan assets is expected to return to amounts within the established policy range during
2009.
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, 2008, plan year.
The Company does not expect to make contributions to the plan during the 2008 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:
51
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
2009
|
|
$
|
424
|
|
2010
|
|
|
436
|
|
2011
|
|
|
451
|
|
2012
|
|
|
467
|
|
2013
|
|
|
477
|
|
2014-2018
|
|
|
2,467
|
|
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, 2008 and 2007, were $2,021,000 and
$1,742,000. Net periodic pension cost of the supplemental retirement benefits for 2008, 2007 and
2006 include the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
Service cost
|
|
$
|
176
|
|
|
$
|
100
|
|
|
$
|
120
|
|
Interest cost
|
|
|
103
|
|
|
|
88
|
|
|
|
75
|
|
|
Net periodic pension cost
|
|
$
|
279
|
|
|
$
|
188
|
|
|
$
|
195
|
|
|
The Company also participates in a number of defined benefit, multi-employer plans. These plans are
union-sponsored, and the Company makes contributions equal to the amounts accrued for pension
expense. Total union pension expense for these plans was $2,961,000, $3,062,000 and $2,009,000 in
2008, 2007 and 2006, 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 $3,777,000,
$2,996,000 and $2,588,000 in 2008, 2007 and 2006, 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 2008 and 2007
was $2,237,000 and $1,257,000. The total liability for deferred
compensation was $3,500,946, $1,498,804, and $59,158 as of
January 31, 2008, 2007, and 2006, respectively.
(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. 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. As of October 15, 2007, the Company amended
the Master Shelf Agreement to increase the amount of senior notes available to be issued to
$105,000,000, which created an available facility amount of $45,000,000, and reinstated and
extended the available issuance period to September 15, 2009. The Company also maintains a
revolving credit facility under 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 contains a revolving loan
commitment of $200,000,000, less any outstanding letter of credit commitments (which are subject to
a $30,000,000 sublimit). 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, 2008, there were letters of credit of $12,716,000 and
no borrowings outstanding on the Credit Agreement resulting in available capacity of $187,284,000.
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, 2008.
Maximum borrowings outstanding under the Companys then-existing credit agreements during 2008
and 2007 were $186,000,000 and $155,000,000, respectively, and the average outstanding borrowings
were $127,300,000 and $141,850,000, respectively. The weighted average interest rates were 6.7% and
6.7%, respectively.
Loan costs incurred for securing long-term financing are amortized using a method that
approximates the effective interest method over the term of the respective loan agreement.
Amortization of these costs for 2008, 2007 and 2006 was $169,000, $161,000 and $96,000,
respectively. Amortization of loan costs is included in interest expense in the consolidated
statements of income.
Debt outstanding as of January 31, 2008 and 2007, whose carrying value approximates fair
market value, was as follows:
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2008
|
|
2007
|
|
Long-term debt:
|
|
|
|
|
|
|
|
|
Credit Agreement
|
|
$
|
|
|
|
$
|
91,600
|
|
Senior Notes
|
|
|
60,000
|
|
|
|
60,000
|
|
|
Total debt
|
|
|
60,000
|
|
|
|
151,600
|
|
Less current maturities
|
|
|
(13,333
|
)
|
|
|
|
|
|
Total long-term debt
|
|
$
|
46,667
|
|
|
$
|
151,600
|
|
|
52
As of January 31, 2008, debt outstanding will mature by fiscal year as follows:
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
2009
|
|
$
|
13,333
|
|
2010
|
|
|
20,000
|
|
2011
|
|
|
20,000
|
|
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, 2008, the Company had committed to deliver 4,190,000 million
British Thermal Units (MMBtu) of natural gas through March 2010 at prices ranging from $7.49 to
$9.05 per MMBtu through March 2008, and $7.64 per MMBtu from April 2008 to March 2010.
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, 2008, was a loss of
$99,000.
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
with forecast expatriate labor
costs and purchases of operating supplies. As of January 31, 2008 and 2007, there were no such
instruments outstanding. The Company does not enter into foreign currency derivative financial
instruments for speculative or trading purposes.
(13) Stock and Stock Option Plans
In October 2007, the Company completed a public stock offering of 3,105,000 common shares.
Proceeds of the offering, net of issuance costs of $9,344,000, were $159,879,000.
In October 1998, the Company adopted a Rights Agreement whereby the Company has authorized and
declared a dividend of one preferred share purchase right (Right) for each outstanding common
share of the Company. Subject to limited exceptions, the Rights are exercisable if a person or
group acquires or announces a tender offer for 25% or more of the Companys common stock. Each
Right will entitle shareholders to buy one one-hundredth of a share of a newly created Series A
Junior Participating Preferred Stock of the Company at an exercise price of $45.00. The Company is
entitled to redeem the Right at $.01 per Right at any time before a person has acquired 25% or more
of the Companys outstanding common stock. The Rights expire 10 years from the date of grant.
The Company has 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 1,450,000
shares of common stock at a price fixed by the Board of Directors or a committee. As of January 31,
2008, there were 586,000 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.
The Company recognized $638,000 and $10,000 in compensation cost of nonvested shares for the
years ended January 31, 2008 and 2007, respectively. A summary of nonvested share activity for
2008, 2007 and 2006 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
Aggregate
|
|
|
|
|
|
|
Average
|
|
Intrinsic
|
|
|
Number of
|
|
Grant Date
|
|
Value (in
|
|
|
Shares
|
|
Fair Value
|
|
thousands)
|
|
Nonvested stock at
January 31, 2005
|
|
|
24,576
|
|
|
$
|
15.26
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested
|
|
|
(10,244
|
)
|
|
|
15.26
|
|
|
|
|
|
Canceled
|
|
|
(5,734
|
)
|
|
|
15.26
|
|
|
|
|
|
|
|
|
|
|
Nonvested stock at
January 31, 2006
|
|
|
8,598
|
|
|
|
15.26
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
1,000
|
|
|
|
29.70
|
|
|
|
|
|
Vested
|
|
|
(8,598
|
)
|
|
|
15.26
|
|
|
|
|
|
|
|
|
|
|
Nonvested stock at
January 31, 2007
|
|
|
1,000
|
|
|
$
|
29.70
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
73,863
|
|
|
|
42.76
|
|
|
|
|
|
Vested
|
|
|
(1,000
|
)
|
|
|
29.70
|
|
|
|
|
|
|
Nonvested stock at
January 31, 2008
|
|
|
73,863
|
|
|
$
|
42.76
|
|
|
$
|
3,159
|
|
|
Significant option groups outstanding at January 31, 2008, and related exercise price and
remaining contractual term follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contractual
|
Grant
|
|
Options
|
|
Options
|
|
Exercise
|
|
Term
|
Date
|
|
Outstanding
|
|
Exercisable
|
|
Price
|
|
(Months)
|
|
4/98
|
|
|
736
|
|
|
|
736
|
|
|
$
|
10.290
|
|
|
|
3
|
|
4/99
|
|
|
9,773
|
|
|
|
9,773
|
|
|
|
4.125
|
|
|
|
15
|
|
4/99
|
|
|
24,875
|
|
|
|
24,875
|
|
|
|
5.250
|
|
|
|
15
|
|
2/00
|
|
|
3,500
|
|
|
|
3,500
|
|
|
|
5.500
|
|
|
|
25
|
|
4/00
|
|
|
14,794
|
|
|
|
14,794
|
|
|
|
3.495
|
|
|
|
27
|
|
6/04
|
|
|
25,000
|
|
|
|
25,000
|
|
|
|
16.600
|
|
|
|
77
|
|
6/04
|
|
|
159,791
|
|
|
|
101,041
|
|
|
|
16.650
|
|
|
|
77
|
|
6/05
|
|
|
12,000
|
|
|
|
12,000
|
|
|
|
17.540
|
|
|
|
89
|
|
9/05
|
|
|
201,250
|
|
|
|
76,250
|
|
|
|
23.050
|
|
|
|
92
|
|
1/06
|
|
|
210,231
|
|
|
|
95,116
|
|
|
|
27.870
|
|
|
|
96
|
|
6/06
|
|
|
12,000
|
|
|
|
12,000
|
|
|
|
29.290
|
|
|
|
101
|
|
6/06
|
|
|
70,000
|
|
|
|
17,500
|
|
|
|
29.290
|
|
|
|
101
|
|
6/07
|
|
|
70,000
|
|
|
|
|
|
|
|
42.260
|
|
|
|
113
|
|
7/07
|
|
|
33,000
|
|
|
|
|
|
|
|
42.760
|
|
|
|
114
|
|
9/07
|
|
|
3,000
|
|
|
|
|
|
|
|
55.480
|
|
|
|
116
|
|
|
|
|
|
849,950
|
|
|
|
392,585
|
|
|
|
|
|
|
|
|
|
|
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 10 years from the date of
grant and generally vest ratably over periods of four to
53
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 2008 and 2007 was $20.82 and $12.68, respectively. The fair value was based on an expected
life of six years, no dividend yield, an average interest rate of 4.79% and 4.95%, respectively,
and assumed volatility of 38% and 35%, respectively.
For purposes of pro forma disclosure, the weighted average fair value at the date of grant for
options granted during 2006 was $10.47 per option. 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 3.97% and assumed
volatility of 34%.
Transactions for stock options for 2008, 2007 and 2006 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, 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at
January 31, 2007
|
|
|
413,356
|
|
|
$
|
15.202
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
106,000
|
|
|
|
42.790
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(215,106
|
)
|
|
|
13.632
|
|
|
|
|
|
|
|
6,890
|
|
Canceled
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(3,750
|
)
|
|
|
16.650
|
|
|
|
|
|
|
|
151
|
|
Expired
|
|
|
(723
|
)
|
|
|
11.400
|
|
|
|
|
|
|
|
19
|
|
|
Outstanding at
January 31, 2008
|
|
|
849,950
|
|
|
$
|
24.541
|
|
|
|
7.36
|
|
|
$
|
13,955
|
|
|
Exercisable at
January 31, 2008
|
|
|
392,585
|
|
|
$
|
19.944
|
|
|
|
6.56
|
|
|
$
|
8,250
|
|
|
(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 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) 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
infrastructure division. The Companys segments are defined as follows:
54
Water 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. This
division has been primarily concentrated on projects in the mid-continent region of the United
States; however, in fiscal 2008 the division began an exploration project in Chile.
Other
Other includes two small specialty energy service companies and any other specialty operations not
included in one of the other divisions.
55
Financial information for the Companys 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 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 a 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,
|
|
2008
|
|
2007
|
|
2006
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Water infrastructure
|
|
$
|
639,584
|
|
|
$
|
531,916
|
|
|
$
|
320,996
|
|
Mineral exploration
|
|
|
178,482
|
|
|
|
148,911
|
|
|
|
124,206
|
|
Energy
|
|
|
39,749
|
|
|
|
27,081
|
|
|
|
12,536
|
|
Other
|
|
|
10,459
|
|
|
|
14,860
|
|
|
|
5,277
|
|
|
Total revenues
|
|
$
|
868,274
|
|
|
$
|
722,768
|
|
|
$
|
463,015
|
|
|
Equity in earnings of affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
Water infrastructure
|
|
$
|
|
|
|
$
|
|
|
|
$
|
839
|
|
Mineral exploration
|
|
|
8,076
|
|
|
|
4,452
|
|
|
|
3,506
|
|
|
Total equity in earnings of affiliates
|
|
$
|
8,076
|
|
|
$
|
4,452
|
|
|
$
|
4,345
|
|
|
Income from continuing operations before income taxes and minority interests
|
|
|
|
|
|
|
|
|
|
|
|
|
Water infrastructure
|
|
$
|
42,995
|
|
|
$
|
35,000
|
|
|
$
|
28,255
|
|
Mineral exploration
|
|
|
37,452
|
|
|
|
26,557
|
|
|
|
13,947
|
|
Energy
|
|
|
13,075
|
|
|
|
10,680
|
|
|
|
2,891
|
|
Other
|
|
|
3,696
|
|
|
|
4,094
|
|
|
|
1,307
|
|
Unallocated corporate expenses
|
|
|
(21,199
|
)
|
|
|
(18,383
|
)
|
|
|
(12,771
|
)
|
Interest
|
|
|
(8,730
|
)
|
|
|
(9,781
|
)
|
|
|
(5,773
|
)
|
|
Total income from continuing operations before income taxes and minority interests
|
|
$
|
67,289
|
|
|
$
|
48,167
|
|
|
$
|
27,856
|
|
|
|
Investment in affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
Water infrastructure
|
|
$
|
|
|
|
$
|
|
|
|
$
|
411
|
|
Mineral exploration
|
|
|
29,835
|
|
|
|
24,280
|
|
|
|
21,330
|
|
|
Total investment in affiliates
|
|
$
|
29,835
|
|
|
$
|
24,280
|
|
|
$
|
21,741
|
|
|
Total assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Water infrastructure
|
|
$
|
388,491
|
|
|
$
|
321,406
|
|
|
$
|
297,928
|
|
Mineral exploration
|
|
|
110,064
|
|
|
|
89,826
|
|
|
|
85,110
|
|
Energy
|
|
|
112,363
|
|
|
|
91,552
|
|
|
|
55,080
|
|
Other
|
|
|
2,449
|
|
|
|
4,112
|
|
|
|
1,546
|
|
Corporate
|
|
|
83,588
|
|
|
|
40,268
|
|
|
|
9,671
|
|
|
Total assets
|
|
$
|
696,955
|
|
|
$
|
547,164
|
|
|
$
|
449,335
|
|
|
Capital expenditures
|
|
|
|
|
|
|
|
|
|
|
|
|
Water infrastructure
|
|
$
|
22,029
|
|
|
$
|
23,777
|
|
|
$
|
10,640
|
|
Mineral exploration
|
|
|
18,451
|
|
|
|
11,607
|
|
|
|
13,525
|
|
Energy
|
|
|
30,345
|
|
|
|
40,737
|
|
|
|
24,639
|
|
Other
|
|
|
1,037
|
|
|
|
483
|
|
|
|
69
|
|
Corporate
|
|
|
1,508
|
|
|
|
196
|
|
|
|
193
|
|
|
Total capital expenditures
|
|
$
|
73,370
|
|
|
$
|
76,800
|
|
|
$
|
49,066
|
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
Water infrastructure
|
|
$
|
21,978
|
|
|
$
|
17,691
|
|
|
$
|
10,604
|
|
Mineral exploration
|
|
|
10,523
|
|
|
|
8,260
|
|
|
|
6,306
|
|
Energy
|
|
|
10,704
|
|
|
|
6,531
|
|
|
|
2,703
|
|
Other
|
|
|
237
|
|
|
|
229
|
|
|
|
273
|
|
Corporate
|
|
|
178
|
|
|
|
142
|
|
|
|
138
|
|
|
Total depreciation, depletion and amortization
|
|
$
|
43,620
|
|
|
$
|
32,853
|
|
|
$
|
20,024
|
|
|
56
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
As of and for the Year Ended January 31,
|
|
2008
|
|
2007
|
|
2006
|
|
Geographic information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
712,098
|
|
|
$
|
595,959
|
|
|
$
|
356,899
|
|
Australia/Africa
|
|
|
89,739
|
|
|
|
78,640
|
|
|
|
71,594
|
|
Mexico
|
|
|
42,242
|
|
|
|
32,749
|
|
|
|
22,345
|
|
Other foreign
|
|
|
24,195
|
|
|
|
15,420
|
|
|
|
12,177
|
|
|
Total revenues
|
|
$
|
868,274
|
|
|
$
|
722,768
|
|
|
$
|
463,015
|
|
|
Property and equipment, net
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
218,047
|
|
|
$
|
191,797
|
|
|
$
|
137,162
|
|
Africa/Australia
|
|
|
19,530
|
|
|
|
16,655
|
|
|
|
17,486
|
|
Mexico
|
|
|
8,555
|
|
|
|
5,279
|
|
|
|
3,104
|
|
Other foreign
|
|
|
1,235
|
|
|
|
786
|
|
|
|
373
|
|
|
Total property and equipment, net
|
|
$
|
247,367
|
|
|
$
|
214,517
|
|
|
$
|
158,125
|
|
|
(16) New Accounting Pronouncements
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 prescribes a
more-likely-than-not threshold for financial statement recognition and measurement of a tax
position taken or expected to be taken in a tax return. FIN 48 also provides guidance on
derecognition of income tax assets or liabilities, classification of current and deferred income
tax assets and liabilities, accounting for interest and penalties associated with tax positions,
accounting for income taxes in interim periods and income tax disclosures. The Company adopted the
provisions of FIN 48 as of February 1, 2007. The cumulative effects of applying FIN 48 have been
recorded as an increase to retained earnings and a decrease to income taxes payable of $465,000 as
of February 1, 2007.
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
with the cumulative effect of the change in accounting principles recorded as an adjustment to
opening retained earnings. 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
has elected to apply the transition option under which a 13-month measurement was determined as of
December 31, 2007 that covers the period until the fiscal year-end measurement is required on
January 31, 2009. As a result, the Company estimates it will record an approximate $44,000 decrease
to retained earnings in the fiscal year ending January 31, 2009.
In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and
Financial Liabilities including an amendment of FASB Statement No. 115 (SFAS 159). SFAS 159
permits the measurement of specified financial instruments and warranty and insurance contracts at
fair value on a contract-by-contract basis, with changes in fair value recognized in earnings each
reporting period. The Company will be required to adopt this standard in the first quarter of the
fiscal year ending January 31, 2009. The Company does not anticipate that adoption of this
statement will have a material impact on the consolidated financial statements.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (SFAS
141R). SFAS 141R establishes principles and requirements for how an acquirer recognizes and
measures in its financial statements the identifiable assets acquired, the liabilities assumed, any
noncontrolling interest in the acquiree and the goodwill acquired. SFAS 141R also establishes
disclosure requirements to enable the evaluation of the nature and financial effects of the
business combination. The Company will be required to adopt this standard in the first quarter of
the fiscal year ending January 31, 2010. The Company is currently evaluating the potential impact,
if any, of the adoption of SFAS 141R on our consolidated results of operations and financial
condition.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statement an amendment of Accounting Research Bulletin No. 51 (SFAS 160). SFAS 160
required noncontrolling interests, previously referred to as minority interests, to be treated as a
separate component of equity, not as a liability or other item outside of permanent equity and
applies to the accounting for noncontrolling interest holders in consolidated financial statements.
The Company will be required to adopt this standard in the first quarter of the fiscal year ending
January 31, 2010. The Company does not anticipate that the adoption of SFAS 160 will have a
material impact on its results of operations and financial condition.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and
Hedging Activities an amendment of FASB Statement No. 133 (SFAS 161). SFAS 161 requires
qualitative disclosures about objectives
57
and strategies for using derivatives, quantitative disclosures about fair value amounts of and
gains and losses on derivative instruments, and disclosures about credit-risk-related contingent
features in derivative agreements. The Company will be required to adopt this standard in the first
quarter of the fiscal year ending January 31, 2010. The Company is currently evaluating the
potential impact, if any, of the adoption of SFAS 161, on our consolidated results of operations
and financial condition.
(17) Quarterly Results (Unaudited)
Unaudited quarterly financial data are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands of dollars, except per share data)
|
|
|
|
|
|
|
|
|
2008:
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
Revenues
|
|
$
|
201,615
|
|
|
$
|
217,844
|
|
|
$
|
225,226
|
|
|
$
|
223,589
|
|
Net income
|
|
|
8,153
|
|
|
|
9,568
|
|
|
|
9,929
|
|
|
|
9,606
|
|
Basic net income per share
|
|
|
0.53
|
|
|
|
0.61
|
|
|
|
0.60
|
|
|
|
0.50
|
|
Diluted net income per share
|
|
|
0.52
|
|
|
|
0.60
|
|
|
|
0.59
|
|
|
|
0.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007:
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
Revenues
|
|
$
|
156,717
|
|
|
$
|
187,146
|
|
|
$
|
185,824
|
|
|
$
|
193,081
|
|
Net income
|
|
|
4,642
|
|
|
|
7,192
|
|
|
|
7,762
|
|
|
|
6,656
|
|
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
|
|
Supplemental Information on Oil and Gas
Producing Activities (Unaudited)
The Companys oil and gas activities are conducted in the United States and Chile. 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, 2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
Oil and gas properties
|
|
$
|
76,844
|
|
|
$
|
58,458
|
|
|
$
|
34,308
|
|
Mineral interest in oil
and gas properties
|
|
|
18,165
|
|
|
|
12,515
|
|
|
|
8,430
|
|
|
|
|
|
95,009
|
|
|
|
70,973
|
|
|
|
42,738
|
|
Accumulated depletion
|
|
|
(16,353
|
)
|
|
|
(7,848
|
)
|
|
|
(2,931
|
)
|
|
Total
|
|
$
|
78,656
|
|
|
$
|
63,125
|
|
|
$
|
39,807
|
|
|
Unproved oil and gas property and mineral interest costs at January 31, 2008 totaled $8,131,000 and
$8,405,000, respectively, a total of $1,498,000 which relates to an exploration project in Chile.
Unevaluated mineral interest costs excluded from depreciation, depletion and amortization at
January 31, 2008 and 2007, totaled $8,405,000 and $4,153,000, respectively.
Capitalized costs and associated depreciation relating to gas transportation facilities and
equipment were as follows at January 31, 2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
Gas transportation facilities
and equipment
|
|
$
|
30,266
|
|
|
$
|
24,939
|
|
|
$
|
12,526
|
|
Accumulated depreciation
|
|
|
(4,355
|
)
|
|
|
(2,353
|
)
|
|
|
(883
|
)
|
|
Total
|
|
$
|
25,911
|
|
|
$
|
22,586
|
|
|
$
|
11,643
|
|
|
Capitalized costs incurred in gas transportation facilities and equipment during 2008, 2007
and 2006 totaled $5,327,000, $12,413,000 and $6,570,000, respectively
Cost Incurred in Oil and Gas Producing Activities
Capitalized costs incurred in oil and gas producing activities were as follows during 2008, 2007
and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2008
|
|
2007
|
|
2006
|
|
Acquisition
Proved
|
|
$
|
5,647
|
|
|
$
|
4,249
|
|
|
$
|
4,751
|
|
Unproved
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration
|
|
|
1,501
|
|
|
|
25
|
|
|
|
64
|
|
Development
|
|
|
16,718
|
|
|
|
23,719
|
|
|
|
13,454
|
|
|
|
|
|
23,866
|
|
|
|
27,993
|
|
|
|
18,269
|
|
Asset retirement costs
|
|
|
170
|
|
|
|
243
|
|
|
|
224
|
|
|
Total
|
|
$
|
24,036
|
|
|
$
|
28,236
|
|
|
$
|
18,493
|
|
|
Exploration costs of $1,498,000 in 2008 were associated with the exploration project in Chile.
58
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, 2008, 2007 and 2006, 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per Mcf)
|
|
2008
|
|
2007
|
|
2006
|
|
Revenues
|
|
$
|
20,861
|
|
|
$
|
14,014
|
|
|
$
|
8,554
|
|
Operating costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes
|
|
|
872
|
|
|
|
552
|
|
|
|
345
|
|
Lease operating expenses
|
|
|
8,242
|
|
|
|
5,051
|
|
|
|
2,753
|
|
Depreciation and depletion
|
|
|
8,504
|
|
|
|
4,917
|
|
|
|
2,021
|
|
Asset retirement accretion expense
|
|
|
60
|
|
|
|
43
|
|
|
|
27
|
|
Income tax expense
|
|
|
1,196
|
|
|
|
1,286
|
|
|
|
1,271
|
|
|
Total operating costs
|
|
|
18,874
|
|
|
|
11,849
|
|
|
|
6,417
|
|
|
Results of operations
|
|
$
|
1,987
|
|
|
$
|
2,165
|
|
|
$
|
2,137
|
|
|
Depletion per Mcf
|
|
$
|
1.80
|
|
|
$
|
1.46
|
|
|
$
|
1.44
|
|
|
Proved Oil and Gas Reserve Quantities
Proved gas reserve quantities as of January 31, 2008 and 2007 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. The Companys project in Chile has not
moved to a production phase and as such, no reserves have been established for Chile.
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):
|
|
2008
|
|
2007
|
|
Balance, beginning of year
|
|
|
57,078
|
|
|
|
45,120
|
|
Revisions of previous estimates
|
|
|
(5,697
|
)
|
|
|
(5,627
|
)
|
Extensions,
discoveries and other additions
|
|
|
3,617
|
|
|
|
19,019
|
|
Production
|
|
|
(4,732
|
)
|
|
|
(3,250
|
)
|
Purchases of reserves in place
|
|
|
|
|
|
|
1,816
|
|
|
Balance, end of year
|
|
|
50,266
|
|
|
|
57,078
|
|
|
Proved Developed Reserves
|
|
|
22,794
|
|
|
|
25,010
|
|
|
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 $7.53 and $6.89 per Mcf for 2008 and
2007, respectively. Future production and development costs represent the estimated future
expenditures to be incurred in developing and producing the proved reserves, assuming continuation
of existing economic conditions. Future income tax expense was computed by applying statutory rates
to pre-tax cash flows relating to the 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)
|
|
2008
|
|
2007
|
|
Future cash inflows
|
|
$
|
376,955
|
|
|
$
|
393,153
|
|
Future production costs
|
|
|
(148,069
|
)
|
|
|
(144,511
|
)
|
Future development costs
|
|
|
(44,077
|
)
|
|
|
(49,073
|
)
|
Future income taxes
|
|
|
(52,961
|
)
|
|
|
(59,098
|
)
|
|
Future net cash flows
|
|
|
131,848
|
|
|
|
140,471
|
|
10% discount to reflect timing of cash flows
|
|
|
(45,364
|
)
|
|
|
(51,459
|
)
|
|
Standardized measure of discounted cash flows
|
|
$
|
86,484
|
|
|
$
|
89,012
|
|
|
The principal sources of change in the standardized measure of discounted future net cash flows
were:
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2008
|
|
2007
|
|
Balance, beginning of year
|
|
$
|
89,012
|
|
|
$
|
79,611
|
|
Sales of gas produced, net of production costs
|
|
|
(17,454
|
)
|
|
|
(11,687
|
)
|
Net changes in prices and production costs
|
|
|
25,005
|
|
|
|
(16,568
|
)
|
Extensions and discoveries, less related costs
|
|
|
8,189
|
|
|
|
37,431
|
|
Revisions of quantity estimates
|
|
|
(20,265
|
)
|
|
|
(14,420
|
)
|
Purchases of reserves in place
|
|
|
|
|
|
|
3,729
|
|
Change in future development
|
|
|
(19,352
|
)
|
|
|
(34,038
|
)
|
Accretion of discount
|
|
|
11,762
|
|
|
|
12,998
|
|
Net change in income taxes
|
|
|
(15,531
|
)
|
|
|
3,075
|
|
Development costs incurred
|
|
|
25,118
|
|
|
|
28,881
|
|
Asset retirement obligation and other
|
|
|
|
|
|
|
|
|
|
Net change
|
|
|
(2,528
|
)
|
|
|
9,401
|
|
Balance, end of year
|
|
$
|
86,484
|
|
|
$
|
89,012
|
|
|
59
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, 2006
|
|
$
|
4,106
|
|
|
$
|
1,496
|
|
|
$
|
709
|
|
|
$
|
(738
|
)
|
|
$
|
5,573
|
|
Fiscal year ended January 31, 2007
|
|
|
5,573
|
|
|
|
1,700
|
|
|
|
666
|
|
|
|
(919
|
)
|
|
|
7,020
|
|
Fiscal year ended January 31, 2008
|
|
|
7,020
|
|
|
|
1,205
|
|
|
|
336
|
|
|
|
(990
|
)
|
|
|
7,571
|
|
60
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, 2008 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, 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 report on
the effectiveness of the Companys internal control over financial reporting as of January 31,
2008. The 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 2008.
61
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Layne Christensen Company
Mission Woods, Kansas
We have audited the internal control over financial reporting of Layne Christensen Company and
subsidiaries (the Company) as of January 31, 2008, based on criteria established in
Internal
Control Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway
Commission. 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, included in the accompanying Managements Report on Internal Control Over
Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk,
and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A 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, the Company maintained, in all material respects, effective internal control
over financial reporting as of January 31, 2008, 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, 2008 of the Company and our report dated April
15, 2008 expressed an unqualified opinion on those financial statements and financial statement
schedule and included an explanatory paragraph relating to a change in accounting principle.
|
/s/ Deloitte & Touche LLP
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|
Kansas City, Missouri
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April 15, 2008
|
62
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 5, 2008, (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 5, 2008, 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 5, 2008, 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 5, 2008, will contain, under the captions Executive Compensation and Other
Information Certain Change-In-Control Agreements, and Certain Transactions Transactions with
Management, the information required by Item 13 of Form 10-K and such information is incorporated
herein by this reference.
Item 14. Principal Accounting Fees and Services
The Registrants Proxy Statement to be used in connection with the Annual Meeting of Stockholders
to be held on June 5, 2008, 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.
63
PART IV
Item 15. Exhibits and Financial Statement Schedules.
(a) Financial Statements, Financial Statement Schedules and Exhibits:
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.
The exhibits filed with or incorporated by reference in this report are listed below:
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
4(1)
|
|
Corrected Certificate of Restated Certificate of Incorporation of the Registrant (filed as
Exhibit 3(1) with the Registrants Registration Statement on Form S-1 which was filed on
September 20, 2007 (File No.333-146184), and incorporated herein by this reference)
|
|
|
|
4(2)
|
|
Certificate of Designations of Series A Junior Participating Preferred Stock of Layne
Christensen Company (filed with the Registrants Annual Report on Form 10-K for the fiscal
year ended January 31, 2007 as Exhibit 4(2) and incorporated herein by this reference)
|
|
|
|
4(3)
|
|
Amended and Restated Bylaws of the Registrant (filed as Exhibit 3.1(b) to the Registrants
Form 8-K filed September 17, 2007 and incorporated herein by this reference)
|
|
|
|
4(4)
|
|
Registration Rights Agreement, dated September 28, 2005, by and among the Company and the
holders of Company common stock listed on the signature pages thereto (incorporated by
reference to Exhibit 4.1 to the Companys Quarterly Report on Form 10-Q filed September 10,
2007)
|
|
|
|
4(5)
|
|
Specimen Common Stock Certificate (filed with Amendment No. 3 to the Registrants
Registration Statement on Form S-1 (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)
|
|
|
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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).
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|
|
|
4(9)
|
|
Amendment No. 3 to Amended and Restated Loan Agreement, dated October 15, 2007, by and among
the Company, LaSalle Bank National Association, as Administrative Agent and Lender, and the
other Lenders listed therein (filed as Exhibit 10(1) to the Companys Form 10-Q for the
quarter ended October 31, 2007, and incorporated herein by this reference)
|
|
|
|
4(10)
|
|
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)
|
64
Item 15. Exhibits and Financial Statement Schedules.
(continued)
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|
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4(11)
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|
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)
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|
|
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4(12)
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|
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)
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|
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4(13)
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|
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)
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|
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4(14)
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|
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)
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|
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4(15)
|
|
Letter Amendment No. 5 to Master Shelf Agreement, dated as of October 15, 2007, 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 October 31,
2007 and incorporated herein by this reference)
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|
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10(1)
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|
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)
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|
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10(2)
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|
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)
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|
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10(2.1)
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|
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)
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|
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10(2.2)
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Second Modification and Ratification of Lease Agreement between Parkway Partners, L.L.C.
and Layne Christensen Company dated April 28, 1997 (filed with the Registrants Annual Report
on Form 10-K for the fiscal year ended January 31, 1999 (File No. 0-20578), as Exhibit 10(2.2)
and incorporated herein by this reference)
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|
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10(2.3)
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|
Third Modification and Extension Agreement between Parkway Partners, L.L.C. and Layne
Christensen Company dated November 3, 1998 (filed with the Companys 10-Q for the quarter
ended October 31, 1998 (File No. 0-20578) as Exhibit 10(1) and incorporated herein by
reference)
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|
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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)
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|
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10(2.5)
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|
Fifth Modification and extension Agreement between Parkway Partners, L.L.C. and Layne
Christensen Company dated March 1, 2003 (filed as Exhibit 10(2.5) to the Registrants Annual
Report on Form 10-K for the fiscal year ended January 31, 2003 (File No. 0-20578) and
incorporated herein by this reference)
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|
|
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10(2.6)
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|
Sixth Modification Agreement, dated February 29, 2008, between 1900 Associates L.L.C. and the Company
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|
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**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)
|
65
Item 15. Exhibits and Financial Statement Schedules.
(continued)
|
|
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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)
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|
|
|
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)
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|
|
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**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)
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|
|
|
**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)
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|
|
|
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 (as amended and restated,
effective February 1, 2008) (filed as Exhibit 10.1 to the Registrants Current Report on Form
8-K filed February 11, 2008 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)
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|
|
|
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)
|
66
Item 15. Exhibits and Financial Statement Schedules.
(continued)
|
|
|
**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)
|
|
Form of Restricted Stock Award Agreement for Management and
Non-Employee Directors under the Companys 2006 Equity Incentive
Plan (incorporated by reference to Exhibit 10.1 to the Companys
Current Report on Form 8-K filed September 17, 2007)
|
|
|
|
**10(24)
|
|
Layne Christensen Company Water Infrastructure Division Incentive
Compensation Plan (as amended and restated, effective February 1,
2008)
|
|
|
|
**10(25)
|
|
Layne Energy, Inc. 2007 Stock Option Plan (incorporated by
reference to Exhibit 10.1 to the Companys Current Report on Form
8-K filed June 13, 2007)
|
|
|
|
**10(26)
|
|
Form of Nonqualified Stock Option Agreement under the Layne
Energy, Inc. 2007 Stock Option Plan (incorporated by reference to
Exhibit 10.2 to the Companys Current Report on Form 8-K filed
June 13, 2007)
|
|
|
|
**10(27)
|
|
Layne Christensen Company Mineral Exploration Division
Incentive Compensation Plan (as amended and restated effective
February 1, 2008)
|
|
|
|
**10(28)
|
|
Severance Agreement, dated March 13, 2008, by and between
Andrew B. Schmitt and Layne Christensen Company (incorporated by
reference to Exhibit 10(1) to the Companys Current Report on
Form 8-K filed March 19, 2008)
|
|
|
|
**10(29)
|
|
Severance Agreement, dated March 13, 2008, by and between
Gregory F. Aluce and Layne Christensen Company (incorporated by
reference to Exhibit 10(2) to the Companys Current Report on
Form 8-K filed March 19, 2008)
|
|
|
|
**10(30)
|
|
Severance Agreement, dated March 13, 2008, by and between Steven
F. Crooke and Layne Christensen Company (incorporated by
reference to Exhibit 10(3) to the Companys Current Report on
Form 8-K filed March 19, 2008)
|
|
|
|
**10(31)
|
|
Severance Agreement, dated march 13, 2008, by and between Jerry
W. Fanska and Layne Christensen Company (incorporated by
reference to Exhibit 10(4) to the Companys Current Report on
Form 8-K filed March 19, 2008)
|
|
|
|
**10(32)
|
|
Severance Agreement, dated march 13, 2008, by and between Jeffrey
J. Reynolds and Layne Christensen Company (incorporated by
reference to Exhibit 10(5) to the Companys Current Report on
Form 8-K filed March 19, 2008)
|
|
|
|
**10(33)
|
|
Summary of 2008 Salaries of Named Executive Officers
|
|
|
|
10(34)
|
|
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)
|
|
|
|
10(35)
|
|
Amendment to Agreement and Plan of Merger, dated July 30, 2007, by and among the Company and
Jeffrey Reynolds, individually and as Agent of the Stockholders listed on the signature pages
thereto (incorporated by reference to Exhibit 10.1 to the Companys Current Report on Form 8-K
filed August 3, 2007)
|
|
|
|
**10(36)
|
|
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(37)
|
|
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(38)
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Settlement Agreement, dated March 31, 2006, by and among Layne Christensen Company, Steel
Partners II, L.P., Steel Partners, L.L.C. and Warren G. Lichtenstein (filed as Exhibit 10.1 to
the Companys Form 8-K, dated April 5, 2006, and incorporated herein by this reference)
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21(1)-
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List of Subsidiaries
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23(1)-
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Consent of Deloitte & Touche LLP
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67
Item 15. Exhibits and Financial Statement Schedules.
(continued)
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23(2)-
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Consent of Cawley, Gillespie & Associates, Inc.
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31(1)-
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Section 302 Certification of Principal Executive Officer of the Company
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31(2)-
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Section 302 Certification of Principal Financial Officer of the Company
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32(1)-
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Section 906 Certification of Principal Executive Officer of the Company
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32(2)-
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Section 906 Certification of Principal Financial Officer of the Company
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** 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).
68
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
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Layne Christensen Company
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By
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/s/ A. B. Schmitt
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Andrew B. Schmitt
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President and Chief Executive Officer:
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Dated April 14, 2008
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed
below by the following persons on behalf of the registrant and in the capacities and on the dates
indicated:
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Signature and Title
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Date
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/s/ A. B. Schmitt
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April 14, 2008
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President, Chief Executive Officer
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and Director (Principal Executive Officer)
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/s/ Jerry W. Fanska
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April 14, 2008
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Senior Vice President-Finance and Treasurer
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(Principal Financial and Accounting Officer)
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/s/ Jeff Reynolds
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April 14, 2008
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Director
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/s/ Donald K. Miller
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April 14, 2008
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Director
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/s/ David A. B. Brown
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April 14, 2008
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Director
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/s/ J. Samuel Butler
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April 14, 2008
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Director
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/s/ Anthony B. Helfet
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April 14, 2008
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Director
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/s/ Nelson Obus
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April 14, 2008
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Director
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69
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