FORM 10-K
United States
Securities and Exchange Commission
Washington, D.C. 20549
Form 10-K
(Mark One)
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Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the Fiscal Year Ended January 31, 2009
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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
to
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Commission
file number: 001-34195
Layne Christensen Company
(Exact name of registrant as specified in its charter)
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Delaware
(State or other jurisdiction
of incorporation or organization)
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48-0920712
(I.R.S. Employer
Identification No.) |
1900 Shawnee Mission Parkway, Mission Woods, Kansas 66205
(Address of principal executive offices) (Zip Code)
Registrants telephone number, including area code: (913) 362-0510
Securities Registered Pursuant to Section 12(b) of the Act:
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Title of each class
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Name of each exchange on which registered |
Common stock, $.01 par value
Preferred Share Purchase Rights
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NASDAQ Global Select Market
NASDAQ Global Select Market |
Securities Registered Pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of
the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or
Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of registrants knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. þ
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):
Large accelerated filer þ |
Accelerated filer o |
Non-accelerated filer o (Do not check if a smaller reporting company) |
Smaller reporting company o
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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 o No þ
The aggregate market value of the 18,498,245 shares of Common Stock of the registrant held by
non-affiliates of the registrant on July 31, 2008, the last business day of the registrants second
fiscal quarter, computed by reference to the closing sale price of such stock on the NASDAQ Global
Select Market on that date was $844,817,133.
At March 18, 2009, there were 19,437,132 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 2009 Annual Meeting of Stockholders to be filed with the
Commission pursuant to Regulation 14A.
PART I
Item 1. Business
General
Layne Christensen Company (we, us or the Company) provides drilling and construction services
and related products in two principal markets: water infrastructure and mineral exploration, as
well as operates as a producer of unconventional natural gas for the energy market. We operate
throughout North America, as well as Africa, Australia, Europe and Brazil. We also operate 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 infrastructure demand is driven by the need to provide and protect one of earths most
precious resources, water, which is drawn from the earth for drinking, irrigation and industrial
use. Main drivers for water supply and treatment include shifting demographics and urban sprawl,
deteriorating water quality and infrastructure that supplies our water, increasing water demand
from industrial expansion, stricter regulation and new technology that allows us to achieve new
standards of quality. The U.S. water well drilling industry is highly fragmented, consisting of
several thousand regionally and locally based contractors. The 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 participate.
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.
Demand for water and wastewater treatment services continues to grow. Increasingly stringent
water quality 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 stricter, the demand for water recycling (re-use) and
conservation services, as well as new specialized treatment media and filtration methods, is
expected to remain strong.
Sewer rehabilitation demand is largely a function of deteriorating urban infrastructure and
pressure from population growth. Additionally, federal and state agencies are forcing
municipalities and industry to address pollution resulting from infiltration of damaged or leaking
lines.
Mineral Exploration
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. Development in these countries
generates significant demand as their populations consume increasing amounts of base and precious
metals for housing, automobiles, electronics and other durable and consumer items.
The mineral exploration market is currently experiencing an unprecedented challenge in the
world financial and credit markets. Many mining companies are choosing to cut their drilling
programs or to cancel them in total to conserve cash. It is expected that this market will not
improve until financial and credit markets become more readily available. In addition, the current
market prices for base metals have limited mining companies ability to seek cash for their
operations through other avenues which traditionally have been available to them.
As mineral resources in developed countries are exhausted and new discoveries begin to slow,
mining companies have focused attention overseas as an important source of future production. South
America and Africa are key markets for future global growth. Mining service companies with
operating expertise in challenging regions should be well-positioned to capture an increasing
amount of these new projects. In addition to new mine development, technological advancements in
drilling and processing allow development of mineral resources previously regarded as uneconomical
and should benefit the largest drilling services companies that are leading technical innovation in
the mineral exploration marketplace.
Energy
The unconventional natural gas market is generally 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
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and surrounding shales and sandstones during the coalification process, when plant material is
progressively 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 46% of U.S. natural gas production in 2006. As
important, unconventional natural gas contribution is forecasted to grow to 49% of U.S. natural gas
production by 2030 based on EIA projections. Factors influencing the demand for unconventional
natural gas include levels of consumption, availability of 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. According to EIA data, the U.S. produces
approximately 85% 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 275,000
gross acres within the Cherokee Basin and New Albany Shale 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 bundled service capabilities and geographic platform and focus on industrial end-markets
for water and wastewater treatment services
We expect to expand our presence in the water well drilling and development, pump installation,
well rehabilitation and specialty drilling 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 a focused group of users of treatment and distribution facilities. These include
municipalities, investor-owned water utilities, industrial companies and developers. By offering
these services on a bundled basis, we believe we can enable our customers to expedite the typical
design-build project. This will allow them to 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 our water infrastructure market
penetration across the U.S. by combining the service offerings provided by our recent acquisitions
with our well-established relationships. Cross-selling broad service offerings into our existing
base of traditional customers should enable us to expand our market share in the water
infrastructure market. We intend to continue our geographic penetration primarily through organic
growth, but will also seek acquisition opportunities that facilitate our access to new markets and
service capabilities.
We believe 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 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. Increased
water management systems, including boiler water treatment and scrubber wastewater treatment, will
be essential to support growth in generating capacity. 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 select 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 opportunities in these
markets. Our ability to maximize these opportunities 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.
Develop existing unconventional natural gas opportunities and expand presence in the upstream
energy market
We are developing and expanding our existing unconventional natural gas properties in the Cherokee
Basin and New Albany Shale 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 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 diame- |
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ter 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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Sonic drilling provides continuous core samples of any overburden formation without the use
of water or drilling additives and is able to core and drill through virtually any formation
or obstruction, including bedrock. Applications include site assessments, underground storage
tank investigation, delineation of contaminants, installation of monitoring wells and recovery
wells, construction, geotech investigations, mineral and sand exploration, and discreet water
sampling. |
Water Infrastructure
We are a leading provider of water systems and water treatment facilities. We offer, on a bundled
basis, a comprehensive range of design, construction and maintenance services for municipal,
industrial and agricultural water and wastewater systems. We believe our water infrastructure
division is the market leader in the water well drilling industry and provides a full suite 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 hydrologic design
and construction, source of supply exploration, well and intake construction and pipeline
installation. In fiscal 2009, these services and products generated approximately 40% of revenue in
the water infrastructure division. The division provides water 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 U.S. 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 and application of drilling techniques. The drilling methods, 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; we perform bacteriological well evaluation and water chemistry analyses to complement this effort. We also have the capability and
inventory to repair, in our own machine shops, most water well pumps, regardless of manufacturer,
as well as to repair well screens, casings and related equipment such as chlorinators, aerators and
filtration systems.
Water and Wastewater Treatment and Plant Construction We are well-positioned to serve the needs
of our municipal and industrial customers by providing the design and construction of both water
and wastewater treatment plants. 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
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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, radon, uranium and perchlorate. 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 groundwater pump stations. 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 continually explore new rehabilitation processes and
technology.
Environmental Specialty 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 the Occupational
Safety and Health Administration (OSHA) and the Mine Safety and Health Administration (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, 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 increases in recent years as new and less expensive mining
techniques make 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. Our
primary markets are in the western U.S., Alaska Canada, Mexico, Australia, Brazil and Africa. We
also have ownership interests in foreign affiliates operating in Latin America that form our
primary presence in this market.
Energy
Our energy business operates primarily in the midwestern U.S, and includes 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. 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.
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 and New
Albany Shale. As of January 31, 2009, we had approximately 275,000 gross acres under lease and 582
gross producing wells. Production from these wells increases more slowly than conventional
natural gas wells and generally takes 18-24 months to reach full capacity. However, their life
span is significantly longer than conventional natural gas wells. We estimate that the average life
span of our current wells is approximately 15-20 years. Additionally, we continue to lease acreage
for purposes of expanding our development potential. We believe the increasing demand for
cleaner-burning fuels and increasingly stringent regulatory limitations to ensure air quality will
have a favorable impact on the price for such fuels.
We use fixed-price physical delivery forward sales contracts to manage price fluctuation
associated with our production of unconventional natural gas and achieve a more predictable cash
flow. These derivative financial 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. As of January 31, 2009, the Company held contracts for physical delivery of
6,183,000 million British Thermal Units (MMBtu) of natural gas through March 31, 2010, at prices
ranging from $7.68 to $8.52 per MMBtu through March 2009, and from $7.61 to $10.67 per MMBtu from
April 2009 through March 2010.
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Operations
We operate on a decentralized basis, with approximately 81 sales and operations offices located in
most regions of the United States as well as in Australia, Africa, Mexico, Canada, Brazil 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 or
product lines 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 division are
through the Companys sales engineers and project managers who cultivate and maintain contacts with
existing and potential customers. We also maintain a business development effort on a national
basis which seeks opportunities with industrial 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 2009,
approximately 68% were derived from municipalities and approximately 11% 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 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, Brazil, 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 as we do not believe it has any
significance for our other businesses. Our backlog consists of the expected gross revenues
associated with executed contracts, or portions thereof, not yet performed by the Company. Backlog
is not necessarily a short term business indicator as there can be
significant variability in the
composition of the contracts and the timing of completion of the services. Our backlog for the
water infrastructure division was $427.9 million at January 31, 2009, compared to $408.4 million at
January 31, 2008. Our backlog as of year-end is generally completed within the following 12 to 24
months.
Seasonality
Our 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. Additionally, our international mineral exploration customers tend to slow drilling
activities surrounding the Christmas and New Years holidays. As a result, our revenues and
earnings in the first and fourth quarters tend to be less than revenues and earnings in the second
and third quarters.
Competition
Our competition for our water infrastructure divisions bundled 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 larger 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
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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.
Treatment plant and pipeline competitors consist mostly of a few national companies. The
majority of the municipal market is contracted through a public bidding process. While the majority
of the market is still price driven, a growing trend supports best value proposals.
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 we have. 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. We have not and do not expect to incur significant capital
expenditures to remain in compliance with these various environmental control regulations.
Many states require regulatory mandated construction permits which typically specify that
wells be constructed in accordance with applicable statutes. 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 licensed 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, 2009, we had approximately 3,600 employees, approximately 460 of whom were members
of collective bargaining units represented by locals affiliated with major labor unions in the U.S.
We believe that our relationship with our employees is satisfactory. In all of our service lines,
an important competitive factor is technical expertise. As a result, we emphasize the training and
development of our personnel. Periodic technical training is provided for senior field employees
covering such areas as pump installation, drilling technology and electrical troubleshooting. In
addition, we emphasize strict adherence to all health and safety requirements and offer incentive
pay based upon achievement of specified safety goals. This emphasis encompasses developing
site-specific safety plans, ensuring regulatory compliance and training employees in regulatory
compliance and good safety practices. Training includes an OSHA-mandated 40-hour hazardous waste
and emergency response training course as well as the required annual eight-hour updates. We have a
safety department staff which allows us to offer such training in-house. This staff also prepares
health and safety plans for specific sites and provides input and analysis for the health and
safety plans prepared by others.
7
On average, our field supervisors and drillers have 22 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 other 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, other than
the Levelland complaint as discussed in Item 3.
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
Demand for our services is vulnerable to economic downturns and reductions in private industry and
municipal spending. If general economic conditions continue or weaken and current constraints on
the availability of capital continue, then our revenues, profits and our financial condition may
decline.
Our customers are vulnerable to general downturns in the domestic and international economies.
Consequently, our results of operations could fluctuate depending on the demand for our services.
Due to the current economic downturn and the tightening in the credit markets, many of our
customers will face considerable budget shortfalls or are delaying capital spending that will
decrease the overall demand for our services. In addition, our customers may find it more difficult
to raise capital in the future due to substantial limitations on the availability of credit and
other uncertainties in the municipal and general credit markets.
We also expect current economic conditions to impact pricing for our services. Our customers
may demand lower pricing as a condition of continuing our services. Negotiated prices for future
work may also be impacted. We expect to see an increase in the number of competitors as other
companies that do not normally operate in our markets enter seeking contracts to keep their
resources employed.
As a result of the above conditions, our revenues, net income and overall financial condition
may decline.
A decline in municipal spending on water treatment and wastewater infrastructure could reduce our
revenue.
For the fiscal year ended January 31, 2009, approximately 68% of our water infrastructure division
revenue was derived from contracts with governmental entities or agencies. Reduced tax revenue in
certain regions, or inability to access traditional sources of credit, 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. |
A material decrease in the rate of mineral exploration and development will reduce the revenue
generated by our mineral exploration division. Based on current global economic uncertainties, we
expect overall exploration spending, and our revenues, to decrease at least in the short term.
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. |
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 domes-
8
tic activities and related revenue and
earnings tend to decrease in the winter months when adverse weather conditions interfere with
access to drilling or other construction sites. As a result, our revenue and earnings in the second
and third quarters tend to be higher than revenue and earnings in the first and fourth quarters.
Accordingly, as a result of the foregoing as well as other factors, our quarterly results should
not be considered indicative of results to be expected for any other quarter or for any full fiscal
year.
Our use of the percentage-of-completion method of accounting could result in a reduction or
reversal of previously recorded results.
Our revenue on large water 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 or no 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, 2009, our total indebtedness was $46.7 million, our total liabilities were $263
million and our total assets were $719 million. The current tightness in the credit markets and the
terms of our credit agreements 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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our credit agreements contain various operating and financial covenants that could restrict
our ability to incur additional indebtedness and liens, make investments and acquisitions,
transfer or sell assets, and transact with affiliates. |
If we fail to make required debt payments, or if we fail to comply with other covenants in our
credit 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.
There may be undisclosed liabilities associated with our acquisitions.
In connection with any acquisition made by us, there may be liabilities that we fail to discover or
are unable to discover including liabilities arising from non-compliance with laws and regulations
by prior owners for which we, as successor owners, may be responsible.
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. 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 through nationalization or expropriation without fair compensation; |
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changes in government policies and regulations; |
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tariffs, taxes and other trade barriers; |
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exchange controls and limitations on remittance of dividends or other payments to us by our
foreign subsidiaries and affiliates; and |
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devaluations and fluctuations in currency exchange rates. |
Some of our contracts are not denominated in dollars, and, other than on a selected basis, we
do not engage in foreign currency hedging transactions. 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 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
9
which we have operations, relating to
matters such as environmental protection, controls and restrictions on production, and,
potentially, nationalization, expropriation or cancellation of contract rights, as well as
restrictions on conducting business in such countries. In addition, in our foreign operations we
face operating difficulties, including political instability, workforce instability, harsh
environmental conditions and remote locations. We do not maintain political risk insurance. Adverse
events beyond our control in the areas of our foreign operations could reduce the revenue derived
from our foreign operations to the extent that contractual provisions and bilateral agreements
between countries may not be sufficient to guard our interests.
Reductions in the market price of gold could significantly reduce our profit.
World gold prices historically have fluctuated widely and are affected by numerous factors beyond
our control, including;
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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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interest rates; |
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sales of gold by central banks and other holders; |
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demand for jewelry containing gold; and |
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speculation. |
Any material decrease in the market price of gold could reduce the demand for our mineral
exploration services and reduce our profits.
Reductions in natural gas prices could further 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 or sustained 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 additional downward adjustments to our estimated proved reserves which could be
substantial. Further decreases in natural gas prices would render a significant number of our
planned exploration 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
further 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 additional impairment charges in the future, which could reduce net income in the period
incurred.
The current turmoil in the credit markets and poor economic conditions could negatively impact the
credit worthiness of our financial counterparties.
Although we evaluate the credit capacity of our financial counterparties, current global economic
conditions could negatively impact their ability to access credit. The risks of such reduction in
credit capacity include:
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non-performance of institutions with whom we negotiate gas forward pricing contracts; |
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viability of institutions holding our cash deposits in excess
of FDIC insurance limits; and |
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ability of institutions with whom we have lines of credit to allow access to those funds. |
If these institutions fail to fulfill their commitments to us, our access to operating cash could
be restricted.
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 forward sales 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. We may not be able to obtain
contracts at rates commensurate with our current contracts. Conversely, our commodity price risk
management strategy may limit our ability to realize cash flow from commodity price increases. As
of January 31, 2009, we had committed to deliver 6,183,000
million MMBtu of natural gas through March 2010
at prices ranging from $7.68 to $8.52 per MMBtu through March 2009, and from
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$7.61 to $10.67 per
MMBtu from April 2009 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 continue to develop our
existing properties and seek opportunities to lease additional acreage in the Cherokee Basin and
other areas. Such expansion will require significant capital expenditure. We may drill wells that
are unproductive or, although productive, do not produce natural gas in economic quantities.
Acquisition and well completion decisions generally are based on subjective judgments and
assumptions that are speculative. It is impossible to predict with certainty the production
potential of a particular property or well. Furthermore, a successful completion of a well does not
ensure a profitable return on the investment. A variety of geological, operational, or
market-related factors, including unusual or unexpected geological formations, pressures, equipment
failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental
risks, shortages or delays in the availability of drilling rigs and the delivery of equipment,
inability to renew leases relating to producing properties, loss of circulation of drilling fluids
or other conditions may substantially delay or prevent completion of any well, or otherwise prevent
a property or well from being profitable.
If we are unable to find, develop and acquire additional unconventional natural gas reserves that
will be commercially viable for production, our reserves and revenue from our energy division would
decline.
The rate of production from unconventional natural gas properties declines as reserves are
depleted. As a result, we must locate and develop or acquire new reserves to replace those being
depleted by production. Without successful development or acquisition activities, our reserves and
revenue from our energy division will decline. Some of our competitors in the energy business are
larger, more established companies with substantially greater resources, and in many instances they
have been engaged in the unconventional natural gas extraction business for longer than we have.
These companies may have acquisition and development strategies that are more aggressive than ours
and may be able to acquire more unconventional natural gas properties or develop their existing
properties much faster than we can. We endeavor to discover new economically feasible natural gas
reserves at least commensurate with the depletion of our existing reserves through production. Our
inability to acquire larger reserves of unconventional natural gas and potential delays in the
expansion of our unconventional natural gas division may prevent us from gaining market share and
reduce our revenue and profitability. We may not be able to find and develop or acquire additional
reserves at an acceptable cost or have necessary financing for these activities in the future. In
addition, drilling activity within a particular area that we lease may be unsuccessful and
exploration activities may not lead to commercial discoveries of unconventional natural gas.
Further, we may also have to venture into more hostile environments, both politically and
geographically, where exploration, development and production of unconventional natural gas will be
more technologically challenging and expensive.
Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any
material inaccuracies in these reserve estimates or underlying assumptions could materially reduce
the quantities and present value of our reserves.
It is not possible to measure underground accumulations of natural gas in an exact way. Natural gas
reserve engineering requires subjective estimates of underground accumulations of natural gas and
assumptions concerning future natural gas prices, production levels and operating and development
costs. In estimating our level of natural gas reserves, we and our independent reserve engineers
make certain assumptions that may prove to be incorrect, including assumptions relating to:
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a constant level of future natural gas prices; |
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geological conditions; |
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production levels; |
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capital expenditures; |
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operating and development costs; |
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the effects of regulation; and |
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availability of funds. |
If these assumptions prove to be incorrect, our estimates of proved reserves, the economically
recoverable quantities of natural gas attributable to any particular group of properties, the
classifications of reserves based on risk of recovery and our estimates of the future net cash flow
from our reserves could change significantly. For example, if natural gas prices at January 31,
2009, had been $1.00 less per Mcf, then the standardized measure of our proved reserves as of that
date would have decreased by $4 million, from $40 million to $36 million, and our estimated net
proved reserves would have decreased by 4.7 Bcfe, from 16.6 Bcfe to 11.9 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 esti-
11
mate. 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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the supply of and demand for natural gas; and |
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changes in governmental regulations or taxation. |
The timing of both our production and our incurrence of expenses in connection with the
development and production of natural gas properties will affect the timing of actual future net
cash flow from proved reserves, and thus their actual present value. In addition, the 10% discount
factor we use when calculating discounted future net cash flow in compliance with the Financial
Accounting Standards 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.
We purchase a significant amount of steel for use in connection with all of our businesses. We also
purchase a significant volume of fuel to operate our trucks and equipment. The manufacture of
materials used in our rehabilitation business is dependent upon the availability of resin, a
petroleum-based product. 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, 2009, the backlog in our water infrastructure division was approximately $428
million. This consists of the expected gross revenue associated with executed contracts, or
portions thereof, not yet performed by us. We cannot assure 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 reduced profits or 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
12
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 sometimes 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 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 construction 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, 2009, approximately 13% of our workforce was unionized and 8 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 bundled 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 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, OSHA and 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.
13
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
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, $1,000,000 for liability insurance and $1,000,000 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; |
|
|
|
valuation of assets acquired and liabilities assumed in connection with business
combinations; |
|
|
|
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.
14
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 the cost of 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 $90 million as of January
31, 2009. 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, 2009, 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 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, 2009, 741,441
shares of our common stock were issuable under currently outstanding stock options granted to
officers, directors and employees and an additional 467,000 shares are available to be granted
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
15
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 $75
per one one-hundredth of a 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 20% 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 stockholders 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.
We are required to assess and report on our internal controls each year. Findings of inadequate
internal controls could reduce investor confidence in the reliability of our financial information.
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. |
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 price
that you paid for the common stock. 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, 2013.
16
As of January 31, 2009, we (excluding foreign affiliates) owned or leased approximately 603
drill and well service rigs throughout the world, a substantial majority of which were located in
the United States. This number includes rigs used primarily in each of our service lines as well as
multi-purpose rigs. In addition, as of January 31, 2009, our foreign affiliates owned or leased
approximately 168 drill rigs.
Our unconventional gas projects consist of working interests in developed and undeveloped
properties primarily located in the Cherokee Basin and New Albany Shale 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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|
2009 |
|
2008 |
|
Proved developed (MMcf) |
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|
16,289 |
|
|
|
22,794 |
|
Proved undeveloped (MMcf) |
|
|
274 |
|
|
|
27,258 |
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|
Total proved reserves (MMcf) |
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|
16,563 |
|
|
|
50,052 |
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|
Standardized measure of discounted
cash flow (in thousands) |
|
$ |
40,176 |
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|
$ |
86,484 |
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|
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 year-end spot price used in estimating future net
revenue was $3.29 and $7.53 per Mcf as of January 31, 2009 and 2008, 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 our natural gas reserves and related
information. During 2009, we filed estimates of our natural gas and oil reserves for the year 2008
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, 2009, we had 582 gross producing wells and 581 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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2009 |
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2008 |
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2007 |
|
Revenues |
|
$ |
7.30 |
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|
$ |
6.45 |
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|
$ |
5.95 |
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Lease operating expenses |
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|
1.81 |
|
|
|
1.71 |
|
|
|
1.46 |
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Transportation costs |
|
|
2.43 |
|
|
|
2.06 |
|
|
|
1.88 |
|
Production and property taxes |
|
|
0.20 |
|
|
|
0.18 |
|
|
|
0.16 |
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The gross and net acreage on leases expiring in each of the following five fiscal years and
thereafter are 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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2010 |
|
|
18,697 |
|
|
|
18,697 |
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2011 |
|
|
34,047 |
|
|
|
34,047 |
|
2012 |
|
|
20,263 |
|
|
|
20,263 |
|
2013 |
|
|
66,986 |
|
|
|
66,986 |
|
2014 |
|
|
31,859 |
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|
|
31,859 |
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Thereafter |
|
|
157 |
|
|
|
157 |
|
Gross and
net developed and undeveloped acreage as of the end of our last two
fiscal years were as
follows:
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|
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Acres |
Fiscal Years Ended January 31, |
|
2009 |
|
2008 |
|
Gross developed |
|
|
102,009 |
|
|
|
66,044 |
|
Net developed |
|
|
101,802 |
|
|
|
65,836 |
|
Gross undeveloped |
|
|
172,509 |
|
|
|
192,473 |
|
Net undeveloped |
|
|
172,509 |
|
|
|
192,473 |
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Drilling Activity
As of January 31, 2009, we had 23 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, |
|
2009 |
|
2008 |
|
2007 |
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Exploratory wells: |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capable of production |
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|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
Dry |
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|
|
|
|
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|
Development wells: |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capable of production |
|
|
116 |
|
|
|
116 |
|
|
|
92 |
|
|
|
104 |
|
|
|
148 |
|
|
|
147 |
|
Dry |
|
|
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|
|
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|
|
|
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|
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Wells abandoned |
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Acquired wells |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14 |
|
|
|
13 |
|
|
Net increase in capable wells |
|
|
116 |
|
|
|
116 |
|
|
|
92 |
|
|
|
104 |
|
|
|
162 |
|
|
|
160 |
|
|
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.
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 physical delivery forward sales contracts.
17
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
On April 30, 2008, Levelland/Hockley County Ethanol, LLC (Levelland) filed a Complaint against
the Company in the District Court for Hockley County, Texas. On May 28, 2008, the Company removed
the case to the United States District Court for the Northern District of Texas, Lubbock Division.
On June 2, 2008, Levelland filed a First Amended Complaint against the Company in the Federal
District Court for the Northern District of Texas, Lubbock Division. Levelland owns an ethanol
plant located in Levelland, Texas. In July 2007, Levelland entered into a lease agreement with the
Company for certain water treatment equipment for the ethanol plant. Levelland alleges that the
equipment leased from the Company fails to treat the water coming into the ethanol plant to
required levels. The First Amended Complaint seeks damages for breach of contract, breach of
warranty, violation of the Texas Deceptive Trade Practices Act, negligence, negligent
misrepresentation and fraud, in connection with the design and construction of the water treatment
facility. The Company believes that it has meritorious defenses to the claims, intends to
vigorously defend against them and does not believe that the claims will have a material effect
upon our business or consolidated financial position, results of operations or cash flows.
We are involved in various other 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, other than
the Levelland complaint as noted above. We believe that the ultimate disposition of these matters
will not, individually and in the aggregate, have a material adverse effect upon our 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, 2009.
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 |
|
Age |
|
Position |
|
Andrew B. Schmitt
|
|
|
60 |
|
|
President, Chief Executive Officer and Director |
Jeffrey J. Reynolds
|
|
|
42 |
|
|
Executive Vice President and Director |
Gregory F. Aluce
|
|
|
53 |
|
|
Senior Vice President and
Division President Water Resources |
Eric R. Despain
|
|
|
60 |
|
|
Senior Vice President and
Division President Mineral Exploration |
Steven F. Crooke
|
|
|
52 |
|
|
Senior Vice President, Secretary and
General Counsel |
Jerry W. Fanska
|
|
|
60 |
|
|
Senior Vice President-Finance and Treasurer |
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
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 25 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
18
since April 1984. On February 1, 2006, Mr. Fanska
was promoted to Senior Vice President Finance and Treasurer.
PART II
Item 5. Market for Registrants Common Equity and Related Stockholder Matters
The Companys common stock is traded on the NASDAQ Global Select Market under the symbol LAYN.
In the year ended January 31, 2009, the Company purchased and subsequently cancelled 5,357 shares
of stock related to settlement of withholding obligations. The following table sets forth the range of high and low sales prices of the Companys
stock by quarter for fiscal 2009 and 2008, as reported by the NASDAQ Global Select Market.
|
|
|
|
|
|
|
|
|
Fiscal Year 2009 |
|
High |
|
Low |
|
First Quarter |
|
$ |
45.83 |
|
|
$ |
32.08 |
|
Second Quarter |
|
|
53.37 |
|
|
|
38.79 |
|
Third Quarter |
|
|
58.26 |
|
|
|
16.54 |
|
Fourth Quarter |
|
|
27.80 |
|
|
|
10.36 |
|
|
|
|
|
|
|
|
|
|
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 |
|
At March 18, 2009, there were 104 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 Bank of America, 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.
See Note 2 of the Notes to Consolidated Financial Statements for discussion of common stock
issued by the Company during the last three years in connection with acquisitions. All such stock
was unregistered.
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, 2009, 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. 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, |
|
2009 |
|
2008 |
|
2007 |
|
2006 |
|
2005 |
|
Income Statement Data (in thousands, except per share data): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
1,008,063 |
|
|
$ |
868,274 |
|
|
$ |
722,768 |
|
|
$ |
463,015 |
|
|
$ |
343,462 |
|
Cost of revenues (exclusive of depreciation, depletion, amortization
and impairment shown below) |
|
|
756,083 |
|
|
|
638,003 |
|
|
|
536,373 |
|
|
|
344,628 |
|
|
|
250,244 |
|
Selling, general and administrative expense |
|
|
136,687 |
|
|
|
119,937 |
|
|
|
102,603 |
|
|
|
69,979 |
|
|
|
60,214 |
|
Depreciation, depletion and amortization |
|
|
52,840 |
|
|
|
43,620 |
|
|
|
32,853 |
|
|
|
20,024 |
|
|
|
14,441 |
|
Impairment of oil and gas properties |
|
|
28,704 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of affiliates |
|
|
14,089 |
|
|
|
8,076 |
|
|
|
4,452 |
|
|
|
4,345 |
|
|
|
2,637 |
|
Interest |
|
|
(3,614 |
) |
|
|
(8,730 |
) |
|
|
(9,781 |
) |
|
|
(5,773 |
) |
|
|
(3,221 |
) |
Other, net |
|
|
3,214 |
|
|
|
1,229 |
|
|
|
2,557 |
|
|
|
900 |
|
|
|
1,220 |
|
|
Income from continuing operations before income taxes
and minority interest |
|
|
47,438 |
|
|
|
67,289 |
|
|
|
48,167 |
|
|
|
27,856 |
|
|
|
19,199 |
|
Income tax expense |
|
|
21,266 |
|
|
|
30,178 |
|
|
|
21,915 |
|
|
|
13,121 |
|
|
|
9,215 |
|
Minority interest |
|
|
362 |
|
|
|
145 |
|
|
|
|
|
|
|
(50 |
) |
|
|
(17 |
) |
|
Net income from continuing operations before discontinued operations |
|
|
26,534 |
|
|
|
37,256 |
|
|
|
26,252 |
|
|
|
14,685 |
|
|
|
9,967 |
|
Loss from discontinued operations, net of income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4 |
) |
|
|
(213 |
) |
|
Net income |
|
$ |
26,534 |
|
|
$ |
37,256 |
|
|
$ |
26,252 |
|
|
$ |
14,681 |
|
|
$ |
9,754 |
|
|
Basic income per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations before discontinued operations |
|
$ |
1.38 |
|
|
$ |
2.23 |
|
|
$ |
1.71 |
|
|
$ |
1.08 |
|
|
$ |
0.79 |
|
Loss from discontinued operations, net of income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.01 |
) |
|
Net income per share |
|
$ |
1.38 |
|
|
$ |
2.23 |
|
|
$ |
1.71 |
|
|
$ |
1.08 |
|
|
$ |
0.78 |
|
|
Diluted income per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations before discontinued operations |
|
$ |
1.37 |
|
|
$ |
2.20 |
|
|
$ |
1.68 |
|
|
$ |
1.05 |
|
|
$ |
0.77 |
|
Loss from discontinued operations, net of income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.02 |
) |
|
Net income per share |
|
$ |
1.37 |
|
|
$ |
2.20 |
|
|
$ |
1.68 |
|
|
$ |
1.05 |
|
|
$ |
0.75 |
|
|
Balance Sheet Data (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working capital, including current maturities of debt |
|
$ |
128,610 |
|
|
$ |
127,696 |
|
|
$ |
66,989 |
|
|
$ |
69,996 |
|
|
$ |
54,455 |
|
Total assets |
|
|
719,357 |
|
|
|
696,955 |
|
|
|
547,164 |
|
|
|
449,335 |
|
|
|
245,380 |
|
Total long term debt, excluding current maturities |
|
|
26,667 |
|
|
|
46,667 |
|
|
|
151,600 |
|
|
|
128,900 |
|
|
|
60,000 |
|
Total stockholders equity |
|
|
456,022 |
|
|
|
423,372 |
|
|
|
205,034 |
|
|
|
171,626 |
|
|
|
104,697 |
|
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 operates as 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 Division
This division provides a full line of water and wastewater 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 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 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 68% of the
divisions fiscal 2009 revenues were derived from the municipal market. The municipal sector can be
adversely impacted by economic slowdowns. Reduced tax revenues can limit spending and new
development by local municipalities. Generally, spending levels in the municipal sector lag an
economic recession or 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 and the availability of credit for mining
companies. In this connection, the recent decline in the level of mineral exploration and
development activities conducted by mining companies is expected to have a material adverse effect
on the Company. It is expected that activity by mining companies will not improve until financial
and credit markets become more readily available. The current market prices for base metals have
also limited mining companies ability to seek cash for their operations through other avenues
which have traditionally been available to them.
The division relies heavily on mining activity in Africa where 33% of total division revenues
were generated for fiscal 2009. 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
21
market by competitors. The Company believes it has positioned itself as the market
leader in Africa and has established the infrastructure to operate effectively.
Energy Division
This division focuses on the exploration and production of unconventional gas properties. This
division has primarily been concentrated on projects in the mid-continent region of the United
States.
The expansion of the Companys energy segment is
contingent upon significant cash investments to develop
the Companys unproved acreage. As of January 31, 2009, the Company has invested $153,570,000
in oil and gas related assets and expects to spend approximately $15,000,000 in development
activities in fiscal 2010.
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 581 net producing wells
on-line as of January 31, 2009.
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
Revenues: |
|
2009 |
|
2008 |
|
2007 |
|
vs. 2008 |
|
vs. 2007 |
|
Water infrastructure |
|
|
76.1 |
% |
|
|
73.7 |
% |
|
|
73.6 |
% |
|
|
19.9 |
% |
|
|
20.2 |
% |
Mineral exploration |
|
|
18.7 |
|
|
|
20.5 |
|
|
|
20.6 |
|
|
|
5.8 |
|
|
|
19.9 |
|
Energy |
|
|
4.6 |
|
|
|
4.6 |
|
|
|
3.7 |
|
|
|
16.6 |
|
|
|
46.8 |
|
Other |
|
|
0.6 |
|
|
|
1.2 |
|
|
|
2.1 |
|
|
|
(44.2 |
) |
|
|
(29.6 |
) |
|
Total revenues |
|
|
100.0 |
% |
|
|
100.0 |
% |
|
|
100.0 |
% |
|
|
16.1 |
% |
|
|
20.1 |
|
Cost of revenues (exclusive of depreciation, depletion, amortization
and impairment shown below) |
|
|
75.0 |
|
|
|
73.5 |
|
|
|
74.2 |
|
|
|
18.5 |
|
|
|
18.9 |
|
Selling, general and administrative expense |
|
|
13.6 |
|
|
|
13.8 |
|
|
|
14.2 |
|
|
|
14.0 |
|
|
|
16.9 |
|
Depreciation, depletion and amortization |
|
|
5.2 |
|
|
|
5.0 |
|
|
|
4.5 |
|
|
|
21.1 |
|
|
|
32.8 |
|
Impairment of oil and gas properties |
|
|
2.8 |
|
|
|
|
|
|
|
|
|
|
|
* |
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of affiliates |
|
|
1.4 |
|
|
|
0.9 |
|
|
|
0.6 |
|
|
|
74.5 |
|
|
|
81.4 |
|
Interest |
|
|
(0.4 |
) |
|
|
(1.0 |
) |
|
|
(1.4 |
) |
|
|
(58.6 |
) |
|
|
(10.7 |
) |
Other, net |
|
|
0.3 |
|
|
|
0.2 |
|
|
|
0.3 |
|
|
|
* |
|
|
|
(51.9 |
) |
|
Income before income taxes and minority interest |
|
|
4.7 |
|
|
|
7.8 |
|
|
|
6.6 |
|
|
|
(29.5 |
) |
|
|
39.7 |
|
Income tax expense |
|
|
2.1 |
|
|
|
3.5 |
|
|
|
3.0 |
|
|
|
(29.5 |
) |
|
|
37.7 |
|
Minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
|
|
* |
|
|
Net income |
|
|
2.6 |
% |
|
|
4.3 |
% |
|
|
3.6 |
% |
|
|
(28.8 |
)% |
|
|
41.9 |
% |
|
Revenues, equity in earnings of affiliates and income before income taxes and minority interest
pertaining to the Companys operating segments are presented on the next page.
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 before income taxes and minority interest are summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
Fiscal Years Ended January 31, |
|
2009 |
|
2008 |
|
2007 |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Water infrastructure |
|
$ |
766,957 |
|
|
$ |
639,584 |
|
|
$ |
531,916 |
|
Mineral exploration |
|
|
188,918 |
|
|
|
178,482 |
|
|
|
148,911 |
|
Energy |
|
|
46,352 |
|
|
|
39,749 |
|
|
|
27,081 |
|
Other |
|
|
5,836 |
|
|
|
10,459 |
|
|
|
14,860 |
|
|
Total revenues |
|
$ |
1,008,063 |
|
|
$ |
868,274 |
|
|
$ |
722,768 |
|
|
Equity in earnings of affiliates |
|
|
|
|
|
|
|
|
|
|
|
|
Mineral exploration |
|
$ |
14,089 |
|
|
$ |
8,076 |
|
|
$ |
4,452 |
|
|
Income (loss) before income taxes and minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
Water infrastructure |
|
$ |
48,399 |
|
|
$ |
42,995 |
|
|
$ |
35,000 |
|
Mineral exploration |
|
|
39,260 |
|
|
|
37,452 |
|
|
|
26,557 |
|
Energy |
|
|
(12,401 |
) |
|
|
13,075 |
|
|
|
10,680 |
|
Other |
|
|
1,280 |
|
|
|
3,696 |
|
|
|
4,094 |
|
Unallocated corporate expenses |
|
|
(25,486 |
) |
|
|
(21,199 |
) |
|
|
(18,383 |
) |
Interest |
|
|
(3,614 |
) |
|
|
(8,730 |
) |
|
|
(9,781 |
) |
|
Total income before income taxes and minority interest |
|
$ |
47,438 |
|
|
$ |
67,289 |
|
|
$ |
48,167 |
|
|
Comparison of Fiscal 2009 to Fiscal 2008
Revenues for fiscal 2009 increased $139,789,000, or 16.1%, to $1,008,063,000 compared to
$868,274,000 for fiscal 2008. Revenues were up across all primary divisions. A further discussion
of results of operations by division is presented below.
Selling, general and administrative expenses increased to $136,687,000 for fiscal 2009
compared to $119,937,000 for fiscal 2008 (13.6% and 13.8% of revenues, respectively). The increase
was primarily the result of $7,497,000 in expenses added from acquisitions and start up operations,
compensation related expense increases of $3,887,000, with the remainder of the increase spread
across various categories.
Depreciation, depletion and amortization increased to $52,840,000 for fiscal 2009 compared to
$43,620,000 for fiscal 2008. The increase was primarily the result of increased depletion of
$3,232,000 resulting from increases in production of unconventional gas from the Companys energy
operations and increased depreciation from property additions and acquisitions in the other
divisions.
The Company recorded non-cash impairments to oil and gas properties of $28,704,000 in fiscal
2009, including $26,690,000 of ceiling test impairment in the fourth
quarter, as a result of a significant decline in
natural gas prices and $2,014,000 related to an exploration project in Chile. There were no
impairments in fiscal 2008.
Equity in earnings of affiliates increased to $14,089,000 for fiscal 2009 compared to
$8,076,000 for fiscal 2008. The increase reflects strong performance in mineral exploration by
affiliates in Latin America, particularly Chile, during most of the fiscal year.
Interest expense decreased to $3,614,000 for fiscal 2009 compared to $8,730,000 for fiscal
2008. The decrease was primarily a result of debt paid off with proceeds from the Companys stock
offering in October 2007.
The Companys effective tax rate was 44.8% for fiscal 2009, compared to 44.8% for fiscal 2008.
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, |
|
2009 |
|
2008 |
|
Revenues |
|
$ |
766,957 |
|
|
$ |
639,584 |
|
Income before income taxes and
minority interest |
|
|
48,399 |
|
|
|
42,995 |
|
Water infrastructure revenues increased 19.9% to $766,957,000 for fiscal 2009, from $639,584,000
for fiscal 2008. The increase in revenues was partially attributable to incremental revenues of
$54,458,000 from the Companys acquisitions and increases of $25,325,000 in water and wastewater
treatment plant construction, $20,389,000 in specialty geoconstruction and $9,396,000 in sewer
rehabilitation.
Income before income taxes for the water infrastructure division increased 12.6% to
$48,399,000 for fiscal 2009, compared to $42,995,000 for fiscal 2008. Included in fiscal 2008
results was $1,626,000 in non-recurring income from the recovery of previously written-off costs
associated with a groundwater transfer project in Texas. Excluding this item, the increase in
income was primarily attributable to increases in earnings of $3,635,000 in specialty
geoconstruction, $2,527,000 in water and wastewater treatment plant construction and $1,135,000 in
sewer rehabilitation.
The backlog in the water infrastructure division was $427,863,000 as of January 31, 2009,
compared to $408,404,000 as of January 31, 2008.
23
Mineral Exploration Division
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
Fiscal Years Ended January 31, |
|
2009 |
|
2008 |
|
Revenues |
|
$ |
188,918 |
|
|
$ |
178,482 |
|
Income before income taxes and
minority interest |
|
|
39,260 |
|
|
|
37,452 |
|
Mineral exploration revenues increased 5.8% to $188,918,000 for fiscal 2009, compared to revenues
of $178,482,000 for fiscal 2008. The increase in revenues was primarily attributable to strength in
exploration activity in the Companys markets as a result of the relatively high gold and base
metal prices in the first three quarters of the year. Revenues decreased in the fourth quarter of
fiscal 2009 as mining companies extended holiday mine shutdowns and delayed spending programs in
response to tightening credit and economic uncertainty. We expect this revenue trend to continue
into next year.
Income before income taxes for the mineral exploration division increased 4.8% to $39,260,000
for fiscal 2009, compared to $37,452,000 for fiscal 2008. Included in income is equity in earnings
of affiliates, which increased $6,013,000 over fiscal 2008. Excluding the affiliate earnings, the
divisions earnings decreased $4,205,000 in earnings for the year, primarily due to the fourth
quarter exploration spending slowdowns noted above.
Energy Division
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
Fiscal Years Ended January 31, |
|
2009 |
|
2008 |
|
Revenues |
|
$ |
46,352 |
|
|
$ |
39,749 |
|
(Loss) income before income taxes and
minority interest |
|
|
(12,401 |
) |
|
|
13,075 |
|
Energy division revenues increased 16.6% to $46,352,000 for fiscal 2009, compared to revenues of
$39,749,000 for fiscal 2008. The increase in revenues was primarily attributable to increased
production from the Companys unconventional gas properties.
During the fourth quarter of fiscal 2009, the Company completed its annual determination of
oil and gas reserves for the Energy division. This determination is made according to SEC
guidelines and uses year end gas prices. Gas prices at January 31, 2009, used in the determination
were $3.29 per Mcf, compared to $7.53 per Mcf used in January 31, 2008. As a result of the lower
prices, the expected future cash flows and gas reserve volumes were significantly reduced.
Accordingly, in the fourth quarter, the Company recorded a non-cash impairment charge of
$26,690,000, or $16,081,000 after income tax, for the carrying value of the assets in excess of
future net cash flows.
Excluding the fourth quarter non-cash impairment charge, income before income taxes for the
energy division increased 9.3% to $14,289,000 for fiscal 2009, compared to $13,075,000 for fiscal
2008. The increases were attributable to increased production, partially offset by reduced pricing
in the second half of the year for the portion of the divisions production which was not covered
by forward sales contracts.
Also included in fiscal 2009, are two additional items. We recorded an impairment of oil and
gas properties of $2,014,000 related to the Companys exploration project in Chile, begun in 2008.
Following initial core testing and further evaluation of infrastructure requirements, it was
determined that recovery of our investment was not likely and costs were written off. We also
recorded settlement income related to litigation initiated in the current year against former
officers of a subsidiary and associated energy production companies. During September 2008, the
Company entered into a settlement agreement whereby it will receive certain payments over a period
through September 2009. Settlement income of $2,173,000 was recorded in the year for the payments
received, net of attorney fees.
Other
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
Fiscal Years Ended January 31, |
|
2009 |
|
2008 |
|
Revenues |
|
$ |
5,836 |
|
|
$ |
10,459 |
|
Income before income taxes and
minority interest |
|
|
1,280 |
|
|
|
3,696 |
|
Included in Other for fiscal 2009 and 2008 were revenues of $470,000 and $4,954,000,
respectively, associated with contracts to provide consulting and logistical support for
international projects in Canada and Africa. Excluding the effects of 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 $25,486,000 and $21,199,000 for fiscal 2009 and 2008,
respectively. The increase for the year was primarily due to compensation related expenses.
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.
24
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. 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 before income taxes 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 before income taxes 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 before income taxes 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 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 the increases in wage and benefit
costs of $1,028,000 and increased share based compensation to employees of $840,000.
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
25
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 or no 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, 2009, the
Company has $46,667,000 in notes outstanding under the Master Shelf Agreement. Additionally, the
Company holds an unsecured $200,000,000 revolving credit facility (the Credit Agreement) which
extends to November 15, 2011. At January 31, 2009, the Company had letters of credits of
$15,841,000 and no borrowings outstanding under the Credit Agreement resulting in available
capacity of $184,159,000.
The Companys Master Shelf Agreement and Credit Agreement each contain certain covenants
including restrictions on the incurrence of additional indebtedness and liens, investments,
acquisitions, transfer or sale of assets, transactions with affiliates and payment of dividends.
These provisions generally allow such activity to occur, subject to specific limitations and
continued compliance with financial maintenance covenants. Significant financial maintenance
covenants are fixed charge coverage ratio, maximum leverage ratio and minimum tangible net worth.
Covenant levels and definitions are consistent between the two agreements. The Company was in
compliance with its covenants as of January 31, 2009 and expects to be in compliance in fiscal
2010.
Compliance with the financial covenants is required on a quarterly basis, using the most
recent four fiscal quarters. The Companys fixed charge coverage ratio and leverage ratio
covenants are based on ratios utilizing adjusted EBITDA and adjusted EBITDAR, as defined in the
agreements. Adjusted EBITDA is generally defined as consolidated net income excluding net interest
expense, provision for income taxes, gains or losses from extraordinary items, gains or losses from
the sale of capital assets, non-cash items including depreciation and amortization, and share-based
compensation. Equity in earnings of affiliates is included only to the extent of dividends or
distributions received. Adjusted EBITDAR is defined as adjusted EBITDA, plus rent expense. The
Companys tangible net worth covenant is based on stockholders equity less intangible assets. All
of these measures are considered non-GAAP financial measures and are not intended to be in
accordance with accounting principles generally accepted in the United States.
The Companys minimum fixed charge coverage ratio covenant is the ratio of adjusted EBITDAR to
the sum of fixed charges. Fixed charges consist of rent expense, interest expense, and principal
payments of long-term debt. The Companys leverage ratio covenant is the ratio of total funded
indebtedness to adjusted EBITDA. Total funded indebtedness generally consists of outstanding debt,
capital leases, unfunded pension liabilities, asset retirement obligations and escrow liabilities.
The Companys tangible net worth covenant is measured based on stockholders equity, less
intangible assets, as compared to a threshold amount defined in the
agreements. The threshold is adjusted over time based on a percentage of net income and the
proceeds from the issuance of equity securities.
As of January 31, 2009 and 2008, the Companys actual and required covenant levels were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual |
|
Required |
|
Actual |
|
Required |
(in thousands) |
|
2009 |
|
2009 |
|
2008 |
|
2008 |
|
Minimum fixed charge
coverage ratio |
|
|
4.22 |
|
|
|
1.50 |
|
|
|
5.65 |
|
|
|
1.50 |
|
Maximum leverage ratio |
|
|
0.44 |
|
|
|
3.00 |
|
|
|
0.57 |
|
|
|
3.25 |
|
Minimum tangible net worth |
|
$ |
340,280 |
|
|
$ |
291,237 |
|
|
$ |
313,571 |
|
|
$ |
274,647 |
|
The Companys working capital as of January 31, 2009, 2008 and 2007, was $128,610,000, $127,696,000
and $66,989,000, respectively. The increase in working capital in 2008 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 operating cash requirements and to fund its budgeted capital
expenditures for fiscal 2010. We do not currently believe we will draw on credit facilities in
fiscal 2010, however, we believe our lenders are sufficiently capitalized to meet our needs if
required.
The Company is also highly dependent on the availability of surety bonding capacity,
particularly in its water infrastructure business. The Company believes it has adequate access
through its insurers to meet its business requirements and growth opportunities.
26
Operating Activities
Cash from operating activities was $92,026,000, $80,163,000 and $74,676,000 for fiscal 2009, 2008
and 2007, 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 proceeds from disposals, of $79,851,000 for the year
ended January 31, 2009, were split between $50,244,000 to maintain and upgrade its construction
equipment and $29,607,000 toward the Companys expansion into unconventional gas exploration and
production, including the construction of gas pipeline infrastructure near the Companys
development projects. During the year, the Company spent $7,070,000 to complete acquisitions to
complement its water infrastructure division.
The Companys capital expenditures, net of proceeds from 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 proceeds from 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.
Financing Activities
The Company had no borrowings under its revolving credit facilities during the year ended January
31, 2009, financing the business from operations and available cash. During July, the Company
made the first scheduled principal payment of $13,333,000 on the Senior Notes.
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.
Contractual Obligations and Commercial Commitments
The Companys contractual obligations and commercial commitments as of January 31, 2009, are
summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments/Expiration by Period |
|
|
|
|
|
|
Less than |
|
|
|
|
|
|
|
|
|
More than |
(in thousands) |
|
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 |
|
|
46,667 |
|
|
|
20,000 |
|
|
|
26,667 |
|
|
|
|
|
|
|
|
|
Interest payments |
|
|
6,511 |
|
|
|
3,500 |
|
|
|
3,011 |
|
|
|
|
|
|
|
|
|
Software financing obligations |
|
|
1,105 |
|
|
|
482 |
|
|
|
623 |
|
|
|
|
|
|
|
|
|
Operating leases |
|
|
35,657 |
|
|
|
12,902 |
|
|
|
14,283 |
|
|
|
8,472 |
|
|
|
|
|
Mineral interest obligations |
|
|
656 |
|
|
|
111 |
|
|
|
363 |
|
|
|
159 |
|
|
|
23 |
|
Income tax uncertainties |
|
|
174 |
|
|
|
174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash contractual obligations |
|
|
90,770 |
|
|
|
37,169 |
|
|
|
44,947 |
|
|
|
8,631 |
|
|
|
23 |
|
Standby letters of credit |
|
|
15,841 |
|
|
|
15,841 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations |
|
|
1,305 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,305 |
|
|
Total contractual obligations and commercial commitments |
|
$ |
107,916 |
|
|
$ |
53,010 |
|
|
$ |
44,947 |
|
|
$ |
8,631 |
|
|
$ |
1,328 |
|
|
27
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, 2009.
The Company has income tax uncertainties in the amount of $7,752,000 at January 31, 2009, 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. 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 under the
full cost accounting rules of the SEC (the ceiling test). The ceiling limitation is the estimated
after-tax future net revenues from proved oil and gas properties discounted at 10%, plus the cost
of properties not subject to amortization. If our net book value of oil and gas properties, less
related deferred income taxes, is in excess of the calculated ceiling, the excess must be written
off as an expense.
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.
28
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 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 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 continue to be appropriate.
Accrued Insurance Expense The Company maintains insurance programs where it is responsible for a
certain amount of each claim up to a retention limit. Estimates are recorded for health and
welfare, property and casualty insurance costs that are associated with these programs. These costs
are estimated based on actuarially determined projections of future payments under these programs.
Should a greater amount of claims occur compared to what was estimated or medical costs increase
beyond what was anticipated, reserves recorded may not be sufficient and additional costs to the
consolidated financial statements could be required.
Costs estimated to be incurred in the future for employee health and welfare benefits,
property, workers compensation and casualty insurance programs resulting from claims which have
occurred are accrued currently. Under the terms of 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
29
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 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.
New Accounting Pronouncements 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, 2009, 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, Canada 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, 2009, the Company held option contracts with an aggregate U.S. dollar notional value of
$9,800,000, which are intended to hedge exposure to Australian dollar fluctuations through January
31, 2010.
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 before income
taxes by approximately $585,000, $511,000 and $416,000 for the years ended January 31, 2009, 2008
and 2007, respectively. This represents approximately 10% of the income before income taxes 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, 2009, 2008 and 2007, were $91,000, ($430,000) and
$95,000, 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 forward
sales contracts covering a portion of its
production to manage price fluctuations and to achieve a more predictable cash flow. As of January
31, 2009, the Company held contracts for physical delivery of 6,183,000 million British Thermal
Units (MMBtu) of natural gas through March 31, 2010, at prices ranging from $7.68 to $8.52 per
MMBtu through March 2009, and from $7.61 to $10.67 per MMBtu from April 2009 through March 2010.
The estimated fair value of such contracts at January 31, 2009, was $27,950,000. The Company
generally intends to maintain contracts in place to cover 50% to 75% of its production, although if
gas prices remain low, the Company may slow production and cover 100% of gas sold in 2010.
We estimate that a 10% change in the price of natural gas would have impacted income before
taxes by approximately $1,652,000 for the year ended January 31, 2009.
30
Item 8.
Financial Statements and Supplementary Data
Index to Consolidated Financial Statements and Financial Statement Schedules
Layne Christensen Company and Subsidiaries
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Page |
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32 |
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33 |
|
Financial Statements: |
|
|
|
|
|
|
|
34 |
|
|
|
|
35 |
|
|
|
|
36 |
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37 |
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38 |
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|
|
|
57 |
|
|
|
|
59 |
|
All other schedules have been omitted because they are not applicable or not required as the
required information is included in the Consolidated Financial Statements of the Company or the
Notes thereto.
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.
|
|
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/s/ A. B. Schmitt
|
|
|
|
/s/ Jerry W. Fanska
|
|
|
|
|
|
|
|
|
|
Andrew B. Schmitt
President and
Chief Executive Officer
|
|
|
|
Jerry W. Fanska
Senior Vice President and
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, 2009 and 2008, and the related consolidated
statements of income, stockholders equity, and cash flows for each of the three years in the
period ended January 31, 2009. 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, 2009
and 2008, and the results of their operations and their cash flows for each of the three years in
the period ended January 31, 2009, in conformity with accounting principles generally accepted in
the United States of America. Also, in our opinion, such financial statement schedule, when
considered in relation to the basic consolidated financial statements taken as a whole, presents
fairly, in all material respects, the information set forth therein.
As discussed in Note 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 Standard (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, 2009, based on the criteria established in Internal ControlIntegrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated
March 31, 2009, expressed an unqualified opinion on the Companys internal control over financial
reporting.
/s/ Deloitte & Touche LLP
Kansas City, Missouri
March 31, 2009
33
Layne Christensen Company and Subsidiaries
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
(in thousands, except per share data) |
|
|
|
|
|
|
January 31, |
|
2009 |
|
|
2008 |
|
|
ASSETS |
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
67,165 |
|
|
$ |
73,068 |
|
Customer receivables, less allowance of $7,878 and $7,571, respectively |
|
|
116,234 |
|
|
|
125,091 |
|
Costs and estimated earnings in excess of billings on uncompleted contracts |
|
|
63,638 |
|
|
|
60,796 |
|
Inventories |
|
|
31,329 |
|
|
|
21,020 |
|
Deferred income taxes |
|
|
16,561 |
|
|
|
18,711 |
|
Income taxes receivable |
|
|
6,806 |
|
|
|
866 |
|
Restricted deposits current |
|
|
774 |
|
|
|
500 |
|
Other |
|
|
10,063 |
|
|
|
5,288 |
|
|
Total current assets |
|
|
312,570 |
|
|
|
305,340 |
|
|
Property and equipment: |
|
|
|
|
|
|
|
|
Land |
|
|
8,586 |
|
|
|
8,643 |
|
Buildings |
|
|
27,209 |
|
|
|
21,868 |
|
Machinery and equipment |
|
|
336,166 |
|
|
|
299,642 |
|
Gas transportation facilities and equipment |
|
|
39,825 |
|
|
|
30,266 |
|
Oil and gas properties |
|
|
92,497 |
|
|
|
76,844 |
|
Mineral interests in oil and gas properties |
|
|
21,248 |
|
|
|
18,165 |
|
|
|
|
|
525,531 |
|
|
|
455,428 |
|
Less accumulated depreciation and depletion |
|
|
(278,786 |
) |
|
|
(208,061 |
) |
|
Net property and equipment |
|
|
246,745 |
|
|
|
247,367 |
|
|
Other assets: |
|
|
|
|
|
|
|
|
Investment in affiliates |
|
|
40,973 |
|
|
|
29,835 |
|
Goodwill |
|
|
90,029 |
|
|
|
85,706 |
|
Other intangible assets, net |
|
|
21,002 |
|
|
|
20,930 |
|
Restricted deposits long term |
|
|
1,155 |
|
|
|
505 |
|
Other |
|
|
6,883 |
|
|
|
7,272 |
|
|
Total other assets |
|
|
160,042 |
|
|
|
144,248 |
|
|
|
|
$ |
719,357 |
|
|
$ |
696,955 |
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
62,575 |
|
|
$ |
67,777 |
|
Current maturities of long term debt |
|
|
20,000 |
|
|
|
13,333 |
|
Accrued compensation |
|
|
36,252 |
|
|
|
36,763 |
|
Accrued insurance expense |
|
|
9,173 |
|
|
|
8,158 |
|
Other accrued expenses |
|
|
17,626 |
|
|
|
15,222 |
|
Acquisition escrow obligation current |
|
|
824 |
|
|
|
550 |
|
Income taxes payable |
|
|
3,254 |
|
|
|
4,200 |
|
Billings in excess of costs and estimated
earnings on uncompleted contracts |
|
|
34,256 |
|
|
|
31,641 |
|
|
Total current liabilities |
|
|
183,960 |
|
|
|
177,644 |
|
|
Noncurrent and deferred liabilities: |
|
|
|
|
|
|
|
|
Long-term debt |
|
|
26,667 |
|
|
|
46,667 |
|
Accrued insurance expense |
|
|
9,947 |
|
|
|
9,736 |
|
Deferred income taxes |
|
|
29,063 |
|
|
|
28,329 |
|
Acquisition escrow obligation long term |
|
|
1,155 |
|
|
|
505 |
|
Other |
|
|
12,468 |
|
|
|
10,304 |
|
|
Total noncurrent and deferred liabilities |
|
|
79,300 |
|
|
|
95,541 |
|
|
Minority interest |
|
|
75 |
|
|
|
398 |
|
Contingencies |
|
|
|
|
|
|
|
|
Stockholders equity: |
|
|
|
|
|
|
|
|
Common stock, par value $.01 per share, 30,000 shares authorized,
19,383 and 19,161 shares issued and
outstanding, respectively |
|
|
194 |
|
|
|
192 |
|
Capital in excess of par value |
|
|
337,528 |
|
|
|
328,301 |
|
Retained earnings |
|
|
128,353 |
|
|
|
101,866 |
|
Accumulated other comprehensive loss |
|
|
(10,053 |
) |
|
|
(6,987 |
) |
|
Total stockholders equity |
|
|
456,022 |
|
|
|
423,372 |
|
|
|
|
$ |
719,357 |
|
|
$ |
696,955 |
|
|
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, |
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
Revenues |
|
$ |
1,008,063 |
|
|
$ |
868,274 |
|
|
$ |
722,768 |
|
Cost of revenues (exclusive of depreciation, depletion, amortization and impairment shown below) |
|
|
756,083 |
|
|
|
638,003 |
|
|
|
536,373 |
|
Selling, general and administrative expense |
|
|
136,687 |
|
|
|
119,937 |
|
|
|
102,603 |
|
Depreciation, depletion and amortization |
|
|
52,840 |
|
|
|
43,620 |
|
|
|
32,853 |
|
Impairment of oil and gas properties |
|
|
28,704 |
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of affiliates |
|
|
14,089 |
|
|
|
8,076 |
|
|
|
4,452 |
|
Interest |
|
|
(3,614 |
) |
|
|
(8,730 |
) |
|
|
(9,781 |
) |
Other, net |
|
|
3,214 |
|
|
|
1,229 |
|
|
|
2,557 |
|
|
Income before income taxes and minority interest |
|
|
47,438 |
|
|
|
67,289 |
|
|
|
48,167 |
|
Income tax expense |
|
|
21,266 |
|
|
|
30,178 |
|
|
|
21,915 |
|
Minority interest |
|
|
362 |
|
|
|
145 |
|
|
|
|
|
|
Net income |
|
$ |
26,534 |
|
|
$ |
37,256 |
|
|
$ |
26,252 |
|
|
Basic income per share |
|
$ |
1.38 |
|
|
$ |
2.23 |
|
|
$ |
1.71 |
|
|
Diluted income per share |
|
$ |
1.37 |
|
|
$ |
2.20 |
|
|
$ |
1.68 |
|
|
Weighted average shares outstanding basic |
|
|
19,191 |
|
|
|
16,670 |
|
|
|
15,320 |
|
Dilutive stock options and unvested shares |
|
|
195 |
|
|
|
268 |
|
|
|
311 |
|
|
Weighted average shares outstanding diluted |
|
|
19,386 |
|
|
|
16,938 |
|
|
|
15,631 |
|
|
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 |
|
|
|
|
(in thousands, except share data) |
|
Shares |
|
|
Amount |
|
|
Par Value |
|
|
Earnings |
|
|
Income (Loss) |
|
|
Total |
|
|
Balance, February 1, 2006 |
|
|
15,233,472 |
|
|
|
152 |
|
|
|
141,023 |
|
|
|
37,893 |
|
|
|
(7,442 |
) |
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,534 |
|
|
|
|
|
|
|
26,534 |
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustments,
net of income benefit of $844 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,549 |
) |
|
|
(2,549 |
) |
Change in unrealized loss on foreign
exchange contracts, net of income tax
benefit of $62 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(96 |
) |
|
|
(96 |
) |
Change in unrecognized pension liability,
net of income tax benefit of $271 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(421 |
) |
|
|
(421 |
) |
|
Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23,468 |
|
|
Issuance of unvested shares |
|
|
38,584 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury stock purchased and subsequently
cancelled |
|
|
(5,357 |
) |
|
|
|
|
|
|
(245 |
) |
|
|
|
|
|
|
|
|
|
|
(245 |
) |
Cumulative effect of adoption of SFAS 158 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(47 |
) |
|
|
|
|
|
|
(47 |
) |
Issuance of stock upon exercise of options |
|
|
189,033 |
|
|
|
2 |
|
|
|
3,321 |
|
|
|
|
|
|
|
|
|
|
|
3,323 |
|
Income tax benefit on exercise of options |
|
|
|
|
|
|
|
|
|
|
2,067 |
|
|
|
|
|
|
|
|
|
|
|
2,067 |
|
Share-based compensation |
|
|
|
|
|
|
|
|
|
|
4,084 |
|
|
|
|
|
|
|
|
|
|
|
4,084 |
|
|
Balance, January 31, 2009 |
|
|
19,382,976 |
|
|
$ |
194 |
|
|
$ |
337,528 |
|
|
$ |
128,353 |
|
|
$ |
(10,053 |
) |
|
$ |
456,022 |
|
|
See Notes to Consolidated Financial Statements.
36
Layne Christensen Company and Subsidiaries
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
Years Ended January 31, |
|
2009 |
|
2008 |
|
2007 |
|
Cash flow from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
26,534 |
|
|
$ |
37,256 |
|
|
$ |
26,252 |
|
Adjustments to reconcile net income to cash from operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
52,840 |
|
|
|
43,620 |
|
|
|
32,853 |
|
Deferred income taxes |
|
|
3,166 |
|
|
|
2,364 |
|
|
|
(2,985 |
) |
Equity in earnings of affiliates |
|
|
(14,089 |
) |
|
|
(8,076 |
) |
|
|
(4,452 |
) |
Dividends received from affiliates |
|
|
2,951 |
|
|
|
2,521 |
|
|
|
1,502 |
|
Minority interest |
|
|
(362 |
) |
|
|
(145 |
) |
|
|
|
|
Gain on disposal of property and equipment |
|
|
(30 |
) |
|
|
(671 |
) |
|
|
(994 |
) |
Impairment of oil and gas properties |
|
|
28,704 |
|
|
|
|
|
|
|
|
|
Gain on sale of mineral concession |
|
|
|
|
|
|
|
|
|
|
(920 |
) |
Share-based compensation |
|
|
4,084 |
|
|
|
3,026 |
|
|
|
2,240 |
|
Share-based compensation excess tax benefits |
|
|
(1,911 |
) |
|
|
(2,313 |
) |
|
|
(1,382 |
) |
Changes in current assets and liabilities, (exclusive of effects of acquisitions and disposals): |
|
|
|
|
|
|
|
|
|
|
|
|
(Increase) decrease in customer receivables |
|
|
13,735 |
|
|
|
(9,616 |
) |
|
|
(7,691 |
) |
Increase in costs and estimated earnings in excess of
billings on uncompleted contracts |
|
|
(1,531 |
) |
|
|
(9,205 |
) |
|
|
(10,044 |
) |
(Increase) decrease in inventories |
|
|
(10,867 |
) |
|
|
(1,788 |
) |
|
|
462 |
|
(Increase) decrease in other current assets |
|
|
(4,949 |
) |
|
|
602 |
|
|
|
598 |
|
Increase (decrease) in accounts payable and accrued expenses |
|
|
(8,478 |
) |
|
|
27,512 |
|
|
|
27,522 |
|
Increase (decrease) in billings in excess of costs and estimated
earnings on uncompleted contracts |
|
|
2,615 |
|
|
|
(2,648 |
) |
|
|
12,312 |
|
Other, net |
|
|
(386 |
) |
|
|
(2,276 |
) |
|
|
(597 |
) |
|
Cash from operating activities |
|
|
92,026 |
|
|
|
80,163 |
|
|
|
74,676 |
|
|
Cash flow used in investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Additions to property and equipment |
|
|
(51,416 |
) |
|
|
(44,177 |
) |
|
|
(36,150 |
) |
Additions to gas transportation facilities and equipment |
|
|
(6,739 |
) |
|
|
(5,327 |
) |
|
|
(12,413 |
) |
Additions to oil and gas properties |
|
|
(19,786 |
) |
|
|
(18,216 |
) |
|
|
(23,075 |
) |
Additions to mineral interests in oil and gas properties |
|
|
(3,082 |
) |
|
|
(5,650 |
) |
|
|
(3,174 |
) |
Payment of cash purchase price adjustment on prior year acquisitions |
|
|
(33 |
) |
|
|
(2,270 |
) |
|
|
(6,120 |
) |
Proceeds from disposal of property and equipment |
|
|
1,172 |
|
|
|
3,333 |
|
|
|
4,646 |
|
Proceeds from sale of mineral concession |
|
|
|
|
|
|
|
|
|
|
920 |
|
Acquisition of businesses, net of cash acquired |
|
|
(7,070 |
) |
|
|
(20,470 |
) |
|
|
(31,305 |
) |
Acquisition of oil and gas properties and mineral interests |
|
|
|
|
|
|
|
|
|
|
(1,988 |
) |
Deposit of cash into restricted accounts |
|
|
(15,200 |
) |
|
|
(2,075 |
) |
|
|
(4,473 |
) |
Release of cash from restricted accounts |
|
|
16,126 |
|
|
|
9,627 |
|
|
|
5,597 |
|
Distribution of restricted cash for prior year acquisition |
|
|
(926 |
) |
|
|
(9,627 |
) |
|
|
|
|
Return of capital from affiliates |
|
|
|
|
|
|
|
|
|
|
411 |
|
|
Cash used in investing activities |
|
|
(86,954 |
) |
|
|
(94,852 |
) |
|
|
(107,124 |
) |
|
Cash flow from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings under revolving credit facilities |
|
|
|
|
|
|
483,800 |
|
|
|
425,925 |
|
Repayments under revolving credit facilities |
|
|
|
|
|
|
(575,400 |
) |
|
|
(403,225 |
) |
Repayments of long-term debt |
|
|
(13,333 |
) |
|
|
|
|
|
|
|
|
Proceeds from public offering of common stock, net of issuance costs |
|
|
|
|
|
|
159,879 |
|
|
|
|
|
Issuances of common stock |
|
|
3,323 |
|
|
|
2,904 |
|
|
|
3,010 |
|
Excess tax benefit on exercise of share-based instruments |
|
|
1,911 |
|
|
|
2,313 |
|
|
|
1,382 |
|
Purchases of treasury stock |
|
|
(245 |
) |
|
|
|
|
|
|
|
|
Contribution by minority interest |
|
|
39 |
|
|
|
543 |
|
|
|
|
|
|
Cash from (used in) financing activities |
|
|
(8,305 |
) |
|
|
74,039 |
|
|
|
27,092 |
|
|
Effects of exchange rate changes on cash |
|
|
(2,670 |
) |
|
|
711 |
|
|
|
380 |
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
(5,903 |
) |
|
|
60,061 |
|
|
|
(4,976 |
) |
Cash and cash equivalents at beginning of year |
|
|
73,068 |
|
|
|
13,007 |
|
|
|
17,983 |
|
|
Cash and cash equivalents at end of year |
|
$ |
67,165 |
|
|
$ |
73,068 |
|
|
$ |
13,007 |
|
|
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, Europe and Brazil. 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. 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
remeasure monetary assets and
liabilities at year-end exchange rates while nonmonetary items are
remeasured at historical rates.
Income and expense accounts are remeasured at the average rates in effect during the year, except
for depreciation, certain cost of revenues and selling expenses which
are remeasured 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 2009, 2008 and 2007 were $91,000,
($430,000) and $95,000, 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 $39,432,000, $33,933,000 and $26,825,000
in 2009, 2008 and 2007, respectively. The lives used for the items within each property
classification are as follows:
|
|
|
|
|
|
|
Years |
|
|
Buildings
|
|
|
15 35 |
|
Machinery and equipment
|
|
|
3 10 |
|
Gas transportation facilities and equipment
|
|
|
15 |
|
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 $11,816,000, $8,504,000 and $4,917,000 in
2009, 2008 and 2007, respectively.
The Company is required to review the carrying value of its oil and gas properties under the
full cost accounting rules of the SEC (the ceiling test). The ceiling limitation is the estimated
after-tax future net revenues from proved oil and gas properties discounted at 10%, plus the cost
of properties not subject to amortization. If our net book value of oil and gas properties, less
related deferred income taxes, is in excess of the calculated ceiling, the excess must be written
off as an expense. 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 forward sales 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. See Note 4 for a
discussion of the impairments recorded in 2009.
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 result ing 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 continue to be appropriate.
39
Cash and Cash Equivalents The Company considers investments with an original maturity of three
months or less when purchased to be cash equivalents. The Companys cash equivalents included
$56,000,000 of short term commercial paper as of January 31, 2008 (none was held as of January 31,
2009). The Companys cash equivalents are subject to potential credit risk. The Companys cash
management and investment policies restrict investments to investment grade, highly liquid
securities. The carrying value of cash and cash equivalents approximates fair value.
Restricted Deposits Restricted deposits consist of escrow funds associated with acquisitions as
described in Note 2 of the Notes to Consolidated Financial Statements.
Accrued Insurance Expense Costs estimated to be incurred in the future for employee health and
welfare benefits, workers compensation, property and casualty insurance programs resulting from
claims which have been incurred are accrued currently. Under the terms of the 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, 2009 and 2008, 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 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.
Supplemental Cash Flow Information The amounts paid for income taxes and interest are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2009 |
|
2008 |
|
2007 |
|
Income taxes |
|
$ |
18,843 |
|
|
$ |
20,704 |
|
|
$ |
15,489 |
|
Interest |
|
|
3,054 |
|
|
|
8,721 |
|
|
|
9,564 |
|
The Company had earnings on restricted deposits of $30,000 and $287,000 for 2009 and 2008,
which was treated as a non-cash item as it was restricted for the account of the escrow
beneficiaries.
During the year ended January 31, 2009, the Company entered into financing obligations for
software licenses amounting to $1,298,000, payable over three years. The associated assets are
recorded as Other Intangible Assets in the balance sheet.
In connection with the Reynolds acquisition (see Note 2), during the year ended January 31,
2008, 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).
In connection with the Collector Wells Acquisition (see Note 2), during the year ended January
31, 2007, the Company issued 45,563 shares of common stock. 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.
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 176,149, 3,000 and 3,000 shares have been excluded from weighted
average shares in 2009, 2008 and 2007, respectively, as their effect was antidilutive. A total of
73,587, none and 668 unvested shares have been excluded from weighted average shares in 2009, 2008
and 2007, respectively, as their effect was antidilutive.
40
Shared-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 (or $0.10 per share basic and diluted earnings) lower for the
year ended January 31, 2007, than if we had continued to account for share-based compensation under
APB 25. As of January 31, 2009, the Company had unrecognized compensation expense of $6,024,000 to
be recognized over a weighted average period of 1.94 years. The Company determines the fair value
of share-based compensation using the Black-Scholes model.
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 as of February
1, 2006.
Other Comprehensive Loss Accumulated balances, net of income taxes, of Other Comprehensive Loss
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized |
|
Accumulated |
|
|
Cumulative |
|
Unrecognized |
|
Loss On |
|
Other |
|
|
Translation |
|
Pension |
|
Exchange |
|
Comprehensive |
(in thousands) |
|
Adjustment |
|
Liability |
|
Contracts |
|
Loss |
|
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 |
) |
Period change |
|
|
(2,549 |
) |
|
|
(421 |
) |
|
|
(96 |
) |
|
|
(3,066 |
) |
|
Balance, January 31, 2009 |
|
$ |
(8,940 |
) |
|
$ |
(1,017 |
) |
|
$ |
(96 |
) |
|
$ |
(10,053 |
) |
|
(2) Acquisitions
Fiscal Year 2009
The company completed three acquisitions during fiscal 2009 as described below:
|
|
On October 24, 2008, the Company acquired 100% of the stock of Meadors Construction Co.,
Inc. (Meadors), a construction company operating primarily in Florida. The operation will be
combined with similar service lines and will serve to foster our further expansion into
Florida and the southeast. |
|
|
On August 7, 2008, the Company acquired certain assets and liabilities of Moore & Tabor, a
geotechnical construction firm operating in California. |
|
|
On May 5, 2008, the Company acquired certain assets and liabilities of Wittman Hydro
Planning Associates (WHPA), a water consulting firm specializing in hydrologic systems
modeling and analysis. |
The aggregate purchase price of $8,926,000, comprised of cash of $8,815,000 ($1,150,000 of which
was placed in escrow to secure certain representations, warranties and idemnifications under the
purchage agreements) and expenses of $111,000 as reflected below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
Meadors |
|
Moore & Tabor |
|
WHPA |
|
Total |
|
Cash |
|
$ |
4,536 |
|
|
$ |
1,785 |
|
|
$ |
2,494 |
|
|
$ |
8,815 |
|
Expenses |
|
|
53 |
|
|
|
33 |
|
|
|
25 |
|
|
|
111 |
|
|
Total purchase price |
|
$ |
4,589 |
|
|
$ |
1,818 |
|
|
$ |
2,519 |
|
|
$ |
8,926 |
|
|
Escrow deposits |
|
$ |
700 |
|
|
$ |
150 |
|
|
$ |
300 |
|
|
$ |
1,150 |
|
|
The preliminary purchase price for each acquisition 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 the acquired entities
are 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 allocations of the purchase price, the acquisitions had the
following effect on the Companys consolidated financial position as of their respective Closing
Dates (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
Meadors |
|
Moore & Tabor |
|
WHPA |
|
Total |
|
Working capital |
|
$ |
2,072 |
|
|
$ |
427 |
|
|
$ |
394 |
|
|
$ |
2,893 |
|
Property and equipment |
|
|
592 |
|
|
|
798 |
|
|
|
40 |
|
|
|
1,430 |
|
Goodwill |
|
|
1,865 |
|
|
|
593 |
|
|
|
1,832 |
|
|
|
4,290 |
|
Other intangible assets |
|
|
60 |
|
|
|
|
|
|
|
250 |
|
|
|
310 |
|
Other assets |
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
3 |
|
|
Total purchase price |
|
$ |
4,589 |
|
|
$ |
1,818 |
|
|
$ |
2,519 |
|
|
$ |
8,926 |
|
|
41
The identifiable intangible assets associated with Meadors consist of non-compete agreements valued
at $60,000 and have a weighted-average useful life of two years. The identifiable intangible
assets associated with WHPA consist of patents valued at $250,000, and have a weighted-average life
of 15 years. The $4,290,000 of aggregate goodwill was assigned to the water infrastructure segment
and is expected to be deductible for tax purposes.
The results of operations of the acquired entities have been included in the Companys
consolidated statements of income commencing with the respective closing dates. Pro forma amounts
for prior periods have not been presented as the acquisitions would not have had a significant
effect on the Companys consolidated revenues or net income.
In addition to the initial purchase price, there is contingent consideration up to a maximum
of $2,500,000 (the WHPA Earnout Amount), which is based on a percentage of the amount by which
WHPAs earnings before interest, taxes, depreciation and amortization exceed a threshold amount
during the 36 months following the acquisition. If earned, up to 80% of the WHPA Earnout Amount may
be paid with Layne common stock, at the Companys discretion. Any portion of the WHPA Earnout
Amount which is ultimately paid will be accounted for as additional purchase consideration.
Fiscal Year 2008
The company completed two acquistions during fiscal 2008 as described below:
|
|
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 similar service lines. |
|
|
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 aggregate purchase price of $20,696,000, comprised of cash of $20,146,000 ($1,665,000 of which
was placed in escrow to secure certain representations, warranties and idemnifications under the
purchage agreements), assumed liabilites of $226,000 and expenses of $324,000, as reflected below:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
Tierdael |
|
Solmetex |
|
Total |
|
Cash |
|
$ |
6,646 |
|
|
$ |
13,500 |
|
|
$ |
20,146 |
|
Assumed liabilities |
|
|
226 |
|
|
|
|
|
|
|
226 |
|
Expenses |
|
|
238 |
|
|
|
86 |
|
|
|
324 |
|
|
Total purchase price |
|
$ |
7,110 |
|
|
$ |
13,586 |
|
|
$ |
20,696 |
|
|
Escrow deposits |
|
$ |
665 |
|
|
$ |
1,000 |
|
|
$ |
1,665 |
|
|
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. Through January 31, 2009, the
contingent earnout consideration earned by SolmeteX was $33,000 which was paid in March 2008.
The purchase price for each acquisition 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.
Based on the Companys allocations of the purchase price, the acquisitions had the following
effect on the Companys consolidated financial position as of their respective Closing Dates (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
Tierdael |
|
Solmetex |
|
Total |
|
Working capital |
|
$ |
3,983 |
|
|
$ |
64 |
|
|
$ |
4,047 |
|
Property and equipment |
|
|
3,127 |
|
|
|
115 |
|
|
|
3,242 |
|
Goodwill |
|
|
|
|
|
|
7,270 |
|
|
|
7,270 |
|
Tradenames |
|
|
|
|
|
|
2,962 |
|
|
|
2,962 |
|
Patents |
|
|
|
|
|
|
2,543 |
|
|
|
2,543 |
|
Deferred income taxes |
|
|
|
|
|
|
551 |
|
|
|
551 |
|
Other intangible assets |
|
|
|
|
|
|
81 |
|
|
|
81 |
|
|
Total purchase price |
|
$ |
7,110 |
|
|
$ |
13,586 |
|
|
$ |
20,696 |
|
|
Of the $6,056,000 of identifiable intangible assets associated with Solmetex, $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 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 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 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 |
|
|
42
The pro forma information provided above is not necessarily indicative of the results of
operations that would actually have resulted if the acquisitions 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 and depreciation and amortization expense on the acquisition adjustments to
property and equipment and other intangible assets.
On September 28, 2005, 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. 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. 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.
Fiscal Year 2007
The company completed two acquisitions during fiscal 2007 as described below:
|
|
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. |
|
|
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. |
The aggregate purchase price of $33,104,000, comprised of cash of $30,674,000, 45,563 shares
of Layne common stock (valued at $1,263,000), cash purchase price adjustments and costs of
$1,167,000 ($240,000 of which were paid in subsequent periods), as reflected below:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
UIG |
|
CWI |
|
Total |
|
Cash |
|
$ |
27,524 |
|
|
$ |
3,150 |
|
|
$ |
30,674 |
|
Layne common stock |
|
|
|
|
|
|
1,263 |
|
|
|
1,263 |
|
Expenses and adjustments |
|
|
138 |
|
|
|
1,029 |
|
|
|
1,167 |
|
|
Total purchase price |
|
$ |
27,662 |
|
|
$ |
5,442 |
|
|
$ |
33,104 |
|
|
The cash portion of the UIG purchase price is net of certain purchase price adjustments based
on the amount of tangible net worth at the closing date, $1,101,000 of which was received by the
Company in February 2007.
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 10,570 and 9,400 shares were released in the years ended January 31, 2008 and 2009,
respectively. The remaining 25,593 shares will be released in fiscal year 2010. 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 for each acquisition has been allocated based on the fair value of the
assets and liabilities acquired, determined based on the historical cost basis of assets and
liabilities, appraisals and other analyses.
Based on the Companys allocations of the purchase price, the acquisitions had the following
effect on the Companys consolidated financial position:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
UIG |
|
CWI |
|
Total |
|
Working capital |
|
$ |
11,723 |
|
|
$ |
1,016 |
|
|
$ |
12,739 |
|
Property and equipment |
|
|
13,602 |
|
|
|
1,580 |
|
|
|
15,182 |
|
Goodwill |
|
|
3,891 |
|
|
|
3,436 |
|
|
|
7,327 |
|
Other intangible assets |
|
|
143 |
|
|
|
|
|
|
|
143 |
|
Other long-term assets |
|
|
69 |
|
|
|
|
|
|
|
69 |
|
Deferred income taxes |
|
|
(1,766 |
) |
|
|
(590 |
) |
|
|
(2,356 |
) |
|
Total purchase price |
|
$ |
27,662 |
|
|
$ |
5,442 |
|
|
$ |
33,104 |
|
|
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 that
year, the unaudited pro forma consolidated revenues, net income and net income per share would have
been as follows:
|
|
|
|
|
(in thousands) |
|
2007 |
|
Revenues |
|
$ |
760,752 |
|
Net income |
|
|
25,199 |
|
Basic earnings per share |
|
|
1.64 |
|
|
Diluted earnings per share |
|
$ |
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 ad-
43
justments 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.
The results of operations of CWI have been included in the Companys consolidated statements
of income commencing with the CWI Closing Date. Pro forma amounts for prior periods are not
presented since the acquisition did not have a significant effect on the Companys consolidated
revenues or net income.
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.
(3) Investments in Affiliates
The Companys investments in affiliates are carried at the fair value of the investment considered
at the date acquired, plus the Companys equity in undistributed earnings from that date. 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, 2009:
|
|
|
|
|
|
|
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 |
|
Centro Internacional de Formacion S.A. (Chile) |
|
|
50.00 |
|
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, 2009, 2008 and 2007, and for
the years then ended, was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2009 |
|
2008 |
|
2007 |
|
Current assets |
|
$ |
99,533 |
|
|
$ |
78,165 |
|
|
$ |
42,584 |
|
Noncurrent assets |
|
|
62,570 |
|
|
|
42,682 |
|
|
|
29,696 |
|
Current liabilities |
|
|
59,844 |
|
|
|
48,496 |
|
|
|
19,857 |
|
Noncurrent liabilities |
|
|
13,319 |
|
|
|
9,373 |
|
|
|
4,755 |
|
Revenues |
|
|
301,268 |
|
|
|
202,649 |
|
|
|
130,090 |
|
Gross profit |
|
|
58,933 |
|
|
|
36,234 |
|
|
|
23,274 |
|
Operating income |
|
|
40,081 |
|
|
|
24,074 |
|
|
|
14,319 |
|
Net income |
|
|
32,626 |
|
|
|
18,762 |
|
|
|
10,862 |
|
The Company had no significant transactions or balances with its affiliates that resulted in
amounts being included in the Consolidated Financial Statements as of January 31, 2009, 2008 and
2007, and for the years then ended.
The Companys equity in undistributed earnings of the affiliates totaled $26,328,000,
$15,190,000 and $9,635,000 as of January 31, 2009, 2008 and 2007, respectively.
(4) Impairment of Oil and Gas Properties
During the fourth quarter of fiscal year 2009, the Company completed its annual determination of
oil and gas reserves for the Energy division. This determination is made according to SEC
guidelines and uses year end gas prices. Gas prices at January 31, 2009, used in the determination
were $3.29 per Mcf, compared to $7.53 per Mcf used in January 31, 2008. As a result of lower
prices, the expected future cash flows and gas reserve volumes were significantly reduced.
Accordingly, in the fourth quarter, the Company recorded a non-cash impairment charge of
$26,690,000, or $16,081,000 after income tax, for the carrying value for the assets in excess of
future net cash flows.
We also recorded an impairment of $2,014,000 during the third quarter of fiscal 2009 related
to the Companys exploration project in Chile, begun in fiscal 2008. Following initial core testing
and further evaluation of infrastructure requirements, it was determined that recovery of our
investment was not likely and the costs were written off.
We
did not have ceiling test or any other oil and gas property impairments during the years
ended January 31, 2008 and 2007.
(5) Goodwill and Other Intangible Assets
Goodwill and other intangible assets consisted of the following as of January 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
|
Gross |
|
|
|
|
|
Gross |
|
|
|
|
Carrying |
|
Accumulated |
|
Carrying |
|
Accumulated |
(in thousands) |
|
Amount |
|
Amortization |
|
Amount |
|
Amortization |
|
Goodwill |
|
$ |
90,029 |
|
|
$ |
|
|
|
$ |
85,706 |
|
|
$ |
|
|
|
Amortizable intangible assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tradenames |
|
$ |
18,962 |
|
|
$ |
(2,275 |
) |
|
$ |
18,962 |
|
|
$ |
(1,464 |
) |
Customer-related |
|
|
332 |
|
|
|
(332 |
) |
|
|
332 |
|
|
|
(340 |
) |
Patents |
|
|
3,152 |
|
|
|
(569 |
) |
|
|
2,902 |
|
|
|
(307 |
) |
Non-competition agreements |
|
|
439 |
|
|
|
(387 |
) |
|
|
379 |
|
|
|
(273 |
) |
Other |
|
|
2,590 |
|
|
|
(910 |
) |
|
|
1,292 |
|
|
|
(553 |
) |
|
Total amortizable intangible assets |
|
$ |
25,475 |
|
|
$ |
(4,473 |
) |
|
$ |
23,867 |
|
|
$ |
(2,937 |
) |
|
44
Amortizable intangible assets are being amortized over their estimated useful lives of two to 40
years with a weighted average amortization period of 25 years. Total amortization expense for other
intangible assets was $1,536,000, $1,123,000 and $1,068,000 in 2009, 2008 and 2007, respectively.
Amortization expense for the subsequent five fiscal years is estimated as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
2010 |
|
$ |
1,535 |
|
2011 |
|
|
1,520 |
|
2012 |
|
|
1,191 |
|
2013 |
|
|
1,037 |
|
2014 |
|
|
1,037 |
|
Of the
total goodwill as of January 31, 2009 and 2008, $19,451,000 and
$13,578,000, 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, 2007 |
|
$ |
950 |
|
|
$ |
64,234 |
|
|
$ |
65,184 |
|
Additions |
|
|
|
|
|
|
20,522 |
|
|
|
20,522 |
|
|
Balance, January 31, 2008 |
|
|
950 |
|
|
|
84,756 |
|
|
|
85,706 |
|
Additions |
|
|
|
|
|
|
4,323 |
|
|
|
4,323 |
|
|
Balance, January 31, 2009 |
|
$ |
950 |
|
|
$ |
89,079 |
|
|
$ |
90,029 |
|
|
(6) Other Income (Expense)
Other income (expense) consisted of the following for the years ended January 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2009 |
|
2008 |
|
2007 |
|
Gain from disposal of
property and equipment |
|
$ |
30 |
|
|
$ |
671 |
|
|
$ |
994 |
|
Settlement income |
|
|
2,173 |
|
|
|
|
|
|
|
|
|
Gain on sale of mineral concession |
|
|
|
|
|
|
|
|
|
|
920 |
|
Interest income |
|
|
1,065 |
|
|
|
953 |
|
|
|
187 |
|
Exchange gain (loss) |
|
|
91 |
|
|
|
(430 |
) |
|
|
95 |
|
Miscellaneous, net |
|
|
(145 |
) |
|
|
35 |
|
|
|
361 |
|
|
Total |
|
$ |
3,214 |
|
|
$ |
1,229 |
|
|
$ |
2,557 |
|
|
In 2009, the Company initiated litigation against former officers of a subsidiary and associated
energy production companies. During September 2008, the Company entered into a settlement agreement
whereby it will receive certain payments over a period through September 2009. The payments
received, net of attorney fees, were recorded as settlement income in 2009.
The gain 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.
(7) Costs and Estimated Earnings on Uncompleted Contracts
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2009 |
|
2008 |
|
Costs incurred on uncompleted contracts |
|
$ |
811,011 |
|
|
$ |
586,459 |
|
Estimated earnings |
|
|
175,308 |
|
|
|
147,796 |
|
|
|
|
|
986,319 |
|
|
|
734,255 |
|
Less: Billings to date |
|
|
956,937 |
|
|
|
705,100 |
|
|
Total |
|
$ |
29,382 |
|
|
$ |
29,155 |
|
|
Included in accompanying balance sheets
under the following captions: |
|
|
|
|
|
|
|
|
Costs and estimated earnings in excess
of billings on uncompleted contracts |
|
$ |
63,638 |
|
|
$ |
60,796 |
|
Billings in excess of costs and estimated
earnings on uncompleted contracts |
|
|
(34,256 |
) |
|
|
(31,641 |
) |
|
Total |
|
$ |
29,382 |
|
|
$ |
29,155 |
|
|
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, 2009 and 2008, the Company held unbilled contract
retainage amounts of $39,149,000 and $33,201,000, respectively.
(8) Income Taxes
Income (loss) before income taxes is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2009 |
|
2008 |
|
2007 |
|
Domestic |
|
$ |
25,962 |
|
|
$ |
46,649 |
|
|
$ |
31,928 |
|
Foreign |
|
|
21,476 |
|
|
|
20,640 |
|
|
|
16,239 |
|
|
Total |
|
$ |
47,438 |
|
|
$ |
67,289 |
|
|
$ |
48,167 |
|
|
Components of income tax expense are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2009 |
|
2008 |
|
2007 |
|
Currently due: |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
$ |
7,696 |
|
|
$ |
17,226 |
|
|
$ |
13,150 |
|
State and local |
|
|
1,820 |
|
|
|
3,125 |
|
|
|
2,541 |
|
Foreign |
|
|
8,433 |
|
|
|
7,099 |
|
|
|
8,615 |
|
|
|
|
|
17,949 |
|
|
|
27,450 |
|
|
|
24,306 |
|
|
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
|
1,355 |
|
|
|
1,632 |
|
|
|
(941 |
) |
State and local |
|
|
1,085 |
|
|
|
288 |
|
|
|
(649 |
) |
Foreign |
|
|
877 |
|
|
|
808 |
|
|
|
(801 |
) |
|
|
|
|
3,317 |
|
|
|
2,728 |
|
|
|
(2,391 |
) |
|
Total |
|
$ |
21,266 |
|
|
$ |
30,178 |
|
|
$ |
21,915 |
|
|
45
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) |
|
2009 |
|
2008 |
|
|
Assets |
|
Liabilities |
|
Total |
|
Assets |
|
Liabilities |
|
Total |
|
Contract income |
|
$ |
659 |
|
|
$ |
|
|
|
$ |
659 |
|
|
$ |
4,545 |
|
|
$ |
|
|
|
$ |
4,545 |
|
Inventories |
|
|
1,912 |
|
|
|
(339 |
) |
|
|
1,573 |
|
|
|
2,125 |
|
|
|
(271 |
) |
|
|
1,854 |
|
Accrued insurance |
|
|
4,395 |
|
|
|
|
|
|
|
4,395 |
|
|
|
2,809 |
|
|
|
|
|
|
|
2,809 |
|
Other accrued liabilities |
|
|
1,720 |
|
|
|
|
|
|
|
1,720 |
|
|
|
2,234 |
|
|
|
|
|
|
|
2,234 |
|
Prepaid expenses |
|
|
|
|
|
|
(718 |
) |
|
|
(718 |
) |
|
|
|
|
|
|
(684 |
) |
|
|
(684 |
) |
Bad debts |
|
|
3,028 |
|
|
|
|
|
|
|
3,028 |
|
|
|
2,866 |
|
|
|
|
|
|
|
2,866 |
|
Employee compensation |
|
|
5,010 |
|
|
|
|
|
|
|
5,010 |
|
|
|
4,905 |
|
|
|
|
|
|
|
4,905 |
|
Other |
|
|
916 |
|
|
|
(22 |
) |
|
|
894 |
|
|
|
481 |
|
|
|
(299 |
) |
|
|
182 |
|
|
Total current |
|
|
17,640 |
|
|
|
(1,079 |
) |
|
|
16,561 |
|
|
|
19,965 |
|
|
|
(1,254 |
) |
|
|
18,711 |
|
|
Cumulative translation adjustment |
|
|
5,508 |
|
|
|
|
|
|
|
5,508 |
|
|
|
4,665 |
|
|
|
|
|
|
|
4,665 |
|
Buildings, machinery and equipment |
|
|
336 |
|
|
|
(19,035 |
) |
|
|
(18,699 |
) |
|
|
440 |
|
|
|
(16,251 |
) |
|
|
(15,811 |
) |
Gas transportation facilities and equipment |
|
|
|
|
|
|
(6,471 |
) |
|
|
(6,471 |
) |
|
|
|
|
|
|
(3,799 |
) |
|
|
(3,799 |
) |
Mineral interests and oil and gas properties |
|
|
|
|
|
|
(9,024 |
) |
|
|
(9,024 |
) |
|
|
|
|
|
|
(14,702 |
) |
|
|
(14,702 |
) |
Intangible assets |
|
|
731 |
|
|
|
(5,478 |
) |
|
|
(4,747 |
) |
|
|
744 |
|
|
|
(5,788 |
) |
|
|
(5,044 |
) |
Tax deductible goodwill |
|
|
1,069 |
|
|
|
|
|
|
|
1,069 |
|
|
|
2,831 |
|
|
|
|
|
|
|
2,831 |
|
Accrued insurance |
|
|
4,051 |
|
|
|
|
|
|
|
4,051 |
|
|
|
3,988 |
|
|
|
|
|
|
|
3,988 |
|
Pension |
|
|
936 |
|
|
|
(337 |
) |
|
|
599 |
|
|
|
781 |
|
|
|
(689 |
) |
|
|
92 |
|
Stock-based compensation |
|
|
2,169 |
|
|
|
|
|
|
|
2,169 |
|
|
|
1,352 |
|
|
|
|
|
|
|
1,352 |
|
Unremitted foreign earnings |
|
|
|
|
|
|
(4,878 |
) |
|
|
(4,878 |
) |
|
|
|
|
|
|
(3,036 |
) |
|
|
(3,036 |
) |
Other |
|
|
1,547 |
|
|
|
(187 |
) |
|
|
1,360 |
|
|
|
1,230 |
|
|
|
(95 |
) |
|
|
1,135 |
|
|
Total noncurrent |
|
|
16,347 |
|
|
|
(45,410 |
) |
|
|
(29,063 |
) |
|
|
16,031 |
|
|
|
(44,360 |
) |
|
|
(28,329 |
) |
|
Total |
|
$ |
33,987 |
|
|
$ |
(46,489 |
) |
|
$ |
(12,502 |
) |
|
$ |
35,996 |
|
|
$ |
(45,614 |
) |
|
$ |
(9,618 |
) |
|
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 $400,000 that expire
between 2013 and 2021.
As of January 31, 2009, undistributed earnings of foreign subsidiaries and certain foreign
affiliates included $45,800,000 for which no federal income or foreign withholding taxes have been
provided. These earnings, which are considered to be in-
vested 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.
A reconciliation of the total income tax expense to the statutory federal rate is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
|
|
|
|
|
Effective |
|
|
|
|
|
Effective |
|
|
|
|
|
Effective |
(in thousands) |
|
Amount |
|
Rate |
|
Amount |
|
Rate |
|
Amount |
|
Rate |
|
Income tax at statutory rate |
|
$ |
16,603 |
|
|
|
35.0 |
% |
|
$ |
23,551 |
|
|
|
35.0 |
% |
|
$ |
16,858 |
|
|
|
35.0 |
% |
State income tax, net |
|
|
1,888 |
|
|
|
4.0 |
|
|
|
2,219 |
|
|
|
3.3 |
|
|
|
1,230 |
|
|
|
2.6 |
|
Difference in tax expense resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nondeductible expenses |
|
|
972 |
|
|
|
2.0 |
|
|
|
1,041 |
|
|
|
1.5 |
|
|
|
842 |
|
|
|
1.8 |
|
Taxes on foreign affiliates |
|
|
(2,873 |
) |
|
|
(6.1 |
) |
|
|
(1,370 |
) |
|
|
(2.0 |
) |
|
|
(774 |
) |
|
|
(1.6 |
) |
Taxes on foreign operations |
|
|
4,357 |
|
|
|
9.2 |
|
|
|
5,033 |
|
|
|
7.5 |
|
|
|
3,461 |
|
|
|
7.2 |
|
Other, net |
|
|
319 |
|
|
|
0.7 |
|
|
|
(296 |
) |
|
|
(0.5 |
) |
|
|
298 |
|
|
|
0.5 |
|
|
|
|
$ |
21,266 |
|
|
|
44.8 |
% |
|
$ |
30,178 |
|
|
|
44.8 |
% |
|
$ |
21,915 |
|
|
|
45.5 |
% |
|
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.
46
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as
follows:
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2009 |
|
2008 |
|
Balance, beginning of year |
|
$ |
6,642 |
|
|
$ |
6,152 |
|
Additions based on tax
positions related
to current year |
|
|
3,033 |
|
|
|
3,248 |
|
Additions for tax positions of
prior years |
|
|
353 |
|
|
|
772 |
|
Impact of changes in exchange
rate |
|
|
(582 |
) |
|
|
79 |
|
Settlements with tax
authorities |
|
|
27 |
|
|
|
(162 |
) |
Reductions for tax positions
of prior years |
|
|
(1,031 |
) |
|
|
(2,995 |
) |
Reductions due to the lapse of
statutes of limitation |
|
|
(830 |
) |
|
|
(452 |
) |
|
Balance, end of year |
|
$ |
7,612 |
|
|
$ |
6,642 |
|
|
Substantially all of the unrecognized tax benefits recorded at January 31, 2009 and 2008, 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 January
31, 2009 and 2008, the Company had $2,872,000 and $2,752,000, respectively, of interest and
penalties accrued associated with unrecognized tax benefits. The liability of interest and
penalties increased $120,000 and $970,000 during the years ended January 31, 2009 and 2008,
respectively.
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, 2005, during the year ended January 31, 2009. The Company is not currently
under IRS examination for its remaining open tax years, and the statutes of limitation will expire
for those years between 2010 through 2012. 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
2010 and 2012.
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 2004 through 2009 remain open to examination.
(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, 2009, are as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
2010 |
|
$ |
12,902 |
|
2011 |
|
|
8,002 |
|
2012 |
|
|
6,281 |
|
2013 |
|
|
5,038 |
|
2014 |
|
|
3,434 |
|
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
$31,660,000, $27,977,000 and $22,866,000 in 2009, 2008 and 2007, 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 retirements 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, 2009, 2008 and 2007 were $185,000, $170,000 and $243,000,
respectively. Accretion during the same periods was $77,000, $60,000 and $43,000, respectively. The carrying
values of the asset retirement obligations as of January 31, 2009 and 2008 were $1,305,000 and
$1,043,000, respectively, and are 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. Depending on market conditions, the Company expects to use assets of the plan to settle its
benefit obligation during 2010.
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
47
previously netted against the plans funded status in the Companys balance sheet
pursuant to the provisions of SFAS 87. These amounts are being 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 are being 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 adoption of SFAS 158 had no effect on the Companys consolidated statements of income for
any period presented. 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plan |
|
|
Prior to |
|
|
|
|
|
Post |
|
|
Adoption |
|
|
|
|
|
Adoption |
|
|
of SFAS |
|
|
|
|
|
of SFAS |
(in thousands) |
|
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 |
) |
|
Beginning with the Companys fiscal year ended January 31, 2009, SFAS 158 also requires a
company to measure its plan assets and benefit obligations as of its fiscal balance sheet date. The
Company had previously used December 31 as its measurement 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 recorded a $47,000 decrease to retained earnings as of February 1, 2008.The
following table sets forth the plans funded status as of the measurement dates and the amounts
recognized in the Companys Consolidated Balance Sheets at January 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2009 |
|
2008 |
|
Change in benefit obligation: |
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year |
|
$ |
7,326 |
|
|
$ |
8,191 |
|
Service cost |
|
|
|
|
|
|
|
|
Interest cost |
|
|
513 |
|
|
|
450 |
|
Actuarial gain (loss) |
|
|
(195 |
) |
|
|
(902 |
) |
Benefits paid |
|
|
(450 |
) |
|
|
(413 |
) |
|
Benefit obligation at end of year |
|
|
7,194 |
|
|
|
7,326 |
|
|
Change in plan assets: |
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning
of year |
|
|
9,109 |
|
|
|
9,049 |
|
Actual return on plan
assets |
|
|
(553 |
) |
|
|
473 |
|
Benefits paid |
|
|
(450 |
) |
|
|
(413 |
) |
|
Fair value of plan assets at end of
year |
|
|
8,106 |
|
|
|
9,109 |
|
|
Funded status recognized as other
non-current assets |
|
$ |
912 |
|
|
$ |
1,783 |
|
|
Net periodic pension cost for 2009, 2008 and 2007 includes the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2009 |
|
2008 |
|
2007 |
|
Service cost and expenses |
|
$ |
105 |
|
|
$ |
96 |
|
|
$ |
86 |
|
Interest cost |
|
|
513 |
|
|
|
450 |
|
|
|
452 |
|
Expected return on assets |
|
|
(592 |
) |
|
|
(536 |
) |
|
|
(529 |
) |
Net amortization |
|
|
149 |
|
|
|
215 |
|
|
|
271 |
|
|
Net periodic pension cost |
|
$ |
175 |
|
|
$ |
225 |
|
|
$ |
280 |
|
|
The Company has recognized the full amount of its actuarially determined pension liability. The
estimated net loss for the plan that is expected to be amortized from accumulated other
comprehensive income to net periodic benefit cost during 2010 is $105,000.
The weighted average assumptions used to determine the benefit obligation and the net periodic
pension cost for the years ending January 31, 2009, 2008 and 2007, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
Discount rate |
|
|
6.92 |
% |
|
|
6.49 |
% |
|
|
5.90 |
% |
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 |
|
Smoothed |
|
Smoothed |
|
|
value |
|
value |
|
value |
The estimated long-term rate of return on assets was developed based on the historical returns and
the future expectations for returns for each asset class, as well as the target asset allocation of
the pension portfolio. Benefit level assumptions for 2009, 2008 and 2007 are based on fixed amounts
per year of credited service.
The percentage of the fair value of total plan assets for each major category of plan assets
as of the measurement date follows:
|
|
|
|
|
|
|
|
|
|
|
As of |
|
|
January 31, |
|
December 31, |
|
|
2009 |
|
2007 |
|
Equity securities |
|
|
|
% |
|
|
60 |
% |
Debt securities |
|
|
13 |
|
|
|
13 |
|
Cash and cash equivalents |
|
|
87 |
|
|
|
27 |
|
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 |
|
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 manager by the Company. As of January 31, 2009, in anticipation of the Companys
decision to settle the obligations of the plan in 2010,
48
the asset allocation was shifted out of
equity securities into short-term bonds.
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. |
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, 2009, plan year.
The Company does not expect to make contributions to the plan during the 2009 calendar year.
The estimated benefit payments expected to be paid in each of the next five fiscal years and
in aggregate for the five fiscal years thereafter are as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
2010 |
|
$ |
425 |
|
2011 |
|
|
436 |
|
2012 |
|
|
447 |
|
2013 |
|
|
456 |
|
2014 |
|
|
460 |
|
2015-2019 |
|
|
4,366 |
|
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, 2009 and 2008, were $2,432,000 and
$2,021,000. Net periodic pension cost of the supplemental retirement benefits for 2009, 2008 and
2007 include the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2009 |
|
2008 |
|
2007 |
|
Service cost |
|
$ |
269 |
|
|
$ |
176 |
|
|
$ |
100 |
|
Interest cost |
|
|
142 |
|
|
|
103 |
|
|
|
88 |
|
|
Net periodic pension cost |
|
$ |
411 |
|
|
$ |
279 |
|
|
$ |
188 |
|
|
The Company also participates in a number of defined benefit, multi-employer plans. These
plans are union-sponsored, and the Company makes contributions equal to the amounts accrued for
pension expense. Total union pension expense for these plans was $3,780,000, $2,961,000 and
$3,062,000 in 2009, 2008 and 2007, 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 $4,215,000,
$3,777,000 and $2,996,000 in 2009, 2008 and 2007, respectively.
In January 2006, the Company initiated a deferred compensation plan for certain management
employees. Participants may elect to defer up to 25% of their salaries, and beginning in January
2007, up to 50% of their bonuses to the plan. Company matching contributions, and the vesting
period of those contributions, are established at the discretion of the Company. Employee deferrals
are vested at all times. The total amount deferred, including Company matching, for 2009, 2008 and
2007 was $1,939,000, $2,237,000 and $1,257,000, respectively. The total liability for deferred
compensation was $4,229,000 and $3,501,000 as of January 31, 2009 and 2008, respectively.
(11) Indebtedness
The Company maintains an agreement (Master Shelf Agreement) whereby it can issue up to
$105,000,000 in unsecured notes before September 15, 2009. On July 31, 2003, 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.
49
The Company also maintains a revolving credit facility under an Amended and Restated Loan
Agreement (the Credit Agreement) with Bank of America, 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, 2009, there
were letters of credit of $15,841,000 and no borrowings outstanding on the Credit Agreement
resulting in available capacity of $184,159,000.
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, 2009.
Compliance with the financial covenants is required on a quarterly basis, using the most
recent four fiscal quarters. The Companys fixed charge coverage ratio and leverage ratio
covenants are based on ratios utilizing adjusted EBITDA and adjusted EBITDAR, as defined in the
agreements. Adjusted EBITDA is generally defined as consolidated net income excluding net interest
expense, provision for income taxes, gains or losses from extraordinary items, gains or losses from
the sale of capital assets, non-cash items including depreciation and amortization, and share-based
compensation. Equity in earnings of affiliates is included only to the extent of dividends or
distributions received. Adjusted EBITDAR is defined as adjusted EBITDA, plus rent expense. The
Companys tangible net worth covenant is based on stockholders equity less intangible assets. All
of these measures are considered non-GAAP financial measures and are not intended to be in
accordance with accounting principles generally accepted in the United States.
The Companys minimum fixed charge coverage ratio covenant is the ratio of adjusted EBITDAR to
the sum of fixed charges. Fixed charges consist of rent expense, interest expense, and principal
payments of long-term debt. The Companys leverage ratio covenant is the ratio of total funded
indebtedness to adjusted EBITDA. Total funded indebtedness generally consists of outstanding debt,
capital leases, unfunded pension liabilities, asset retirement obligations and escrow liabilities.
The Companys tangible net worth covenant is measured based on stockholders equity, less
intangible assets, as compared to a threshold amount defined in the agreements. The threshold is
adjusted over time based on a percentage of net income and the proceeds from the issuance of equity
securities.
As of January 31, 2009 and 2008, the Companys actual and required covenant levels were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual |
|
Required |
|
Actual |
|
Required |
(in thousands) |
|
2009 |
|
2009 |
|
2008 |
|
2008 |
|
Minimum fixed charge
coverage ratio |
|
|
4.22 |
|
|
|
1.50 |
|
|
|
5.65 |
|
|
|
1.50 |
|
Maximum leverage ratio |
|
|
0.44 |
|
|
|
3.00 |
|
|
|
0.57 |
|
|
|
3.25 |
|
Minimum tangible net worth |
|
$ |
340,280 |
|
|
$ |
291,237 |
|
|
$ |
313,571 |
|
|
$ |
274,647 |
|
Maximum borrowings outstanding under the Companys credit agreements during 2009 and 2008 were
$60,000,000 and $186,000,000, respectively, and the average outstanding borrowings were $52,200,000
and $127,300,000 , respectively. The weighted average interest rates, including amortization of
loan costs, were 6.4% 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 2009, 2008 and 2007 was $183,000, $169,000 and $161,000,
respectively. Amortization of loan costs is included in interest expense in the consolidated
statements of income.
Debt outstanding as of January 31, 2009 and 2008, whose carrying value approximates fair
market value, was as follows:
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2009 |
|
2008 |
|
Long-term debt: |
|
|
|
|
|
|
|
|
Credit Agreement |
|
$ |
|
|
|
$ |
|
|
Senior Notes |
|
|
46,667 |
|
|
|
60,000 |
|
|
Total debt |
|
|
46,667 |
|
|
|
60,000 |
|
Less current maturities |
|
|
(20,000 |
) |
|
|
(13,333 |
) |
|
Total long-term debt |
|
$ |
26,667 |
|
|
$ |
46,667 |
|
|
As of January 31, 2009, debt outstanding will mature by fiscal year as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
2010 |
|
$ |
20,000 |
|
2011 |
|
|
20,000 |
|
2012 |
|
|
6,667 |
|
Thereafter |
|
|
|
|
50
(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, 2009, the Company had committed to deliver 6,183,000 million
British Thermal Units (MMBtu) of natural gas through March 2010 at prices ranging from $7.68 to
$8.52 per MMBtu through March 2009, and from $7.61 to $10.67 per MMBtu from April 2009 to March
2010.
The fixed-price physical delivery forward sales 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, 2009, was
$27,950,000.
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. The Company does not enter into foreign currency
derivative financial instruments for speculative or trading purposes.
As of January 31, 2009, the Company held option contracts with an aggregate U.S. dollar
notional value of $9,800,000, which are intended to hedge exposure to Australian dollar
fluctuations. The contracts settle in various increments through January 31, 2010. The fair value
of the instruments of $158,000 as of January 31, 2009, is recorded in other current liabilities,
and net of income taxes of $62,000, in accumulated other comprehensive income.
(13) Stock and Stock Option Plans
In October 2008, the Company amended the Rights Agreement signed in October 1998 whereby the
Company 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 20% 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 $75.00. The
Company is entitled to redeem the Right at $.01 per Right at any time before a person has acquired
20% or more of the Companys outstanding common stock. The Rights expire three years from the date
of grant.
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.
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 at a price fixed by the Board of
Directors or a committee. As of January 31, 2009, there were an aggregate of 1,450,000 shares
registered under the plans, 467,000 of which remain available to be granted under the plans. Of
this amount, 250,000 shares may only be granted as stock in payment of bonuses and 217,000 may be
issued as stock or options. Subsequent to January 31, 2009, the Company has issued substantially
all remaining available options. 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. In the year ended January 31, 2009, the
Company purchased and subsequently cancelled 5,357 shares of stock related to settlement of
withholding obligations.
The Company recognized $1,369,000 and $638,000 in compensation cost of nonvested shares for
the years ended January 31, 2009 and 2008, respectively. A summary of nonvested share activity for
2009, 2008 and 2007 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
Aggregate |
|
|
|
|
|
|
Average |
|
Intrinsic |
|
|
Number of |
|
Grant Date |
|
Value (in |
|
|
Shares |
|
Fair Value |
|
thousands) |
|
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 |
|
|
|
|
|
|
|
|
|
|
Granted |
|
|
38,584 |
|
|
|
37.39 |
|
|
|
|
|
Vested |
|
|
(22,638 |
) |
|
|
42.76 |
|
|
|
|
|
|
Nonvested stock at
January 31, 2009 |
|
|
89,809 |
|
|
$ |
40.48 |
|
|
$ |
1,417 |
|
|
Significant option groups outstanding at January 31, 2009, and related exercise price and
remaining contractual term follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contractual |
Grant |
|
Options |
|
Options |
|
Exercise |
|
Term |
Date |
|
Outstanding |
|
Exercisable |
|
Price |
|
(Months) |
|
4/99 |
|
|
7,741 |
|
|
|
7,741 |
|
|
|
4.125 |
|
|
|
3 |
|
2/00 |
|
|
1,900 |
|
|
|
1,900 |
|
|
|
5.500 |
|
|
|
13 |
|
4/00 |
|
|
13,794 |
|
|
|
13,794 |
|
|
|
3.495 |
|
|
|
15 |
|
6/04 |
|
|
20,000 |
|
|
|
20,000 |
|
|
|
16.600 |
|
|
|
65 |
|
6/04 |
|
|
77,376 |
|
|
|
77,376 |
|
|
|
16.650 |
|
|
|
65 |
|
6/05 |
|
|
10,000 |
|
|
|
10,000 |
|
|
|
17.540 |
|
|
|
77 |
|
9/05 |
|
|
157,000 |
|
|
|
94,500 |
|
|
|
23.050 |
|
|
|
80 |
|
1/06 |
|
|
191,481 |
|
|
|
138,922 |
|
|
|
27.870 |
|
|
|
84 |
|
6/06 |
|
|
10,000 |
|
|
|
10,000 |
|
|
|
29.290 |
|
|
|
89 |
|
6/06 |
|
|
70,000 |
|
|
|
35,000 |
|
|
|
29.290 |
|
|
|
89 |
|
6/07 |
|
|
65,625 |
|
|
|
13,125 |
|
|
|
42.260 |
|
|
|
101 |
|
7/07 |
|
|
33,000 |
|
|
|
8,250 |
|
|
|
42.760 |
|
|
|
102 |
|
9/07 |
|
|
3,000 |
|
|
|
750 |
|
|
|
55.480 |
|
|
|
104 |
|
2/08 |
|
|
74,524 |
|
|
|
|
|
|
|
35.710 |
|
|
|
108 |
|
1/09 |
|
|
6,000 |
|
|
|
6,000 |
|
|
|
24.010 |
|
|
|
119 |
|
|
|
|
|
741,441 |
|
|
|
437,358 |
|
|
|
|
|
|
|
|
|
|
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 10 years from the date of grant
51
and generally vest ratably over periods of three to five years. Certain option awards provide for
accelerated vesting if there is a change of control (as defined in the plans) and for equitable
adjustments in the event of changes in the Companys equity structure. The Company does not expect
any unvested shares to be forfeited. The fair value of options at date of grant was estimated using
the Black-Scholes model. The weighted average fair value at the date of grant for options granted
during 2009, 2008 and 2007 was $16.30, $20.82 and $12.68, respectively. The fair value was based on an expected
life of six years, no dividend yield, an average risk-free rate of
2.48%, 4.79% and 4.95%, respectively,
and assumed volatility of 48%, 38% and 35%, respectively.
Stock option transactions for 2009, 2008 and 2007 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
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at
January 31, 2008 |
|
|
392,585 |
|
|
$ |
19.944 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted |
|
|
80,524 |
|
|
|
34.838 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(189,033 |
) |
|
|
17.578 |
|
|
|
|
|
|
|
6,385 |
|
Canceled |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expired |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at
January 31, 2009 |
|
|
741,441 |
|
|
$ |
27.435 |
|
|
|
6.99 |
|
|
|
279 |
|
|
Exercisable at
January 31, 2009 |
|
|
437,358 |
|
|
$ |
23.659 |
|
|
|
6.39 |
|
|
|
279 |
|
|
(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, bundled 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 protec tion 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 other 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.
On April 30, 2008, Levelland/Hockley County Ethanol, LLC (Levelland) filed a Complaint
against the Company in the District Court for Hockley County, Texas. On May 28, 2008, the Company
removed the case to the United States District Court for the Northern District of Texas, Lubbock
Division. On June 2, 2008, Levelland filed a First Amended Complaint against the Company in the
Federal District Court for the Northern District of Texas, Lubbock Division. Levelland owns an
ethanol plant located in Levelland, Texas. In July 2007, Levelland entered into a lease agreement
with the Company for certain water treatment equipment for the ethanol plant. Levelland alleges
that the equipment leased from the Company fails to treat the water coming into the ethanol plant
to required levels. The First Amended Complaint seeks damages for breach of contract, breach of
warranty, violation of the Texas Deceptive Trade Practices Act, negligence, negligent
misrepresentation and fraud, in connection with the design and construction of the water treatment
facility. The Company believes that it has meritorious defenses to the claims, intends to
vigorously defend against them and does not believe that the claims will have a material adverse
effect upon its business, 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
52
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:
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 and
wastewater treatment facilities, 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, Ranney collector wells, sewer rehabilitation and water and wastewater transmission
lines. The division also offers environmental services to assess and monitor groundwater
contaminants.
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, primarily
concentrating on projects in the mid-continent region of the United States.
Other
Other includes two small specialty energy service companies and any other specialty operations
not included in one of the other divisions.
53
Financial information for the Companys segments is presented below. 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 and deferred income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
As of and for the Year Ended January 31, |
|
2009 |
|
2008 |
|
2007 |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Water infrastructure |
|
$ |
766,957 |
|
|
$ |
639,584 |
|
|
$ |
531,916 |
|
Mineral exploration |
|
|
188,918 |
|
|
|
178,482 |
|
|
|
148,911 |
|
Energy |
|
|
46,352 |
|
|
|
39,749 |
|
|
|
27,081 |
|
Other |
|
|
5,836 |
|
|
|
10,459 |
|
|
|
14,860 |
|
|
Total revenues |
|
$ |
1,008,063 |
|
|
$ |
868,274 |
|
|
$ |
722,768 |
|
|
Equity in earnings of affiliates |
|
|
|
|
|
|
|
|
|
|
|
|
Mineral exploration |
|
$ |
14,089 |
|
|
$ |
8,076 |
|
|
$ |
4,452 |
|
|
Income (loss) before income taxes and minority interests |
|
|
|
|
|
|
|
|
|
|
|
|
Water infrastructure |
|
$ |
48,399 |
|
|
$ |
42,995 |
|
|
$ |
35,000 |
|
Mineral exploration |
|
|
39,260 |
|
|
|
37,452 |
|
|
|
26,557 |
|
Energy |
|
|
(12,401 |
) |
|
|
13,075 |
|
|
|
10,680 |
|
Other |
|
|
1,280 |
|
|
|
3,696 |
|
|
|
4,094 |
|
Unallocated corporate expenses |
|
|
(25,486 |
) |
|
|
(21,199 |
) |
|
|
(18,383 |
) |
Interest |
|
|
(3,614 |
) |
|
|
(8,730 |
) |
|
|
(9,781 |
) |
|
Total income before income taxes and minority interests |
|
$ |
47,438 |
|
|
$ |
67,289 |
|
|
$ |
48,167 |
|
|
|
Investment in affiliates |
|
|
|
|
|
|
|
|
|
|
|
|
Mineral exploration |
|
$ |
40,973 |
|
|
$ |
29,835 |
|
|
$ |
24,280 |
|
|
Total assets |
|
|
|
|
|
|
|
|
|
|
|
|
Water infrastructure |
|
$ |
422,383 |
|
|
$ |
388,491 |
|
|
$ |
321,406 |
|
Mineral exploration |
|
|
125,588 |
|
|
|
110,064 |
|
|
|
89,826 |
|
Energy |
|
|
100,309 |
|
|
|
112,363 |
|
|
|
91,552 |
|
Other |
|
|
2,482 |
|
|
|
2,449 |
|
|
|
4,112 |
|
Corporate |
|
|
68,595 |
|
|
|
83,588 |
|
|
|
40,268 |
|
|
Total assets |
|
$ |
719,357 |
|
|
$ |
696,955 |
|
|
$ |
547,164 |
|
|
Capital expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
Water infrastructure |
|
$ |
27,924 |
|
|
$ |
22,029 |
|
|
$ |
23,777 |
|
Mineral exploration |
|
|
20,944 |
|
|
|
18,451 |
|
|
|
11,607 |
|
Energy |
|
|
30,891 |
|
|
|
30,345 |
|
|
|
40,737 |
|
Other |
|
|
237 |
|
|
|
1,037 |
|
|
|
483 |
|
Corporate |
|
|
1,027 |
|
|
|
1,508 |
|
|
|
196 |
|
|
Total capital expenditures |
|
$ |
81,023 |
|
|
$ |
73,370 |
|
|
$ |
76,800 |
|
|
Depreciation, depletion and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
Water infrastructure |
|
$ |
23,741 |
|
|
$ |
21,978 |
|
|
$ |
17,691 |
|
Mineral exploration |
|
|
13,362 |
|
|
|
10,523 |
|
|
|
8,260 |
|
Energy |
|
|
14,644 |
|
|
|
10,704 |
|
|
|
6,531 |
|
Other |
|
|
935 |
|
|
|
237 |
|
|
|
229 |
|
Corporate |
|
|
158 |
|
|
|
178 |
|
|
|
142 |
|
|
Total depreciation, depletion and amortization |
|
$ |
52,840 |
|
|
$ |
43,620 |
|
|
$ |
32,853 |
|
|
54
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
Fiscal Years Ended January 31, |
|
2009 |
|
2008 |
|
2007 |
|
Geographic information: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
841,542 |
|
|
$ |
712,098 |
|
|
$ |
595,959 |
|
Australia/Africa |
|
|
88,967 |
|
|
|
89,739 |
|
|
|
78,640 |
|
Mexico |
|
|
37,775 |
|
|
|
42,242 |
|
|
|
32,749 |
|
Other foreign |
|
|
39,779 |
|
|
|
24,195 |
|
|
|
15,420 |
|
|
Total revenues |
|
$ |
1,008,063 |
|
|
$ |
868,274 |
|
|
$ |
722,768 |
|
|
Property and equipment, net |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
213,408 |
|
|
$ |
218,047 |
|
|
$ |
191,797 |
|
Australia/Africa |
|
|
18,663 |
|
|
|
19,530 |
|
|
|
16,655 |
|
Mexico |
|
|
9,379 |
|
|
|
8,555 |
|
|
|
5,279 |
|
Other foreign |
|
|
5,295 |
|
|
|
1,235 |
|
|
|
786 |
|
|
Total property and equipment, net |
|
$ |
246,745 |
|
|
$ |
247,367 |
|
|
$ |
214,517 |
|
|
(16) New Accounting Pronouncements
In September 2006, the Financial Accounting Standards Board (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 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. On February 1, 2008, the Company
adopted SFAS 157 for its financial assets and liabilities. The adoption of SFAS 157 did not impact
the Companys financial position, results of operations, liquidity or disclosures.
In February 2008, the FASB issued Staff Position 157-2, Effective Date of FASB Statement No.
157 (FSP 157-2), which delays the effective date of SFAS 157 for all nonfinancial assets and
nonfinancial liabilities, except those that are recognized or disclosed at fair value in the
financial statements on a recurring basis (at least annually), until fiscal years beginning after
November 15, 2008, and interim periods within those fiscal years. These nonfinancial items include
assets and liabilities such as reporting units measured at fair value in a goodwill impairment
test, nonfinancial assets acquired and liabilities assumed in a business combination and other
purchased intangible assets. The adoption of SFAS 157 for those nonfinancial assets within the
scope of FSP 157-2 is not expected to have a material impact on the Companys financial position,
results of operations or liquidity.
In October 2008, the FASB issued Staff
Position 157-3, Determining the Fair Value of an Asset When the Market for That Asset
Is Not Active (FSP 157-3), with the intent to
clarify the application of SFAS 157 in a market that is not
active by providing an example to illustrate the key considerations in the application of this
guidance. It emphasizes that the use of a reporting entitys own assumptions about future cash
flows and an appropriately risk-adjusted discount rate in determining the fair value for a
financial asset is acceptable when relevant observable inputs are not
available. FSP 157-3 was
effective upon its issuance and did not impact the Companys financial position, results of
operations, liquidity or disclosures.
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. In addition, beginning
with the Companys fiscal year ending January 31, 2009, SFAS 158 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 recorded a $47,000 decrease to retained earnings as of
February 1, 2008.
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 adopted this standard on a prospective basis as of February 1, 2008.
The adoption of SFAS 159 did not impact our consolidated financial statements since we did not
elect to apply the fair value option for any of our eligible financial instruments or other items
on the February 1, 2008, effective date.
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 beginning in the first
quarter of the fiscal year ending January 31, 2010. The Company does not expect the adoption of
SFAS 141R to have a significant
55
impact on our consolidated results of operations or 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 beginning in the first quarter of the fiscal
year ending January 31, 2010. The adoption of SFAS 160 will result in a reclassification of $75,000
of minority interest into equity.
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 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 impact of the new rules on its accounting and
disclosure.
On December 29, 2008, the SEC adopted new rules related to modernizing accounting and disclosure
requirements for oil and natural gas companies. The new disclosure requirements include provisions
that permit the use of new technologies to determine proved reserves if those technologies have
been demonstrated empirically to lead to reliable conclusions about reserve volumes. The new rules
also allow companies the option to disclose probable and possible reserves in addition to the
existing requirement to disclose proved reserves. The new disclosure requirements also require
companies to report the independence and qualifications of third party preparers of reserves and
file reports when a third party is relied upon to prepare reserves estimates. A significant change
to the rules involves the pricing at which reserves are measured. The new rules utilize a 12-month
average price using beginning of the month pricing (February 1 to January 1) to report oil and gas
reserves rather than year-end prices. In addition, the 12-month average will also be used to test
cost center ceilings for impairment and to compute depreciation, depletion and amortization. The
Company will be required to adopt these rules in the fiscal year ending January 31, 2010. Early
adoption is not permitted. The Company is currently evaluating the impact of the new rules on its
accounting and disclosure.
(17) Quarterly Results (Unaudited)
Unaudited quarterly financial data are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per share data) |
|
|
|
|
|
|
|
|
2009 |
|
First |
|
Second |
|
Third |
|
Fourth |
|
Revenues |
|
$ |
244,544 |
|
|
$ |
269,638 |
|
|
$ |
264,483 |
|
|
$ |
229,398 |
|
Net income (loss) |
|
|
10,562 |
|
|
|
15,096 |
|
|
|
12,227 |
|
|
|
(11,351 |
) |
Basic net income (loss) per share |
|
|
0.55 |
|
|
|
0.79 |
|
|
|
0.64 |
|
|
|
(0.59 |
) |
Diluted net income (loss) per share |
|
|
0.55 |
|
|
|
0.78 |
|
|
|
0.63 |
|
|
|
(0.59 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
During the fourth quarter of 2009, the Company recorded a non-cash impairment charge of
$26,690,000, or $16,081,000 after income tax, related to its energy operations as a result of its
annual determination of oil and gas reserves.
56
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
The Companys oil and gas activities are primarily conducted in the United States. See Note 1 for
additional information regarding the Companys oil and gas properties.
Capitalized Costs Related to Oil and Gas Producing Activities
Capitalized costs and associated depletion relating to oil and gas producing activities were as
follows at January 31, 2009, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2009 |
|
2008 |
|
2007 |
|
Oil and gas properties |
|
$ |
92,497 |
|
|
$ |
76,844 |
|
|
$ |
58,458 |
|
Mineral interest in oil
and gas properties |
|
|
21,248 |
|
|
|
18,165 |
|
|
|
12,515 |
|
|
|
|
|
113,745 |
|
|
|
95,009 |
|
|
|
70,973 |
|
Accumulated depletion |
|
|
(54,859 |
) |
|
|
(16,353 |
) |
|
|
(7,848 |
) |
|
Total |
|
$ |
58,886 |
|
|
$ |
78,656 |
|
|
$ |
63,125 |
|
|
Included in accumulated depletion at January 31, 2009, were non-cash ceiling test impairments
of $26,690,000. There were no such impairments at January 31, 2008 and 2007. See Note 4 for
additional information regarding impairment of oil and gas properties.
Unproved oil and gas property and mineral interest costs at January 31, 2009, totaled
$10,348,000 and $9,305,000, respectively. Unevaluated mineral interest costs excluded from
depreciation, depletion and amortization at January 31, 2009 and 2008, totaled $9,305,000 and
$8,405,000, respectively.
Capitalized costs and associated depreciation relating to gas transportation facilities and
equipment were as follows at January 31, 2009, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2009 |
|
2008 |
|
2007 |
|
Gas transportation facilities
and equipment |
|
$ |
39,825 |
|
|
$ |
30,266 |
|
|
$ |
24,939 |
|
Accumulated depreciation |
|
|
(6,831 |
) |
|
|
(4,355 |
) |
|
|
(2,353 |
) |
|
Total |
|
$ |
32,994 |
|
|
$ |
25,911 |
|
|
$ |
22,586 |
|
|
Capitalized costs incurred in gas transportation facilities and equipment during 2009, 2008
and 2007 totaled $6,739,000, $5,327,000 and $12,413,000, respectively. During fiscal 2009, we
transferred $2,820,000 from oil and gas properties to gas transportation facilities and equipment
as the Company began to use these facilities to transport third party natural gas to market.
Cost Incurred in Oil and Gas Producing Activities
Capitalized costs incurred in oil and gas producing activities were as follows during 2009, 2008
and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2009 |
|
2008 |
|
2007 |
|
Acquisition |
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
$ |
2,061 |
|
|
$ |
5,647 |
|
|
$ |
4,249 |
|
Unproved |
|
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
|
5 |
|
|
|
1,501 |
|
|
|
25 |
|
Development |
|
|
20,802 |
|
|
|
16,718 |
|
|
|
23,719 |
|
|
|
|
|
22,868 |
|
|
|
23,866 |
|
|
|
27,993 |
|
Asset retirement costs |
|
|
185 |
|
|
|
170 |
|
|
|
243 |
|
|
Total |
|
$ |
23,053 |
|
|
$ |
24,036 |
|
|
$ |
28,236 |
|
|
Exploration costs of $1,498,000 in 2008 were associated with an exploration project in Chile. These
costs were considered impaired and written off in 2009.
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, 2009, 2008 and 2007, and include 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 depletion allowances.
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per Mcf) |
|
2009 |
|
2008 |
|
2007 |
|
Revenues |
|
$ |
24,994 |
|
|
$ |
20,861 |
|
|
$ |
14,014 |
|
Operating costs: |
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes |
|
|
1,034 |
|
|
|
872 |
|
|
|
552 |
|
Lease operating expenses |
|
|
10,194 |
|
|
|
8,242 |
|
|
|
5,051 |
|
Depletion |
|
|
11,816 |
|
|
|
8,504 |
|
|
|
4,917 |
|
Asset retirement accretion expense |
|
|
76 |
|
|
|
60 |
|
|
|
43 |
|
Impairment of oil and gas properties |
|
|
28,704 |
|
|
|
|
|
|
|
|
|
Income tax expense (benefit) |
|
|
(10,666 |
) |
|
|
1,196 |
|
|
|
1,286 |
|
|
Total operating costs |
|
|
41,158 |
|
|
|
18,874 |
|
|
|
11,849 |
|
|
Results of operations |
|
$ |
(16,164 |
) |
|
$ |
1,987 |
|
|
$ |
2,165 |
|
|
Depletion per Mcf |
|
$ |
2.30 |
|
|
$ |
1.80 |
|
|
$ |
1.46 |
|
|
Proved Oil and Gas Reserve Quantities
Proved gas reserve quantities as of January 31, 2009 and 2008 are based on estimates prepared by
the Companys independent petroleum engineers, Cawley, Gillespie & Associates, Inc., in accordance
with Rule 4-10 of Regulation S-X. All of the Companys reserves are located within the United
States.
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
57
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): |
|
2009 |
|
2008 |
|
Balance, beginning of year |
|
|
50,052 |
|
|
|
57,078 |
|
Revisions of previous estimates |
|
|
(33,238 |
) |
|
|
(5,697 |
) |
Extensions, discoveries and other additions |
|
|
4,881 |
|
|
|
3,403 |
|
Production |
|
|
(5,132 |
) |
|
|
(4,732 |
) |
Purchases of reserves in place |
|
|
|
|
|
|
|
|
|
Balance, end of year |
|
|
16,563 |
|
|
|
50,052 |
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves |
|
|
16,289 |
|
|
|
22,794 |
|
|
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 $3.29 and $7.53 per Mcf for 2009 and
2008, 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) |
|
2009 |
|
2008 |
|
Future cash inflows |
|
$ |
82,261 |
|
|
$ |
376,955 |
|
Future production costs |
|
|
(33,514 |
) |
|
|
(148,069 |
) |
Future development costs |
|
|
(467 |
) |
|
|
(44,077 |
) |
Future income taxes |
|
|
(2,196 |
) |
|
|
(52,961 |
) |
|
Future net cash flows |
|
|
46,084 |
|
|
|
131,848 |
|
10% discount to reflect timing of cash flows |
|
|
(5,908 |
) |
|
|
(45,364 |
) |
|
Standardized measure of discounted cash flows |
|
$ |
40,176 |
|
|
$ |
86,484 |
|
|
The principal sources of change in the standardized measure of discounted future net cash
flows were:
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2009 |
|
2008 |
|
Balance, beginning of year |
|
$ |
86,484 |
|
|
$ |
89,012 |
|
Sales of gas produced, net of production costs |
|
|
(22,214 |
) |
|
|
(17,454 |
) |
Net changes in prices, net of future production
costs |
|
|
(65,507 |
) |
|
|
18,399 |
|
Net changes
in future development costs |
|
|
20,565 |
|
|
|
(19,353 |
) |
Extensions and discoveries, less related costs |
|
|
12,799 |
|
|
|
8,189 |
|
Purchases of reserves in place |
|
|
|
|
|
|
|
|
Net change
in quantity estimates |
|
|
(17,183 |
) |
|
|
(17,294 |
) |
Accretion of discount |
|
|
11,319 |
|
|
|
11,762 |
|
Net changes
in timing and other |
|
|
(33,398 |
) |
|
|
(15,308 |
) |
Net change in income taxes |
|
|
30,761 |
|
|
|
3,413 |
|
Development costs incurred |
|
|
16,550 |
|
|
|
25,118 |
|
|
Net change |
|
|
(46,308 |
) |
|
|
(2,528 |
) |
Balance, end of year |
|
$ |
40,176 |
|
|
$ |
86,484 |
|
|
58
Layne Christensen Company and Subsidiaries
Schedule II: Valuation and Qualifying Accounts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions |
|
|
|
|
|
|
|
|
Balance at |
|
Charges to |
|
Charges to |
|
|
|
|
|
Balance |
|
|
Beginning |
|
Costs and |
|
Other |
|
|
|
|
|
at End |
(in thousands) |
|
of Period |
|
Expenses |
|
Accounts |
|
Deductions |
|
of Period |
|
Allowance for customer
receivables: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal year ended January 31, 2007 |
|
$ |
5,573 |
|
|
$ |
1,700 |
|
|
$ |
666 |
|
|
$ |
(919 |
) |
|
$ |
7,020 |
|
Fiscal year ended January 31, 2008 |
|
|
7,020 |
|
|
|
1,205 |
|
|
|
336 |
|
|
|
(990 |
) |
|
|
7,571 |
|
Fiscal year ended January 31, 2009 |
|
|
7,571 |
|
|
|
2,082 |
|
|
|
608 |
|
|
|
(2,383 |
) |
|
|
7,878 |
|
59
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures. Based on an evaluation of disclosure controls and procedures
for the period ended January 31, 2009, 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, 2009. 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,
2009. 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 2009.
60
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, 2009, 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, 2009, 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, 2009, of the Company and our report dated March
31, 2009, expressed an unqualified opinion on those financial statements and financial statement
schedule.
/s/Deloitte & Touche LLP
Kansas City, Missouri
March 31, 2009
61
PART III
Item 10. Directors and Executive Officers of the Registrant
The Registrants Proxy Statement to be used in connection with the Annual Meeting of Stockholders
to be held on June 3, 2009, (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 3, 2009, 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.
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 3, 2009, 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 3, 2009, will contain, under the captions Other Corporate Governance Matters,
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 3, 2009, 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.
62
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) |
|
Financial Statements, Financial Statement Schedules and Exhibits: |
1. Financial Statements:
The financial statements are listed in the index for Item 8 of this Form 10-K.
2. Financial Statement Schedules:
The applicable financial statement schedule is listed in the index for Item 8 of this Form
10-K.
3. Exhibits:
The exhibits filed with or incorporated by reference in this report are listed below:
|
|
|
Exhibit |
|
|
Number |
|
Description |
|
|
|
3(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) |
|
|
|
3(2)
|
|
Amended and Restated Bylaws of the Registrant (as adopted October 9, 2008) (filed as Exhibit
3.2 to the Registrants Form 8-K filed October 14, 2008, and incorporated herein by this
reference) |
|
|
|
4(1)
|
|
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(2)
|
|
Rights Agreement, dated as of October 14, 2008, between the Registrant and National City Bank
as Rights Agent, which includes as Exhibit C, the Summary of Rights to Purchase Preferred
Shares (filed as Exhibit 4.1 to the Registrants Form 8-K filed October 14, 2008, and
incorporated herein by this reference) |
|
|
|
4(3)
|
|
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(4)
|
|
Amended and Restated Loan Agreement, dated as of September 28, 2005, by and among Layne
Christensen Company, LaSalle Bank National Association, as Administrative Agent and as Lender,
and the other Lenders listed therein (filed as Exhibit 4.1 to the Companys Form 8-K, dated
September 28, 2005, and incorporated herein by this reference) |
|
|
|
4(5)
|
|
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(6)
|
|
Amendment No. 2 to the Amended and Restated Loan Agreement, dated as of November 20, 2006, by
and among Layne Christensen Company and LaSalle, as Administrative Agent, and LaSalle and the
other Lenders a party thereto (filed as Exhibit 4(1) to the Companys Form 8-K, dated November
20, 2006, and incorporated herein by this reference) |
|
|
|
4(7)
|
|
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(8)
|
|
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) |
63
Item 15. Exhibits and Financial Statement Schedules (continued)
|
|
|
Exhibit |
|
|
Number |
|
Description |
|
|
|
4(9)
|
|
Letter Amendment No. 1 to Master Shelf Agreement, dated as of May 15, 2004, by and among
Layne Christensen Company, Prudential Investment Management, Inc., The Prudential Insurance
Company of America, Pruco Life Insurance Company, Security Life of Denver Insurance Company
and such other Purchasers of the Notes as may be named in the Master Shelf Agreement from time
to time (filed as Exhibit 4(6) to the Companys Form 10-K for the fiscal year ended January
31, 2006, and incorporated herein by this reference) |
|
|
|
4(10)
|
|
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) |
|
|
|
4(11)
|
|
Letter Amendment No. 3 to Master Shelf Agreement, dated as of June 16, 2006, by and among
Layne Christensen Company, Prudential Investment Management, Inc., The Prudential Insurance
Company of America, Pruco Life Insurance Company, Security Life of Denver Insurance Company
and such other Purchasers of the Notes as may be named in the Master Shelf Agreement from time
to time (filed as Exhibit 10(2) to the Companys Form 10-Q for the quarter ended July 31,
2006, and incorporated herein by this reference) |
|
|
|
4(12)
|
|
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) |
|
|
|
4(13)
|
|
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) |
|
|
|
10(1)
|
|
Tax Liability Indemnification Agreement between the Registrant and The Marley Company (filed
with Amendment No. 3 to the Registrants Registration Statement (File No. 33-48432) as Exhibit
10(2) and incorporated herein by reference) |
|
|
|
10(2)
|
|
Lease Agreement between the Registrant and Parkway Partners, L.L.C. dated December 21, 1994
(filed with the Registrants Annual Report on Form 10-K for the fiscal year ended January 31,
1995 (File No. 0-20578) as Exhibit 10(2) and incorporated herein by reference) |
|
|
|
10(2.1)
|
|
First Modification & Ratification of Lease, dated as of February 26, 1996, between Parkway
Partners, L.L.C. and the Registrant (filed with the Registrants Annual Report on Form 10-K
for the fiscal year ended January 31, 1996 (File No. 0-20578), as Exhibit 10(2.1) and
incorporated herein by this reference) |
|
|
|
10(2.2)
|
|
Second Modification and Ratification of Lease Agreement between Parkway Partners, L.L.C.
and Layne Christensen Company dated April 28, 1997 (filed with the Registrants Annual Report
on Form 10-K for the fiscal year ended January 31, 1999 (File No. 0-20578), as Exhibit 10(2.2)
and incorporated herein by this reference) |
|
|
|
10(2.3)
|
|
Third Modification and Extension Agreement between Parkway Partners, L.L.C. and Layne
Christensen Company dated November 3, 1998 (filed with the Companys 10-Q for the quarter
ended October 31, 1998 (File No. 0-20578) as Exhibit 10(1) and incorporated herein by
reference) |
|
|
|
10(2.4)
|
|
Fourth Modification and Extension Agreement between Parkway Partners, L.L.C. and Layne
Christensen Company executed May 17, 2000, effective as of December 29, 1998 (filed with the
Companys 10-Q for the quarter ended July 31, 2000 (File No. 0-20578) as Exhibit 10.1 and
incorporated herein by reference) |
|
|
|
10(2.5)
|
|
Fifth Modification and extension Agreement between Parkway Partners, L.L.C. and Layne
Christensen Company dated March 1, 2003 (filed as Exhibit 10(2.5) to the Registrants Annual
Report on Form 10-K for the fiscal year ended January 31, 2003 (File No. 0-20578) and
incorporated herein by this reference) |
|
|
|
10(2.6)
|
|
Sixth Modification Agreement, dated February 29, 2008, between 1900 Associates L.L.C. and
the Company (filed as Exhibit 10(2.6) to the Registrants Annual Report on Form 10-K for the
fiscal year ended January 31, 2008, filed April 15, 2008, and incorporated herein by this
reference) |
64
Item 15. Exhibits and Financial Statement Schedules (continued)
|
|
|
Exhibit |
|
|
Number |
|
Description |
|
|
|
**10(3)
|
|
Form of Stock Option Agreement between the Company and management of the Company (filed
with Amendment No. 3 to the Registrants Registration Statement (File No. 33-48432) as Exhibit
10(7) and incorporated herein by reference) |
|
|
|
10(4)
|
|
Insurance Liability Indemnity Agreement between the Company and The Marley Company (filed
with Amendment No. 3 to the Registrants Registration Statement (File No. 33-48432) as Exhibit
10(10) and incorporated herein by reference) |
|
|
|
10(5)
|
|
Agreement between The Marley Company and the Company relating to tradename (filed with the
Registrants Registration Statement (File No.33-48432) as Exhibit 10(10) and incorporated
herein by reference) |
|
|
|
**10(6)
|
|
Form of Subscription Agreement for management of the Company
(filed with Amendment No. 3 to the Registrants Registration
Statement (File No. 33-48432) as Exhibit 10(16) and incorporated
herein by reference) |
|
|
|
**10(7)
|
|
Form of Subscription Agreement between the Company and Robert J.
Dineen (filed with Amendment No. 3 to the Registrants
Registration Statement (File No. 33-48432) as Exhibit 10(17) and
incorporated herein by reference) |
|
|
|
**10(8)
|
|
Letter Agreement between Andrew B. Schmitt and the Company (as
amended and restated to comply with Section 409A) dated December
2, 2008 |
|
|
|
**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) |
|
|
|
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 November 3, 2008) |
|
|
|
**10(16)
|
|
Layne Christensen Company Corporate
Staff Incentive Compensation Plan (as amended, effective
February 1, 2007) |
|
|
|
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) |
65
Item 15. Exhibits and Financial Statement Schedules (continued)
|
|
|
Exhibit |
|
|
Number |
|
Description |
|
|
|
**10(20)
|
|
Form of Nonqualified Stock Option Agreement between the Company
and management of the Company for use with the 2006 Equity
Incentive Plan, as amended effective January 26, 2009 |
|
|
|
**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, as amended effective January 26, 2009 |
|
|
|
**10(22)
|
|
Form of Restricted Stock Award Agreement between the Company and
management of the Company for use with the 2006 Equity Incentive
Plan, as amended effective January 23, 2008 |
|
|
|
**10(23)
|
|
Form of Restricted Stock Award Agreement between the Company and
non-employee directors of the Company for use with the Companys
2006 Equity Incentive Plan, as amended effective January 26, 2009 |
|
|
|
**10(24)
|
|
Layne Christensen Company Water Infrastructure Division Incentive
Compensation Plan (as amended and restated, effective February 1,
2008) (incorporated by reference to Exhibit 10(24) to the
Companys Annual Report on Form 10-K for the fiscal year ended
January 31, 2008, filed April 15, 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) (incorporated by reference to Exhibit 10(27) to
the Companys Annual Report on Form 10-K for the fiscal year
ended January 31, 2008, filed April 15, 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)
|
|
Severance Agreement dated July 10, 2008, by and between Eric R.
Despain and Layne Christensen Company (incorporated by reference
to Exhibit 10(1) to the Companys Current Report on Form 8-K
filed July 14, 2008) |
|
|
|
**10(34)
|
|
Summary of 2009 Salaries of Named Executive Officers |
|
|
|
10(35)
|
|
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(36)
|
|
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(37)
|
|
Layne Christensen Company Deferred
Compensation Plan for Directors (Amended and Restated, effective as
of January 1, 2009) |
|
|
|
**10(38)
|
|
Amended and Restated Layne Christensen Company Key Management Deferred Compensation Plan,
effective as of January 1, 2008 |
|
|
|
**10(39)
|
|
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(40)
|
|
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) |
66
Item 15. Exhibits and Financial Statement Schedules (continued)
|
|
|
Exhibit |
|
|
Number |
|
Description |
|
|
|
10(41)
|
|
Form of Indemnification Agreement for use in connection with the Rights Agreement dated
October 14, 2008 (filed as Exhibit 10.1 to the Registrants Form 8-K filed October 14, 2008,
and incorporated herein by this reference) |
|
|
|
21(1)-
|
|
List of Subsidiaries |
|
|
|
23(1)-
|
|
Consent of Deloitte & Touche LLP |
|
|
|
23(2)-
|
|
Consent of Cawley, Gillespie & Associates, Inc. |
|
|
|
31(1)-
|
|
Section 302 Certification of Principal Executive Officer of the Company |
|
|
|
31(2)-
|
|
Section 302 Certification of Principal Financial Officer of the Company |
|
|
|
32(1)-
|
|
Section 906 Certification of Principal Executive Officer of the Company |
|
|
|
32(2)-
|
|
Section 906 Certification of Principal Financial Officer of the Company |
|
|
|
** |
|
Management contracts or compensatory plans or arrangements required to be identified by Item
14(a)(3). |
(b) Exhibits
The exhibits filed with this report on Form 10-K are identified above under Item 15(a)(3).
(c) Financial Statement Schedules
67
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
|
|
|
|
|
|
Layne Christensen Company
|
|
|
By |
/s/ A. B. Schmitt
|
|
|
|
Andrew B. Schmitt |
|
|
|
President and Chief Executive
Officer:
Dated March 31, 2009 |
|
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed
below by the following persons on behalf of the registrant and in the capacities and on the dates
indicated:
|
|
|
Signature and Title |
|
Date |
|
|
|
/s/ A. B. Schmitt
Andrew B. Schmitt
President, Chief Executive Officer
and Director (Principal Executive Officer)
|
|
March 31, 2009 |
|
|
|
/s/ Jerry W. Fanska
Jerry W. Fanska
Senior Vice President-Finance and Treasurer
(Principal Financial and Accounting Officer)
|
|
March 31, 2009 |
|
|
|
/s/ Jeff Reynolds
Jeffrey J. Reynolds
Director
|
|
March 31, 2009 |
|
|
|
/s/ Donald K. Miller
Donald K. Miller
Director
|
|
March 31 , 2009 |
|
|
|
/s/ David A. B. Brown
David A. B. Brown
Director
|
|
March 31, 2009 |
|
|
|
/s/ J. Samuel Butler
J. Samuel Butler
Director
|
|
March 31, 2009 |
|
|
|
/s/ Anthony B. Helfet
Anthony B. Helfet
Director
|
|
March 31, 2009 |
|
|
|
/s/ Nelson Obus
Nelson Obus
Director
|
|
March 31, 2009 |
|
|
|
/s/ Rene Robichaud
Rene Robichaud
Director
|
|
March 31, 2009 |
|
|
|
/s/ Robert Gilmore
Robert Gilmore
Director
|
|
March 31, 2009 |
68