e10vk
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
December 31, 2006
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OR
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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
no. 001-32693
Basic Energy Services,
Inc.
(Exact name of registrant as
specified in its charter)
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Delaware
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54-2091194
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(State or other jurisdiction
of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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400 W. Illinois,
Suite 800
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79701
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Midland, Texas
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(Zip code
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(Address of principal executive
offices)
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Registrants telephone number, including area code:
(432) 620-5500
Securities
registered pursuant to Section 12(b) of the Act:
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Common Stock, $0.01 par
value per share
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New York Stock
Exchange
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(Title of Class)
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(Name of each exchange on which
registered)
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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
Exchange
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 the registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. o
Indicate by check mark whether the registrant is a large
accelerated filer, and accelerated filer, or a non-accelerated
filer. See definition of accelerated filer and large
accelerated filer in
Rule 12b-2
of the Act). (Check one)
Large Accelerated
Filer o Accelerated
Filer þ Non-Accelerated
Filer o
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
The aggregate market value of the registrants Common Stock
held by non-affiliates of the registrant was approximately
$532,887,772 as of June 30, 2006 (based on a closing price
of $30.57 per share and 17,431,723 shares held by
non-affiliates).
38,300,105 shares of the registrants Common Stock
were outstanding as of March 8, 2007.
Documents incorporated by reference: Portions of
the definitive proxy statement for the registrants Annual
Meeting of Stockholders (to be filed within 120 days of the
close of the registrants fiscal year) are incorporated by
reference into Part III.
BASIC
ENERGY SERVICES, INC.
Index to
Form 10-K
i
CAUTIONARY
STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS
This annual report contains certain statements that are, or may
be deemed to be, forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933,
as amended, and Section 21E of the Securities Exchange Act
of 1934, as amended, or the Exchange Act. We have based these
forward-looking statements largely on our current expectations
and projections about future events and financial trends
affecting the financial condition of our business. These
forward-looking statements are subject to a number of risks,
uncertainties and assumptions, including, among other things,
the risk factors discussed in this annual report and other
factors, most of which are beyond our control.
The words believe, may,
estimate, continue,
anticipate, intend, plan,
expect and similar expressions are intended to
identify forward-looking statements. All statements other than
statements of current or historical fact contained in this
annual report are forward looking-statements. Although we
believe that the forward-looking statements contained in this
annual report are based upon reasonable assumptions, the
forward-looking events and circumstances discussed in this
annual report may not occur and actual results could differ
materially from those anticipated or implied in the
forward-looking statements.
Important factors that may affect our expectations, estimates or
projections include:
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a decline in, or substantial volatility of, oil and gas prices,
and any related changes in expenditures by our customers;
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the effects of future acquisitions on our business;
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changes in customer requirements in markets or industries we
serve;
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competition within our industry;
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general economic and market conditions;
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our access to current or future financing arrangements;
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our ability to replace or add workers at economic rates; and
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environmental and other governmental regulations.
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Our forward-looking statements speak only as of the date of this
annual report. Unless otherwise required by law, we undertake no
obligation to publicly update or revise any forward-looking
statements, whether as a result of new information, future
events or otherwise.
This annual report includes market share, industry data and
forecasts that we obtained from internal company surveys
(including estimates based on our knowledge and experience in
the industry in which we operate), market research, consultant
surveys, publicly available information, industry publications
and surveys. These sources include World Oil magazine, Baker
Hughes Incorporated, the Association of Energy Service
Companies, and the Energy Information Administration of the
U.S. Department of Energy. Industry surveys, publications,
consultant surveys and forecasts generally state that the
information contained therein has been obtained from sources
believed to be reliable. Although we believe such information is
accurate and reliable, we have not independently verified any of
the data from third party sources cited or used for our
managements industry estimates, nor have we ascertained
the underlying economic assumptions relied upon therein. For
example, the number of onshore well servicing rigs in the
U.S. could be lower than our estimate to the extent our two
larger competitors have continued to report as stacked rigs
equipment that is not actually complete or subject to
refurbishment. Statements as to our position relative to our
competitors or as to market share refer to the most recent
available data.
1
PART I
ITEMS 1.
AND 2. BUSINESS AND PROPERTIES
General
We provide a wide range of well site services to oil and gas
drilling and producing companies, including well servicing,
fluid services, drilling and completion services and well site
construction services. These services are fundamental to
establishing and maintaining the flow of oil and gas throughout
the productive life of a well. Our broad range of services
enables us to meet multiple needs of our customers at the well
site. Our operations are managed regionally and are concentrated
in the major United States onshore oil and gas producing regions
in Texas, New Mexico, Oklahoma, Arkansas and Louisiana and the
Rocky Mountain states. We provide our services to a diverse
group of over 1,000 oil and gas companies. We operate the
third-largest fleet of well servicing rigs (also commonly
referred to as workover rigs) in the United States, representing
over 11% of the overall available U.S. fleet, with our two
larger competitors controlling approximately 25% and 14%,
respectively, according to the Association of Energy Services
Companies and other publicly available data.
We currently conduct our operations through the following four
business segments:
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Well Servicing. Our well servicing segment
(45% of our revenues in 2006) currently operates our fleet
of over 360 well servicing rigs and related equipment. This
business segment encompasses a full range of services performed
with a mobile well servicing rig, including the installation and
removal of downhole equipment and elimination of obstructions in
the well bore to facilitate the flow of oil and gas. These
services are performed to establish, maintain and improve
production throughout the productive life of an oil and gas well
and to plug and abandon a well at the end of its productive
life. Our well servicing equipment and capabilities are
essential to facilitate most other services performed on a well.
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Fluid Services. Our fluid services segment
(27% of our revenues in 2006) currently utilizes our fleet
of fluid services trucks and related assets, including
specialized tank trucks, storage tanks, water wells, disposal
facilities and related equipment. These assets provide,
transport, store and dispose of a variety of fluids. These
services are required in most workover, drilling and completion
projects and are routinely used in daily producing well
operations.
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Drilling and Completion Services. Our drilling
and completion services segment (21% of our revenues in
2006) currently operates our fleet of pressure pumping
units, air compressor packages specially configured for
underbalanced drilling operations, cased-hole wireline units and
an array of specialized rental equipment and fishing tools. We
entered the rental and fishing tool business through an
acquisition in the first quarter of 2006. The largest portion of
this business consists of pressure pumping services focused on
cementing, acidizing and fracturing services in niche markets.
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Well Site Construction Services. Our well site
construction services segment (7% of our revenues in
2006) currently utilizes our fleet of earth moving
equipment, which includes dozers, trenchers, motor graders,
backhoes and other heavy equipment. We utilize these assets
primarily to provide services for the construction and
maintenance of oil and gas production infrastructure, such as
preparing and maintaining access roads and well locations,
installation of small diameter gathering lines and pipelines and
construction of temporary foundations to support drilling rigs.
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Our
Competitive Strengths
We believe that the following competitive strengths currently
position us well within our industry:
Significant Market Position. We maintain a
significant market share for our well servicing operations in
our core operating areas throughout Texas and a growing market
share in the other markets that we serve. Our fleet of over
360 well servicing rigs represents the third-largest fleet
in the United States, and our goal is to be one of the top two
providers of well site services in each of our core operating
areas. Our market position allows us to expand the range of
services performed on a well throughout its life, such as
maintenance, workover, completion and plugging and abandonment
services.
2
Modern and Active Fleet. We operate a modern
and active fleet of well servicing rigs. We believe over
80% of the active U.S. well servicing rig fleet was
built prior to 1985. Approximately 128 of our rigs at
December 31, 2006 were either 2000 model year or newer, or
have undergone major refurbishments during the last five years.
As of December 31, 2006, we have taken delivery of 66
newbuild well servicing rigs since October 2004 as part of a
120-rig newbuild commitment, driven by our desire to maintain
one of the most efficient, reliable and safest fleets in the
industry. The remainder of these newbuilds is scheduled to be
delivered to us prior to the end of December 2007. In addition
to our regular maintenance program, we have an established
program to routinely monitor and evaluate the condition of our
fleet. We selectively refurbish rigs and other assets to
maintain the quality of our service and to provide a safe work
environment for our personnel and have made major refurbishments
on 57 of our rigs since the beginning of 2001. Approximately 99%
of our fleet was active or available for work and the remainder
was awaiting refurbishment at December 31, 2006. Since
2003, we have obtained annual independent reviews and
evaluations of substantially all of our assets, which confirmed
the location and condition of these assets.
Extensive Domestic Footprint in the Most Prolific
Basins. Our operations are concentrated in the
major United States onshore oil and gas producing regions in
Texas, New Mexico, Oklahoma, Arkansas and Louisiana and the
Rocky Mountain states. We operate in states that accounted
for approximately 56% of the approximately 900,000 existing
onshore oil and gas wells in the 48 contiguous states and
approximately 69% of onshore oil production and 85% of onshore
gas production in 2006. We believe that our operations are
located in the most active U.S. well services markets, as
we currently focus our operations on onshore domestic oil and
gas production areas that include both the highest concentration
of existing oil and gas production activities and the largest
prospective acreage for new drilling activity. This extensive
footprint allows us to offer our suite of services to more than
1,000 customers who are active in those areas and allows us to
redeploy equipment between markets as activity shifts.
Diversified Service Offering for Further Revenue
Growth. We believe our range of well site
services provides us a competitive advantage over smaller
companies that typically offer fewer services. Our experience,
equipment and network of 92 area offices position us to
market our full range of well site services to our existing
customers. By utilizing a wider range of our services, our
customers can use fewer service providers, which enables them to
reduce their administrative costs and simplify their logistics.
Furthermore, offering a broader range of services allows us to
capitalize on our existing customer base and management
structure to grow within existing markets, generate more
business from existing customers, and increase our operating
profits as we spread our overhead costs over a larger revenue
base.
Decentralized Management with Strong Corporate
Infrastructure. Our corporate group is
responsible for maintaining a unified infrastructure to support
our diversified operations through standardized financial and
accounting, safety, environmental and maintenance processes and
controls. Below our corporate level, we operate a decentralized
operational organization in which our nine regional or service
line managers are responsible for their regional operations,
including asset management, cost control, policy compliance and
training and other aspects of quality control. With an average
of over 25 years of industry experience, each regional
manager has extensive knowledge of the customer base, job
requirements and working conditions in each local market. Below
our nine regional or service line managers, our 81 area managers
are directly responsible for customer relationships, personnel
management, accident prevention and equipment maintenance, the
key drivers of our operating profitability. This management
structure allows us to monitor operating performance on a daily
basis, maintain financial, accounting and asset management
controls, integrate acquisitions, prepare timely financial
reports and manage contractual risk.
Our
Business Strategy
We intend to increase our shareholder value by pursuing the
following strategies:
Establish and Maintain Leadership Position in Core Operating
Areas. We strive to establish and maintain market
leadership positions within our core operating areas. To achieve
this goal, we maintain close customer relationships, seek to
expand the breadth of our services and offer high quality
services and equipment that meet the scope of customer
specifications and requirements. In addition, our significant
presence in our core operating areas facilitates employee
retention and attraction, a key factor for success in our
business. Our significant presence in our
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core operating areas also provides us with brand recognition
that we intend to utilize in creating leading positions in new
operating areas.
Expand Within Our Regional Markets. We intend
to continue strengthening our presence within our existing
geographic footprint through internal growth and acquisitions of
businesses with strong customer relationships, well-maintained
equipment and experienced and skilled personnel. Our larger
competitors have not actively pursued acquisitions of small to
mid-size regional businesses or assets in recent years due to
the small relative scale and financial impact of these potential
acquisitions. In contrast, we have successfully pursued these
types of acquisitions, which remain attractive to us and make a
meaningful impact on our overall operations. We typically enter
into new markets through the acquisition of businesses with
strong management teams that will allow us to expand within
these markets. Management of acquired companies often remain
with us and retain key positions within our organization, which
enhances our attractiveness as an acquisition partner. We have a
record of successfully implementing this strategy. During the
past three years, our acquisitions have included: Energy Air
Drilling and AWS Wireline services in 2004; three inland barges
that increased our presence along the Gulf Coast in
December 2004, two of which have been refurbished and were
available for service in the second quarter of 2005; Oilwell
Fracturing Services, Inc., a pressure pumping services company
operating in our
Mid-Continent
region in 2005, and in 2006 LeBus Oil Field Service Co., a fluid
service company operating in our Ark-La-Tex region, and G&L
Tool, Ltd., a rental and fishing tool company included in our
drilling and completion line of business.
Develop Additional Service Offerings Within the Well
Servicing Market. We intend to continue
broadening the portfolio of services we provide to our clients
by leveraging our well servicing infrastructure. A customer
typically begins a new maintenance or workover project by
securing access to a well servicing rig, which generally stays
on site for the duration of the project. As a result, our rigs
are often the first equipment to arrive at the well site and
typically the last to leave, providing us the opportunity to
offer our customers other complementary services. We believe the
fragmented nature of the well servicing market creates an
opportunity to sell more services to our core customers and to
expand our total service offering within each of our markets. We
have expanded our suite of services available to our customers
and increased our opportunities to cross-sell new services to
our core well servicing customers through recent acquisitions
and internal growth. We expect to continue to develop or
selectively acquire capabilities to provide additional services
to expand and further strengthen our customer relationships.
Pursue Growth Through Selective Capital
Deployment. We intend to continue growing our
business through selective acquisitions, continuing a newbuild
program
and/or
upgrading our existing assets. Our capital investment decisions
are determined by an analysis of the projected return on capital
employed of each of those alternatives. Acquisitions are
evaluated for fit with our area and regional
operations management and are thoroughly reviewed by corporate
level financial, equipment, safety and environmental specialists
to ensure consideration is given to identified risks. We also
evaluate the cost to acquire existing assets from a third party,
the capital required to build new equipment and the point in the
oil and gas commodity price cycle. Based on these factors, we
make capital investment decisions that we believe will support
our long-term growth strategy, and these decisions may involve a
combination of asset acquisitions and the purchase of new
equipment. In 2006, we completed 10 separate acquisitions for an
aggregate purchase price of $135.6 million, net of cash
acquired, and took delivery of 31 new well servicing rigs.
General
Industry Overview
Demand for services offered by our industry is a function of our
customers willingness to make operating and capital
expenditures to explore for, develop and produce hydrocarbons in
the U.S., which in turn is affected by current and expected
levels of oil and gas prices. The following industry statistics
illustrate the growing spending dynamic in the U.S. oil and
gas sector:
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As oil and gas prices rebounded beginning in early 1999, oil and
gas companies have increased their drilling and workover
activities. The increased activity resulted in increased
exploration and production spending compared to the prior year
of 30% in 2005 and 17% in 2006, according to www.WorldOil.com.
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Increased spending by oil and gas operators is generally driven
by oil and gas prices. The table below sets forth average daily
closing prices for the Cushing WTI Spot Oil Price and the Energy
Information Agency average wellhead price for natural gas since
1999:
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Cushing WTI Spot
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Average Wellhead Price
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Period
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Oil Price ($/bbl)
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Natural Gas ($/mcf)
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1/1/99
12/31/99
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$
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19.34
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$
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2.19
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1/1/00
12/31/00
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30.38
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3.69
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1/1/01
12/31/01
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25.97
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4.01
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1/1/02
12/31/02
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26.18
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2.95
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1/1/03
12/31/03
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31.08
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4.98
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1/1/04
12/31/04
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41.51
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5.49
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1/1/05
12/31/05
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56.64
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7.51
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1/1/06
12/31/06
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66.05
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6.42
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Source: U.S. Department of Energy.
Increased expenditures for exploration and production activities
generally involve the deployment of more drilling and well
servicing rigs, which often serves as an indicator of demand for
our services. Rising oil and gas prices since early 1999 and the
corresponding increase in onshore oil exploration and production
spending have led to expanded drilling and well service
activity, as the U.S. land-based drilling rig count
increased approximately 11% from year-end 2003 to year-end
2004, 22% from year-end 2004 to year-end 2005, and 17% from
year-end 2005 to year-end 2006. In addition, the
U.S. land-based workover rig count increased approximately
10% from year-end 2003 to year-end 2004, 17% from year-end 2004
to year-end 2005 and decreased 1% from year-end 2005 to year-end
2006, according to Baker Hughes.
Exploration and production spending is generally categorized as
either an operating expenditure or a capital expenditure.
Activities designed to add hydrocarbon reserves are classified
as capital expenditures, while those associated with maintaining
or accelerating production are categorized as operating
expenditures.
Capital expenditures by oil and gas companies tend to be
relatively sensitive to volatility in oil or gas prices because
project decisions are tied to a return on investment spanning a
number of years. As such, capital expenditure economics often
require the use of commodity price forecasts which may prove
inaccurate in the amount of time required to plan and execute a
capital expenditure project (such as the drilling of a deep
well). When commodity prices are depressed for even a short
period of time, capital expenditure projects are routinely
deferred until prices return to an acceptable level.
In contrast, both mandatory and discretionary operating
expenditures are substantially more stable than exploration and
drilling expenditures. Mandatory operating expenditure projects
involve activities that cannot be avoided in the short term,
such as regulatory compliance, safety, contractual obligations
and projects to maintain the well and related infrastructure in
operating condition (for example, repairs to a central tank
battery, downhole pump, saltwater disposal system or gathering
system). Discretionary operating expenditure projects may not be
critical to the short-term viability of a lease or field but
these projects are relatively insensitive to commodity price
volatility. Discretionary operating expenditure work is
evaluated according to a simple short-term payout criterion
which is far less dependent on commodity price forecasts.
Our business is influenced substantially by both operating and
capital expenditures by oil and gas companies. Because existing
oil and gas wells require ongoing spending to maintain
production, expenditures by oil and gas companies for the
maintenance of existing wells are relatively stable and
predictable. In contrast, capital expenditures by oil and gas
companies for exploration and drilling are more directly
influenced by current and expected oil and gas prices and
generally reflect the volatility of commodity prices.
5
Overview
of Our Segments and Services
Well
Servicing Segment
Our well servicing segment encompasses a full range of services
performed with a mobile well servicing rig, also commonly
referred to as a workover rig, and ancillary equipment. Our rigs
and personnel provide the means for hoisting equipment and tools
into and out of the well bore, and our well servicing equipment
and capabilities are essential to facilitate most other services
performed on a well. Our well servicing segment services, which
are performed to maintain and improve production throughout the
productive life of an oil and gas well, include:
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maintenance work involving removal, repair and replacement of
down-hole equipment and returning the well to production after
these operations are completed;
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hoisting tools and equipment required by the operation into and
out of the well, or removing equipment from the well bore, to
facilitate specialized production enhancement and well repair
operations performed by other oilfield service
companies; and
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plugging and abandonment services when a well has reached the
end of its productive life.
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Regardless of the type of work being performed on the well, our
personnel and rigs are often the first to arrive at the well
site and the last to leave. We generally charge our customers an
hourly rate for these services, which rate varies based on a
number of considerations including market conditions in each
region, the type of rig and ancillary equipment required, and
the necessary personnel.
Our fleet included 365 well service rigs as of
December 31, 2006, including 66 newbuilds since October
2004 and 77 rebuilds since the beginning of 2001. We operate
from more than 90 facilities in Texas, Wyoming, Oklahoma, North
Dakota, New Mexico, Louisiana, Colorado and Montana. Our rigs
are mobile units that generally operate within a radius of
approximately 75 to 100 miles from their respective bases.
Prior to December 2004, our well servicing segment consisted
entirely of land-based equipment. During December 2004, we
acquired three inland barges, two of which were equipped with
rigs, have been refurbished and were placed into service in the
second quarter of 2005. In January 2007, we acquired two
additional inland barges equipped with rigs in the acquisition
of Parker Drilling Offshore USA, LLC. Inland barges are used to
service wells in shallow water marine environments, such as
coastal marshes and bays.
The following table sets forth the location, characteristics and
number of the well servicing rigs that we operated at
December 31, 2006. We categorize our rig fleet by the rated
capacity of the mast, which indicates the maximum weight that
the rig is capable of lifting. This capability is the limiting
factor in our ability to provide services. These figures do not
include 54 new well servicing rigs that we have contracted for
delivery from January 2007 through December 2007 as part of a
120-rig newbuild commitment:
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Operating Region
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Permian
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South
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Ark-La-
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Mid-
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Northern
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Southern
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Rig Type
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Rated Capacity
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Basin
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Texas
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Tex
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Continent
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Rockies
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Rockies
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Stacked
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Total
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Swab
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N/A
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3
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1
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7
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6
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0
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0
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1
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18
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Light Duty
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<90 tons
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7
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2
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0
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22
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2
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0
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1
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34
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Medium Duty
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³90-<125
tons
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112
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36
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25
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42
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18
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18
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1
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252
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Heavy Duty
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³125
tons
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28
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4
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5
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6
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5
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3
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0
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51
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24-Hour
|
|
³125
tons
|
|
|
1
|
|
|
|
4
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
5
|
|
Drilling Rigs
|
|
³125
tons
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
3
|
|
|
|
0
|
|
|
|
3
|
|
Inland Barge
|
|
³125
tons
|
|
|
0
|
|
|
|
0
|
|
|
|
2
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
151
|
|
|
|
47
|
|
|
|
39
|
|
|
|
76
|
|
|
|
25
|
|
|
|
24
|
|
|
|
3
|
|
|
|
365
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Management currently estimates that there are approximately
3,500 onshore well service rigs currently in the U.S., owned by
an estimated 125 contractors, and that the actual number that
are actively marketed and operable without major capital
expenditures may be as much as 15% lower than this estimate.
Based on information from U.S. contractors reporting their
utilization to Weatherford-AESC, there were 2,580 well
servicing rigs working in
6
December 2006. This figure represents a projected utilization
rate of 91% for the available fleet that are operable without
major capital expenditures.
According to the Guiberson Well Service Rig Count, by 1982
substantial new rig construction increased the total well
servicing rig fleet to a total of 8,063 well servicing rigs
operating in the United States owned by a large number of small
companies, several multi-regional contractors and a few large
national contractors. The largest well servicing contractor at
that time had less than 500 rigs, or less than 6% of the total
number of operating rigs. Due to increased competition and lower
day rates, the domestic well servicing fleet has declined
substantially over the last 20 years and has experienced
considerable consolidation that has affected companies of all
sizes, including the consolidation of several larger regional
companies. Specifically, the well servicing segment of our
industry has consolidated from nine large competitors (with 50
or more well servicing rigs) ten years ago to four today. The
excess capacity of rigs that has existed in the industry since
the early 1980s has also been reduced due to the lack of
new rig construction, retirements due to mechanical problems,
casualties, exports to foreign markets and, to some extent,
cannibalization efforts by rig operators, wherein parts are
stripped from idle rigs to outfit refurbishments on an active
rig fleet.
Based on the most recent publicly available information, our two
largest competitors market a combined 1,336 rigs. As
reported by the AESC, these two competitors total rigs
represent approximately 47% of the industrys marketed
fleet. We have the third-largest fleet with over 360 rigs, or
approximately 13% of the available U.S. industrys
fleet. Due to the fragmented nature of the market, we believe
only one company other than us and our two larger competitors
owns more than 60 rigs (with a total of only 147 rigs) and a
total of an estimated 100 companies own the approximately
1,000 estimated remaining rigs, or approximately 35% of the
industrys total fleet.
Maintenance. Regular maintenance is generally
required throughout the life of a well to sustain optimal levels
of oil and gas production. We believe regular maintenance
comprises the largest portion of our work in this business
segment. We provide well service rigs, equipment and crews for
these maintenance services. Maintenance services are often
performed on a series of wells in proximity to each other. These
services consist of routine mechanical repairs necessary to
maintain production, such as repairing inoperable pumping
equipment in an oil well or replacing defective tubing in a gas
well, and removing debris such as sand and paraffin from the
well. Other services include pulling the rods, tubing, pumps and
other downhole equipment out of the well bore to identify and
repair a production problem. These downhole equipment failures
are typically caused by the repetitive pumping action of an oil
well. Corrosion, water cut, grade of oil, sand production and
other factors can also result in frequent failures of downhole
equipment.
The need for maintenance activity does not directly depend on
the level of drilling activity, although it is somewhat impacted
by short-term fluctuations in oil and gas prices. Demand for our
maintenance services is affected by changes in the total number
of producing oil and gas wells in our geographic service areas.
Accordingly, maintenance services generally experience
relatively stable demand.
Our regular well maintenance services involve relatively
low-cost, short-duration jobs which are part of normal well
operating costs. Demand for well maintenance is driven primarily
by the production requirements of the local oil or gas fields
and, to a lesser degree, the actual prices received for oil and
gas. Well operators cannot delay all maintenance work without a
significant impact on production. Operators may, however, choose
to temporarily shut in producing wells when oil or gas prices
are too low to justify additional expenditures, including
maintenance.
Workover. In addition to periodic maintenance,
producing oil and gas wells occasionally require major repairs
or modifications called workovers, which are typically more
complex and more time consuming than maintenance operations.
Workover services include extensions of existing wells to drain
new formations either through perforating the well casing to
expose additional productive zones not previously produced,
deepening well bores to new zones or the drilling of lateral
well bores to improve reservoir drainage patterns. Our workover
rigs are also used to convert former producing wells to
injection wells through which water or carbon dioxide is then
pumped into the formation for enhanced oil recovery operations.
Workovers also include major subsurface repairs such as repair
or replacement of well casing, recovery or replacement of tubing
and removal of foreign objects from the well bore. These
extensive workover operations are normally performed by a
workover rig with additional
7
specialized auxiliary equipment, which may include rotary
drilling equipment, mud pumps, mud tanks and fishing tools,
depending upon the particular type of workover operation. Most
of our well servicing rigs are designed to perform complex
workover operations. A workover may require a few days to
several weeks and generally requires additional auxiliary
equipment. The demand for workover services is sensitive to oil
and gas producers intermediate and long-term expectations
for oil and gas prices. As oil and gas prices increase, the
level of workover activity tends to increase as oil and gas
producers seek to increase output by enhancing the efficiency of
their wells.
New Well Completion. New well completion
services involve the preparation of newly drilled wells for
production. The completion process may involve selectively
perforating the well casing in the productive zones to allow oil
or gas to flow into the well bore, stimulating and testing these
zones and installing the production string and other downhole
equipment. We provide well service rigs to assist in this
completion process. Newly drilled wells are frequently completed
by well servicing rigs to minimize the use of higher cost
drilling rigs in the completion process. The completion process
typically requires a few days to several weeks, depending on the
nature and type of the completion, and generally requires
additional auxiliary equipment. Accordingly, completion services
require less
well-to-well
mobilization of equipment and generally provide higher operating
margins than regular maintenance work. The demand for completion
services is directly related to drilling activity levels, which
are sensitive to expectations relating to and changes in oil and
gas prices.
Plugging and Abandonment. Well servicing rigs
are also used in the process of permanently closing oil and gas
wells no longer capable of producing in economic quantities.
Plugging and abandonment work can be performed with a well
servicing rig along with wireline and cementing equipment;
however, this service is typically provided by companies that
specialize in plugging and abandonment work. Many well operators
bid this work on a turnkey basis, requiring the
service company to perform the entire job, including the sale or
disposal of equipment salvaged from the well as part of the
compensation received, and complying with state regulatory
requirements. Plugging and abandonment work can provide
favorable operating margins and is less sensitive to oil and gas
pricing than drilling and workover activity since well operators
must plug a well in accordance with state regulations when it is
no longer productive. We perform plugging and abandonment work
throughout our core areas of operation in conjunction with
equipment provided by other service companies.
Fluid
Services Segment
Our fluid services segment provides oilfield fluid supply,
transportation and storage services. These services are required
in most workover, drilling and completion projects and are
routinely used in daily producing well operations. These
services include:
|
|
|
|
|
transportation of fluids used in drilling and workover
operations and of salt water produced as a by-product of oil and
gas production;
|
|
|
|
sale and transportation of fresh and brine water used in
drilling and workover activities;
|
|
|
|
rental of portable frac tanks and test tanks used to store
fluids on well sites; and
|
|
|
|
operation of company-owned fresh water and brine source wells
and of non-hazardous wastewater disposal wells.
|
This segment utilizes our fleet of fluid services trucks and
related assets, including specialized tank trucks, portable
storage tanks, water wells, disposal facilities and related
equipment. The following table sets forth the type, number and
location of the fluid services equipment that we operated at
December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Region
|
|
|
|
|
|
|
Northern
|
|
|
Permian
|
|
|
Ark-La-
|
|
|
South
|
|
|
Mid-
|
|
|
|
|
|
|
Rockies
|
|
|
Basin
|
|
|
Tex
|
|
|
Texas
|
|
|
Continent
|
|
|
Total
|
|
|
Fluid Services Trucks
|
|
|
89
|
|
|
|
198
|
|
|
|
192
|
|
|
|
128
|
|
|
|
39
|
|
|
|
646
|
|
Salt Water Disposal Wells
|
|
|
0
|
|
|
|
15
|
|
|
|
20
|
|
|
|
9
|
|
|
|
7
|
|
|
|
51
|
|
Fresh/Brine Water Stations
|
|
|
0
|
|
|
|
34
|
|
|
|
0
|
|
|
|
1
|
|
|
|
0
|
|
|
|
35
|
|
Fluid Storage Tanks
|
|
|
286
|
|
|
|
268
|
|
|
|
676
|
|
|
|
292
|
|
|
|
78
|
|
|
|
1,600
|
|
8
Requirements for minor or incidental fluid services are usually
purchased on a call out basis and charged according
to a published schedule of rates. Larger projects, such as
servicing the requirements of a multi-well drilling program or
frac program, generally involve a bidding process. We compete
for services both on a call out basis and for multi-well
contract projects.
We provide a full array of fluid sales, transportation, storage
and disposal services required on most workover, drilling and
completion projects. Our breadth of capabilities in this
business segment allows us to serve as a one-stop source for our
customers. Many of our smaller competitors in this segment can
provide some, but not all, of the equipment and services
required by customers, requiring them to use several companies
to meet their requirements and increasing their administrative
burden.
As in our well servicing segment, our fluid services segment has
a base level of business volume related to the regular
maintenance of oil and gas wells. Most oil and gas fields
produce residual salt water in conjunction with oil or gas.
Fluid service trucks pick up this fluid from tank batteries at
the well site and transport it to a salt water disposal well for
injection. This regular maintenance work must be performed if a
well is to remain active. Transportation and disposal of
produced water is considered a low value service by most
operators, and it is difficult for us to command a premium over
rates charged by our competition. Our ability to out perform
competitors in this segment depends on our ability to achieve
significant economies relating to logistics
specifically, proximity between areas where salt water is
produced and our company owned disposal wells. Ownership of
disposal wells eliminates the need to pay third parties a fee
for disposal. We operate salt water disposal wells in most of
our markets.
Workover, drilling and completion activities also provide the
opportunity for higher operating margins from tank rentals and
fluid sales. Drilling and workover jobs typically require fresh
or brine water for drilling mud or circulating fluid used during
the job. Completion and workover procedures often also require
large volumes of water for fracturing operations, a process of
stimulating a well hydraulically to increase production. Spent
mud and flowback fluids are required to be transported from the
well site to an approved disposal facility.
Competitors in the fluid services industry are mostly small,
regionally focused companies. There are currently no companies
that have a dominant position on a nationwide basis. The level
of activity in the fluid services industry is comprised of a
relatively stable demand for services related to the maintenance
of producing wells and a highly variable demand for services
used in the drilling and completion of new wells. As a result,
the level of onshore drilling activity significantly affects the
level of activity in the fluid services industry. While there
are no industry- wide statistics, the Baker Hughes Land Drilling
Rig Count is an indirect indication of demand for fluid services
because it directly reflects the level of onshore drilling
activity.
Fluid Services. We currently own and operate
over 640 fluid service tank trucks equipped with a fluid hauling
capacity of up to 150 barrels. Each fluid service truck is
equipped to pump fluids from or into wells, pits, tanks and
other storage facilities. The majority of our fluid service
trucks are also used to transport water to fill frac tanks on
well locations, including frac tanks provided by us and others,
to transport produced salt water to disposal wells, including
injection wells owned and operated by us, and to transport
drilling and completion fluids to and from well locations. In
conjunction with the rental of our frac tanks, we generally use
our fluid service trucks to transport water for use in
fracturing operations. Following completion of fracturing
operations, our fluid service trucks are used to transport the
flowback produced as a result of the fracturing operations from
the well site to disposal wells. Fluid services trucks are
generally provided to oilfield operators within a
50-mile
radius of our nearest yard.
Salt Water Disposal Well Services. We own
disposal wells that are permitted to dispose of salt water and
incidental non-hazardous oil and gas wastes. Our transport
trucks frequently transport fluids that are disposed of in these
salt water disposal wells. The disposal wells have injection
capacities ranging up to 3,500 barrels per day. Our salt
water disposal wells are strategically located in close
proximity to our customers producing wells. Most oil and
gas wells produce varying amounts of salt water throughout their
productive lives. In the states in which we generate oil and gas
wastes and salt water produced from oil and gas wells are
required by law to be disposed of in authorized facilities,
including permitted salt water disposal wells. Injection wells
are licensed by state authorities and are completed in permeable
formations below the fresh water table. We maintain separators
at most of our disposal wells permitting us to salvage residual
crude oil, which is later sold for our account.
9
Fresh and Brine Water Stations. Our network of
fresh and brine water stations, particularly, in the Permian
Basin, where surface water is generally not available, are used
to supply water necessary for the drilling and completion of oil
and gas wells. Our strategic locations, in combination with our
other fluid handling services, give us a competitive advantage
over other service providers in those areas in which these other
companies cannot provide these services.
Fluid Storage Tanks. Our fluid storage tanks
can store up to 500 barrels of fluid and are used by
oilfield operators to store various fluids at the well site,
including fresh water, brine and acid for frac jobs, flowback,
temporary production and mud storage. We transport the tanks on
our trucks to well locations that are usually within a
50-mile
radius of our nearest yard. Frac tanks are used during all
phases of the life of a producing well. We generally rent fluid
services tanks at daily rates for a minimum of three days. A
typical fracturing operation can be completed within four days
using 5 to 50 frac tanks.
Drilling
and Completion Services Segment
Our drilling and completion services segment provides oil and
gas operators with a package of services that include the
following:
|
|
|
|
|
pressure pumping services, such as cementing, acidizing,
fracturing, coiled tubing and pressure testing;
|
|
|
|
cased-hole wireline services;
|
|
|
|
underbalanced drilling in low pressure and fluid sensitive
reservoirs; and
|
|
|
|
rental and fishing tools.
|
This segment currently operates 69 pressure pumping units, with
over 58,000 of horsepower capacity, to conduct a variety of
services designed to stimulate oil and gas production or to
enable cement slurry to be placed in or circulated within a
well. As of December 31, 2006, we also operated 43 air
compressor packages, including foam circulation units, for
underbalanced drilling and 11 wireline units for cased-hole
measurement and pipe recovery services.
Just as a well servicing rig is required to perform various
operations over the life cycle of a well, there is a similar
need for equipment capable of pumping fluids into the well under
varying degrees of pressure. During the drilling and completion
phase, the well bore is lined with large diameter steel pipe
called casing. Casing is cemented into place by circulating
slurry into the annulus created between the pipe and the rock
wall of the well bore. The cement slurry is forced into the well
by pressure pumping equipment located on the surface. Cementing
services are also utilized over the life of a well to repair
leaks in the casing, to close perforations that are no longer
productive and ultimately to plug the well at the
end of its productive life.
A hydrocarbon reservoir is essentially an interval of rock that
is saturated with oil
and/or gas,
usually in combination with water. Three primary factors
determine the productivity of a well that intersects a
hydrocarbon reservoir: porosity the percentage of
the reservoir volume represented by pore space in which the
hydrocarbons reside, permeability the natural
propensity for the flow of hydrocarbons toward the well bore,
and skin the degree to which the portion
of the reservoir in close proximity to the well bore has
experienced reduced permeability as a result of exposure to
drilling fluids or other contaminants. Well productivity can be
increased by artificially improving either permeability or skin
through stimulation methods.
Permeability can be increased through the use of fracturing
methods. The reservoir is subjected to fluids pumped into it
under high pressure. This pressure creates stress in the
reservoir and causes the rock to fracture thereby creating
additional channels through which hydrocarbons can flow. In most
cases, sand or another form of proppant is pumped with the fluid
as a means of holding open the newly created fractures.
The most common means of reducing near-well bore damage, or
skin, is the injection of a highly reactive solvent (such as
hydrochloric acid) solution into the area where the hydrocarbons
enter the well. This solution has the effect of dissolving
contaminants which have accumulated and are restricting flow.
This process is generically known as acidizing.
10
As a well is drilled, long intervals of rock are left exposed
and unprotected. In order to prevent the exposed rock from
caving and to prevent fluids from entering or leaving the
exposed sections, steel casing is lowered into the hole and
cemented in place. Pressure pumping equipment is utilized to
force a cement slurry into the area between the rock face and
the casing, thereby securing it. After a well is drilled and
completed, the casing may develop leaks as a result of abrasion
from production tubing, exposure to corrosive elements or
inadequate support from the original attempt to cement it in
place. When a leak develops, it is necessary to place
specialized equipment into the well and to pump cement in such a
way as to seal the leak. Repairing leaks in this manner is known
as squeeze cementing a method that
utilizes pressure pumping equipment.
Our pressure pumping business focuses primarily on lower
horsepower cementing, acidizing and fracturing services in
markets. Major pressure pumping companies have deemphasized new
well cementing and stimulation work in the shallow well markets
and do not aggressively pursue the remedial work available in
many of the deeper well markets.
The following table sets forth the type, number and location of
the drilling and completion services equipment that we operated
at December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern
|
|
|
Southern
|
|
|
Permian
|
|
|
|
|
|
|
Ark-La-Tex
|
|
|
Mid-Continent
|
|
|
Rockies
|
|
|
Rockies
|
|
|
Basin
|
|
|
Total
|
|
|
Pressure Pumping Units
|
|
|
14
|
|
|
|
51
|
|
|
|
4
|
|
|
|
0
|
|
|
|
0
|
|
|
|
69
|
|
Coiled Tubing Units
|
|
|
0
|
|
|
|
3
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
3
|
|
Air/Foam Packages
|
|
|
0
|
|
|
|
2
|
|
|
|
0
|
|
|
|
37
|
|
|
|
4
|
|
|
|
43
|
|
Wireline Units
|
|
|
0
|
|
|
|
11
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
11
|
|
Rental and Fishing Tool Stores
|
|
|
0
|
|
|
|
9
|
|
|
|
1
|
|
|
|
0
|
|
|
|
8
|
|
|
|
18
|
|
Currently, there are only three pressure pumping companies that
provide their services on a national basis. For the most part,
these companies have concentrated their assets in markets
characterized by complex work with the potential for high profit
margins. This has created an opportunity in the markets for
pressure pumping services in mature areas with less complex
requirements. We, along with a number of smaller, regional
companies, have concentrated our efforts on these markets. One
of our major well servicing competitors also participates in the
pressure pumping business, but primarily outside our core areas
of operations for pumping services.
Like our fluid services business, the level of activity of our
pressure pumping business is tied to drilling and workover
activity. The bulk of pressure pumping work is associated with
cementing casing in place as the well is drilled or pumping
fluid that stimulates production from the well during the
completion phase. Pressure pumping work is awarded based on a
combination of price and expertise. More complex work is less
sensitive to price and routine work is often awarded on the
basis of price alone.
Cased-hole wireline services typically utilize a single truck
equipped with a spool of wireline that is used to lower and
raise a variety of specialized tools in and out of a cased
wellbore. These tools can be used to measure pressures and
temperatures as well as the condition of the casing and the
cement that holds the casing in place. Other applications for
wireline tools include placing equipment in or retrieving
equipment from the wellbore, or perforating the casing and
cutting off pipe that is stuck in the well so that the free
section can be recovered. Electric wireline contains a conduit
that allows signals to be transmitted to or from tools located
in the well. A simpler form of wireline, slickline, lacks an
electrical conduit and is used only to perform mechanical tasks
such as setting or retrieving various tools. Wireline trucks are
often used in place of a well servicing rig when there is no
requirement to remove tubulars from the well in order to make
repairs. Wireline trucks, like well servicing rigs, are utilized
throughout the life of a well.
Underbalanced drilling services, unlike pressure pumping and
wireline services, are not utilized universally throughout oil
and gas operations. Underbalanced drilling is a technique that
involves maintaining the pressure in a well at or slightly below
that of the surrounding formation using air, nitrogen, mist,
foam or lightweight drilling fluids instead of conventional
drilling fluid. Underbalanced drilling services are utilized in
areas where conventional drilling fluids or stimulation
techniques will severely damage the producing formation or in
areas where
11
drilling performance can be substantially improved with a
lightened drilling fluid. In these cases, the drilling fluid is
lightened to make the natural pressure of the formation greater
than the hydrostatic pressure of the drilling fluid, thereby
creating a situation where pressure is forcing fluid out of the
formation (i.e., underbalanced) as opposed to into the formation
(i.e., over balanced). The most common method of lightening
drilling fluid is to mix it with air as the fluid is pumped into
the well. By varying the volume of air pumped with the fluid,
the net hydrostatic pressure can be adjusted to the desired
level. In extreme cases, air alone can be used to circulate rock
cuttings from the well.
Since reservoir pressure depletes over time as a well is
produced, it may be desirable to use underbalanced fluids in
workover operations associated with an existing well. Our air
compressors, pressure boosters, trailer-mounted foam units and
associated equipment are used in a variety of drilling and
workover applications involving lightened fluids. Due to its
limited application, there is only one service company providing
these services on a national basis. The rest of the market is
serviced by small regional firms or rig contractors who supply
the equipment as part of the rig package.
Our rental and fishing tool business provides a range of
specialized services and equipment that are utilized on a
non-routine basis for both drilling and well servicing
operations. Drilling and well servicing rigs are equipped with a
complement of tools to complete routine operations under normal
conditions for most projects in the geographic area where they
are employed. When problems develop with drilling or servicing
operations, or conditions require non-routine equipment, our
customers will rely on a provider of rental and fishing tools to
augment equipment that is provided with a typical drilling or
well servicing rig package.
The term fishing applies to a wide variety of
downhole operations designed to correct a problem that has
developed when drilling or servicing a well. Most commonly the
problem involves equipment that has become lodged in the well
and cannot be removed without special equipment. Our customers
employ our technicians and our tools that are specifically
suited to retrieve the trapped equipment, or fish,
in order for operations to resume.
Well
Site Construction Services Segment
Our well site construction services segment employs an array of
equipment and assets to provide services for the construction
and maintenance of oil and gas production infrastructure. These
services are primarily related to new drilling activities,
although the same equipment is utilized to maintain oil and gas
field infrastructure. Our well site construction services
segment includes dirt work for the following services:
|
|
|
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preparation and maintenance of access roads;
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building of drilling locations;
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installation of small gathering lines and pipelines; and
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maintenance of production facilities.
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This segment utilizes a fleet of power units, including dozers,
trenchers, motor graders, backhoes and other heavy equipment
used in road construction. In addition, we own rock pits in some
markets in our Rocky Mountain operations to ensure a reliable
source of rock to support our construction activities. We also
own a substantial quantity of wooden mats in our Gulf Coast
operations to support the well site construction requirements in
that marshy environment. This range of services, coupled with
our fluid service capabilities in the same markets,
differentiates us from our more specialized competitors.
Companies engaged in oilfield construction and maintenance
services are typically privately owned and highly localized.
There are currently no companies that provide these services on
a nationwide basis. Our well site construction services in the
Gulf Coast and the Rocky Mountain states have a significant
presence in these markets.
Contracts for well site construction services are normally
awarded by our customers on the basis of competitive bidding and
may range in scope from several days to several months in
duration.
Properties
Our principal executive offices are currently located at 400 W.
Illinois, Suite 800, Midland, Texas 79701. We currently
conduct our business from 92 area offices, 45 of which we own
and 47 of which we lease. Each office
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typically includes a yard, administrative office and maintenance
facility. Of our 92 area offices, 61 are located in Texas, 8 are
in Oklahoma, 5 are in Wyoming, 5 are in New Mexico, 4 are in
Colorado, 3 are in Louisiana, 2 are in Montana, 2 are in North
Dakota, 1 is in Arkansas and 1 is in Utah.
Customers
We serve numerous major and independent oil and gas companies
that are active in our core areas of operations. During 2006, we
provided services to several customers, with no one customer
comprising over 4% of our revenues. The majority of our business
is with independent oil and gas companies. While we believe we
could redeploy equipment in the current market environment if we
lost a single material customer, or a few of them, such loss
could have an adverse effect on our business until the equipment
is redeployed.
Operating
Risks and Insurance
Our operations are subject to hazards inherent in the oil and
gas industry, such as accidents, blowouts, explosions,
craterings, fires and oil spills, that can cause:
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personal injury or loss of life;
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damage or destruction of property, equipment and the
environment; and
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suspension of operations.
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In addition, claims for loss of oil and gas production and
damage to formations can occur in the well services industry. If
a serious accident were to occur at a location where our
equipment and services are being used, it could result in our
being named as a defendant in lawsuits asserting large claims.
Because our business involves the transportation of heavy
equipment and materials, we may also experience traffic
accidents which may result in spills, property damage and
personal injury.
Despite our efforts to maintain high safety standards, we from
time to time have suffered accidents in the past and anticipate
that we could experience accidents in the future. In addition to
the property and personal losses from these accidents, the
frequency and severity of these incidents affect our operating
costs and insurability and our relationships with customers,
employees and regulatory agencies. Any significant increase in
the frequency or severity of these incidents, or the general
level of compensation awards, could adversely affect the cost
of, or our ability to obtain, workers compensation and
other forms of insurance, and could have other material adverse
effects on our financial condition and results of operations.
Although we maintain insurance coverage of types and amounts
that we believe to be customary in the industry, we are not
fully insured against all risks, either because insurance is not
available or because of the high premium costs. We do maintain
employers liability, pollution, cargo, umbrella,
comprehensive commercial general liability, workers
compensation and limited physical damage insurance. There can be
no assurance, however, that any insurance obtained by us will be
adequate to cover any losses or liabilities, or that this
insurance will continue to be available or available on terms
which are acceptable to us. Liabilities for which we are not
insured, or which exceed the policy limits of our applicable
insurance, could have a material adverse effect on us.
Competition
Our competition includes small regional contractors as well as
larger companies with international operations. Our two largest
competitors, Key Energy Services, Inc. and Nabors Well Services
Co., combined own approximately 47% of the U.S. marketable
well servicing rigs. Both of these competitors are public
companies or subsidiaries of public companies that operate in
most of the large oil and gas producing regions in the
U.S. These competitors have centralized management teams
that direct their operations and decision-making primarily from
corporate and regional headquarters. In addition, because of
their size, these companies market a large portion of their work
to the major oil and gas companies.
We differentiate ourselves from our major competition by our
operating philosophy. We operate a decentralized organization,
where local management teams are largely responsible for sales
and marketing to develop
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stronger relationships with our customers at the field level. We
target areas that are attractive to independent oil and gas
operators who in our opinion tend to be more aggressive in
spending, less focused on price and more likely to award work
based on performance. With the major oil and gas companies
divesting mature U.S. properties, we expect our target
customers well population to grow over time through
acquisition of properties formerly operated by major oil and gas
companies. We concentrate on providing services to a diverse
group of large and small independent oil and gas companies.
These independents typically are relationship driven, make
decisions at the local level and are willing to pay higher rates
for services. We have been successful using this business model
and believe it will enable us to continue to grow our business
and maintain or expand our operating margins.
Safety
Program
Our business involves the operation of heavy and powerful
equipment which can result in serious injuries to our employees
and third parties and substantial damage to property. We have
comprehensive safety and training programs designed to minimize
accidents in the work place and improve the efficiency of our
operations. In addition, many of our larger customers now place
greater emphasis on safety and quality management programs of
their contractors. We believe that these factors will gain
further importance in the future. We have directed substantial
resources toward employee safety and quality management training
programs as well as our employee review process. While our
efforts in these areas are not unique, we believe many
competitors, and particularly smaller contractors, have not
undertaken similar training programs for their employees.
We believe our approach to safety management is consistent with
our decentralized management structure. Company-mandated
policies and procedures provide the overall framework to ensure
our operations minimize the hazards inherent in our work and are
intended to meet regulatory requirements, while allowing our
operations to satisfy customer-mandated policies and local needs
and practices.
Environmental
Regulation
Our operations are subject to stringent federal, state and local
laws regulating the discharge of materials into the environment
or otherwise relating to health and safety or the protection of
the environment. Numerous governmental agencies, such as the
U.S. Environmental Protection Agency, commonly referred to
as the EPA, issue regulations to implement and
enforce these laws, which often require difficult and costly
compliance measures. Failure to comply with these laws and
regulations may result in the assessment of substantial
administrative, civil and criminal penalties, as well as the
issuance of injunctions limiting or prohibiting our activities.
In addition, some laws and regulations relating to protection of
the environment may, in certain circumstances, impose strict
liability for environmental contamination, rendering a person
liable for environmental damages and cleanup costs without
regard to negligence or fault on the part of that person. Strict
adherence with these regulatory requirements increases our cost
of doing business and consequently affects our profitability. We
believe that we are in substantial compliance with current
applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material
adverse impact on our operations. However, environmental laws
and regulations have been subject to frequent changes over the
years, and the imposition of more stringent requirements could
have a materially adverse effect upon our capital expenditures,
earnings or our competitive position.
The Comprehensive Environmental Response, Compensation and
Liability Act, referred to as CERCLA or the
Superfund law, and comparable state laws impose liability,
without regard to fault on certain classes of persons that are
considered to be responsible for the release of a hazardous
substance into the environment. These persons include the
current or former owner or operator of the disposal site or
sites where the release occurred and companies that disposed or
arranged for the disposal of hazardous substances that have been
released at the site. Under CERCLA, these persons may be subject
to joint and several liability for the costs of investigating
and cleaning up hazardous substances that have been released
into the environment, for damages to natural resources and for
the costs of some health studies. In addition, companies that
incur liability frequently confront additional claims because it
is not uncommon for neighboring landowners and other third
parties to file claims for personal injury and property damage
allegedly caused by hazardous substances or other pollutants
released into the environment.
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The federal Solid Waste Disposal Act, as amended by the Resource
Conservation and Recovery Act of 1976, referred to as
RCRA, generally does not regulate most wastes
generated by the exploration and production of oil and natural
gas because that act specifically excludes drilling fluids,
produced waters and other wastes associated with the
exploration, development or production of oil and gas from
regulation as hazardous wastes. However, these wastes may be
regulated by the EPA or state agencies as non-hazardous wastes
as long as these wastes are not commingled with regulated
hazardous wastes. Moreover, in the ordinary course of our
operations, industrial wastes such as paint wastes and waste
solvents as well as wastes generated in the course of us
providing well services may be regulated as hazardous waste
under RCRA or hazardous substances under CERCLA.
We currently own or lease, and have in the past owned or leased,
a number of properties that have been used for many years as
service yards in support of oil and natural gas exploration and
production activities. Although we have utilized operating and
disposal practices that were standard in the industry at the
time, there is the possibility that repair and maintenance
activities on rigs and equipment stored in these service yards,
as well as well bore fluids stored at these yards, may have
resulted in the disposal or release of hydrocarbons or other
wastes on or under these yards or other locations where these
wastes have been taken for disposal. In addition, we own or
lease properties that in the past were operated by third parties
whose operations were not under our control. These properties
and the hydrocarbons or wastes disposed thereon may be subject
to CERCLA, RCRA and analogous state laws. Under these laws, we
could be required to remove or remediate previously disposed
wastes or property contamination. We believe that we are in
substantial compliance with the requirements of CERCLA and RCRA.
Our operations are also subject to the federal Clean Water Act
and analogous state laws. Under the Clean Water Act, the
Environmental Protection Agency has adopted regulations
concerning discharges of storm water runoff. This program
requires covered facilities to obtain individual permits, or
seek coverage under a general permit. Some of our properties may
require permits for discharges of storm water runoff and, as
part of our overall evaluation of our current operations, we are
applying for stormwater discharge permit coverage and updating
stormwater discharge management practices at some of our
facilities. We believe that we will be able to obtain, or be
included under, these permits, where necessary, and make minor
modifications to existing facilities and operations that would
not have a material effect on us.
The federal Clean Water Act and the federal Oil Pollution Act of
1990, which contains numerous requirements relating to the
prevention of and response to oil spills into waters of the
United States, require some owners or operators of facilities
that store or otherwise handle oil to prepare and implement
spill prevention, control and countermeasure plans, also
referred to as SPCC plans, relating to the possible
discharge of oil into surface waters. In the course of our
ongoing operations, we recently updated and implemented SPCC
plans for several of our facilities. We believe we are in
substantial compliance with these regulations.
Our underground injection operations are subject to the federal
Safe Drinking Water Act, as well as analogous state and local
laws and regulations. Under Part C of the Safe Drinking
Water Act, the EPA established the Underground Injection Control
program, which established the minimum program requirements for
state and local programs regulating underground injection
activities. The Underground Injection Control program includes
requirements for permitting, testing, monitoring, record keeping
and reporting of injection well activities, as well as a
prohibition against the migration of fluid containing any
contaminant into underground sources of drinking water. The
substantial majority of our saltwater disposal wells are located
in the State of Texas and regulated by the Texas Railroad
Commission, also known as the RRC. We also operate
salt water disposal wells in Oklahoma and Wyoming and are
subject to similar regulatory controls in those states.
Regulations in these states require us to obtain a permit from
the applicable regulatory agencies to operate each of our
underground injection wells. We believe that we have obtained
the necessary permits from these agencies for each of our
underground injection wells and that we are in substantial
compliance with permit conditions and commission rules.
Nevertheless, these regulatory agencies have the general
authority to suspend or modify one or more of these permits if
continued operation of one of our underground injection wells is
likely to result in pollution of freshwater, substantial
violation of permit conditions or applicable rules, or leaks to
the environment. Although we monitor the injection process of
our wells, any leakage from the subsurface portions of the
injection wells could cause degradation of fresh groundwater
resources, potentially resulting in cancellation of operations
of a well, issuance of fines and penalties from governmental
agencies, incurrence of expenditures for remediation of the
affected resource and imposition of liability by third parties
for property damages and personal injuries. In addition, our
sales of residual crude oil
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collected as part of the saltwater injection process could
impose liability on us in the event that the entity to which the
oil was transferred fails to manage the residual crude oil in
accordance with applicable environmental health and safety laws.
We maintain insurance against some risks associated with
underground contamination that may occur as a result of well
service activities. However, this insurance is limited to
activities at the wellsite and there can be no assurance that
this insurance will continue to be commercially available or
that this insurance will be available at premium levels that
justify its purchase by us. The occurrence of a significant
event that is not fully insured or indemnified against could
have a materially adverse effect on our financial condition and
operations.
We are also subject to the requirements of the federal
Occupational Safety and Health Act (OSHA) and comparable state
statutes that regulate the protection of the health and safety
of workers. In addition, the OSHA hazard communication standard
requires that information be maintained about hazardous
materials used or produced in operations and that this
information be provided to employees, state and local government
authorities and the public. We believe that our operations are
in substantial compliance with the OSHA requirements, including
general industry standards, record keeping requirements, and
monitoring of occupational exposure to regulated substances.
Employees
As of December 31, 2006, we employed approximately
4,000 people, with approximately 85% employed on an hourly
basis. Our future success will depend partially on our ability
to attract, retain and motivate qualified personnel. We are not
a party to any collective bargaining agreements, and we consider
our relations with our employees to be satisfactory.
The following are some of the important factors that could
affect our financial performance or could cause actual results
to differ materially from estimates contained in our
forward-looking statements. We may encounter risks in addition
to those described below. Additional risks and uncertainties not
currently known to us, or that we currently deem to be
immaterial, may also impair or adversely affect our business,
results of operation, financial condition and prospects.
Risks
Relating to Our Business
A
decline in or substantial volatility of oil and gas prices could
adversely affect the demand for our services.
The demand for our services is primarily determined by current
and anticipated oil and gas prices and the related general
production spending and level of drilling activity in the areas
in which we have operations. Volatility or weakness in oil and
gas prices (or the perception that oil and gas prices will
decrease) affects the spending patterns of our customers and may
result in the drilling of fewer new wells or lower production
spending on existing wells. This, in turn, could result in lower
demand for our services and may cause lower rates and lower
utilization of our well service equipment. A decline in oil and
gas prices or a reduction in drilling activities could
materially and adversely affect the demand for our services and
our results of operations.
Prices for oil and gas historically have been extremely volatile
and are expected to continue to be volatile. For example,
although oil and natural gas prices have recently hit record
levels exceeding $70 per barrel and $10 per mcf,
respectively, oil and natural gas prices fell below $11 per
barrel and $2 per mcf, respectively, in early 1999. The Cushing
WTI Spot Oil Price averaged $41.51, $56.64 and $66.05 per
barrel in 2004, 2005, and 2006 respectively, and the average
wellhead price for natural gas, as recorded by the Energy
Information Agency, was $5.49, $7.51 and $6.42 per mcf for
2004, 2005, and 2006 respectively. Commodity prices have
increased significantly in recent years, and these prices may
not remain at current levels.
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Our
business depends on domestic spending by the oil and gas
industry, and this spending and our business may be adversely
affected by industry conditions that are beyond our
control.
We depend on our customers willingness to make operating
and capital expenditures to explore, develop and produce oil and
gas in the United States. Customers expectations for lower
market prices for oil and gas may curtail spending thereby
reducing demand for our services and equipment.
Industry conditions are influenced by numerous factors over
which we have no control, such as the supply of and demand for
oil and gas, domestic and worldwide economic conditions,
political instability in oil and gas producing countries and
merger and divestiture activity among oil and gas producers. The
volatility of the oil and gas industry and the consequent impact
on exploration and production activity could adversely impact
the level of drilling and workover activity by some of our
customers. This reduction may cause a decline in the demand for
our services or adversely affect the price of our services. In
addition, reduced discovery rates of new oil and gas reserves in
our market areas also may have a negative long-term impact on
our business, even in an environment of stronger oil and gas
prices, to the extent existing production is not replaced and
the number of producing wells for us to service declines.
We may
not be able to grow successfully through future acquisitions or
successfully manage future growth, and we may not be able to
effectively integrate the businesses we do
acquire.
Our business strategy includes growth through the acquisitions
of other businesses. We may not be able to continue to identify
attractive acquisition opportunities or successfully acquire
identified targets. In addition, we may not be successful in
integrating our current or future acquisitions into our existing
operations, which may result in unforeseen operational
difficulties or diminished financial performance or require a
disproportionate amount of our managements attention. Even
if we are successful in integrating our current or future
acquisitions into our existing operations, we may not derive the
benefits, such as operational or administrative synergies, that
we expected from such acquisitions, which may result in the
commitment of our capital resources without the expected returns
on such capital. Furthermore, competition for acquisition
opportunities may escalate, increasing our cost of making
further acquisitions or causing us to refrain from making
additional acquisitions. We also must meet certain financial
covenants in order to borrow money under our existing credit
agreement to fund future acquisitions.
We may
require additional capital in the future. We cannot assure you
that we will be able to generate sufficient cash internally or
obtain alternative sources of capital on favorable terms, if at
all. If we are unable to fund capital expenditures our business
may be adversely affected.
We anticipate that we will continue to make substantial capital
investments to purchase additional equipment to expand our
services, refurbish our well servicing rigs and replace existing
equipment. For the year ended December 31, 2005, we
invested approximately $83.1 million in cash for capital
expenditures, excluding acquisitions. For the year ended
December 31, 2006, we invested approximately
$104.6 million in cash for capital expenditures, excluding
acquisitions. Historically, we have financed these investments
through internally generated funds, debt and equity offerings,
our capital lease program and our secured credit facilities.
These significant capital investments require cash that we could
otherwise apply to other business needs. However, if we do not
incur these expenditures while our competitors make substantial
fleet investments, our market share may decline and our business
may be adversely affected. In addition, if we are unable to
generate sufficient cash internally or obtain alternative
sources of capital to fund our proposed capital expenditures,
acquisitions, take advantage of business opportunities or
respond to competitive pressures, it could materially adversely
affect our results of operations, financial condition and
growth. If we raise additional funds by issuing equity
securities, dilution to existing stockholders may result.
Competition
within the well services industry may adversely affect our
ability to market our services.
The well services industry is highly competitive and fragmented
and includes numerous small companies capable of competing
effectively in our markets on a local basis as well as several
large companies that possess substantially greater financial and
other resources than we do. Our larger competitors greater
resources could allow those competitors to compete more
effectively than we can. The amount of equipment available may
exceed demand, which could result in active price competition.
Many contracts are awarded on a bid basis, which may further
increase competition based primarily on price. In addition,
recent market conditions have stimulated the
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reactivation of well servicing rigs and construction of new
equipment, which could result in excess equipment and lower
utilization rates in future periods.
We
depend on several significant customers, and a loss of one or
more significant customers could adversely affect our results of
operations.
Our customers consist primarily of major and independent oil and
gas companies. During 2005 and 2006, our top five customers
accounted for 16% and 15%, respectively, of our revenues. The
loss of any one of our largest customers or a sustained decrease
in demand by any of such customers could result in a substantial
loss of revenues and could have a material adverse effect on our
results of operations.
We are
dependent on particular suppliers for our newbuild rig program
and are vulnerable to delayed deliveries and future price
increases.
We currently purchase our well servicing rigs from a single
supplier as part of a 120-rig commitment for rigs to be
delivered through the end of December 2007, of which 66 rigs
have been delivered as of December 31, 2006. There are also
a limited number of suppliers that manufacture this type of
equipment. Although pricing is generally fixed for this newbuild
contract and program, future price increases could affect our
ability to continue to increase the number of newbuild rigs in
our fleet at economic levels. In addition, the failure of our
current supplier to timely deliver the newbuild rigs could
adversely affect our budgeted or projected financial and
operational data.
Our
industry has experienced a high rate of employee turnover. Any
difficulty we experience replacing or adding personnel could
adversely affect our business.
We may not be able to find enough skilled labor to meet our
needs, which could limit our growth. Our business activity
historically decreases or increases with the price of oil and
gas. We may have problems finding enough skilled and unskilled
laborers in the future if the demand for our services increases.
We have raised wage rates to attract workers from other fields
and to retain or expand our current work force during the past
year. If we are not able to increase our service rates
sufficiently to compensate for wage rate increases, our
operating results may be adversely affected.
Other factors may also inhibit our ability to find enough
workers to meet our employment needs. Our services require
skilled workers who can perform physically demanding work. As a
result of our industry volatility and the demanding nature of
the work, workers may choose to pursue employment in fields that
offer a more desirable work environment at wage rates that are
competitive with ours. We believe that our success is dependent
upon our ability to continue to employ and retain skilled
technical personnel. Our inability to employ or retain skilled
technical personnel generally could have a material adverse
effect on our operations.
Our
success depends on key members of our management, the loss of
any of whom could disrupt our business operations.
We depend to a large extent on the services of some of our
executive officers. The loss of the services of Kenneth V.
Huseman, our President and Chief Executive Officer, or other key
personnel could disrupt our operations. Although we have entered
into employment agreements with Mr. Huseman and our other
executive officers that contain, among other provisions,
non-compete agreements, we may not be able to enforce the
non-compete provisions in the employment agreements. Also, we do
not have key man life insurance on these officers.
Our
operations are subject to inherent risks, some of which are
beyond our control. These risks may be self-insured, or may not
be fully covered under our insurance policies.
Our operations are subject to hazards inherent in the oil and
gas industry, such as, but not limited to, accidents, blowouts,
explosions, craterings, fires and oil spills. These conditions
can cause:
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personal injury or loss of life;
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damage to or destruction of property, equipment and the
environment; and
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suspension of operations.
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The occurrence of a significant event or adverse claim in excess
of the insurance coverage that we maintain or that is not
covered by insurance could have a material adverse effect on our
financial condition and results of operations. In addition,
claims for loss of oil and gas production and damage to
formations can occur in the well services industry. Litigation
arising from a catastrophic occurrence at a location where our
equipment and services are being used may result in us being
named as a defendant in lawsuits asserting large claims.
We maintain insurance coverage that we believe to be customary
in the industry against these hazards. However, we do not have
insurance against all foreseeable risks, either because
insurance is not available or because of the high premium costs.
We are also self-insured up to retention limits with regard to
workers compensation and medical and dental coverage on
our workover rig fleet. We maintain accruals in our consolidated
balance sheets related to self-insurance retentions by using
third-party data and historical claims history. The occurrence
of an event not fully insured against, or the failure of an
insurer to meet its insurance obligations, could result in
substantial losses. In addition, we may not be able to maintain
adequate insurance in the future at rates we consider
reasonable. Insurance may not be available to cover any or all
of these risks, or, even if available, it may be inadequate, or
insurance premiums or other costs could risk significantly in
the future so as to make such insurance prohibitive. It is
likely that, in our insurance renewals, our premiums and
deductibles will be higher, and certain insurance coverage
either will be unavailable or considerably more expensive than
it has been in the recent past. In addition, our insurance is
subject to coverage limits and some policies exclude coverage
for damages resulting from environmental contamination.
We are
subject to federal, state and local regulation regarding issues
of health, safety and protection of the environment. Under these
regulations, we may become liable for penalties, damages or
costs of remediation. Any changes in laws and government
regulations could increase our costs of doing
business.
Our operations are subject to federal, state and local laws and
regulations relating to protection of natural resources and the
environment, health and safety, waste management, and
transportation of waste and other materials. Our fluid services
segment includes disposal operations into injection wells that
pose some risks of environmental liability, including leakage
from the wells to surface or subsurface soils, surface water or
groundwater. Liability under these laws and regulations could
result in cancellation of well operations, fines and penalties,
expenditures for remediation, and liability for property damage
and personal injuries. Sanctions for noncompliance with
applicable environmental laws and regulations also may include
assessment of administrative, civil and criminal penalties,
revocation of permits and issuance of corrective action orders.
Laws protecting the environment generally have become more
stringent over time and are expected to continue to do so, which
could lead to material increases in costs for future
environmental compliance and remediation. The modification or
interpretation of existing laws or regulations, or the adoption
of new laws or regulations, could curtail exploratory or
developmental drilling for oil and gas and could limit well
servicing opportunities. Some environmental laws and regulations
may impose strict liability, which means that in some situations
we could be exposed to liability as a result of our conduct that
was lawful at the time it occurred or conduct of, or conditions
caused by, prior operators or other third parties.
Clean-up
costs and other damages arising as a result of environmental
laws, and costs associated with changes in environmental laws
and regulations could be substantial and could have a material
adverse effect on our financial condition. Please read
Business Environmental Regulation for
more information on the environmental laws and government
regulations that are applicable to us.
Our
indebtedness could restrict our operations and make us more
vulnerable to adverse economic conditions.
We now have, and will continue to have, a significant amount of
indebtedness. As of December 31, 2006, our total debt was
$262.7 million, including the aggregate principal amount
due under our Senior Notes and capital lease obligations in the
aggregate amount of $37.7 million. For the year ended
December 31, 2006, we made cash interest payments totaling
$12.6 million.
Our current and future indebtedness could have important
consequences to you. For example, it could:
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impair our ability to make investments and obtain additional
financing for working capital, capital expenditures,
acquisitions or other general corporate purposes;
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limit our ability to use operating cash flow in other areas of
our business because we must dedicate a substantial portion of
these funds to make principal and interest payments on our
indebtedness;
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make us more vulnerable to a downturn in our business, our
industry or the economy in general as a substantial portion of
our operating cash flow will be required to make principal and
interest payments on our indebtedness, making it more difficult
to react to changes in our business and in industry and market
conditions;
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limit our ability to obtain additional financing that may be
necessary to operate or expand our business;
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put us at a competitive disadvantage to competitors that have
less debt; and
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increase our vulnerability to interest rate increases to the
extent that we incur variable rate indebtedness.
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If we are unable to generate sufficient cash flow or are
otherwise unable to obtain the funds required to make principal
and interest payments on our indebtedness, or if we otherwise
fail to comply with the various covenants in our senior credit
facility or other instruments governing any future indebtedness,
we could be in default under the terms of our senior credit
facility or such instruments. In the event of a default, the
holders of our indebtedness could elect to declare all the funds
borrowed under those instruments to be due and payable together
with accrued and unpaid interest, the lenders under our credit
facilities could elect to terminate their commitments thereunder
and we or one or more of our subsidiaries could be forced into
bankruptcy or liquidation. Any of the foregoing consequences
could restrict our ability to grow our business and cause the
value of our common stock to decline.
Our
revolving credit facility and the indenture governing our Senior
Notes impose restrictions on us that may affect our ability to
successfully operate our business.
Our revolving credit facility and the indenture governing our
Senior Notes limit our ability to take various actions, such as:
|
|
|
|
|
limitations on the incurrence of additional indebtedness;
|
|
|
|
restrictions on mergers, sales or transfer of assets without the
lenders consent; and
|
|
|
|
limitation on dividends and distributions.
|
In addition, our revolving credit facility requires us to
maintain certain financial ratios and to satisfy certain
financial conditions, several of which become more restrictive
over time and may require us to reduce our debt or take some
other action in order to comply with them. The failure to comply
with any of these financial conditions, such as financial ratios
or covenants would cause a default under our revolving credit
facility. A default, if not waived, could result in acceleration
of the outstanding indebtedness under our revolving credit
facility, in which case the debt would become immediately due
and payable. In addition, a default or acceleration of
indebtedness under our revolving credit facility could result in
a default or acceleration of our Senior Notes or other
indebtedness with cross-default or cross-acceleration
provisions. If this occurs, we may not be able to pay our debt
or borrow sufficient funds to refinance it. Even if new
financing is available, it may not be available on terms that
are acceptable to us. These restrictions could also limit our
ability to obtain future financings, make needed capital
expenditures, withstand a downturn in our business or the
economy in general, or otherwise conduct necessary corporate
activities. We also may be prevented from taking advantage of
business opportunities that arise because of the limitations
imposed on us by the restrictive covenants under our revolving
credit facility. In February 2007, we amended and restated our
2005 Credit Facility by entering into a Fourth Amended and
Restated Credit Agreement. Please read Managements
Discussion and Analysis of Financial Condition and Results of
Operations Liquidity and Capital
Resources Credit Facilities for a discussion
of our Credit Facilities.
One of
our directors may have a conflict of interest because he is also
currently an affiliate, director or officer of a private equity
firm that makes investments in the energy sector. The resolution
of this conflict of interest may not be in our or our
stockholders best interests.
Steven A. Webster, the Chairman of our Board of Directors, is
the Co-Managing Partner of Avista Capital Holdings, L.P., a
private equity firm that makes investments in the energy sector.
This relationship may create a
20
conflict of interest because of his responsibilities to Avista
and its owners. His duties as a partner in, or director or
officer of, Avista or its affiliates may conflict with his
duties as a director of our company regarding corporate
opportunities and other matters. The resolution of this conflict
may not always be in our or our stockholders best interest.
Risks
Relating to Our Relationship with DLJ Merchant Banking
Affiliates
of DLJ Merchant Banking will have a substantial influence on the
outcome of stockholder voting and may exercise this voting power
in a manner that may not be in the best interest of our other
stockholders.
As of March 8, 2007, DLJ Merchant Banking
Partners III, L.P. and affiliated funds (DLJ Merchant
Banking), which are managed by affiliates of Credit
Suisse, a Swiss Bank, and Credit Suisse Securities (USA) LLC,
beneficially owned approximately 47.2% of our outstanding common
stock. Accordingly, DLJ Merchant Banking is in a position to
have a substantial influence on the outcome of matters requiring
a stockholder vote, including the election of directors,
adoption of amendments to our certificate of incorporation or
bylaws or approval of transactions involving a change of
control. The interests of DLJ Merchant Banking may differ from
those of our other stockholders, and DLJ Merchant Banking may
vote its common stock in a manner that may adversely affect our
other stockholders.
Risks
Relating to Ownership of Our Common Stock
Our
certificate of incorporation and bylaws, as well as Delaware
law, contain provisions that could discourage acquisition bids
or merger proposals, which may adversely affect the market price
of our common stock.
Our certificate of incorporation authorizes our board of
directors to issue preferred stock without stockholder approval.
If our board of directors elects to issue preferred stock, it
could be more difficult for a third party to acquire us. In
addition, some provisions of our certificate of incorporation
and bylaws could make it more difficult for a third party to
acquire control of us, even if the change of control would be
beneficial to our stockholders, including:
|
|
|
|
|
a classified board of directors, so that only approximately
one-third of our directors are elected each year;
|
|
|
|
limitations on the removal of directors;
|
|
|
|
the prohibition of stockholder action by written
consent; and
|
|
|
|
limitations on the ability of our stockholders to call special
meetings and establish advance notice provisions for stockholder
proposals and nominations for elections to the board of
directors to be acted upon at meetings of stockholders.
|
Delaware law prohibits us from engaging in any business
combination with any interested stockholder, meaning
generally that a stockholder who beneficially owns more than 15%
of our stock cannot acquire us for a period of three years from
the date this person became an interested stockholder, unless
various conditions are met, such as approval of the transaction
by our board of directors.
Because
we have no plans to pay dividends on our common stock, investors
must look solely to stock appreciation for a return on their
investment in us.
We do not anticipate paying any cash dividends on our common
stock in the foreseeable future. We currently intend to retain
all future earnings to fund the development and growth of our
business. Any payment of future dividends will be at the
discretion of our board of directors and will depend on, among
other things, our earnings, financial condition, capital
requirements, level of indebtedness, statutory and contractual
restrictions applying to the payment of dividends and other
considerations that the board of directors deems relevant. The
terms of our existing senior credit facility restrict the
payment of dividends without the prior written consent of the
lenders. Investors must rely on sales of their common stock
after price appreciation, which may never occur, as the only way
to realize a return on their investment. Investors seeking cash
dividends should not purchase our common stock.
21
ITEM 1B. UNRESOLVED
STAFF COMMENTS
None.
|
|
ITEM 3.
|
LEGAL
PROCEEDINGS
|
From time to time, Basic is a party to litigation or other legal
proceedings that Basic considers to be a part of the ordinary
course of business. Basic is not currently involved in any legal
proceedings that it considers probable or reasonably possible,
individually or in the aggregate, to result in a material
adverse effect on its financial condition, results of operations
or liquidity.
Neither Basic, nor any entity required to be consolidated with
Basic for purposes of this annual report, has been required to
pay a penalty to the Internal Revenue Service for failing to
make disclosures required with respect to certain transactions
that have been identified by the Internal Revenue Service as
abusive or that have a significant tax avoidance.
|
|
ITEM 4.
|
SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS
|
None.
Executive
Officers and Other Key Employees
Our executive officers and other key employees as of
December 31, 2006 and their respective ages and positions
are as follows:
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Position
|
|
Kenneth V. Huseman
|
|
|
54
|
|
|
President, Chief Executive Officer
and Director
|
Alan Krenek
|
|
|
51
|
|
|
Senior Vice President, Chief
Financial Officer, Treasurer and Secretary
|
Charles W. Swift
|
|
|
57
|
|
|
Senior Vice President
Rig and Truck Operations
|
Dub W. Harrison
|
|
|
49
|
|
|
Vice President
Equipment & Safety
|
Mark D. Rankin
|
|
|
53
|
|
|
Vice President Risk
Management
|
James E. Tyner
|
|
|
56
|
|
|
Vice President Human
Resources
|
T.M. Roe Patterson
|
|
|
32
|
|
|
Vice President
Corporate Development, Rental and Fishing Tool Operations
|
Set forth below is the description of the backgrounds of our
executive officers and other key employees.
Kenneth V. Huseman (President Chief Executive
Officer and Director) has 28 years of well servicing
experience. He has been our President, Chief Executive Officer
and Director of Basic Energy Services since 1999. Prior to
joining Basic, he was Chief Operating Officer at Key Energy
Services from 1996 to 1999. He was a Divisional Vice President
at WellTech, Inc., from 1993 to 1996. From 1982 to 1993, he was
employed at Pool Energy Services Co., where he managed
operations throughout the United States, including drilling
operations in Alaska. Mr. Huseman graduated with a B.B.A.
degree in Accounting from Texas Tech University.
Alan Krenek (Senior Vice President, Chief Financial Officer,
Treasurer and Secretary) has 19 years of related
industry experience. He has been our Vice President, Chief
Financial Officer and Treasurer since January 2005. He became
Senior Vice President and Secretary in May 2006. From October
2002 to January 2005, he served as Vice President and Controller
of Fleetwood Retail Corp., a subsidiary in the manufactured
housing division of Fleetwood Enterprises, Inc. From March 2002
to August 2002, he was a consultant involved in management,
assessment of operational and financial internal controls, cost
recovery and cash flow management. Mr. Krenek pursued
personal interests from November 2001 to March 2002. He worked
in various financial management positions at Pool Energy
Services Co. from 1980 to 1993 and at Noble Corporation from
1993 to 1995. Mr. Krenek graduated with a B.B.A. degree in
Accounting from Texas A&M University in 1977 and is a
certified public accountant.
Charles W. Swift (Senior Vice President Rig and
Truck Operations) has 34 years of related industry
experience including 26 years specifically in the domestic
well service business. He was named Senior Vice
22
President Rig and Truck Operations in July 2006, has
served as a Vice President since 1997 and was involved in
integrating several acquisitions during our expansion phase in
late 1997. He was a co-owner of S&N Well Service from 1986
to 1997 and expanded the business to 17 rigs at the time of sale
of the company to us. From 1980 to 1986, he worked at Pool
Energy Services Co. where he managed well service and fluid
services businesses. Mr. Swift graduated with a B.B.A.
degree in International Trade from Texas Tech University.
Dub W. Harrison (Vice President
Equipment & Safety) has spent 30 years in the
well services industry. He has been a Vice President since 1995,
during which time he established operations in east Texas,
negotiated an acquisition to enter the south Texas market and
implemented a consistent maintenance program. From 1987 to 1995,
he worked in operations and maintenance management at Pool
Energy Services Co.
Mark D. Rankin (Vice President Business
Development) has 29 years of related industry
experience. He has been a Vice President since 2004. From 1997
to 2004, he was a consultant to oil and gas companies and was
involved in operations research and work process redesign. From
1985 to 1995, he acted as Director of International Marketing
and Marketing for U.S. Operations and a District Manager at
Pool Energy Services Co.. He was an International Sales Manager
and Director of Planning and Market Research at Zapata Off-Shore
Company from 1979 to 1985. From 1977 to 1989, he was a Contract
Manager at Western Oceanic, Inc. He graduated with a B.A. in
Political Science from Texas A&M University.
James E. Tyner (Vice President Human Resources)
has been a Vice President since January 2004. From 1999 to
June 2003, he was the General Manager of Human Resources at CMS
Panhandle Companies, where he directed delivery of HR Services.
Mr. Tyner was the Director of Human Resources
Administration and Payroll Services at Duke Energys Gas
Transmission Group from 1998 to 1999. From 1981 to 1998,
Mr. Tyner held various positions at Panhandle Eastern
Corporation. At Panhandle, he managed all Human Resources
functions and developed corporate policies and as a Certified
Safety Professional, he designed and implemented programs to
control workplace hazards. Mr. Tyner received a B.S. in
General Science and M.S. in Microbiology from Mississippi State
University.
T. M. Roe Patterson (Vice
President Corporate Development, Rental &
Fishing Tool Operations) has 12 years of related
industry experience. He has been our Vice President of Corporate
Development since February 2006. He became our Vice President of
Rental and Fishing Tool Operations in July of 2006. Prior to
joining us, he was president of his own manufacturing and
oilfield service company, TMP Companies, Inc., from 2000 to
2006. He was the Contracts/Sales Manager for Permian Division of
Patterson Drilling Company from 1996 to 2000. He was an Engine
Sales Manager for West Texas Caterpillar from 1995 to 1996.
Mr. Patterson graduated with a B.S. degree in Biology from
Texas Tech University.
23
PART II
|
|
ITEM 5.
|
MARKET
PRICE FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
|
Market
Price for Registrants Common Equity
Our common stock has traded on the New York Stock Exchange under
the symbol BAS since December 9, 2005. The
table below presents the high and low daily closing sales prices
of the common stock, as reported by the New York Stock Exchange,
for the period from our initial trading (December 9,
2005) until the end of the fourth quarter of 2005 and for
each of the quarters in the year ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
High
|
|
|
Low
|
|
|
2005:
|
|
|
|
|
|
|
|
|
Fourth Quarter
|
|
$
|
22.00
|
|
|
$
|
19.20
|
|
2006:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
29.80
|
|
|
$
|
20.36
|
|
Second Quarter
|
|
$
|
36.82
|
|
|
$
|
24.37
|
|
Third Quarter
|
|
$
|
31.30
|
|
|
$
|
23.13
|
|
Fourth Quarter
|
|
$
|
26.84
|
|
|
$
|
22.34
|
|
As of March 8, 2007, we had 38,300,105 shares of
common stock outstanding held by approximately 285 record
holders.
We have not declared or paid any cash dividends on our common
stock, and we do not currently anticipate paying any cash
dividends on our common stock in the foreseeable future. We
currently intend to retain all future earnings to fund the
development and growth of our business. Any future determination
relating to our dividend policy will be at the discretion of our
board of directors and will depend on our results of operations,
financial condition, capital requirements and other factors
deemed relevant by our board. We are also currently restricted
in our ability to pay dividends under our senior credit facility.
Securities
Authorized for Issuance under Equity Compensation
Plans
The following table provides information regarding options or
warrants authorized for issuance under our equity compensation
plans as of December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
Number of
|
|
|
|
|
|
Securities
|
|
|
|
Securities to be
|
|
|
Weighted
|
|
|
Remaining
|
|
|
|
Issued upon
|
|
|
Average Exercise
|
|
|
Available for
|
|
|
|
Exercise of
|
|
|
Price of
|
|
|
Future Issuance
|
|
|
|
Outstanding
|
|
|
Outstanding
|
|
|
Under Equity
|
|
Plan Category
|
|
Options
|
|
|
Options
|
|
|
Compensation Plans
|
|
|
Equity compensation plans approved
by security holders(1)
|
|
|
2,457,780
|
|
|
$
|
9.05
|
|
|
|
1,406,950
|
|
Equity compensation plans not
approved by security holders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,457,780
|
|
|
$
|
9.05
|
|
|
|
1,406,950
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Consists of the Basic Energy Services, Inc. Second Amended and
Restated 2003 Incentive Plan (as amended effective
April 22, 2005) |
24
|
|
ITEM 6.
|
SELECTED
FINANCIAL DATA
|
The following table sets forth our selected historical financial
information for the periods shown. The following information
should be read in conjunction with Managements
Discussion and Analysis of Financial Condition and Results of
Operations and our financial statements included elsewhere
in this report. The amounts for each historical annual period
presented below were derived from our audited financial
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2002
|
|
|
2003
|
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
|
(Dollars in thousands, except per share data)
|
|
|
Statement of Operations
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
$
|
73,848
|
|
|
$
|
104,097
|
|
|
$
|
142,551
|
|
|
$
|
221,993
|
|
|
$
|
330,725
|
|
Fluid services
|
|
|
34,170
|
|
|
|
52,810
|
|
|
|
98,683
|
|
|
|
132,280
|
|
|
|
194,636
|
|
Drilling and completion services
|
|
|
733
|
|
|
|
14,808
|
|
|
|
29,341
|
|
|
|
59,832
|
|
|
|
154,412
|
|
Well site construction services
|
|
|
|
|
|
|
9,184
|
|
|
|
40,927
|
|
|
|
45,647
|
|
|
|
50,375
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
108,751
|
|
|
|
180,899
|
|
|
|
311,502
|
|
|
|
459,752
|
|
|
|
730,148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
|
55,643
|
|
|
|
73,244
|
|
|
|
98,058
|
|
|
|
137,392
|
|
|
|
186,428
|
|
Fluid services
|
|
|
22,705
|
|
|
|
34,420
|
|
|
|
65,167
|
|
|
|
82,551
|
|
|
|
118,378
|
|
Drilling and completion services
|
|
|
512
|
|
|
|
9,363
|
|
|
|
17,481
|
|
|
|
30,900
|
|
|
|
74,981
|
|
Well site construction services
|
|
|
|
|
|
|
6,586
|
|
|
|
31,454
|
|
|
|
32,000
|
|
|
|
35,067
|
|
General and administration(a)
|
|
|
13,019
|
|
|
|
22,722
|
|
|
|
37,186
|
|
|
|
55,411
|
|
|
|
81,318
|
|
Depreciation and amortization
|
|
|
13,414
|
|
|
|
18,213
|
|
|
|
28,676
|
|
|
|
37,072
|
|
|
|
62,087
|
|
Loss (gain) on disposal of assets
|
|
|
351
|
|
|
|
391
|
|
|
|
2,616
|
|
|
|
(222
|
)
|
|
|
277
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
105,644
|
|
|
|
164,939
|
|
|
|
280,638
|
|
|
|
375,104
|
|
|
|
558,536
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
3,107
|
|
|
|
15,960
|
|
|
|
30,864
|
|
|
|
84,648
|
|
|
|
171,612
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest expense
|
|
|
(4,750
|
)
|
|
|
(5,174
|
)
|
|
|
(9,550
|
)
|
|
|
(12,660
|
)
|
|
|
(15,504
|
)
|
Gain (loss) on early
extinguishment of debt
|
|
|
|
|
|
|
(5,197
|
)
|
|
|
|
|
|
|
(627
|
)
|
|
|
(2,705
|
)
|
Other income (expense)
|
|
|
31
|
|
|
|
146
|
|
|
|
(398
|
)
|
|
|
220
|
|
|
|
169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing
operations before income taxes
|
|
|
(1,612
|
)
|
|
|
5,735
|
|
|
|
20,916
|
|
|
|
71,581
|
|
|
|
153,572
|
|
Income tax (expense) benefit
|
|
|
382
|
|
|
|
(2,772
|
)
|
|
|
(7,984
|
)
|
|
|
(26,800
|
)
|
|
|
(54,742
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing
operations
|
|
|
(1,230
|
)
|
|
|
2,963
|
|
|
|
12,932
|
|
|
|
44,781
|
|
|
|
98,830
|
|
Discontinued operations, net of tax
|
|
|
|
|
|
|
22
|
|
|
|
(71
|
)
|
|
|
|
|
|
|
|
|
Cumulative effect of accounting
change, net of tax
|
|
|
|
|
|
|
(151
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
(1,230
|
)
|
|
|
2,834
|
|
|
|
12,861
|
|
|
|
44,781
|
|
|
|
98,830
|
|
Preferred stock dividend
|
|
|
(1,075
|
)
|
|
|
(1,525
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of preferred stock
discount
|
|
|
(374
|
)
|
|
|
(3,424
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to
common stockholders
|
|
$
|
(2,679
|
)
|
|
$
|
(2,115
|
)
|
|
$
|
12,861
|
|
|
$
|
44,781
|
|
|
$
|
98,830
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2002
|
|
|
2003
|
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
|
(Dollars in thousands, except per share data)
|
|
|
Basic earnings (loss) per share of
common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations less
preferred stock dividend and accretion
|
|
$
|
(0.13
|
)
|
|
$
|
(0.09
|
)
|
|
$
|
0.46
|
|
|
$
|
1.57
|
|
|
$
|
2.87
|
|
Discontinued operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of accounting
change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to
common stockholders
|
|
$
|
(0.13
|
)
|
|
$
|
(0.09
|
)
|
|
$
|
0.46
|
|
|
$
|
1.57
|
|
|
$
|
2.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per share
of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations less
preferred stock dividend and accretion
|
|
$
|
(0.13
|
)
|
|
$
|
(0.09
|
)
|
|
$
|
0.42
|
|
|
$
|
1.35
|
|
|
$
|
2.56
|
|
Discontinued operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of accounting
change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to
common stockholders
|
|
$
|
(0.13
|
)
|
|
$
|
(0.09
|
)
|
|
$
|
0.42
|
|
|
$
|
1.35
|
|
|
$
|
2.56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from operating
activities
|
|
|
17,012
|
|
|
|
29,815
|
|
|
|
46,539
|
|
|
|
99,189
|
|
|
|
145,678
|
|
Cash flows from investing
activities
|
|
|
(45,303
|
)
|
|
|
(84,903
|
)
|
|
|
(73,587
|
)
|
|
|
(107,679
|
)
|
|
|
(241,351
|
)
|
Cash flows from financing
activities
|
|
|
21,572
|
|
|
|
79,859
|
|
|
|
21,498
|
|
|
|
21,188
|
|
|
|
114,193
|
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquistions, net of cash acquired
|
|
|
31,075
|
|
|
|
61,885
|
|
|
|
19,284
|
|
|
|
25,378
|
|
|
|
135,568
|
|
Property and equipment
|
|
|
14,674
|
|
|
|
23,501
|
|
|
|
55,674
|
|
|
|
83,095
|
|
|
|
104,574
|
|
|
|
|
(a) |
|
Includes approximately $0, $994,000, $1,587,000, $2,890,000 and
$3,429,000 of non-cash stock compensation expense for the years
ended December 31, 2002, 2003, 2004, 2005 and 2006,
respectively. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2002
|
|
|
2003
|
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
|
(Dollars in thousands)
|
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
926
|
|
|
$
|
25,697
|
|
|
$
|
20,147
|
|
|
$
|
32,845
|
|
|
$
|
51,365
|
|
Property and equipment, net
|
|
|
108,487
|
|
|
|
188,243
|
|
|
|
233,451
|
|
|
|
309,075
|
|
|
|
475,431
|
|
Total assets
|
|
|
156,502
|
|
|
|
302,653
|
|
|
|
367,601
|
|
|
|
496,957
|
|
|
|
796,260
|
|
Long-term debt
|
|
|
39,706
|
|
|
|
142,116
|
|
|
|
170,915
|
|
|
|
119,241
|
|
|
|
250,742
|
|
Mandatorily redeemable cumulative
preferred stock
|
|
|
12,093
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity (deficit)
|
|
|
72,558
|
|
|
|
107,295
|
|
|
|
121,786
|
|
|
|
258,575
|
|
|
|
379,250
|
|
|
|
ITEM 7.
|
MANAGEMENTS
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATION
|
Managements
Overview
We provide a wide range of well site services to oil and gas
drilling and producing companies, including well servicing,
fluid services, drilling and completion services and well site
construction services. Our results of operations since the
beginning of 2002 reflect the impact of our acquisition strategy
as a leading consolidator in the
26
domestic land-based well services industry during this period.
Our acquisitions have increased our breadth of service offerings
at the well site and expanded our market presence. In
implementing this strategy, we have purchased businesses and
assets in 47 separate acquisitions from January 1, 2001 to
December 31, 2006. Our weighted average number of well
servicing rigs has increased from 126 in 2001 to 362 in the
fourth quarter of 2006, and our weighted average number of fluid
service trucks has increased from 156 to 640 in the same period.
In 2006, primarily through acquisitions, we significantly
increased our drilling and completion (principally pressure
pumping and rental and fishing tools) service. These
acquisitions make changes in revenues, expenses and income not
directly comparable.
Our operating revenues from each of our segments, and their
relative percentages of our total revenues, consisted of the
following (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
$
|
142.6
|
|
|
|
46
|
%
|
|
$
|
222.0
|
|
|
|
48
|
%
|
|
$
|
330.7
|
|
|
|
45
|
%
|
Fluid services
|
|
|
98.7
|
|
|
|
32
|
%
|
|
|
132.3
|
|
|
|
29
|
%
|
|
|
194.6
|
|
|
|
27
|
%
|
Drilling and completion services
|
|
|
29.3
|
|
|
|
9
|
%
|
|
|
59.8
|
|
|
|
13
|
%
|
|
|
154.4
|
|
|
|
21
|
%
|
Well site construction services
|
|
|
40.9
|
|
|
|
13
|
%
|
|
|
45.7
|
|
|
|
10
|
%
|
|
|
50.4
|
|
|
|
7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
311.5
|
|
|
|
100
|
%
|
|
$
|
459.8
|
|
|
|
100
|
%
|
|
$
|
730.1
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our core businesses depend on our customers willingness to
make expenditures to produce, develop and explore for oil and
gas in the United States. Industry conditions are influenced by
numerous factors, such as the supply of and demand for oil and
gas, domestic and worldwide economic conditions, political
instability in oil producing countries and merger and
divestiture activity among oil and gas producers. The volatility
of the oil and gas industry, and the consequent impact on
exploration and production activity, could adversely impact the
level of drilling and workover activity by some of our
customers. This volatility affects the demand for our services
and the price of our services. In addition, the discovery rate
of new oil and gas reserves in our market areas also may have an
impact on our business, even in an environment of stronger oil
and gas prices. For a more comprehensive discussion of our
industry trends, see Business General Industry
Overview.
We derive a majority of our revenues from services supporting
production from existing oil and gas operations. Demand for
these production-related services, including well servicing and
fluid services, tends to remain relatively stable, even in
moderate oil and gas price environments, as ongoing maintenance
spending is required to sustain production. As oil and gas
prices reach higher levels, demand for all of our services
generally increases as our customers engage in more well
servicing activities relating to existing wells to maintain or
increase oil and gas production from those wells. Because our
services are required to support drilling and workover
activities, we are also subject to changes in capital spending
by our customers as oil and gas prices increase or decrease.
We believe that the most important performance measures for our
lines of business are as follows:
|
|
|
|
|
Well Servicing rig hours, rig utilization rate,
revenue per rig hour and segment profits as a percent of
revenues;
|
|
|
|
Fluid Services revenue per truck and segment profits
as a percent of revenues;
|
|
|
|
Drilling and Completion Services segment profits as
a percent of revenues; and
|
|
|
|
Well Site Construction Services segment profits as a
percent of revenues.
|
Segment profits are computed as segment operating revenues less
direct operating costs. These measurements provide important
information to us about the activity and profitability of our
lines of business. For a detailed analysis of these indicators
for our company, see below in Segment
Overview.
We intend to continue growing our business through selective
acquisitions, continuing a newbuild program
and/or
upgrading our existing assets. Our capital investment decisions
are determined by an analysis of the projected return on capital
employed of each of those alternatives, which is substantially
driven by the cost to
27
acquire existing assets from a third party, the capital required
to build new equipment and the point in the oil and gas
commodity price cycle. Based on these factors, we make capital
investment decisions that we believe will support our long-term
growth strategy. While we believe our costs of integration for
prior acquisitions have been reflected in our historical results
of operations, integration of acquisitions may result in
unforeseen operational difficulties or require a
disproportionate amount of our managements attention. As
discussed below in Liquidity and Capital
Resources, we also must meet certain financial covenants
in order to borrow money under our existing credit agreement to
fund future acquisitions
Recent
Strategic Acquisitions and Expansions
During the period 2004 through 2006, we grew significantly
through acquisitions and capital expenditures. During 2004 and
2005, we directed our focus for growth more on the integration
and expansion of our existing businesses, through capital
expenditures and to a lesser extent, acquisitions. During 2006,
we completed ten acquisitions, of which G&L Tool, Ltd. was
considered significant for purposes of Statement of Financial
Accounting Standards No. 141 Business
Combinations.
We discuss the aggregate purchase prices and related financing
issues below in Liquidity and Capital
Resources and present the pro forma effects of the
acquisition of G&L Tool, Ltd. in note 3 of the audited
historical financial statements included in this report.
Selected
2004 Acquisitions
During 2004, we made a number of smaller acquisitions and
capital expenditures that served as a platform for future
growth. These included:
Energy
Air Drilling
On August 30, 2004, we completed the acquisition of Energy
Air Drilling Service Company, an underbalanced drilling services
company, with operations in Farmington, New Mexico, and Grand
Junction, Colorado. This acquisition added 18 air drilling
packages, four trailer-mounted foam units, and additional
compressors and boosters. This acquisition provided a platform
to expand into the Southern Rockies market area, while expanding
our service offerings. The transaction was structured as a
securities purchase for a total purchase price of approximately
$6.5 million in cash.
AWS
Wireline Services
On November 1, 2004, we completed the acquisition of
substantially all of the operating assets of AWS Wireline
Services, a cased-hole wireline company based in Albany, Texas.
This acquisition of six wireline units was our initial entry
into the wireline business. This service is complementary to our
existing pressure pumping service organization infrastructure in
this same market area. This transaction was structured as an
asset purchase for a total purchase price of approximately
$4.3 million in cash.
Selected
2005 Acquisitions
During 2005, we made several acquisitions that complemented our
existing lines of business. These included, among others:
MD Well
Service, Inc.
On May 17, 2005, we completed the acquisition of MD Well
Service, Inc., a well servicing company operating in the Rocky
Mountain region. This transaction was structured as an asset
purchase for a total purchase price of $6.0 million.
Oilwell
Fracturing Services, Inc.
On October 10, 2005, we completed the acquisition of
Oilwell Fracturing Services, Inc., a pressure pumping services
company that provides acidizing and fracturing services with
operations in central Oklahoma. This
28
acquisition will strengthen the presence of our drilling and
completion services segment in our Mid Continent division. This
transaction was structured as a stock purchase for a total
purchase price of approximately $16.1 million. The assets
acquired in the acquisition included approximately
$2.3 million in cash. The cash used to acquire Oilwell
Fracturing Services was primarily from borrowings under our
senior credit facility.
Selected
2006 Acquisitions
During 2006, we made several acquisitions that complemented our
existing lines of business and increased our presence in the
rental tool business. These included, among others:
LeBus Oil
Field Service Co.
On January 31, 2006, we acquired all of the outstanding
capital stock of LeBus Oil Field Service Co. for an acquisition
price of $26 million, subject to adjustments. This
acquisition significantly expanded our fluid services line of
business in the Ark-La-Tex region. The cash used to acquire
LeBus was primarily from borrowings under our senior credit
facility.
G&L
Tool, Ltd.
On February 28, 2006, we acquired substantially all of the
operating assets of G&L Tool, Ltd. for total consideration
of $58.5 million cash. This acquisition provided an entry
into the rental and fishing tool market and operates within our
drilling and completion line of business. The purchase agreement
also contained an earn-out agreement based on annual EBITDA
targets. The cash used to acquire G&L was primarily from
borrowings under our senior credit facility.
Chaparral
Service, Inc.
On August 15, 2006, we acquired all of the outstanding
capital stock and substantially all operating assets of the
subsidiaries of Chaparral Service, Inc. for total consideration
of $19 million cash, subject to adjustments. This
acquisition expanded our well servicing and fluid services
capabilities in the eastern New Mexico portion of the Permian
Basin. The cash used to acquire Chaparral was primarily from
operating cash.
Segment
Overview
Well
Servicing
In 2006, our well servicing segment represented 45% of our
revenues. Revenue in our well servicing segment is derived from
maintenance, workover, completion and plugging and abandonment
services. We provide maintenance-related services as part of the
normal, periodic upkeep of producing oil and gas wells.
Maintenance-related services represent a relatively consistent
component of our business. Workover and completion services
generate more revenue per hour than maintenance work due to the
use of auxiliary equipment, but demand for workover and
completion services fluctuates more with the overall activity
level in the industry.
We typically charge our customers for services on an hourly
basis at rates that are determined by the type of service and
equipment required, market conditions in the region in which the
rig operates, the ancillary equipment provided on the rig and
the necessary personnel. Depending on the type of job, we may
also charge by the project or by the day. We measure our
activity levels by the total number of hours worked by all of
the rigs in our fleet. We monitor our fleet utilization levels,
with full utilization deemed to be 55 hours per week per
rig. Our fleet has increased from a weighted average number of
272 rigs in the first quarter of 2004 to 362 in the fourth
quarter of 2006 through a combination of new build purchases and
the remainder through acquisitions and other individual
equipment purchases.
29
The following is an analysis of our well servicing operations
for each of the quarters and years in the years ended
December 31, 2004, 2005 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
Segment
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Rig
|
|
|
|
|
|
Profits
|
|
|
|
|
|
|
Number of
|
|
|
Rig
|
|
|
Utilization
|
|
|
Revenue Per
|
|
|
Per Rig
|
|
|
Segment
|
|
|
|
Rigs
|
|
|
Hours
|
|
|
Rate
|
|
|
Rig Hour
|
|
|
Hour
|
|
|
Profits %
|
|
|
2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
272
|
|
|
|
145,900
|
|
|
|
75.0
|
%
|
|
$
|
218
|
|
|
$
|
69
|
|
|
|
31.5
|
%
|
Second Quarter
|
|
|
276
|
|
|
|
154,600
|
|
|
|
78.4
|
%
|
|
$
|
222
|
|
|
$
|
69
|
|
|
|
31.1
|
%
|
Third Quarter
|
|
|
282
|
|
|
|
162,400
|
|
|
|
80.5
|
%
|
|
$
|
234
|
|
|
$
|
72
|
|
|
|
30.6
|
%
|
Fourth Quarter
|
|
|
284
|
|
|
|
155,900
|
|
|
|
76.8
|
%
|
|
$
|
246
|
|
|
$
|
78
|
|
|
|
31.7
|
%
|
Full Year
|
|
|
279
|
|
|
|
618,800
|
|
|
|
77.8
|
%
|
|
$
|
230
|
|
|
$
|
72
|
|
|
|
31.2
|
%
|
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
291
|
|
|
|
175,300
|
|
|
|
84.3
|
%
|
|
$
|
255
|
|
|
$
|
94
|
|
|
|
37.1
|
%
|
Second Quarter
|
|
|
303
|
|
|
|
192,400
|
|
|
|
88.8
|
%
|
|
$
|
280
|
|
|
$
|
107
|
|
|
|
38.2
|
%
|
Third Quarter
|
|
|
311
|
|
|
|
198,000
|
|
|
|
89.0
|
%
|
|
$
|
299
|
|
|
$
|
108
|
|
|
|
36.0
|
%
|
Fourth Quarter
|
|
|
316
|
|
|
|
195,000
|
|
|
|
86.3
|
%
|
|
$
|
329
|
|
|
$
|
134
|
|
|
|
40.7
|
%
|
Full Year
|
|
|
305
|
|
|
|
760,700
|
|
|
|
87.1
|
%
|
|
$
|
292
|
|
|
$
|
111
|
|
|
|
38.1
|
%
|
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
327
|
|
|
|
209,000
|
|
|
|
89.4
|
%
|
|
$
|
352
|
|
|
$
|
152
|
|
|
|
43.4
|
%
|
Second Quarter
|
|
|
341
|
|
|
|
221,800
|
|
|
|
91.0
|
%
|
|
$
|
366
|
|
|
$
|
161
|
|
|
|
43.9
|
%
|
Third Quarter
|
|
|
353
|
|
|
|
230,100
|
|
|
|
91.2
|
%
|
|
$
|
383
|
|
|
$
|
173
|
|
|
|
45.1
|
%
|
Fourth Quarter
|
|
|
362
|
|
|
|
218,900
|
|
|
|
84.6
|
%
|
|
$
|
401
|
|
|
$
|
169
|
|
|
|
42.1
|
%
|
Full Year
|
|
|
346
|
|
|
|
879,800
|
|
|
|
88.9
|
%
|
|
$
|
376
|
|
|
$
|
164
|
|
|
|
43.6
|
%
|
We gauge activity levels in our well servicing segment based on
rig utilization rate, revenue per rig hour and segment profits
per rig hour.
Improving market conditions since 2004 have created increased
demand for our services. Rig hours have increased due to a
combination of the improved utilization of our well servicing
rigs and the expansion of our well servicing fleet as a result
of our newbuild rig program.
We have been able to increase our revenue per rig hour from $218
in the first quarter of 2004 to $401 in the fourth quarter of
2006 mainly as a result of this higher utilization, which has
contributed to our improved segment profits.
Fluid
Services
In 2006, our fluid services segment represented 27% of our
revenues. Revenues in our fluid services segment are earned from
the sale, transportation, storage and disposal of fluids used in
the drilling, production and maintenance of oil and gas wells.
The fluid services segment has a base level of business
consisting of transporting and disposing of salt water produced
as a by-product of the production of oil and gas. These services
are necessary for our customers and generally have a stable
demand but typically produce lower relative segment profits than
other parts of our fluid services segment. Fluid services for
completion and workover projects typically require fresh or
brine water for making drilling mud, circulating fluids or frac
fluids used during a job, and all of these fluids require
storage tanks and hauling and disposal. Because we can provide a
full complement of fluid sales, trucking, storage and disposal
required on most drilling and workover projects, the add-on
services associated with drilling and workover activity enable
us to generate higher segment profits contributions. The higher
segment profits are due to the relatively small incremental
labor costs associated with providing these services in addition
to our base fluid services segment. We typically price fluid
services by the job, by the hour or by the quantities sold,
disposed of or hauled.
30
The following is an analysis of our fluid services operations
for each of the quarters and years in the years ended
December 31, 2004, 2005 and 2006 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Profits
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Per
|
|
|
|
|
|
|
Number of
|
|
|
Revenue Per
|
|
|
Fluid
|
|
|
|
|
|
|
Fluid Service
|
|
|
Fluid Service
|
|
|
Service
|
|
|
Segment
|
|
|
|
Trucks
|
|
|
Truck
|
|
|
Truck
|
|
|
Profits %
|
|
|
2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
371
|
|
|
$
|
60
|
|
|
$
|
21
|
|
|
|
34.5
|
%
|
Second Quarter
|
|
|
376
|
|
|
$
|
61
|
|
|
$
|
20
|
|
|
|
33.4
|
%
|
Third Quarter
|
|
|
386
|
|
|
$
|
67
|
|
|
$
|
23
|
|
|
|
33.7
|
%
|
Fourth Quarter
|
|
|
411
|
|
|
$
|
68
|
|
|
$
|
23
|
|
|
|
34.3
|
%
|
Full Year
|
|
|
386
|
|
|
$
|
256
|
|
|
$
|
87
|
|
|
|
34.0
|
%
|
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
435
|
|
|
$
|
67
|
|
|
$
|
24
|
|
|
|
34.3
|
%
|
Second Quarter
|
|
|
447
|
|
|
$
|
71
|
|
|
$
|
26
|
|
|
|
37.0
|
%
|
Third Quarter
|
|
|
465
|
|
|
$
|
74
|
|
|
$
|
28
|
|
|
|
38.6
|
%
|
Fourth Quarter
|
|
|
472
|
|
|
$
|
79
|
|
|
$
|
31
|
|
|
|
39.8
|
%
|
Full Year
|
|
|
455
|
|
|
$
|
291
|
|
|
$
|
109
|
|
|
|
37.6
|
%
|
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
529
|
|
|
$
|
82
|
|
|
$
|
32
|
|
|
|
39.0
|
%
|
Second Quarter
|
|
|
568
|
|
|
$
|
86
|
|
|
$
|
34
|
|
|
|
39.9
|
%
|
Third Quarter
|
|
|
614
|
|
|
$
|
83
|
|
|
$
|
32
|
|
|
|
38.5
|
%
|
Fourth Quarter
|
|
|
640
|
|
|
$
|
81
|
|
|
$
|
32
|
|
|
|
39.3
|
%
|
Full Year
|
|
|
588
|
|
|
$
|
332
|
|
|
$
|
130
|
|
|
|
39.2
|
%
|
We gauge activity levels in our fluid services segment based on
revenue and segment profits per fluid service truck.
Improved market conditions since 2004 have enabled us to further
increase our fluid services truck fleet through internal
expansion. During 2006, we also expanded this segment with the
acquisition of LeBus.
The majority of the increase in revenue per fluid services truck
from $60,000 in the first quarter of 2004 to $81,000 in the
fourth quarter of 2006 is due to the revenues derived from the
expansion of our frac tank fleet and disposal facilities as well
as minor pricing improvement from our fluid services trucks. Our
segment profits per fluid services truck have increased because
of these factors and increased utilization of our equipment.
Drilling
and Completion Services
In 2006, our drilling and completion services segment
represented 21% of our revenues. Revenues from our drilling and
completion services segment are generally derived from a variety
of services designed to stimulate oil and gas production or
place cement slurry within the wellbores. Our drilling and
completion services segment includes pressure pumping,
cased-hole wireline services, underbalanced drilling and rental
and fishing tool operations.
Our pressure pumping operations concentrate on providing single
truck, lower-horsepower cementing, acidizing and fracturing
services in selected markets. We entered the market for pressure
pumping in East Texas during late 2002, and we expanded our
presence with the acquisition of New Force in January 2003. We
entered this market in the Rocky Mountain states with the
acquisition of FESCO, which had a small cementing business based
in Gillette, Wyoming. In December 2003, we acquired the assets
of Graham Acidizing and integrated these assets into our North
Texas and East Texas operations.
31
We entered the wireline business in 2004 as part of our
acquisition of AWS Wireline, a regional firm based in North
Texas. We entered the underbalanced drilling services business
in 2004 through our acquisition of Energy Air Drilling Services,
a business operating in northwest New Mexico and the western
slope of Colorado markets. For a description of our wireline and
underbalanced drilling services, please read
Business Overview of Our Segments and
Services Drilling and Completion Services
Segment.
We entered the rental and fishing tool business through our
acquisition of G&L in the first quarter of 2006. This
acquisition added 16 stores in the north Texas, west Texas, and
Oklahoma markets.
In this segment, we generally derive our revenues on a
project-by-project
basis in a competitive bidding process. Our bids are generally
based on the amount and type of equipment and personnel
required, with the materials consumed billed separately. During
periods of decreased spending by oil and gas companies, we may
be required to discount our rates to remain competitive, which
would cause lower segment profits.
The following is an analysis of our drilling and completion
services segment for each of the quarters and years in the years
ended December 31, 2004, 2005 and 2006 (dollars in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
|
|
|
|
Revenues
|
|
|
Profits %
|
|
|
2004:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
4,865
|
|
|
|
35.5
|
%
|
Second Quarter
|
|
$
|
7,251
|
|
|
|
46.0
|
%
|
Third Quarter
|
|
$
|
8,463
|
|
|
|
41.0
|
%
|
Fourth Quarter
|
|
$
|
8,762
|
|
|
|
38.0
|
%
|
Full Year
|
|
$
|
29,341
|
|
|
|
40.4
|
%
|
2005:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
10,764
|
|
|
|
45.6
|
%
|
Second Quarter
|
|
$
|
13,512
|
|
|
|
49.1
|
%
|
Third Quarter
|
|
$
|
15,883
|
|
|
|
48.2
|
%
|
Fourth Quarter
|
|
$
|
19,673
|
|
|
|
49.5
|
%
|
Full Year
|
|
$
|
59,832
|
|
|
|
48.4
|
%
|
2006:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
27,455
|
|
|
|
49.5
|
%
|
Second Quarter
|
|
$
|
40,939
|
|
|
|
53.1
|
%
|
Third Quarter
|
|
$
|
42,109
|
|
|
|
51.3
|
%
|
Fourth Quarter
|
|
$
|
43,909
|
|
|
|
51.2
|
%
|
Full Year
|
|
$
|
154,412
|
|
|
|
51.5
|
%
|
We gauge the performance of our drilling and completion services
segment based on the segments operating revenues and
segment profits. Improved market conditions since 2004 have
enabled us to increase our pricing for these services,
contributing to the improved segment profits as a percentage of
segment revenues.
Well
Site Construction Services
In 2006, our well site construction services segment represented
7% of our revenues. Revenues from our well site construction
services segment are derived primarily from preparing and
maintaining access roads and well locations, installing small
diameter gathering lines and pipelines, constructing foundations
to support drilling rigs and providing maintenance services for
oil and gas facilities. These services are independent of our
other services and, while offered to some customers utilizing
other services, are not offered on a bundled basis. We entered
the well site construction services segment during the fourth
quarter of 2003 in the Gulf Coast through the acquisition of PWI
and in the Rocky Mountain states through our acquisition of
FESCO.
Within this segment, we generally charge established hourly
rates or competitive bid for projects depending on customer
specifications and equipment and personnel requirements. This
segment allows us to perform services to
32
customers outside the oil and gas industry, since substantially
all of our power units are general purpose construction
equipment. However, the majority of our current business in this
segment is with customers in the oil and gas industry. If our
customer base has the demand for certain types of power units
that we do not currently own, we generally purchase or lease
them without significant delay.
The following is an analysis of our well site construction
services services segment for each of the quarters and years in
the years ended December 31, 2004, 2005 and 2006 (dollars
in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
|
|
|
|
Revenues
|
|
|
Profits %
|
|
|
2004:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
8,776
|
|
|
|
24.6
|
%
|
Second Quarter
|
|
$
|
9,869
|
|
|
|
21.3
|
%
|
Third Quarter
|
|
$
|
11,297
|
|
|
|
24.3
|
%
|
Fourth Quarter
|
|
$
|
10,985
|
|
|
|
22.4
|
%
|
Full Year
|
|
$
|
40,927
|
|
|
|
23.1
|
%
|
2005:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
8,948
|
|
|
|
20.6
|
%
|
Second Quarter
|
|
$
|
10,918
|
|
|
|
30.8
|
%
|
Third Quarter
|
|
$
|
11,367
|
|
|
|
31.6
|
%
|
Fourth Quarter
|
|
$
|
14,414
|
|
|
|
33.6
|
%
|
Full Year
|
|
$
|
45,647
|
|
|
|
29.9
|
%
|
2006:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
10,265
|
|
|
|
25.5
|
%
|
Second Quarter
|
|
$
|
12,879
|
|
|
|
31.5
|
%
|
Third Quarter
|
|
$
|
13,483
|
|
|
|
30.2
|
%
|
Fourth Quarter
|
|
$
|
13,748
|
|
|
|
33.1
|
%
|
Full Year
|
|
$
|
50,375
|
|
|
|
30.5
|
%
|
We gauge the performance of our well site construction services
segment based on the segments operating revenues and
segment profits. While we monitor our levels of idle equipment,
we do not focus on revenues per piece of equipment.
Operating
Cost Overview
Our operating costs are comprised primarily of labor, including
workers compensation and health insurance, repair and
maintenance, fuel and insurance. A majority of our employees are
paid on an hourly basis. With a reduced pool of workers in the
industry, it is possible that we will have to raise wage rates
to attract workers from other fields and retain or expand our
current work force. We believe we will be able to increase
service rates to our customers to compensate for wage rate
increases. We also incur costs to employ personnel to sell and
supervise our services and perform maintenance on our fleet.
These costs are not directly tied to our level of business
activity. Compensation for our administrative personnel in local
operating yards and in our corporate office is accounted for as
general and administrative expenses. Repair and maintenance is
performed by our crews, company maintenance personnel and
outside service providers. Insurance is generally a fixed cost
regardless of utilization and relates to the number of rigs,
trucks and other equipment in our fleet, employee payroll and
safety record.
Critical
Accounting Policies and Estimates
Our consolidated financial statements are impacted by the
accounting policies used and the estimates and assumptions made
by management during their preparation. A complete summary of
these policies is included in note 2 of the notes to our
historical consolidated financial statements. The following is a
discussion of our critical accounting policies and estimates.
33
Critical
Accounting Policies
We have identified below accounting policies that are of
particular importance in the presentation of our financial
position, results of operations and cash flows and which require
the application of significant judgment by management.
Property and Equipment. Property and equipment
are stated at cost, or at estimated fair value at acquisition
date if acquired in a business combination. Expenditures for
repairs and maintenance are charged to expense as incurred. We
also review the capitalization of refurbishment of workover rigs
as described in note 2 of the notes to our historical
consolidated financial statements.
Impairments. We review our assets for
impairment at a minimum annually, or whenever, in
managements judgment, events or changes in circumstances
indicate that the carrying amount of a long-lived asset may not
be recovered over its remaining service life. Provisions for
asset impairment are charged to income when the sum of the
estimated future cash flows, on an undiscounted basis, is less
than the assets carrying amount. When impairment is
indicated, an impairment charge is recorded based on an estimate
of future cash flows on a discounted basis.
Self-Insured Risk Accruals. We are
self-insured up to retention limits with regard to workers
compensation and medical and dental coverage of our employees.
We generally maintain no physical property damage coverage on
our workover rig fleet, with the exception of certain of our
24-hour
workover rigs and newly manufactured rigs. We have deductibles
per occurrence for workers compensation and medical and
dental coverage of $150,000 and $150,000 respectively. We have
lower deductibles per occurrence for automobile liability and
general liability. We maintain accruals in our consolidated
balance sheets related to self-insurance retentions by using
third-party actuarial data and historical claims history.
Revenue Recognition. We recognize revenues
when the services are performed, collection of the relevant
receivables is probable, persuasive evidence of the arrangement
exists and the price is fixed and determinable.
Income Taxes. We account for income taxes
based upon Statement of Financial Accounting Standards
No. 109, Accounting for Income Taxes
(SFAS No. 109). Under
SFAS No. 109, deferred tax assets and liabilities are
recognized for the future tax consequences attributable to
differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases.
Deferred tax assets and liabilities are measured using statutory
tax rates expected to apply to taxable income in the years in
which those temporary differences are expected to be recovered
or settled. The effect on deferred tax assets and liabilities of
a change in tax rate is recognized in the period that includes
the statutory enactment date. A valuation allowance for deferred
tax assets is recognized when it is more likely than not that
the benefit of deferred tax assets will not be realized.
Critical
Accounting Estimates
The preparation of our consolidated financial statements in
conformity with accounting principles generally accepted in the
United States of America (GAAP) requires management to make
certain estimates and assumptions. These estimates and
assumptions affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities
at the balance sheet date and the amounts of revenues and
expenses recognized during the reporting period. We analyze our
estimates based on historical experience and various other
assumptions that we believe to be reasonable under the
circumstances. However, actual results could differ from such
estimates. The following is a discussion of our critical
accounting estimates.
Depreciation and Amortization. In order to
depreciate and amortize our property and equipment and our
intangible assets with finite lives, we estimate the useful
lives and salvage values of these items. Our estimates may be
affected by such factors as changing market conditions,
technological advances in industry or changes in regulations
governing the industry.
Impairment of Property and Equipment. Our
impairment of property and equipment requires us to estimate
undiscounted future cash flows. Actual impairment charges are
recorded using an estimate of discounted future cash flows. The
determination of future cash flows requires us to estimate rates
and utilization in future periods and such estimates can change
based on market conditions, technological advances in industry
or changes in regulations governing the industry.
34
Allowance for Doubtful Accounts. We estimate
our allowance for doubtful accounts based on an analysis of
historical collection activity and specific identification of
overdue accounts. Factors that may affect this estimate include
(1) changes in the financial positions of significant
customers and (2) a decline in commodity prices that could
affect the entire customer base.
Litigation and Self-Insured Risk Reserves. We
estimate our reserves related to litigation and self-insure risk
based on the facts and circumstances specific to the litigation
and self-insured risk claims and our past experience with
similar claims. The actual outcome of litigated and insured
claims could differ significantly from estimated amounts. As
discussed in Self-Insured Risk Accruals
above with respect to our critical accounting policies, we
maintain accruals on our balance sheet to cover self-insured
retentions. These accruals are based on certain assumptions
developed using third-party data and historical data to project
future losses. Loss estimates in the calculation of these
accruals are adjusted based upon actual claim settlements and
reported claims.
Fair Value of Assets Acquired and Liabilities
Assumed. We estimate the fair value of assets
acquired and liabilities assumed in business combinations, which
involves the use of various assumptions. These estimates may be
affected by such factors as changing market conditions,
technological advances in industry or changes in regulations
governing the industry. The most significant assumptions, and
the ones requiring the most judgment, involve the estimated fair
value of property and equipment, intangible assets and the
resulting amount of goodwill, if any. Our adoption of
SFAS No. 142 on January 1, 2002 requires us to
test annually for impairment the goodwill and intangible assets
with indefinite useful lives recorded in business combinations.
This requires us to estimate the fair values of our own assets
and liabilities at the reporting unit level. Therefore,
considerable judgment, similar to that described above in
connection with our estimation of the fair value of acquired
company, is required to assess goodwill and certain intangible
assets for impairment.
Cash Flow Estimates. Our estimates of future
cash flows are based on the most recent available market and
operating data for the applicable asset or reporting unit at the
time the estimate is made. Our cash flow estimates are used for
asset impairment analyses.
Stock-Based Compensation. On January 1,
2006, we adopted the fair value recognition provisions of
Statement of Financial Accounting Standards No. 123R,
Share-Based Payment
(SFAS No. 123R). Prior to
January 1, 2006, we accounted for share-based payments
under the recognition and measurement provisions of Accounting
Principles Board Opinion No. 25, Accounting for
stock Issued to Employees (APB
No. 25) which was permitted by Statement of Financial
Accounting Standards No. 123, Accounting for
Stock-Based Compensation
(SFAS No. 123).
We adopted SFAS No. 123R using both the modified
prospective method and the prospective method as applicable to
the specific awards granted. The modified prospective method was
applied to awards granted subsequent to the Company becoming a
public company. Awards granted prior to the Company becoming
public and which were accounted for under APB No. 25 were
adopted by using the prospective method. The results of prior
periods have not been restated. Compensation expense of the
unvested portion of awards granted as a private company and
outstanding as of January 1, 2006 will continue to be based
upon the intrinsic value method calculated under APB No. 25.
The fair value of common stock for options granted from
July 1, 2004 through September 30, 2005 was estimated
by management using an internal valuation methodology. We did
not obtain contemporaneous valuations by an unrelated valuation
specialist because we were focused on internal growth and
acquisitions and because we had consistently used our internal
valuation methodology for previous stock awards.
Income Taxes. The amount and availability of
our loss carryforwards (and certain other tax attributes) are
subject to a variety of interpretations and restrictive tests.
The utilization of such carryforwards could be limited or lost
upon certain changes in ownership and the passage of time.
Accordingly, although we believe substantial loss carryforwards
are available to us, no assurance can be given concerning the
realization of such loss carryforwards, or whether or not such
loss carryforwards will be available in the future.
Asset Retirement
Obligations. SFAS No. 143 requires us
to record the fair value of an asset retirement obligation as a
liability in the period in which it incurs a legal obligation
associated with the retirement of tangible long-lived assets and
to capitalize an equal amount as a cost of the asset,
depreciating it over the life of the asset.
35
Subsequent to the initial measurement of the asset retirement
obligation, the obligation is adjusted at the end of each
quarter to reflect the passage of time, changes in the estimated
future cash flows underlying the obligation, acquisition or
construction of assets, and settlement of obligations.
Results
of Operations
The results of operations between periods will not be
comparable, primarily due to the significant number of
acquisitions made and their relative timing in the year
acquired. See note 3 of the notes to our historical
consolidated financial statements for more detail.
Year
Ended December 31, 2006 Compared to Year Ended
December 31, 2005
Revenues. Revenues increased by 59% to
$730.1 million in 2006 from $459.8 million in 2005.
This increase was primarily due to the internal expansion of our
business segments, particularly well servicing and fluid
services, and in part due to acquisitions. The pricing and
utilization of our services, and thus related revenues, improved
due to the increase in well maintenance and drilling activity
caused by continued relatively high oil and gas prices.
Well servicing revenues increased by 49% to $330.7 million
in 2006 compared to $222.0 million in 2005. The increase
was due mainly to our internal growth of this segment as well as
an increase in our revenue per rig hour of approximately 29%,
from $292 per hour to $376 per hour. Our weighted
average number of rigs increased to 346 in 2006 compared to 305
in 2005, an increase of approximately 13%. In addition, the
utilization rate of our rig fleet increased to 88.9% in 2006
compared to 87.1% in 2005.
Fluid services revenues increased by 47% to $194.6 million
in 2006 compared to $132.3 million in 2005. This increase
was primarily due to our internal growth and acquisitions. Our
weighted average number of fluid service trucks increased to 588
in 2006 compared to 455 in 2005, an increase of approximately
29%. The increase in weighted average number of fluid service
trucks is primarily due to the internal expansion as wells as
the trucks added from the LeBus acquisition. During 2006, our
average revenue per fluid service truck was approximately
$332,000 as compared to $291,000 in 2005. The increase in
average revenue per fluid service truck reflects the expansion
of our frac tank fleet and saltwater disposal operations, as
well as increases in prices charged for our services.
Drilling and completion services revenues increased by 158% to
$154.4 million in 2006 as compared to $59.8 million in
2005. The increase in revenue between these periods was
primarily the result of internal expansion, the acquisition of
Oilwell Fracturing Services in October 2005, the acquisition of
G&L during February 2006 and improved pricing and
utilization of our services.
Well site construction services revenues increased 10% to
$50.4 million in 2006 as compared to $45.6 million in
2005.
Direct Operating Expenses. Direct operating
expenses, which primarily consist of labor, including workers
compensation and health insurance, and maintenance and repair
costs, increased by 47% to $414.9 million in 2006 from
$282.8 million in 2005 as a result of additional rigs and
trucks, increase in labor costs and higher utilization of our
equipment. Direct operating expenses decreased to 57% of
revenues in 2006 from 62% in 2005, as fixed operating costs such
as field supervision, insurance and vehicle expenses were spread
over a higher revenue base. We also benefited from higher
utilization and increased pricing of our services.
Direct operating expenses for the well servicing segment
increased by 36% to $186.4 million in 2006 as compared to
$137.4 million in 2005 due primarily due to the internal
growth of this segment. Segment profits increased to 43.6% of
revenues in 2006 compared to 38.1% in 2005, due to improved
pricing for our services and higher utilization of our equipment.
Direct operating expenses for the fluid services segment
increased by 43% to $118.4 million in 2006 as compared to
$82.6 million in 2005 due primarily to increased activity
and expansion of our fluid services fleet. Segment profits
increased to 39.1% of revenues in 2006 compared to 37.6% in 2005.
Direct operating expenses for the drilling and completion
services segment increased by 143% to $75.0 million in 2006
as compared to $30.9 million in 2005 due primarily to
increased activity and expansion of our services and
36
equipment, including the G&L acquisition. Our segment
profits increased to 51.4% of revenues in 2006 from 48.4% in
2005.
Direct operating expenses for the well-site construction
services segment increased by 10% to $35.0 million in 2006
as compared to $32.0 million in 2005. Segment profits for
this segment increased to 30.3% of revenues in 2006 as compared
to 29.9% in 2005.
General and Administrative Expenses. General
and administrative expenses increased by 47% to
$81.3 million in 2006 from $55.4 million in 2005,
which included $3.4 million and $2.9 million of
stock-based compensation expense in 2006 and 2005, respectively.
The increase primarily reflects higher salary and office
expenses related to the expansion of our business as well as
additional staffing and other costs to enhance internal controls
as a public company.
Depreciation and Amortization
Expenses. Depreciation and amortization expenses
were $62.1 million in 2006 as compared to
$37.1 million in 2005, reflecting the increase in the size
of and investment in our asset base. We invested
$135.6 million for acquisitions in 2006 and an additional
$131.0 million for capital expenditures in 2006 (including
capital leases).
Interest Expense. Interest expense increased
by 33% to $17.5 million in 2006 from $13.1 million in
2005. The increase was due to an increase in the amount of
long-term debt during the period. In April 2006, Basic issued
$225.0 million in senior notes.
Income Tax Expense. Income tax expense was
$54.7 million in 2006 as compared to $26.8 million in
2005. Our effective tax rate in 2006 and 2005 was approximately
36% and 38%, respectively.
Loss on Early Extinguishment of Debt. In April
2006, we used the proceeds from our issuance of
$225 million aggregate principal amount of senior notes to
pay in full our Term B Loan under or senior credit facility. In
connection with the payment on the Term B Loan, we recognized a
loss on the early extinguishment of debt and wrote-off
unamortized debt issuance costs of approximately
$2.7 million compared to an approximately $627,000 loss on
the early extinguishment of debt in 2005 for amending and
restating our credit facility.
Net Income. Our net income increased to
$98.8 million in 2006 from $44.8 million in 2005. This
improvement was due primarily to the factors described above,
including our increased asset base and related revenues, higher
utilization rates and increased revenues per rig and fluid
service truck, and higher operating margins on our drilling and
completion services equipment.
Year
Ended December 31, 2005 Compared to Year Ended
December 31, 2004
Revenues. Revenues increased by 48% to
$459.8 million in 2005 from $311.5 million in 2004.
This increase was primarily due to the internal expansion of our
business segments, particularly well servicing and fluid
services. The pricing and utilization of our services improved
due to the increase in well maintenance and drilling activity
caused by higher oil and gas prices.
Well servicing revenues increased by 56% to $222.0 million
in 2005 compared to $142.6 million in 2004. The increase
was due mainly to our internal growth of this segment as well as
an increase in our revenue per rig hour of approximately 27%,
from $230 per hour to $292 per hour. Our weighted
average number of rigs increased to 305 in 2005 compared to 279
in 2004, an increase of approximately 9%. In addition, the
utilization rate of our rig fleet increased to 87.1% in 2005
compared to 77.8% in 2004.
Fluid services revenues increased by 34% to $132.3 million
in 2005 compared to $98.7 million in 2004. This increase
was primarily due to our internal growth of this segment. Our
weighted average number of fluid service trucks increased to 455
in 2005 compared to 386 in 2004, an increase of approximately
18%. During 2005, our average revenue per fluid service truck
was approximately $291,000 as compared to $256,000 in 2004. The
increase in average revenue per fluid service truck reflects the
expansion of our frac tank fleet and saltwater disposal
operations, and minor increases in prices charged for our
services.
Drilling and completion services revenues increased by 104% to
$59.8 million in 2005 as compared to $29.3 million in
2004. The increase in revenues between these periods was
primarily the result of acquisitions,
37
including our acquisition of wireline and underbalanced drilling
businesses in 2004, increased rates for our services and
internal growth.
Well site construction services revenues increased 12% to
$45.6 million in 2005 as compared to $40.9 million in
2004.
Direct Operating Expenses. Direct operating
expenses, which primarily consist of labor, including workers
compensation and health insurance, and maintenance and repair
costs, increased by 33% to $282.8 million in 2005 from
$212.2 million in 2004 as a result of additional rigs and
trucks, as well as higher utilization of our equipment. Direct
operating expenses decreased to 62% of revenues for the period
from 68% in 2004, as fixed operating costs such as field
supervision, insurance and vehicle expenses were spread over a
higher revenue base. We also benefited from higher utilization
and increased pricing of our services.
Direct operating expenses for the well servicing segment
increased by 40% to $137.4 million in 2005 as compared to
$98.1 million in 2004 due primarily to increased activity
and increased labor costs for our crews. Segment profits
increased to 38.1% of revenues in 2005 compared to 31.2% in
2004, due to improved pricing for our services and higher
utilization of our equipment.
Direct operating expenses for the fluid services segment
increased by 27% to $82.6 million in 2005 as compared to
$65.2 million in 2004 due primarily to increased activity
and expansion of our fluid services fleet. Segment profits
increased to 37.6% of revenues in 2005 compared to 34.0% in 2004.
Direct operating expenses for the drilling and completion
services segment increased by 77% to $30.9 million in 2005
as compared to $17.5 million in 2004 due primarily to
increased activity and expansion of our services and equipment.
Our segment profits increased to 48.4% of revenues in 2005 from
40.4% in 2004.
Direct operating expenses for the well-site construction
services segment increased by 2% to $32.0 million in 2005
as compared to $31.5 million in 2004. Segment profits for
this segment increased to 29.9% of revenues in 2005 as compared
to 23.1% for the same period in 2004.
General and Administrative Expenses. General
and administrative expenses increased by 49% to
$55.4 million in 2005 from $37.2 million in 2004 which
included $2.9 million and $1.6 million of stock-based
compensation expense in 2005 and 2004, respectively. The
increase primarily reflects higher salary and office expenses
related to the expansion of our business.
Depreciation and Amortization
Expenses. Depreciation and amortization expenses
were $37.1 million in 2005 and $28.7 million in 2004,
reflecting the increase in the size of and investment in our
asset base. We invested $25.4 million for acquisitions in
2005 and an additional $83.1 million for capital
expenditures in 2005 (excluding capital leases).
Interest Expense. Interest expense increased
by 35% to $13.1 million in 2005 from $9.7 million in
2004. The increase was due to an increase in the amount of
long-term debt during the period and higher interest rates. Both
prime and LIBOR interest rates increased substantially in 2005,
and both our revolver and term loan interest rates are tied
directly to these rates.
Income Tax Expense. Income tax expense was
$26.8 million in 2005 as compared to $8.0 million in
2004. Our effective tax rate in 2005 and 2004 was approximately
38%.
Loss on Early Extinguishment of Debt. In
December 2005, we entered into a Third Amended and Restated
Credit Agreement. In connection with this, we recognized a loss
on the early extinguishment of debt and wrote-off unamortized
debt issuance costs of approximately $627,000.
Net Income. Our net income increased to
$44.8 million in 2005 from $12.9 million in 2004. This
improvement was due primarily to the factors described above,
including our increased asset base and related revenues, higher
utilization rates and increased revenue per rig and fluid
service truck, and higher operating margins on our drilling and
completion services equipment.
38
Liquidity
and Capital Resources
Currently, our primary capital resources are net cash flows from
our operations, utilization of capital leases as allowed under
our 2005 Credit Facility and availability under our 2005 Credit
Facility, of which approximately $139.4 million was
available and $10.6 million letters of credit were
outstanding at December 31, 2006. As of April 30,
2006, we had paid down all amounts under the revolving portion
of our 2005 Credit Facility with the proceeds from our offering
of Senior Notes and had availability of $140.4 million and
$9.6 million of letters of credit outstanding under this
facility. As of December 31, 2006, we had cash and cash
equivalents of $51.4 million compared to $32.8 million
as of December 31, 2005. We have utilized, and expect to
utilize in the future, bank and capital lease financing and
sales of equity to obtain capital resources. When appropriate,
we will consider public or private debt and equity offerings and
non-recourse transactions to meet our liquidity needs.
Net
Cash Provided by Operating Activities
Cash flow from operating activities was $145.7 million for
the year ended December 31, 2006 as compared to
$99.2 million in 2005, and $46.5 million in 2004. The
increase in operating cash flows in 2006 compared to 2005 and to
2004 was primarily due to expansion of our fleet and
improvements in the segment profits and utilization of our
equipment. For 2004 and 2005, these favorable trends were
negatively impacted by an increase in cash required to satisfy
our working capital requirements, particularly the increase in
accounts receivable.
Capital
Expenditures
Capital expenditures are the main component of our investing
activities. Cash capital expenditures (including for
acquisitions) for 2006 were $240.1 million as compared to
$108.5 million in 2005, and $75.0 million in 2004. In
2006, the majority of our capital expenditures were for business
acquisitions. In 2005 and 2004, the majority of our capital
expenditures were for the expansion of our fleet. We also added
assets through our capital lease program of approximately
$26.4 million, $10.3 million, and $10.5 million
in 2006, 2005 and 2004, respectively.
For 2007, we currently have planned approximately
$130 million in cash capital expenditures and
$30 million through capital leases, none of which is
planned for acquisitions. We do not budget acquisitions in the
normal course of business, but we believe that we may spend a
significant amount for acquisitions in 2007. The
$160 million of capital expenditures planned for property
and equipment is primarily for (1) purchase of additional
equipment to expand our services, (2) continued
refurbishment of our well servicing rigs and
(3) replacement of existing equipment. We regularly engage
in discussions related to potential acquisitions related to the
well services industry. As of December 31, 2006, we had
executed six letters of intent for acquisitions providing for an
aggregate purchase price, including potential future payments,
of approximately $189.3 million. The acquisition of JetStar
Consolidated Holdings, Inc. was completed on March 6, 2007
and was funded with common stock and available capacity under
our credit facility revolver.
Capital
Resources and Financing
Our current primary capital resources are cash flow from our
operations, the ability to enter into capital leases of up to an
additional $12.3 million at December 31, 2006, the
availability under our credit facility of $139.4 million at
December 31, 2006 and a cash balance of $51.4 million
at December 31, 2006. In 2006, we financed activities in
excess of cash flow from operations primarily through the use of
bank debt and capital leases. During 2006, we utilized bank debt
and the issuance of senior notes for cash as consideration for
acquisitions.
39
We have significant contractual obligations in the future that
will require capital resources. Our primary contractual
obligations are (1) our long-term debt, (2) interest
on senior notes, (3) our capital leases, (4) our
operating leases, (5) our rig purchase obligations,
(6) our asset retirement obligations, and (7) our
other long-term liabilities. The following table outlines our
contractual obligations as of December 31, 2006 (in
thousands):
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Obligations Due in Periods Ended
|
|
|
|
|
|
|
December 31,
|
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|
|
|
Contractual Obligations
|
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Total
|
|
|
2007
|
|
|
2008-2009
|
|
|
2010-2011
|
|
|
Thereafter
|
|
|
Long-term debt (excluding capital
leases)
|
|
$
|
225,000
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
225,000
|
|
Interest on senior notes
|
|
|
148,957
|
|
|
|
16,031
|
|
|
|
32,063
|
|
|
|
32,063
|
|
|
|
68,800
|
|
Capital leases
|
|
|
37,743
|
|
|
|
12,001
|
|
|
|
19,454
|
|
|
|
6,288
|
|
|
|
|
|
Operating leases
|
|
|
13,606
|
|
|
|
2,551
|
|
|
|
4,458
|
|
|
|
2,693
|
|
|
|
3,904
|
|
Rig purchase obligations
|
|
|
39,823
|
|
|
|
39,823
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
|
1,336
|
|
|
|
|
|
|
|
|
|
|
|
486
|
|
|
|
850
|
|
Other long-term liabilities
|
|
|
1,733
|
|
|
|
|
|
|
|
793
|
|
|
|
106
|
|
|
|
834
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
468,198
|
|
|
$
|
70,406
|
|
|
$
|
56,768
|
|
|
$
|
41,636
|
|
|
$
|
299,388
|
|
|
|
|
|
|
|
|
|
|
|
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|
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Our long-term debt, excluding capital leases, consists primarily
of term loan indebtedness outstanding under our senior credit
facility. Interest on senior notes relates to our future
contractual interest obligation on our $225 million
7.125% Senior Notes offering in April of 2006. Our capital
leases relate primarily to light-duty and heavy-duty vehicles
and trailers. Our operating leases relate primarily to real
estate.
The table above does not reflect any additional payments that we
may be required to make pursuant to contingent earn-out
agreements that are associated with certain acquisitions. At
December 31, 2006, we had a maximum potential obligation of
$17.3 million related to the contingent earn-out
agreements. This amount does not include the balance owed for an
acquisition with no maximum earn-out exposure. In this
situation, we will pay to the sellers an amount for each of the
five consecutive 12 month periods equal to 50% of the
amount by which annual EBITDA will be reached. See note 3
of the notes to our historical consolidated financial statements
for additional detail.
The table above also does not reflect $10.6 million of
outstanding standby letters of credit issued under our revolving
line of credit. At December 31, 2006, of the
$150.0 million in financial commitments under the revolving
line of credit under our senior credit facility, there was only
$139.4 million of available capacity due to the
$10.6 million of outstanding standby letters of credit. In
the normal course of business, we have performance obligations
which are supported by surety bonds and letters of credit. These
obligations primarily cover various reclamation and plugging
obligations related to our operations, and collateral for future
workers compensation and liability retained losses.
Our ability to access additional sources of financing will be
dependent on our operating cash flows and demand for our
services, which could be negatively impacted due to the extreme
volatility of commodity prices.
Senior
Notes
In April 2006, we completed a private offering for $225,000,000
aggregate principal amount of 7.125% Senior Notes due
April 15, 2016. The Senior Notes are jointly and severally
guaranteed by each of our subsidiaries. The net proceeds from
the offering were used to retire the outstanding Term B Loan
balance and to pay down the outstanding balance under the
revolving credit facility. Remaining proceeds were used for
general corporate purposes, including acquisitions.
We issued the Senior Notes pursuant to an indenture, dated as of
April 12, 2006, by and among us, the guarantor parties
thereto and The Bank of New York Trust Company, N.A., as trustee.
Interest on the Senior Notes will accrue from and including
April 12, 2006 at a rate of 7.125% per year. Interest
on the Senior Notes is payable in cash semi-annually in arrears
on April 15 and October 15 of each year, commencing on
October 15, 2006. The Senior Notes will mature on
April 15, 2016. The Senior Notes and the
40
guarantees are unsecured and will rank equally with all of our
and the guarantors existing and future unsecured and
unsubordinated obligations. The Senior Notes and the guarantees
will rank senior in right of payment to any of our and the
guarantors existing and future obligations that are, by
their terms, expressly subordinated in right of payment to the
Senior Notes and the guarantees. The Senior Notes and the
guarantees will be effectively subordinated to our and the
guarantors secured obligations, including our senior
secured credit facilities, to the extent of the value of the
assets securing such obligations.
The indenture contains covenants that limit the ability of us
and certain of our subsidiaries to:
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incur additional indebtedness;
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pay dividends or repurchase or redeem capital stock;
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make certain investments;
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incur liens;
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enter into certain types of transactions with affiliates;
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limit dividends or other payments by restricted
subsidiaries; and
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sell assets or consolidate or merge with or into other companies.
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These limitations are subject to a number of important
qualifications and exceptions.
Upon an Event of Default (as defined in the indenture), the
trustee or the holders of at least 25% in aggregate principal
amount of the Senior Notes then outstanding may declare all of
the amounts outstanding under the Senior Notes to be due and
payable immediately.
We may, at our option, redeem all or part of the Senior Notes,
at any time on or after April 15, 2011 at a redemption
price equal to 100% of the principal amount thereof, plus a
premium declining ratably to par and accrued and unpaid
interest, if any, to the date of redemption.
At any time or from time to time prior to April 15, 2009,
we, at our option, may redeem up to 35% of the outstanding
Senior Notes with money that we raise in one or more equity
offerings at a redemption price of 107.125% of the principal
amount of the Senior Notes redeemed, plus accrued and unpaid
interest, as long as:
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at least 65% of the aggregate principal amount of Senior Notes
issued under the indenture remains outstanding immediately after
giving effect to any such redemption; and
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we redeem the Senior Notes not more than 90 days after the
closing date of any such equity offering.
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If we experience certain kinds of changes of control, holders of
the Senior Notes will be entitled to require us to purchase all
or a portion of the Senior Notes at 101% of their principal
amount, plus accrued and unpaid interest.
Credit
Facilities
2007
Credit Facility
On February 6, 2007, we amended and restated our existing
credit agreement by entering into a Fourth Amended and Restated
Credit Agreement with a syndicate of lenders (the 2007
Credit Facility). The amendments contained in the 2007
Credit Facility included:
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eliminating the $90 million class of Term B Loans;
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creating a new class of Revolving Loans, which increased the
lenders total revolving commitments from $150 million
to $225 million
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increasing the Incremental Revolving Commitments
under the 2007 Credit Facility from $75.0 million to an
aggregate principal amount of $100 million;
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changing the applicable margins for Alternative Base Rate or
Eurodollar revolving loans;
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41
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amending our negative covenants relating to our ability to incur
indebtedness and liens, to add tests based on a percentage of
our consolidated tangible assets in addition to fixed dollar
amounts, or to increase applicable dollar limits on baskets or
other tests for permitted indebtedness or liens;
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amending our negative covenants relating to our ability to pay
dividends, or repurchase or redeem our capital stock, in order
to conform more closely with permitted payments under our senior
notes; and
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Eliminating certain restrictions on our ability to create or
incur certain lease obligations.
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Under the 2007 Credit Facility, Basic Energy Services, Inc. is
the sole borrower and each of our subsidiaries is a subsidiary
guarantor. The 2007 Credit Facility provides for a
$225 million revolving line of credit
(Revolver). The 2007 Credit Facility includes
provisions allowing us to request an increase in commitments of
up to $100.0 million aggregate principal amount at any
time. Additionally, the 2007 Credit Facility permits us to make
greater expenditures for acquisitions, capital expenditures and
capital leases and to incur greater purchase money obligations,
acquisition indebtedness and general unsecured indebtedness. The
commitment under the Revolver provides for (1) the
borrowing of funds, (2) the issuance of up to
$30 million of letters of credit and
(3) $2.5 million of swing-line loans. All of the
outstanding amounts under the Revolver are due and payable on
December 15, 2010. The 2007 Credit Facility is secured by
substantially all of our tangible and intangible assets. We
incurred approximately $0.9 million in debt issuance costs
in connection with the 2007 Credit Facility.
At our option, borrowings under the Revolver bears interest at
either (1) the Alternative Base Rate (i.e., the
higher of the banks prime rate or the federal funds rate
plus .50% per year) plus a margin ranging from 0.25% to
0.5% or (2) an Adjusted LIBOR Rate (equal to
(a) the London Interbank Offered Rate (the LIBOR
rate) as determined by the Administrative Agent in effect
for such interest period divided by (b) one minus the
Statutory Reserves, if any, for such borrowing for such interest
period) plus a margin ranging from 1.25% to 1.5%. The margins
vary depending on our leverage ratio. Fees on the letters of
credit are due quarterly on the outstanding amount of the
letters of credit at a rate ranging from 1.25% to 1.5% for
participation fees and 0.125% for fronting fees. A commitment
fee is due quarterly on the available borrowings under the
Revolver at a rate of 0.375%.
At February 6, 2007, after giving affect to the amendments
under the 2007 Credit Facility, we had no outstanding borrowings
under the Revolver.
Pursuant to the 2007 Credit Facility, we must apply proceeds
from certain specified events to reduce principal outstanding
borrowings under the Revolver, including:
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|
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|
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assets sales greater than $2.0 million individually or
$7.5 million in the aggregate on an annual basis;
|
|
|
|
100% of the net cash proceeds from any debt issuance, including
certain permitted unsecured senior or senior subordinated debt,
but excluding certain other permitted debt issuances; and
|
|
|
|
50% of the net cash proceeds from any equity issuance (including
equity issued upon the exercise of any warrant or option).
|
The 2007 Credit Facility contains various restrictive covenants
and compliance requirements, including the following:
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limitations on the incurrence of additional indebtedness;
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|
restrictions on mergers, sales or transfer of assets without the
lenders consent;
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limitations on dividends and distributions; and
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various financial covenants, including:
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a maximum leverage ratio of 3.50 to 1.00, reducing to 3.25 to
1.00 on April 1, 2007, and
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|
a minimum interest coverage ratio of 3.00 to 1.00.
|
42
2005
Credit Facility
Under our Third Amended and Restated Credit Agreement with a
syndicate of lenders (the 2005 Credit Facility), as
amended effective March 28, 2006, Basic Energy Services,
Inc. was the sole borrower and each of our subsidiaries was a
subsidiary guarantor. The 2005 Credit Facility provided for a
$90 million Term B Loan (Term B Loan), which
outstanding balance was repaid in April 2006, and provided for a
$150 million revolving line of credit
(Revolver). The 2005 Credit Facility included
provisions allowing us to request an increase in commitments of
up to $75 million at any time. The commitment under the
Revolver provides for (1) the borrowing of funds,
(2) the issuance of up to $30 million of letters of
credit and (3) $2.5 million of swing-line loans. The
amounts outstanding under the Term B Loan required quarterly
amortization at various amounts during each quarter with all
amounts outstanding being due and payable in full on
December 15, 2011. All the outstanding amounts under the
Revolver were due and payable on December 15, 2010. The
2005 Credit Facility was secured by substantially all of our
tangible and intangible assets.
The 2005 Credit Facility contained customary events of default,
which are subject to customary grace periods and materiality
standards, including, among others, events of default upon the
occurrence of: (1) non-payment of any amounts payable under
the 2005 Credit Facility when due; (2) any representation
or warranty made in connection with the 2005 Credit Facility
being incorrect in any material respect when made or deemed
made; (3) default in the observance or performance of any
covenant, condition or agreement contained in the 2005 Credit
Facility or related loan documents and such default shall
continue unremedied or shall not be waived for 30 days;
(4) failure to make payments on other indebtedness
involving in excess of $1.0 million; (5) voluntary or
involuntary bankruptcy, insolvency or reorganization of us or
any of our subsidiaries; (6) entry of fines or judgments
against us for payment of an amount in excess of
$2.5 million; (7) an ERISA event which could
reasonably be expected to cause a material adverse effect or the
imposition of a lien on any of our assets; (8) any security
agreement or document under the 2005 Credit Facility ceases to
create a lien on any assets securing the 2005 Credit Facility;
(9) any guarantee ceases to be in full force and effect;
(10) any material provision of the 2005 Credit Facility
ceases to be valid and binding or enforceable; (11) a
change of control as defined in the 2005 Credit Agreement; of
(12) any determination, ruling, decision, decree or order
of any governmental authority, which prohibits or restrains
Basic and its subsidiaries from conducting business and that
could reasonably be expected to cause a material adverse effect.
2004
Credit Facility
On December 21, 2004, we amended and restated our credit
facility with a syndicate of lenders (2004 Credit
Facility) which increased aggregate commitments to us from
$170 million to $220 million. The 2004 Credit Facility
provided for a $170 million Term B Loan (2004 Term B
Loan) and a $50 million revolving line of credit
(2004 Revolver). The commitment under the 2004
Revolver allowed for (1) the borrowing of funds,
(2) the issuance of up to $20 million of letters of
credit and (3) $2.5 million of swing-line loans. The
amounts outstanding under the 2004 Term B Loan required
quarterly amortization at various amounts during each quarter
with all amounts outstanding being due and payable in full on
October 3, 2009. All the outstanding amounts under the 2004
Revolver would have been due and payable on October 3,
2008. The 2004 Credit Facility was secured by substantially all
of our tangible and intangible assets. We incurred approximately
$0.8 million in debt issuance costs in obtaining the 2004
Credit Facility.
Other
Debt
We have a variety of other capital leases and notes payable
outstanding that is generally customary in our business. None of
these debt instruments are material individually or in the
aggregate. As of December 31, 2006, we had total capital
leases of approximately $37.7 million.
Losses on
Extinguishment of Debt
In April 2006, we recognized a loss on the early extinguishment
of debt of $2.7 million representing unamortized deferred
debt issuance costs in connection with the retirement of the
Term B Loan.
43
In 2005 we recognized a loss on the early extinguishment of debt
of $627,000 in connection with our 2005 Credit Facility
discussed above.
Credit
Rating Agencies
In April 2006, we received credit ratings of Baa3 from
Moodys and B+ from Standard & Poors for our
2005 Credit Facility. Also, we received ratings of B1 from
Moodys and B from Standard & Poors for our
Senior Notes. None of our debt or other instruments is dependent
upon our credit ratings. However, the credit ratings may affect
our ability to obtain financing in the future. On
February 6, 2007, we received credit ratings of Ba1 from
Moodys and BB from Standard & Poors for our 2007
Credit Facility.
Preferred
Stock
At December 31, 2006 and December 31, 2005, Basic had
5,000,000 shares of $.01 par value preferred stock
authorized, of which none is designated.
Other
Matters
Net
Operating Losses
We used all of our then-available net operating losses for
federal income tax purposes when we completed a recapitalization
in December 2000, which included a significant amount of debt
forgiveness. In 2002, our profitability suffered and, when
combined with a significant level of capital expenditures, we
ended 2002 with a net operating loss, or NOL, of
$30.4 million. In 2003, we returned to profitability, but
we again made significant investments in existing equipment,
additional equipment and acquisitions. Due to these events, we
again reported a tax loss in 2003 and ended the year with a
$50.7 million NOL, including $7.0 million that was
included in the purchase of FESCO. As of December 31, 2006,
we had approximately $4.0 million of NOL carryforwards
related to the pre-acquisition period of FESCO, which is subject
to an annual limitation of approximately $900,000. The
carryforwards begin to expire in 2017.
Recent
Accounting Pronouncements
In September 2006, the Securities and Exchange Commission issued
Staff Accounting Bulletin No. 108 (SAB 108),
Considering the Effects of Prior Year Misstatements when
Quantifying Misstatement in Current Year Financial
Statements. The bulletins interpretations address
diversity in practice in quantifying financial statement
misstatements and the potential under current practice for the
build up of improper amounts on the balance sheet. Basic adopted
the interpretation in the fourth quarter of 2006. The adoption
of SAB 108 did not have a material impact on the
Companys financial position, cash flows, or results of
operations.
In June 2006, the Financial Accounting Standards Board (FASB)
issued Interpretation No. 48 (FIN 48), Accounting
for Uncertainty in Income Taxes, an interpretation of FASB
Statement No. 109, Accounting for Income Taxes. The
interpretation prescribes a recognition threshold and
measurement attribute for the financial statement recognition
and measurement of a tax position taken or expected to be taken,
in a tax return. FIN 48 also provides guidance on
derecognition, classification, interest and penalties accounting
in interim periods, disclosure and transition. The
interpretation is effective for fiscal years beginning after
December 15, 2006. The cumulative effect of applying the
provisions of this interpretation, which is required to be
reported as an adjustment to our opening balance of retained
earnings in 2007, is currently not expected to have a material
impact on our results of operations, financial position or cash
flows.
In December 2004, the FASB issued Statement of Financial
Accounting Standard No. 123R, Share-Based
Payment (SFAS No. 123R). We adopted
the provisions of SFAS No. 123R on January 1,
2006 using the modified prospective application. Accordingly, we
will recognize compensation expense for all newly granted awards
and awards modified, repurchased, or cancelled after
January 1, 2006.
Compensation cost for the unvested portion of awards that are
outstanding as of January 1, 2006 will be recognized
ratably over the remaining vesting period. The compensation cost
for the unvested portion of awards will be based on the fair
value at date of grant as calculated for our pro forma
disclosure under SFAS No. 123.
44
However, we will continue to account for any portion of awards
outstanding on January 1, 2006 that were initially measured
using the minimum value method under the intrinsic value method
in accordance with APB No. 25. We began to recognize
compensation expense for awards under our 2003 Incentive Plan on
January 1, 2006.
Impact
of Inflation on Operations
Management is of the opinion that inflation has not had a
significant impact on our business.
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ITEM 7A.
|
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
As of December 31, 2006, we had no outstanding borrowings
subject to variable interest rate risk. In April 2006, we
completed a private offering for $225,000,000 aggregate
principal amount of 7.125% Senior Notes. The net proceeds
from the offering were used to retire the outstanding Term B
Loan balance under our senior credit facility and to pay down
the outstanding balance under the revolving credit facility.
When the Term B Loan was retired, we settled an existing
interest rate swap agreement and realized a gain on settlement
of $287,000.
However, we do have available borrowing capacity under our
revolving credit facility, and we will be subject to variable
interest rate risk in the event we have outstanding borrowings
under the revolving credit facility in the future. On
March 6, 2007, we borrowed approximately
$85.0 million, which was subject to variable interest rate
risk, under the revolving credit facility to help fund the
acquisition of JetStar Consolidated Holdings, Inc.
45
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ITEM 8.
|
FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
|
Basic
Energy Services, Inc.
INDEX TO
CONSOLIDATED FINANCIAL STATEMENTS
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Page
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47
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48
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51
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52
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53
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54
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|
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55
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|
81
|
|
46
MANAGEMENTS
REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Basic Energy Services, Inc. (Basic or
the Company) is responsible for establishing and
maintaining adequate internal control over financial reporting
and for the assessment of the effectiveness of internal control
over financial reporting for the Company. As defined by the
Securities and Exchange Commission
(Rule 13a-15(f)
under the Exchange Act of 1934, as amended), internal control
over financial reporting is a process designed by, or under the
supervision of Basics principal executive and principal
financial officers and effected by its Board of Directors,
management and other personnel, to provide reasonable assurance
regarding the reliability of financial reporting and the
preparation of the consolidated financial statements in
accordance with U.S. generally accepted accounting
principles.
The Companys internal control over financial reporting is
supported by written policies and procedures that
(1) pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect the
Companys transactions and dispositions of the
Companys assets; (2) provide reasonable assurance
that transactions are recorded as necessary to permit
preparation of the consolidated financial statements in
accordance with U.S. generally accepted accounting
principles, and that receipts and expenditures of the Company
are being made only in accordance with authorization of the
Companys management and directors; 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
consolidated financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In connection with the preparation of the Companys annual
consolidated financial statements, management has undertaken an
assessment of the effectiveness of the Companys internal
control over financial reporting as of December 31, 2006,
based on criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO Framework).
Managements assessment included an evaluation of the
design of the Companys internal control over financial
reporting and testing of the operational effectiveness of those
controls.
Based on this assessment, management has concluded that as of
December 31, 2006, the Companys internal control over
financial reporting was effective to provide reasonable
assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in
accordance with U.S. generally accepted accounting
principles.
The Company acquired G&L Tool, Ltd., Arkla Cementing, Inc.,
Globe Well Service, Inc., Hennessey Rental Tools, Inc.,
Chaparral Service, Inc., Reddline Services, LLC and Rebel
Testers, Ltd. during 2006, and management excluded from its
assessment of the effectiveness of the Companys internal
control over financial reporting as of December 31, 2006
any internal control evaluation over financial reporting the
associated total assets of approximately $113.3 million and
total revenues of approximately $65.1 million included in
the consolidated financial statements of Basic Energy Services
Inc. and subsidiaries as of and for the year ended
December 31, 2006.
KPMG LLP, the independent registered public accounting firm that
audited the Companys consolidated financial statements
included in this report, has issued an attestation report on
managements assessment of internal control over financial
reporting.
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/s/ Kenneth
V. Huseman
Kenneth
V. Huseman
|
|
/s/ Alan
Krenek Alan
Krenek
|
Chief Executive Officer
|
|
Chief Financial Officer
|
47
Report of
Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Basic Energy Services, Inc.:
We have audited managements assessment, included in the
accompanying Managements Report on Internal Control over
Financial Reporting, that Basic Energy Services, Inc and
subsidiaries (Company) maintained effective internal control
over financial reporting as of December 31, 2006 based on
criteria established in Internal Control Integrated
Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission (COSO). The Companys management is
responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness
of internal control over financial reporting. Our responsibility
is to express an opinion on managements assessment and an
opinion on the effectiveness of the Companys internal
control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, evaluating
managements assessment, testing and evaluating the design
and operating effectiveness of internal control, and performing
such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable
basis for our opinion.
A companys internal control over financial reporting is a
process designed 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 its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, managements assessment that the Company
maintained effective internal control over financial reporting
as of December 31, 2006, is fairly stated, in all material
respects, based on criteria established in Internal
Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission
(COSO). Also, in our opinion, the Company maintained, in all
material respects, effective internal control over financial
reporting as of December 31, 2006, based on criteria
established in Internal Control Integrated
Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO).
The Company acquired G&L Tool, Ltd, Arkla Cementing, Inc.,
Globe Well Services, Inc., Hennessey Rental Tools Inc.,
Chaparral Service, Inc., Reddline Services, LLC, and Rebel
Testers, Ltd. (collectively the 2006 Excluded Acquisitions)
during 2006, and management excluded from its assessment of the
effectiveness of the Companys internal control over
financial reporting as of December 31, 2006, the 2006
Excluded Acquisitions internal control over financial
reporting associated with total assets of $113.3 million
and total revenues of $65.1 million included in the
consolidated financial statements of Basic Energy Services, Inc.
and subsidiaries as of and for the year ended December 31,
2006. Our audit of internal control over financial reporting of
Basic Energy Services, Inc. also excluded an evaluation of the
internal control over financial reporting of the 2006 Excluded
Acquisitions.
48
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of Basic Energy Services, Inc. as of
December 31, 2006 and 2005, and the related consolidated
statements of operations and comprehensive income,
stockholders equity, and cash flows for each of the years
in the three-year period ended December 31, 2006. Our
report dated March 15, 2007 expressed an unqualified
opinion on those consolidated financial statements.
KPMG LLP
Dallas, Texas
March 15, 2007
49
Report of
Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Basic Energy Services, Inc:
We have audited the accompanying consolidated balance sheets of
Basic Energy Services, Inc. and subsidiaries as of
December 31, 2006 and 2005, and the related consolidated
statements of operations and comprehensive income,
stockholders equity, and cash flows for each of the years
in the three-year period ended December 31, 2006. In
connection with our audits of the consolidated financial
statements, we also have audited the accompanying financial
statement schedule. These consolidated financial statements and
financial statement schedule are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these consolidated 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, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of Basic Energy Services, Inc. and subsidiaries as of
December 31, 2006 and 2005, and the results of their
operations and their cash flows for each of the years in the
three-year period ended December 31, 2006, in conformity
with U.S. generally accepted accounting principles. Also in
our opinion, the related 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 2 to the consolidated financial
statements, effective January 1, 2006, the Company adopted
the provisions of Statement of Financial Accounting Standards
No. 123 (revised 2004), Share Based Payment.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
effectiveness of Basic Energy Services, Inc.s internal
control over financial reporting as of December 31, 2006,
based on criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO), and our report
dated March 15, 2007 expressed an unqualified opinion on
managements assessment of, and the effective operation of,
internal control over financial reporting.
KPMG LLP
Dallas, Texas
March 15, 2007
50
Basic
Energy Services, Inc.
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December 31,
|
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2006
|
|
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2005
|
|
|
|
(In thousands, except share data)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
51,365
|
|
|
$
|
32,845
|
|
Trade accounts receivable, net of
allowance of $3,963 and $2,775, respectively
|
|
|
129,381
|
|
|
|
86,932
|
|
Accounts receivable
related parties
|
|
|
94
|
|
|
|
65
|
|
Inventories
|
|
|
8,409
|
|
|
|
1,648
|
|
Prepaid expenses
|
|
|
8,873
|
|
|
|
3,112
|
|
Other current assets
|
|
|
3,210
|
|
|
|
2,060
|
|
Deferred tax assets
|
|
|
8,432
|
|
|
|
6,020
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
209,764
|
|
|
|
132,682
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
|
475,431
|
|
|
|
309,075
|
|
Deferred debt costs, net of
amortization
|
|
|
6,536
|
|
|
|
4,833
|
|
Goodwill
|
|
|
101,579
|
|
|
|
48,227
|
|
Other assets
|
|
|
2,950
|
|
|
|
2,140
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
796,260
|
|
|
$
|
496,957
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
20,335
|
|
|
$
|
13,759
|
|
Accrued expenses
|
|
|
43,719
|
|
|
|
33,548
|
|
Income taxes payable
|
|
|
12,301
|
|
|
|
7,210
|
|
Current portion of long-term debt
|
|
|
12,001
|
|
|
|
7,646
|
|
Other current liabilities
|
|
|
1,430
|
|
|
|
1,124
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
89,786
|
|
|
|
63,287
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
250,742
|
|
|
|
119,241
|
|
Deferred income
|
|
|
|
|
|
|
17
|
|
Deferred tax liabilities
|
|
|
73,413
|
|
|
|
53,770
|
|
Other long-term liabilities
|
|
|
3,069
|
|
|
|
2,067
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Preferred stock; $.01 par
value; 5,000,000 shares authorized; none designated at
December 31, 2006 and 2005, respectively
|
|
|
|
|
|
|
|
|
Common stock; $.01 par value;
80,000,000 shares authorized; 38,297,605 issued;
38,297,605 shares outstanding at December 31, 2006 and
33,931,935 issued; 33,785,359 shares outstanding at
December 31, 2005
|
|
|
383
|
|
|
|
339
|
|
Additional paid-in capital
|
|
|
256,527
|
|
|
|
239,218
|
|
Deferred compensation
|
|
|
|
|
|
|
(7,341
|
)
|
Retained earnings
|
|
|
122,340
|
|
|
|
28,654
|
|
Treasury stock,
146,576 shares at December 31, 2005, at cost
|
|
|
|
|
|
|
(2,531
|
)
|
Accumulated other comprehensive
income
|
|
|
|
|
|
|
236
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
379,250
|
|
|
|
258,575
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
796,260
|
|
|
$
|
496,957
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial
statements.
51
Basic
Energy Services, Inc.
Consolidated
Statements of Operations and Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Dollars in thousands, except per share amounts)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
$
|
330,725
|
|
|
$
|
221,993
|
|
|
$
|
142,551
|
|
Fluid services
|
|
|
194,636
|
|
|
|
132,280
|
|
|
|
98,683
|
|
Drilling and completion services
|
|
|
154,412
|
|
|
|
59,832
|
|
|
|
29,341
|
|
Well site construction services
|
|
|
50,375
|
|
|
|
45,647
|
|
|
|
40,927
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
730,148
|
|
|
|
459,752
|
|
|
|
311,502
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
|
186,428
|
|
|
|
137,392
|
|
|
|
98,058
|
|
Fluid services
|
|
|
118,378
|
|
|
|
82,551
|
|
|
|
65,167
|
|
Drilling and completion services
|
|
|
74,981
|
|
|
|
30,900
|
|
|
|
17,481
|
|
Well site construction services
|
|
|
35,067
|
|
|
|
32,000
|
|
|
|
31,454
|
|
General and administrative,
including stock-based compensation of $3,429, $2,890, and $1,587
in 2006, 2005 and 2004, respectively
|
|
|
81,318
|
|
|
|
55,411
|
|
|
|
37,186
|
|
Depreciation and amortization
|
|
|
62,087
|
|
|
|
37,072
|
|
|
|
28,676
|
|
(Gain) loss on disposal of assets
|
|
|
277
|
|
|
|
(222
|
)
|
|
|
2,616
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
558,536
|
|
|
|
375,104
|
|
|
|
280,638
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
171,612
|
|
|
|
84,648
|
|
|
|
30,864
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(17,466
|
)
|
|
|
(13,065
|
)
|
|
|
(9,714
|
)
|
Interest income
|
|
|
1,962
|
|
|
|
405
|
|
|
|
164
|
|
Loss on early extinguishment of
debt
|
|
|
(2,705
|
)
|
|
|
(627
|
)
|
|
|
|
|
Other income (expense)
|
|
|
169
|
|
|
|
220
|
|
|
|
(398
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
before income taxes
|
|
|
153,572
|
|
|
|
71,581
|
|
|
|
20,916
|
|
Income tax expense
|
|
|
(54,742
|
)
|
|
|
(26,800
|
)
|
|
|
(7,984
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
|
98,830
|
|
|
|
44,781
|
|
|
|
12,932
|
|
Discontinued operations, net of tax
|
|
|
|
|
|
|
|
|
|
|
(71
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common
stockholders
|
|
$
|
98,830
|
|
|
$
|
44,781
|
|
|
$
|
12,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share of common
stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$
|
2.87
|
|
|
$
|
1.57
|
|
|
$
|
0.46
|
|
Discontinued operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common
stockholders
|
|
$
|
2.87
|
|
|
$
|
1.57
|
|
|
$
|
0.46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share of
common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$
|
2.56
|
|
|
$
|
1.35
|
|
|
$
|
0.42
|
|
Discontinued operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common
stockholders
|
|
$
|
2.56
|
|
|
$
|
1.35
|
|
|
$
|
0.42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
98,830
|
|
|
$
|
44,781
|
|
|
$
|
12,861
|
|
Unrealized gains on hedging
activities
|
|
|
51
|
|
|
|
193
|
|
|
|
43
|
|
Less: reclassification adjustment
for gain included in net income
|
|
|
(287
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income:
|
|
$
|
98,594
|
|
|
$
|
44,974
|
|
|
$
|
12,904
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial
statements.
52
Basic
Energy Services, Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
|
Retained
|
|
|
Other
|
|
|
Total
|
|
|
|
Common Stock
|
|
|
Paid-in
|
|
|
Deferred
|
|
|
Treasury
|
|
|
Earnings
|
|
|
Comprehensive
|
|
|
Stockholders
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Compensation
|
|
|
Stock
|
|
|
(Deficit)
|
|
|
Income
|
|
|
Equity
|
|
|
|
( In thousands, except share data)
|
|
|
Balance
December 31, 2003
|
|
|
28,094,435
|
|
|
$
|
56
|
|
|
$
|
136,524
|
|
|
$
|
(297
|
)
|
|
$
|
|
|
|
$
|
(28,988
|
)
|
|
$
|
|
|
|
$
|
107,295
|
|
Issuance of restricted stock and
stock options
|
|
|
837,500
|
|
|
|
2
|
|
|
|
6,278
|
|
|
|
(6,280
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of deferred
compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,587
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,587
|
|
Unrealized gain on interest rate
swap agreement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
43
|
|
|
|
43
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,861
|
|
|
|
|
|
|
|
12,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
December 31, 2004
|
|
|
28,931,935
|
|
|
|
58
|
|
|
|
142,802
|
|
|
|
(4,990
|
)
|
|
|
|
|
|
|
(16,127
|
)
|
|
|
43
|
|
|
|
121,786
|
|
Stock-based compensation awards
|
|
|
|
|
|
|
|
|
|
|
5,241
|
|
|
|
(5,241
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of deferred
compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,890
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,890
|
|
Unrealized gain on interest rate
swap agreement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
193
|
|
|
|
193
|
|
Forfeited 11,250 shares at
cost of $0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of stock split
|
|
|
|
|
|
|
231
|
|
|
|
(231
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from common stock
issuance, net of $2,044 of offering costs
|
|
|
5,000,000
|
|
|
|
50
|
|
|
|
91,406
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91,456
|
|
Purchase of 135,326 of treasury
stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,531
|
)
|
|
|
|
|
|
|
|
|
|
|
(2,531
|
)
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44,781
|
|
|
|
|
|
|
|
44,781
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
December 31, 2005
|
|
|
33,931,935
|
|
|
|
339
|
|
|
|
239,218
|
|
|
|
(7,341
|
)
|
|
|
(2,531
|
)
|
|
|
28,654
|
|
|
|
236
|
|
|
|
258,575
|
|
Adoption of Statement of Financial
Accounting Standard No. 123R
|
|
|
|
|
|
|
|
|
|
|
(7,341
|
)
|
|
|
7,341
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of deferred
compensation
|
|
|
|
|
|
|
|
|
|
|
3,429
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,429
|
|
Unrealized gain on interest rate
swap agreement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
51
|
|
|
|
51
|
|
Settlement of interest rate swap
agreement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(287
|
)
|
|
|
(287
|
)
|
Offering costs
|
|
|
|
|
|
|
|
|
|
|
(227
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(227
|
)
|
Exercise of stock warrants
|
|
|
4,350,000
|
|
|
|
44
|
|
|
|
17,357
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,401
|
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,218
|
)
|
|
|
|
|
|
|
|
|
|
|
(3,218
|
)
|
Exercise of stock options
|
|
|
15,670
|
|
|
|
|
|
|
|
4,091
|
|
|
|
|
|
|
|
5,749
|
|
|
|
(5,144
|
)
|
|
|
|
|
|
|
4,696
|
|
Net Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
98,830
|
|
|
|
|
|
|
|
98,830
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
December 31, 2006
|
|
|
38,297,605
|
|
|
$
|
383
|
|
|
$
|
256,527
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
122,340
|
|
|
$
|
|
|
|
$
|
379,250
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial
statements.
53
Basic
Energy Services, Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Cash flows from operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
98,830
|
|
|
$
|
44,781
|
|
|
$
|
12,861
|
|
Adjustments to reconcile net
income to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
62,087
|
|
|
|
37,072
|
|
|
|
28,676
|
|
Accretion on asset retirement
obligation
|
|
|
78
|
|
|
|
42
|
|
|
|
33
|
|
Change in allowance for doubtful
accounts
|
|
|
1,188
|
|
|
|
(333
|
)
|
|
|
1,150
|
|
Non-cash interest expense
|
|
|
804
|
|
|
|
1,062
|
|
|
|
970
|
|
Non-cash compensation
|
|
|
3,429
|
|
|
|
2,890
|
|
|
|
1,587
|
|
Loss on early extinguishment of
debt
|
|
|
2,705
|
|
|
|
627
|
|
|
|
|
|
(Gain) loss on disposal of assets
|
|
|
277
|
|
|
|
(222
|
)
|
|
|
2,616
|
|
Deferred income taxes
|
|
|
2,611
|
|
|
|
18,301
|
|
|
|
7,984
|
|
Changes in operating assets and
liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(32,933
|
)
|
|
|
(27,577
|
)
|
|
|
(13,841
|
)
|
Inventories
|
|
|
(714
|
)
|
|
|
(262
|
)
|
|
|
394
|
|
Prepaid expenses and other current
assets
|
|
|
(6,771
|
)
|
|
|
304
|
|
|
|
446
|
|
Other assets
|
|
|
(450
|
)
|
|
|
(49
|
)
|
|
|
(569
|
)
|
Accounts payable
|
|
|
5,128
|
|
|
|
2,174
|
|
|
|
3,416
|
|
Excess tax benefits from exercise
of employee stock options
|
|
|
(4,022
|
)
|
|
|
|
|
|
|
|
|
Income tax payable
|
|
|
6,344
|
|
|
|
7,013
|
|
|
|
|
|
Deferred income and other
liabilities
|
|
|
(171
|
)
|
|
|
374
|
|
|
|
127
|
|
Accrued expenses
|
|
|
7,258
|
|
|
|
12,992
|
|
|
|
689
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
|
145,678
|
|
|
|
99,189
|
|
|
|
46,539
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of property and equipment
|
|
|
(104,574
|
)
|
|
|
(83,095
|
)
|
|
|
(55,674
|
)
|
Proceeds from sale of assets
|
|
|
5,560
|
|
|
|
2,436
|
|
|
|
2,484
|
|
Payments for other long-term assets
|
|
|
(6,769
|
)
|
|
|
(1,642
|
)
|
|
|
(1,113
|
)
|
Payments for businesses, net of
cash acquired
|
|
|
(135,568
|
)
|
|
|
(25,378
|
)
|
|
|
(19,284
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing
activities
|
|
|
(241,351
|
)
|
|
|
(107,679
|
)
|
|
|
(73,587
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from debt
|
|
|
305,546
|
|
|
|
16,000
|
|
|
|
43,500
|
|
Payments of debt
|
|
|
(204,793
|
)
|
|
|
(81,924
|
)
|
|
|
(21,236
|
)
|
Proceeds from common stock, net of
$2,044 of offering costs
|
|
|
|
|
|
|
91,456
|
|
|
|
|
|
Purchase of treasury stock
|
|
|
(3,218
|
)
|
|
|
(2,531
|
)
|
|
|
|
|
Offering costs related to initial
public offering
|
|
|
(227
|
)
|
|
|
|
|
|
|
|
|
Excess tax benefits from exercise
of employee stock options
|
|
|
4,022
|
|
|
|
|
|
|
|
|
|
Exercise of employee stock options
|
|
|
674
|
|
|
|
|
|
|
|
|
|
Proceeds from exercise stock
warrants
|
|
|
17,401
|
|
|
|
|
|
|
|
|
|
Deferred loan costs and other
financing activities
|
|
|
(5,212
|
)
|
|
|
(1,813
|
)
|
|
|
(766
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing
activities
|
|
|
114,193
|
|
|
|
21,188
|
|
|
|
21,498
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash
and equivalents
|
|
|
18,520
|
|
|
|
12,698
|
|
|
|
(5,550
|
)
|
Cash and cash
equivalents beginning of year
|
|
|
32,845
|
|
|
|
20,147
|
|
|
|
25,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash
equivalents end of year
|
|
$
|
51,365
|
|
|
$
|
32,845
|
|
|
$
|
20,147
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial
statements.
54
BASIC
ENERGY SERVICES, INC.
December 31, 2006, 2005, and 2004
Basic Energy Services, Inc. provides a range of well site
services to oil and gas drilling and producing companies,
including well servicing, fluid services, drilling and
completion services and well site construction services. These
services are primarily provided by Basics fleet of
equipment. Basics operations are concentrated in the major
United States onshore oil and gas producing regions in Texas,
New Mexico, Oklahoma, Arkansas and Louisiana, and the Rocky
Mountain states.
|
|
2.
|
Summary
of Significant Accounting Policies
|
Principles
of Consolidation
The accompanying consolidated financial statements include the
accounts of Basic and its wholly-owned subsidiaries. Basic has
no interest in any other organization, entity, partnership, or
contract that could require any evaluation under FASB
Interpretation No. 46R or Accounting Research
Bulletin No. 51. All intercompany transactions and
balances have been eliminated.
Estimates
and Uncertainties
Preparation of the accompanying consolidated 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 amount
of assets and liabilities and disclosures of contingent assets
and liabilities at the date of the consolidated financial
statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from
those estimates. Areas where critical accounting estimates are
made by management include:
|
|
|
|
|
Depreciation and amortization of property and equipment and
intangible assets
|
|
|
|
Impairment of property and equipment and goodwill
|
|
|
|
Allowance for doubtful accounts
|
|
|
|
Litigation and self-insured risk reserves
|
|
|
|
Fair value of assets acquired and liabilities assumed
|
|
|
|
Stock-based compensation
|
|
|
|
Income taxes
|
|
|
|
Asset retirement obligation
|
Revenue
Recognition
Well Servicing Well servicing consists
primarily of maintenance services, workover services, completion
services and plugging and abandonment services. Basic recognizes
revenue when services are performed, collection of the relevant
receivables is probable, persuasive evidence of an arrangement
exists and the price is fixed or determinable. Basic prices well
servicing by the hour of service performed.
Fluid Services Fluid services consists
primarily of the sale, transportation, storage and disposal of
fluids used in drilling, production and maintenance of oil and
natural gas wells. Basic recognizes revenue when services are
performed, collection of the relevant receivables is probable,
persuasive evidence of an arrangement exists and the price is
fixed or determinable. Basic prices fluid services by the job,
by the hour or by the quantities sold, disposed of or hauled.
55
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Drilling and Completion Services Basic
recognizes revenue when services are performed, collection of
the relevant receivables is probable, persuasive evidence of an
arrangement exists and the price is fixed or determinable. Basic
prices drilling and completion services by the hour, day, or
project depending on the type of service performed. When Basic
provides multiple services to a customer, revenue is allocated
to the services performed based on the fair values of the
services.
Well Site Construction Services Basic
recognizes revenue when services are performed, collection of
the relevant receivables is probable, persuasive evidence of an
arrangement exists and the price is fixed or determinable. Basic
prices well site construction services by the hour, day, or
project depending on the type of service performed.
Cash
and Cash Equivalents
Basic considers all highly liquid instruments purchased with a
maturity of three months or less to be cash equivalents. Basic
maintains its excess cash in various financial institutions,
where deposits may exceed federally insured amounts at times.
Fair
Value of Financial Instruments
The carrying value amount of cash, accounts receivable, accounts
payable and accrued liabilities approximate fair value due to
the short maturity of these instruments. The carrying amount of
long-term debt approximates fair value because Basics
current borrowing rate is based on a variable market rate of
interest.
Inventories
For Rental and Fishing Tools, inventories consisting mainly of
grapples, controls, and drill bits are stated at the lower of
cost or market, with cost being determined on the average cost
method. Other inventories, consisting mainly of rig components,
repair parts, drilling and completion materials and gravel, are
held for use in the operations of Basic and are stated at the
lower of cost or market, with cost being determined on the
first-in,
first-out (FIFO) method.
Property
and Equipment
Property and equipment are stated at cost, or at estimated fair
value at acquisition date if acquired in a business combination.
Expenditures for repairs and maintenance are charged to expense
as incurred and additions and improvements that significantly
extend the lives of the assets are capitalized. Upon sale or
other retirement of depreciable property, the cost and
accumulated depreciation and amortization are removed from the
related accounts and any gain or loss is reflected in
operations. All property and equipment are depreciated or
amortized (to the extent of estimated salvage values) on the
straight-line method and the estimated useful lives of the
assets are as follows:
|
|
|
|
|
Building and improvements
|
|
|
20-30 years
|
|
Well servicing units and equipment
|
|
|
3-15 years
|
|
Fluid services equipment
|
|
|
5-10 years
|
|
Brine and fresh water stations
|
|
|
15 years
|
|
Frac/test tanks
|
|
|
10 years
|
|
Pressure pumping equipment
|
|
|
5-10 years
|
|
Construction equipment
|
|
|
3-10 years
|
|
Disposal facilities
|
|
|
10-15 years
|
|
Vehicles
|
|
|
3-7 years
|
|
Rental equipment
|
|
|
3-15 years
|
|
Aircraft
|
|
|
20 years
|
|
Software and computers
|
|
|
3 years
|
|
56
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The components of a well servicing rig generally require
replacement or refurbishment during the well servicing
rigs life and are depreciated over their estimated useful
lives, which ranges from 3 to 15 years. The costs of the
original components of a purchased or acquired well servicing
rig are not maintained separately from the base rig.
Impairments
In accordance with Statement of Financial Accounting Standards
No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets (SFAS No. 144),
long-lived assets, such as property, plant, and equipment, and
purchased intangibles subject to amortization, are reviewed for
impairment at a minimum annually, or whenever, in
managements judgment events or changes in circumstances
indicate that the carrying amount of such assets may not be
recoverable. Recoverability of assets to be held and used is
measured by a comparison of the carrying amount of such assets
to estimated undiscounted future cash flows expected to be
generated by the assets. Expected future cash flows and carrying
values are aggregated at their lowest identifiable level. If the
carrying amount of such assets exceeds its estimated future cash
flows, an impairment charge is recognized by the amount by which
the carrying amount of such assets exceeds the fair value of the
assets. Assets to be disposed of would be separately presented
in the consolidated balance sheet and reported at the lower of
the carrying amount or fair value less costs to sell, and are no
longer depreciated. The assets and liabilities, if material, of
a disposed group classified as held for sale would be presented
separately in the appropriate asset and liability sections of
the consolidated balance sheet.
Goodwill and intangible assets not subject to amortization are
tested annually for impairment, and are tested for impairment
more frequently if events and circumstances indicate that the
asset might be impaired. An impairment loss is recognized to the
extent that the carrying amount exceeds the assets fair
value.
Basic had no impairment expense in 2006, 2005 or 2004.
Deferred
Debt Costs
Basic capitalizes certain costs in connection with obtaining its
borrowings, such as lenders fees and related
attorneys fees. These costs are being amortized to
interest expense using the effective interest method.
Deferred debt costs of approximately $7.1 million at
December 31, 2006 and $7.0 million at
December 31, 2005, respectively, represent debt issuance
costs and are recorded net of accumulated amortization of
$523,000, and $2.2 million at December 31, 2006 and
December 31, 2005, respectively. Amortization of deferred
debt costs totaled approximately $804,000, $1,062,000 and
$907,000 for the years ended December 31, 2006, 2005 and
2004, respectively.
In 2006, Basic recognized a loss on early extinguishment of debt
related to deferred debt costs. (See note 5)
Goodwill
and Other Intangible Assets
Statement of Financial Accounting Standards No. 142,
Goodwill and Other Intangible Assets
(SFAS No. 142) eliminates the
amortization of goodwill and other intangible assets with
indefinite lives. Intangible assets with lives restricted by
contractual, legal, or other means will continue to be amortized
over their useful lives. Goodwill and other intangible assets
not subject to amortization are tested for impairment annually
or more frequently if events or changes in circumstances
indicate that the asset might be impaired.
SFAS No. 142 requires a two-step process for testing
impairment. First, the fair value of each reporting unit is
compared to its carrying value to determine whether an
indication of impairment exists. If impairment is indicated,
then the fair value of the reporting units goodwill is
determined by allocating the units fair value to its
assets and liabilities (including any unrecognized intangible
assets) as if the reporting unit had been acquired in a business
combination. The amount of impairment for goodwill is measured
as the excess of its carrying value over its fair value. Basic
completed its assessment of goodwill impairment as of the date
of adoption and completed a subsequent annual impairment
assessment as of December 31 each year thereafter. The
assessments did not result in any indications of goodwill
impairment.
57
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Intangible assets subject to amortization under
SFAS No. 142 consist of non-compete agreements. The
gross carrying amount of non-compete agreements subject to
amortization totaled approximately $2.9 million and
$2.7 million at December 31, 2006 and 2005,
respectively. Accumulated amortization related to these
intangible assets totaled approximately $1.3 and
$1.6 million at December 31, 2006 and 2005,
respectively. Amortization expense for the years ended
December 31, 2006, 2005 and 2004 was approximately
$650,000, $519,000, and $457,000, respectively. Amortization
expense for the next five succeeding years is estimated to be
approximately $519,000, $418,000, $315,000, $217,000, and
$81,000 in 2007, 2008, 2009, 2010, and 2011 respectively.
Basic has identified its reporting units to be well servicing,
fluid services, drilling and completion services and well site
construction services. The goodwill allocated to such reporting
units as of December 31, 2006 is $22.1 million,
$38.3 million, $37.5 million and $3.7 million,
respectively. The change in the carrying amount of goodwill for
the year ended December 31, 2006 of $53.4 million
relates to goodwill from acquisitions and payments pursuant to
contingent earn-out agreements, with approximately
$12.1 million, $17.8 million and $23.5 million of
goodwill additions relating to the well servicing, fluid
services and drilling and completion units, respectively.
Stock-Based
Compensation
On January 1, 2006, Basic adopted Statement of Financial
Accounting Standards No. 123 (revised
2004) Share-Based Payment
(SFAS No. 123R). Prior to January 1,
2006, the Company accounted for share-based payments under the
recognition and measurement provisions of Accounting Principles
Board Opinion No. 25, Accounting for Stock issued
to Employees (APB No. 25) which was
permitted by Statement of Financial Accounting Standards
No. 123, Accounting for Stock-Based
Compensation (SFAS No. 123).
Basic adopted SFAS No. 123R using both the modified
prospective method and the prospective method as applicable to
the specific awards granted. The modified prospective method was
applied to awards granted subsequent to the Company becoming a
public company. Awards granted prior to the Company becoming
public and which were accounted for under APB No. 25 were
adopted by using the prospective method. The results of prior
periods have not been restated. Compensation expense cost of the
unvested portion of awards granted as a private company and
outstanding as of January 1, 2006 will continue to be based
upon the intrinsic value method calculated under APB No. 25.
Under SFAS No. 123R, entities using the minimum value
method and the prospective application are not permitted to
provide the pro forma disclosures (as was required under
Statement of Financial Accounting Standard No. 123,
Accounting for Stock-Based Compensation
(SFAS No. 123)) subsequent to adoption
of SFAS No. 123R since they do not have the fair value
information required by SFAS No. 123R. Therefore, in
accordance with SFAS No. 123R, Basic will no longer
include pro forma disclosures that were required by
SFAS No. 123.
Income
Taxes
Basic accounts for income taxes based upon Statement of
Financial Accounting Standards No. 109, Accounting
for Income Taxes (SFAS 109). Under
SFAS No. 109, deferred tax assets and liabilities are
recognized for the future tax consequences attributable to
differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases.
Deferred tax assets and liabilities are measured using statutory
tax rates expected to apply to taxable income in the years in
which those temporary differences are expected to be recovered
or settled. The effect on deferred tax assets and liabilities of
a change in tax rate is recognized in the period that includes
the statutory enactment date. A valuation allowance for deferred
tax assets is recognized when it is more likely than not that
the benefit of deferred tax assets will not be realized.
58
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Concentrations
of Credit Risk
Financial instruments, which potentially subject Basic to
concentration of credit risk, consist primarily of temporary
cash investments and trade receivables. Basic restricts
investment of temporary cash investments to financial
institutions with high credit standing. Basics customer
base consists primarily of multi-national and independent oil
and natural gas producers. It performs ongoing credit
evaluations of its customers but generally does not require
collateral on its trade receivables. Credit risk is considered
by management to be limited due to the large number of customers
comprising its customer base. Basic maintains an allowance for
potential credit losses on its trade receivables, and such
losses have been within managements expectations.
Basic did not have any one customer which represented 10% or
more of consolidated revenue for 2006, 2005, or 2004.
Derivative
Instruments and Hedging Activities
In June 1998, the Financial Accounting Standards Board
(FASB) issued Statement of Financial Accounting
Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities
(SFAS No. 133), which establishes
standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for
hedging activities. It requires that an entity recognize all
derivative as either assets or liabilities on the balance sheet
and measure those instruments at fair value. It establishes
conditions under which a derivative may be designated as a
hedge, and establishes standards for reporting changes in the
fair value of a derivative. Basic adopted
SFAS No. 133, as amended by SFAS No. 138, on
January 1, 2001. Basic adopted the additional amendments
pursuant to SFAS No. 149 for contracts entered or
modified after June 30, 2003, if any. At inception, Basic
formally documents the relationship between the hedging
instrument and the underlying hedged item as well as risk
management objective and strategy. Basic assesses, both at
inception and on an ongoing basis, whether the derivative used
in hedging transition is highly effective in offsetting changes
in the fair value of cash flows of the respective hedged item.
In May 2004, Basic implemented a cash flow hedge to protect
itself from fluctuation in cash flows associated with its credit
facility. Changes in fair value of the hedging derivative were
initially recorded in other comprehensive income, then
recognized in income in the same period(s) in which the hedged
transaction affected income. Ineffective portions of a cash flow
hedging derivatives change in fair value were recognized
currently in earnings. Basic had no ineffectiveness related to
its cash flow hedge in 2005 or 2004. The March 28, 2006
amendment to the 2005 credit facility deleted the requirement to
maintain the cash flow hedge upon payoff of the Term B Loans. In
April 2006, Basic paid off all outstanding borrowings under the
Term B Loan (See note 5). Accordingly in April 2006, the
interest rate swap was terminated and the balance remaining in
accumulated comprehensive income was recognized in earnings.
Asset
Retirement Obligations
As of January 1, 2003, Basic adopted Statement of Financial
Accounting Standards No. 143, Accounting for Asset
Retirement Obligation
(SFAS No. 143). SFAS No. 143
requires Basic to record the fair value of an asset retirement
obligation as a liability in the period in which it incurs a
legal obligation associated with the retirement of tangible
long-lived assets and capitalize an equal amount as a cost of
the asset depreciating it over the life of the asset. Subsequent
to the initial measurement of the asset retirement obligation,
the obligation is adjusted at the end of each quarter to reflect
the passage of time, changes in the estimated future cash flows
underlying the obligation, acquisition or construction of
assets, and settlements of obligations.
59
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Basic owns and operates salt water disposal sites, brine water
wells, gravel pits and land farm sites, each of which is subject
to rules and regulations regarding usage and eventual closure.
The following table reflects the changes in the liability during
years ended December 31, 2006 and 2005 (in thousands):
|
|
|
|
|
Balance, December 31, 2004
|
|
$
|
473
|
|
Additional asset retirement
obligations recognized through acquisitions
|
|
|
74
|
|
Accretion expense
|
|
|
42
|
|
Settlements
|
|
|
(20
|
)
|
|
|
|
|
|
Balance, December 31, 2005
|
|
$
|
569
|
|
Additional asset retirement
obligations recognized through acquisitions
|
|
|
289
|
|
Accretion expense
|
|
|
78
|
|
Settlements
|
|
|
(78
|
)
|
Increase in asset retirement
obligations due to change in estimate
|
|
|
479
|
|
|
|
|
|
|
Balance, December 31, 2006
|
|
$
|
1,336
|
|
|
|
|
|
|
Environmental
Basic is subject to extensive federal, state and local
environmental laws and regulations. These laws, which are
constantly changing, regulate the discharge of materials into
the environment and may require Basic to remove or mitigate the
adverse environmental effects of disposal or release of
petroleum, chemical and other substances at various sites.
Environmental expenditures are expensed or capitalized depending
on the future economic benefit. Expenditures that relate to an
existing condition caused by past operations and that have no
future economic benefits are expensed. Liabilities for
expenditures of a non-capital nature are recorded when
environmental assessment
and/or
remediation is probable and the costs can be reasonably
estimated.
Litigation
and Self-Insured Risk Reserves
Basic estimates its reserves related to litigation and
self-insured risks based on the facts and circumstances specific
to the litigation and self-insured claims and its past
experience with similar claims in accordance with Statement of
Financial Accounting Standard No. 5 Accounting for
Contingencies. Basic maintains accruals in the
consolidated balance sheets to cover self-insurance retentions
(See note 7).
Comprehensive
Income
Basic follows the provisions of Statement of Financial
Accounting Standards No. 130, Reporting of
Comprehensive Income
(SFAS No. 130). SFAS No. 130
establishes standards for reporting and presentation of
comprehensive income and its components. SFAS No. 130
requires all items that are required to be recognized under
accounting standards as components of comprehensive income to be
reported in a financial statement that is displayed with the
same prominence as other financial statements. In accordance
with the provisions of SFAS No. 130, gains and losses
on cash flow hedging derivatives, to the extent effective, are
included in other comprehensive income (loss).
Reclassifications
Certain reclassifications of prior year financial statement
amounts have been made to conform to current year presentations.
60
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Recent
Accounting Pronouncements
In September 2006, the Securities and Exchange Commission issued
Staff Accounting Bulletin No. 108 (SAB 108),
Considering the Effects of Prior Year Misstatements when
Quantifying Misstatement in Current Year Financial
Statements. The bulletins interpretations address
diversity in practice in quantifying financial statement
misstatements and the potential under current practice for the
build up of improper amounts on the balance sheet. Basic adopted
the interpretation in the fourth quarter of 2006. The adoption
of SAB 108 did not have a material impact on the
Companys financial position, cash flows, or results of
operations.
In June 2006, the Financial Accounting Standards Board (FASB)
issued Interpretation No. 48 (FIN 48), Accounting
for Uncertainty in Income Taxes, an interpretation of FASB
Statement No. 109, Accounting for Income Taxes. The
interpretation prescribes a recognition threshold and
measurement attribute for the financial statement recognition
and measurement of a tax position taken or expected to be taken,
in a tax return. FIN 48 also provides guidance on
derecognition, classification, interest and penalties accounting
in interim periods, disclosure and transition. The
interpretation is effective for fiscal years beginning after
December 15, 2006. The cumulative effect of applying the
provisions of this interpretation, which is required to be
reported separately as an adjustment to our opening balance of
retained earnings in 2007, is currently not expected to have a
material impact on our results of operations, financial position
or cash flows.
In December 2004, the FASB issued SFAS No. 123R. As
discussed under Note 2, Stock-Based
Compensation, Basic adopted the provisions of
SFAS No. 123R on January 1, 2006.
In 2006, 2005 and 2004, Basic acquired either substantially all
of the assets or all of the outstanding capital stock of each of
the following businesses, each of which were accounted for using
the purchase method of accounting (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Cash Paid
|
|
|
|
|
|
|
(net of cash
|
|
|
|
Closing Date
|
|
|
acquired)
|
|
|
Action Trucking Curtis
Smith, Inc.
|
|
|
April 27, 2004
|
|
|
$
|
821
|
|
Rolling Plains
|
|
|
May 30, 2004
|
|
|
|
3,022
|
|
Perrys Pump Service
|
|
|
May 30, 2004
|
|
|
|
1,379
|
|
Lone Tree Construction
|
|
|
June 23, 2004
|
|
|
|
211
|
|
Hayes Services
|
|
|
July 1, 2004
|
|
|
|
1,595
|
|
Western Oil Well
|
|
|
July 30, 2004
|
|
|
|
854
|
|
Summit Energy
|
|
|
August 19, 2004
|
|
|
|
647
|
|
Energy Air Drilling
|
|
|
August 30, 2004
|
|
|
|
6,500
|
|
AWS Wireline
|
|
|
November 1, 2004
|
|
|
|
4,255
|
|
|
|
|
|
|
|
|
|
|
Total 2004
|
|
|
|
|
|
$
|
19,284
|
|
|
|
|
|
|
|
|
|
|
61
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Cash Paid
|
|
|
|
|
|
|
(net of cash
|
|
|
|
Closing Date
|
|
|
acquired)
|
|
|
R & R Hot Oil Service
|
|
|
January 5, 2005
|
|
|
|
1,702
|
|
Premier Vacuum Service, Inc.
|
|
|
January 28, 2005
|
|
|
|
1,009
|
|
Spencers Coating Specialist
|
|
|
February 9, 2005
|
|
|
|
619
|
|
Marks Well Service
|
|
|
February 25, 2005
|
|
|
|
579
|
|
Max-Line, Inc.
|
|
|
April 28, 2005
|
|
|
|
1,498
|
|
MD Well Service, Inc.
|
|
|
May 17, 2005
|
|
|
|
4,478
|
|
179 Disposal, Inc.
|
|
|
August 4, 2005
|
|
|
|
1,729
|
|
Oilwell Fracturing Services,
Inc.
|
|
|
October 11, 2005
|
|
|
|
13,764
|
|
|
|
|
|
|
|
|
|
|
Total 2005
|
|
|
|
|
|
$
|
25,378
|
|
|
|
|
|
|
|
|
|
|
LeBus Oil Field Services Co.
|
|
|
January 31, 2006
|
|
|
$
|
24,618
|
|
G&L Tool, Ltd.
|
|
|
February 28, 2006
|
|
|
|
58,514
|
|
Arkla Cementing, Inc.
|
|
|
March 27, 2006
|
|
|
|
5,012
|
|
Globe Well Service, Inc.
|
|
|
May 30, 2006
|
|
|
|
11,674
|
|
Hydro-Static Tubing Testers,
Inc.
|
|
|
July 6, 2006
|
|
|
|
1,143
|
|
Hennessey Rental Tools, Inc.
|
|
|
August 1, 2006
|
|
|
|
8,205
|
|
Stimulation Services, LLC
|
|
|
August 1, 2006
|
|
|
|
4,500
|
|
Chaparral Service, Inc.
|
|
|
August 15, 2006
|
|
|
|
17,605
|
|
Reddline Services, LLC
|
|
|
August 24, 2006
|
|
|
|
1,900
|
|
Rebel Testers, Ltd.
|
|
|
September 14, 2006
|
|
|
|
2,397
|
|
|
|
|
|
|
|
|
|
|
Total 2006
|
|
|
|
|
|
$
|
135,568
|
|
|
|
|
|
|
|
|
|
|
The operations of each of the acquisitions listed above are
included in Basics statement of operations as of each
respective closing date. The acquisition of G&L Tool, Ltd in
2006 is deemed significant and is discussed below in further
detail.
G&L
Tool, Ltd.
On February 28, 2006, Basic acquired substantially all of
the assets of G&L Tool Ltd. (G&L) for $58.5 million
plus a contingent earn-out payment not to exceed
$21.0 million. The contingent earn-out payment will be
equal to fifty percent of the amount by which the annual EBITDA
(as defined in the purchase agreement) earned by the G&L
assets exceeds an annual targeted EBITDA. There is no guarantee
or assurance that the targeted EBITDA will be reached. This
acquisition provided a platform to expand into the rental and
fishing tool market operations. The cost of the G&L
acquisition was allocated $40.8 million to property and
equipment, $5.2 million to inventory, $12.5 million to
goodwill, all of which is expected to be deductible for tax
purposes, and $51,000 to non-compete agreements. During the
year, an adjustment was made to the purchase price allocation
which increased the value of inventory by $5.2 million and
reduced fixed assets and goodwill by $3.8 million and
$1.4 million, respectively. This allocation adjustment was
made as a result of an increase to the fair market value of the
asset and the increased ability for tracking certain assets
obtained in the acquisition.
62
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The following unaudited pro-forma results of operations have
been prepared as though the G&L acquisition had been
completed on January 1, 2005. Pro forma amounts are based
on the final purchase price allocations of the significant
acquisitions and are not necessarily indicative of the results
that may be reported in the future (in thousands, except per
share data).
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Revenues
|
|
$
|
739,641
|
|
|
$
|
499,177
|
|
Net income
|
|
$
|
101,294
|
|
|
$
|
52,527
|
|
Earnings per common
share basic
|
|
$
|
2.94
|
|
|
$
|
1.84
|
|
Earnings per common
share diluted
|
|
$
|
2.62
|
|
|
$
|
1.58
|
|
Basic does not believe the pro-forma effect of the remainder of
the acquisitions completed in 2004, 2005 or 2006 is material,
either individually or when aggregated, to the reported results
of operations.
Contingent
Earn-out Arrangements and Final Purchase Price
Allocations
Contingent earn-out arrangements are generally arrangements
entered into on certain acquisitions to encourage the
owner/manager to continue operating and building the business
after the purchase transaction. The contingent earn-out
arrangements of the related acquisitions are generally linked to
certain financial measures and performance of the assets
acquired in the various acquisitions. All amounts paid or
reasonably accrued for related to the contingent earn-out
payments are reflected as increases to the goodwill associated
with the acquisitions of New Force Energy Services, Rolling
Plains, Premier Vacuum Services and G&L Tool. Payments
related to contingent earn-out agreements on Chaparral Services
and Redline Services will be reflected as compensation expense
when paid or accrued.
The following presents a summary of acquisitions that have a
contingent earn-out arrangement in effect as of
December 31, 2006 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum
|
|
|
|
|
|
|
|
|
Exposure of
|
|
|
|
|
|
|
Termination date of
|
|
Contingent
|
|
|
Amount Paid or
|
|
|
|
Contingent Earn-out
|
|
Earn-out
|
|
|
Accrued Through
|
|
Acquisition
|
|
Arrangement
|
|
Arrangement
|
|
|
December 31, 2006
|
|
|
New Force Energy Services
|
|
January 27, 2008
|
|
$
|
2,700
|
|
|
$
|
2,191
|
|
Rolling Plains
|
|
April 30, 2009
|
|
|
*
|
|
|
|
3,157
|
|
Premier Vacuum Services, Inc.
|
|
February 1, 2010
|
|
|
900
|
|
|
|
515
|
|
Chaparral Services, Inc.
|
|
August 31, 2011
|
|
|
1,000
|
|
|
|
67
|
|
Reddline Services LLC
|
|
August 30, 2011
|
|
|
625
|
|
|
|
42
|
|
G&L Tool, Ltd.
|
|
February 28, 2011
|
|
|
21,000
|
|
|
|
2,994
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
26,225
|
|
|
$
|
8,966
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Basic will pay to the sellers an amount for each of the five
consecutive 12 month periods beginning on May 1, 2004
equal to 50% of the amount by which annual EBITDA exceeds an
annual targeted EBITDA. There is no guarantee or assurance that
the targeted EBITDA will be reached. |
63
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
4.
|
Property
and Equipment
|
Property and equipment consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Land
|
|
$
|
2,913
|
|
|
$
|
1,902
|
|
Buildings and improvements
|
|
|
13,293
|
|
|
|
8,634
|
|
Well service units and equipment
|
|
|
283,084
|
|
|
|
199,070
|
|
Fluid services equipment
|
|
|
87,139
|
|
|
|
59,104
|
|
Brine and fresh water stations
|
|
|
8,710
|
|
|
|
7,746
|
|
Frac/test tanks
|
|
|
49,582
|
|
|
|
31,475
|
|
Pressure pumping equipment
|
|
|
67,540
|
|
|
|
31,101
|
|
Construction equipment
|
|
|
27,342
|
|
|
|
24,224
|
|
Disposal facilities
|
|
|
25,913
|
|
|
|
16,828
|
|
Vehicles
|
|
|
32,215
|
|
|
|
23,329
|
|
Rental equipment
|
|
|
32,548
|
|
|
|
6,519
|
|
Aircraft
|
|
|
4,119
|
|
|
|
3,236
|
|
Other
|
|
|
8,807
|
|
|
|
8,602
|
|
|
|
|
|
|
|
|
|
|
|
|
|
643,205
|
|
|
|
421,770
|
|
Less accumulated depreciation and
amortization
|
|
|
167,774
|
|
|
|
112,695
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
$
|
475,431
|
|
|
$
|
309,075
|
|
|
|
|
|
|
|
|
|
|
Basic is obligated under various capital leases for certain
vehicles and equipment that expire at various dates during the
next five years. The gross amount of property and equipment and
related accumulated amortization recorded under capital leases
and included above consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Light vehicles
|
|
$
|
23,843
|
|
|
$
|
17,912
|
|
Well service units and equipment
|
|
|
808
|
|
|
|
|
|
Fluid services equipment
|
|
|
26,460
|
|
|
|
14,011
|
|
Pressure pumping equipment
|
|
|
1,820
|
|
|
|
|
|
Construction equipment
|
|
|
3,559
|
|
|
|
1,300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
56,490
|
|
|
|
33,223
|
|
Less accumulated amortization
|
|
|
13,785
|
|
|
|
8,474
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
42,705
|
|
|
$
|
24,749
|
|
|
|
|
|
|
|
|
|
|
Amortization of assets held under capital leases of
approximately $5.3 million, $1.3 million, and
$1.8 million for the years ended December 31, 2006,
2005, and 2004, respectively, is included in depreciation and
amortization expense in the consolidated statements of
operations.
64
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Long-term debt consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Credit Facilities:
|
|
|
|
|
|
|
|
|
Term B Loan
|
|
$
|
|
|
|
$
|
90,000
|
|
Revolver
|
|
|
|
|
|
|
16,000
|
|
7.125% Senior Notes
|
|
|
225,000
|
|
|
|
|
|
Capital leases and other notes
|
|
|
37,743
|
|
|
|
20,887
|
|
|
|
|
|
|
|
|
|
|
|
|
|
262,743
|
|
|
|
126,887
|
|
Less current portion
|
|
|
12,001
|
|
|
|
7,646
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
250,742
|
|
|
$
|
119,241
|
|
|
|
|
|
|
|
|
|
|
Senior
Notes
On April 12, 2006, the Company issued $225.0 million
of 7.125% Senior Notes due April 2016 in a private
placement. Proceeds from the sale of the Senior Notes were used
to retire the outstanding balance on the $90.0 million Term
B Loan and to pay down approximately $96.0 million under
the revolving credit facility, which amounts may be reborrowed
to fund future acquisitions or for general corporate purposes.
Interest payments on the Senior Notes are due semi-annually, on
April 15 and October 15, commencing on October 15,
2006. The Senior Notes are unsecured. Under the terms of the
sale of the Senior Notes, the Company was required to take
appropriate steps to offer to exchange other Senior Notes with
the same terms that have been registered with the Securities and
Exchange Commission for the private placement Senior Notes. The
Company completed the exchange offer for all of the Senior Notes
on October 16, 2006.
The Senior Notes are redeemable at the option of the Company on
or after April 15, 2011 at the specified redemption price
as described in the Indenture. Prior to April 15, 2011, the
Company may redeem, in whole or in part, at a redemption price
equal to 100% of the principal amount of the Senior Notes
redeemed plus the Applicable Premium as defined in the
Indenture. Prior to April 15, 2009, the Company may redeem
up to 35% of the Senior Notes with the proceeds of certain
equity offerings at a redemption price equal to 107.125% of the
principal amount of the 7.125% Senior Notes, plus accrued
and unpaid interest to the date of redemption. This redemption
must occur less than 90 days after the date of the closing
of any such equity offering.
Following a change of control, as defined in the Indenture, the
Company will be required to make an offer to repurchase all or
any portion of the 7.125% Senior Notes at a purchase price
of 101% of the principal amount, plus accrued and unpaid
interest to the date of repurchase.
Pursuant to the Indenture, the Company is subject to covenants
that limit the ability of the Company and its restricted
subsidiaries to, among other things: incur additional
indebtedness, pay dividends or repurchase or redeem capital
stock, make certain investments, incur liens, enter into certain
types of transactions with affiliates, limit dividends or other
payments by restricted subsidiaries, and sell assets or
consolidate or merge with or into other companies. These
limitations are subject to a number of important qualifications
and exceptions set forth in the Indenture. The Company was in
compliance with the restrictive covenants at December 31,
2006.
As part of the issuance of the above-mentioned Senior Notes, the
Company incurred debt issuance costs of approximately
$4.6 million, which are being amortized to interest expense
using the effective interest method over the term of the Senior
Notes.
65
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The Senior Notes are jointly and severally guaranteed by the
Company and all of its restricted subsidiaries. Basic Energy
Services, Inc., the ultimate parent company, does not have any
independent operating assets or operations. Subsidiaries other
than the restricted subsidiaries that are guarantors are minor.
2005
Credit Facility
On December 15, 2005, Basic entered into a
$240 million Third Amended and Restated Credit Agreement
with a syndicate of lenders (2005 Credit Facility),
which refinanced all of its then existing credit facilities. The
2005 Credit Facility, as amended effective March 28, 2006,
provides for a $90 million Term B Loan (2005 Term B
Loan) and a $150 million revolving line of credit
(Revolver). The commitment under the Revolver allows
for (a) the borrowing of funds (b) issuance of up to
$30 million of letters of credit and
(c) $2.5 million of swing-line loans (next day
borrowing). The amounts outstanding under the 2005 Term B Loan
require quarterly amortization at various amounts during each
quarter with all amounts outstanding on December 15, 2011
being due and payable in full. All the outstanding amounts under
the Revolver are due and payable on December 15, 2010. The
2005 Credit Facility is secured by substantially all of
Basics tangible and intangible assets. Basic incurred
approximately $1.8 million in debt issuance costs in
obtaining the 2005 Credit Facility.
At Basics option, borrowings under the 2005 Term B Loan
bear interest at either the (a) Alternative Base
Rate (i.e. the higher of the banks prime rate or the
federal funds rate plus .5% per annum) plus 1% or
(b) the LIBOR rate plus 2.0%. At December 31, 2006,
Basic had paid outstanding borrowings under the Term B Loan in
full; therefore, a Term B Loan weighted average interest rate
was not calculated. However, at December 31, 2005,
Basics weighted average interest rate on its Term B Loan
was 6.4%.
At Basics option, borrowings under the 2005 Revolver bear
interest at either the (a) Alternative Base
Rate (i.e. the higher of the banks prime rate or the
federal funds rate plus .5% per annum) plus a margin
ranging from .50% to 1.25% or (b) the LIBOR rate plus a
margin ranging from 1.5% to 2.25%. The margins vary depending on
Basics leverage ratio. At December 31, 2006,
Basics margin on Alternative Base Rates and LIBOR tranches
was .75% and 1.75%, respectively. Fees on the letters of credit
are due quarterly on the outstanding amount of the letters of
credit at a rate ranging from 1.5% to 2.25% for participation
fees and .125% for fronting fees. A commitment fee is due
quarterly on the available borrowings under the Revolver at
rates ranging from .375% to .5%.
At December 31, 2006, Basic, under its Revolver, had no
outstanding borrowings and $10.6 million of letters of
credit and no amounts outstanding in swing-line loans. At
December 31, 2006 and December 31, 2005 Basic had
availability under its Revolver of $139.4 million and
$124.4 million, respectively.
Pursuant to the 2005 Credit Facility, Basic must apply proceeds
to reduce principal outstanding under the 2005 Revolver from
(a) individual assets sales greater than $2 million or
$7.5 million in the aggregate on an annual basis, and
(b) 50% of the proceeds from any equity offering. The 2005
Credit Facility required Basic to enter into an interest rate
hedge, through May 28, 2006 on at least $65 million of
Basics then outstanding indebtedness. The March 28,
2006 amendment deleted this requirement upon payoff of the Term
B Loans. In April 2006, Basic paid off all outstanding
borrowings under the Term B Loan. Paydowns on the 2005 Term B
Loan may not be reborrowed.
The 2005 Credit Facility contains various restrictive covenants
and compliance requirements, which include (a) limiting of
the incurrence of additional indebtedness, (b) restrictions
on mergers, sales or transfers of assets without the
lenders consent, (c) limitation on dividends and
distributions and (d) various financial covenants,
including (1) a maximum leverage ratio of 3.5 to 1.0
reducing over time to 3.25 to 1.0, (2) a minimum interest
coverage ratio of 3.0 to 1.0 and (e) limitations on capital
expenditures in any period of four consecutive quarters in
excess of 20% of Consolidated Net Worth unless certain criteria
are met. At December 31, 2006, Basic was in compliance with
its covenants.
66
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Other
Debt
Basic has a variety of other capital leases and notes payable
outstanding that are generally customary in its business. None
of these debt instruments are material individually or in the
aggregate.
As of December 31, 2006 the aggregate maturities of debt,
including capital leases, for the next five years and thereafter
are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Debt
|
|
|
Capital Leases
|
|
|
2007
|
|
$
|
|
|
|
$
|
12,001
|
|
2008
|
|
|
|
|
|
|
10,891
|
|
2009
|
|
|
|
|
|
|
8,563
|
|
2010
|
|
|
|
|
|
|
5,719
|
|
2011
|
|
|
|
|
|
|
569
|
|
Thereafter
|
|
|
225,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
225,000
|
|
|
$
|
37,743
|
|
|
|
|
|
|
|
|
|
|
Basics interest expense consisted of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Cash payments for interest
|
|
$
|
12,587
|
|
|
$
|
11,421
|
|
|
$
|
8,159
|
|
Commitment and other fees paid
|
|
|
566
|
|
|
|
185
|
|
|
$
|
25
|
|
Amortization of debt issuance costs
|
|
|
805
|
|
|
|
1,062
|
|
|
|
970
|
|
Accrued interest on senior notes
|
|
|
3,384
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
124
|
|
|
|
397
|
|
|
|
560
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
17,466
|
|
|
$
|
13,065
|
|
|
$
|
9,714
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Losses
on Extinguishment of Debt
In April of 2006, Basic recognized a loss on the early
extinguishment of debt. Basic wrote off unamortized debt
issuance costs of approximately $2.7 million, which related
to the prepayment of the Term B Loan.
In 2005, Basic recognized a loss on the early extinguishment of
debt. Basic wrote-off unamortized debt issuance costs of
approximately $627,000.
Income tax provision (benefit) was allocated as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Income from continuing operations
|
|
$
|
54,742
|
|
|
$
|
26,800
|
|
|
$
|
7,984
|
|
Discontinued operations
|
|
|
|
|
|
|
|
|
|
|
(38
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
54,742
|
|
|
$
|
26,800
|
|
|
$
|
7,946
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
67
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Income tax expense attributable to income from continuing
operations consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
50,499
|
|
|
$
|
8,048
|
|
|
$
|
|
|
State
|
|
|
1,632
|
|
|
|
451
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
52,131
|
|
|
$
|
8,499
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
3,594
|
|
|
$
|
17,335
|
|
|
$
|
7,563
|
|
State
|
|
|
(983
|
)
|
|
|
966
|
|
|
|
421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,611
|
|
|
$
|
18,301
|
|
|
$
|
7,984
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic paid Federal income taxes of $40,200,000 during 2006 and
$1,325,000 during 2005. No Federal income taxes were paid or
received in 2004.
Reconciliation between the amount determined by applying the
Federal statutory rate of 35% to the income from continuing
operations with the provision for income taxes is as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Statutory Federal income tax
|
|
$
|
53,750
|
|
|
$
|
25,053
|
|
|
$
|
7,321
|
|
Meals and entertainment
|
|
|
430
|
|
|
|
324
|
|
|
|
265
|
|
State taxes, net of Federal benefit
|
|
|
778
|
|
|
|
1,415
|
|
|
|
421
|
|
Change in tax rates
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in estimates and other
|
|
|
(216
|
)
|
|
|
8
|
|
|
|
(23
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
54,742
|
|
|
$
|
26,800
|
|
|
$
|
7,984
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
68
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The tax effects of temporary differences that give rise to
significant portions of the deferred tax assets and deferred tax
liabilities are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Receivables allowance
|
|
$
|
1,461
|
|
|
$
|
1,025
|
|
Asset retirement obligation
|
|
|
234
|
|
|
|
210
|
|
Accrued liabilities
|
|
|
6,659
|
|
|
|
5,181
|
|
Operating loss carryforward
|
|
|
1,412
|
|
|
|
1,856
|
|
Deferred Compensation
|
|
|
1,790
|
|
|
|
1,140
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
11,556
|
|
|
|
9,412
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Property and equipment
|
|
|
(73,926
|
)
|
|
|
(55,768
|
)
|
Goodwill and intangibles
|
|
|
(2,611
|
)
|
|
|
(1,208
|
)
|
Interest rate derivative
|
|
|
|
|
|
|
(186
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
(76,537
|
)
|
|
|
(57,162
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
|
(64,981
|
)
|
|
|
(47,750
|
)
|
|
|
|
|
|
|
|
|
|
Recognized as:
|
|
|
|
|
|
|
|
|
Deferred tax assets
current
|
|
|
8,432
|
|
|
|
6,020
|
|
Deferred tax
liabilities non-current
|
|
|
(73,413
|
)
|
|
|
(53,770
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
(64,981
|
)
|
|
$
|
(47,750
|
)
|
|
|
|
|
|
|
|
|
|
Basic provides a valuation allowance when it is more likely than
not that some portion of the deferred tax assets will not be
realized. There was no valuation allowance necessary as of
December 31, 2006 or 2005.
As of December 31, 2006, Basic had approximately
$4.0 million of net operating loss carryforwards
(NOL) for U.S. federal income tax purposes
related to the preacquisition period of FESCO, which are subject
to an annual limitation of approximately $900,000. The
carryforwards begin to expire in 2017.
|
|
7.
|
Commitments
and Contingencies
|
Environmental
Basic is subject to various federal, state and local
environmental laws and regulations that establish standards and
requirements for protection of the environment. Basic cannot
predict the future impact of such standards and requirements
which are subject to change and can have retroactive
effectiveness. Basic continues to monitor the status of these
laws and regulations. Management believes that the likelihood of
the disposition of any of these items resulting in a material
adverse impact to Basics financial position, liquidity,
capital resources or future results of operations is remote.
Currently, Basic has not been fined, cited or notified of any
environmental violations that would have a material adverse
effect upon its financial position, liquidity or capital
resources. However, management does recognize that by the very
nature of its business, material costs could be incurred in the
near term to bring Basic into total compliance. The amount of
such future expenditures is not determinable due to several
factors including the unknown magnitude of possible
contamination, the unknown timing and extent of the corrective
actions which may be required, the determination of Basics
liability in proportion to other responsible parties and the
extent to which such expenditures are recoverable from insurance
or indemnification.
69
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Litigation
From time to time, Basic is a party to litigation or other legal
proceedings that Basic considers to be a part of the ordinary
course of business. Basic is not currently involved in any legal
proceedings that it considers probable or reasonably possible,
individually or in the aggregate, to result in a material
adverse effect on its financial condition, results of operations
or liquidity.
Operating
Leases
Basic leases certain property and equipment under non-cancelable
operating leases. The term of the operating leases generally
range from 12 to 60 months with varying payment dates
throughout each month.
As of December 31, 2006, the future minimum lease payments
under non-cancelable operating leases are as follows (in
thousands):
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
2007
|
|
$
|
2,551
|
|
2008
|
|
|
2,360
|
|
2009
|
|
|
2,098
|
|
2010
|
|
|
1,493
|
|
2011
|
|
|
1,200
|
|
Thereafter
|
|
|
3,904
|
|
Rent expense approximated $13.9 million, $7.0 million,
and $5.6 million for 2006, 2005 and 2004, respectively.
Basic leases rights for the use of various brine and fresh water
wells and disposal wells ranging in terms from
month-to-month
up to 99 years. The above table reflects the future minimum
lease payments if the lease contains a periodic rental. However,
the majority of these leases require payments based on a royalty
percentage or a volume usage.
Employment
Agreements
Under the employment agreement with Mr. Huseman, Chief
Executive Officer and president of Basic, effective
December 31, 2006 through December 31, 2009,
Mr. Huseman will be entitled to an annual salary of
$400,000 and a minimum annual bonus of $50,000. Under this
employment agreement, Mr. Huseman is eligible from time to
time to receive grants of stock options and other long-term
equity incentive compensation under our Amended and Restated
2003 Incentive Plan. In addition, upon a qualified termination
of employment, Mr. Huseman would be entitled to three times
his base salary plus his current annual incentive target bonus
for the full year in which the termination of employment
occurred. If employment is terminated for certain reasons within
the six months preceding or the twelve months following the
change of control of our Company, Mr. Huseman would be
entitled to a lump sum severance payment equal to three times
the sum of his base salary plus the higher of (i) his
current incentive target bonus for the full year in which the
termination of employment occurred or (ii) the highest
annual incentive bonus received by him for any of the last three
fiscal years.
Basic has entered into employment agreements with various other
executive officers of Basic that range in term up through
December 2007. Under these agreements, if the officers
employment is terminated for certain reasons, he would be
entitled to a lump sum severance payment equal to amounts
ranging from 1.5 times to 0.75 times the sum of his base salary
plus his current annual incentive target bonus for the full year
in which the termination occurred . If employment is terminated
for certain reasons within the six months preceding or the
twelve months following the chance of control of our Company, he
would be entitled to a lump sum severance payment equal to three
times the sum of his base salary plus the higher of (i) his
current incentive target bonus for the full year in
70
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
which the termination of employment occurred or (ii) the
highest annual incentive bonus received by him for any of the
last three fiscal years.
Self-Insured
Risk Accruals
Basic is self-insured up to retention limits as it relates to
workers compensation and medical and dental coverage of
its employees. Basic, generally, maintains no physical property
damage coverage on its workover rig fleet, with the exception of
certain of its
24-hour
workover rigs and newly manufactured rigs. Basic has deductibles
per occurrence for workers compensation and medical and
dental coverage of $150,000 and $150,000, respectively. Basic
has lower deductibles per occurrence for automobile liability
and general liability. Basic maintains accruals in the
accompanying consolidated balance sheets related to
self-insurance retentions by using third-party data and claims
history.
At December 31, 2006 and December 31, 2005,
self-insured risk accruals totaled approximately
$12.6 million, net of $652,000 receivable for medical and
dental coverage, and $9.5 million, net of $127,000
receivable for medical and dental coverage, respectively.
Common
Stock
In February 2002, a group of related investors purchased a total
of 3,000,000 shares of Basics common stock at a
purchase price of $4 per share, for a total purchase price
of $12 million. As part of the purchase, 600,000 common
stock warrants were issued in connection with this transaction,
the fair value of which was approximately $1.2 million
(calculated using an option valuation model). The warrants allow
the holder to purchase 600,000 shares of Basics
common stock at $4 per share. The warrants were exercisable
in whole or in part after June 30, 2002 and prior to
February 13, 2007.
In June of 2002 Basic granted 3,750,000 common stock warrants to
acquire a total of 3,750,000 shares of common stock at a
price of $4 per share, exercisable in whole or in part from
June 30, 2002 through June 30, 2007.
In February 2004, Basic granted certain officers and directors
837,500 restricted shares of common stock. The shares vest
25% per year for four years from the award date and are
subject to other vesting and forfeiture provisions. The
estimated fair value of the restricted shares was
$5.8 million at the date of the grant and was recorded as
deferred compensation, a component of stockholders equity.
This amount is being charged to expense over the respective
vesting period and totaled approximately $1.3 million,
$1.6 million and $1.3 million for the years ended
December 31, 2006, 2005 and 2004.
In December 2005, Basic issued 5,000,000 shares of common
stock during the Companys Initial Public Offering to a
group of investors for $100 million or $20 per share.
After deducting fees, this resulted in net proceeds to Basic
totaling approximately $91.5 million.
On October 5, 2006, all outstanding warrants were exercised
to purchase an aggregate of 4,350,000 shares of
Basics common stock. In connection with the exercise of
the warrants, Basic received an aggregate of $17.4 million
from the Holders in satisfaction of the exercise price of the
warrants (representing an exercise price of $4.00 per share
of Basics common stock acquired).
During year ended 2006, Basic issued 293,350 shares of
common stock from treasury stock for the exercise of stock
options. Also, Basic issued 15,670 shares of newly-issued
common stock for the exercise of stock options.
Preferred
Stock
At December 31, 2006 and 2005, Basic had
5,000,000 shares of $.01 par value preferred stock
authorized, of which none is designated.
71
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
9.
|
Stockholders
Agreement
|
Basic has a Stockholders Agreement, as amended on
April 2, 2004 (Stockholders Agreement),
which provides for rights relating to the shares of our
stockholders and certain corporate governance matters.
The Stockholders Agreement provides for participation
rights of the other stockholders to require affiliates of DLJ
Merchant Banking to offer to include a specified percentage of
their shares whenever affiliates of DLJ Merchant Banking
sell their shares for value, other than a public offering or a
sale in which all of the parties to the Stockholders
Agreement agree to participate. The Stockholders Agreement
also contains drag-along rights. The
drag-along rights entitle the affiliated of DLJ
Merchant Banking to require the other stockholders who are a
party to this agreement to sell a portion of their shares of
common stock and common stock equivalents in the sale in any
proposed to sale of shares of common stock and common stock
equivalents representing more than 50% of such equity interest
held by the affiliates of DLJ Merchant Banking to a person or
persons who are not an affiliate of them.
The Stockholders Agreement currently provides for demand
and piggyback registration rights following the completion of
our 2005 initial public offering of Basics common stock.
In May 2003, Basics board of directors and stockholders
approved the Basic 2003 Incentive Plan (as amended effective
April 22, 2005) (the Plan), which provides for
granting of incentive awards in the form of stock options,
restricted stock, performance awards, bonus shares, phantom
shares, cash awards and other stock-based awards to officers,
employees, directors and consultants of Basic. The Plan assumed
awards of the plans of Basics successors that were awarded
and remained outstanding prior to adoption of the Plan. The Plan
provides for the issuance of 5,000,000 shares. The Plan is
administered by the Plan committee, and in the absence of a Plan
committee, by the Board of Directors, which determines the
awards, and the associated terms of the awards and interprets
its provisions and adopts policies for implementing the Plan.
The number of shares authorized under the Plan and the number of
shares subject to an award under the Plan will be adjusted for
stock splits, stock dividends, recapitalizations, mergers and
other changes affecting the capital stock of Basic.
On March 15, 2006, the board of directors granted various
employees and directors options to purchase 418,000 shares
of common stock of Basic at an exercise price of $26.84 per
share. All of the 418,000 options granted in 2006 vest over a
five-year period and expire 10 years from the date they
were granted. Option awards are generally granted with an
exercise price equal to the market price of the Companys
stock at the date of grant.
The fair value of each option award is estimated on the date of
grant using the Black-Scholes-Merton option-pricing model that
uses the subjective assumptions noted in the following table.
Since the Company has only been public since December 2005,
expected volatility for options granted during 2006 is an
implied volatility based upon a peer group. When the Company has
sufficient historical data to calculate expected volatility, the
Company will use its own historical data to calculate
expected volatility. The expected term of options granted
represents the period of time that options granted are expected
to be outstanding. For options granted in 2006, the Company used
the simplified method to calculate the expected term. The
risk-free rate for periods within the contractual life of the
options is based on the U.S. Treasury yield curve in effect
at the time of grant. The estimates involve inherent
uncertainties and the application of management judgment. In
addition, we are required to estimate the expected forfeiture
rate and only recognize expense for those options expected to
vest. During the years ended December 31, 2006, 2005 and
2004, compensation expense related to share-based arrangements
was approximately $3.4 million, $2.9 million and
$1.6 million , respectively. For compensation expense
recognized during the years ended
72
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
December 31, 2006, 2005 and 2004 Basic recognized a tax
benefit of approximately $1,222,000, $1,082,000 and $606,000,
respectively.
The fair value of each option award accounted for under
SFAS No. 123R is estimated on the date of grant using
the Black-Scholes-Merton option-pricing model that uses the
assumptions noted in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Risk-free interest rate
|
|
|
4.7
|
%
|
|
|
4.2% - 4.5
|
%
|
|
|
4.0% - 4.7
|
%
|
Expected term
|
|
|
6.65
|
|
|
|
6.00 - 10.00
|
|
|
|
10.0
|
|
Expected volatility
|
|
|
47.0
|
%
|
|
|
0.0
|
%
|
|
|
0.0
|
%
|
Expected dividend yield
|
|
|
|
|
|
|
|
|
|
|
|
|
Options granted under the Plan expire 10 years from the
date they are granted, and generally vest over a
three-to-five
year service period.
The following table reflects the summary of stock options
outstanding at December 31, 2006 and the changes during the
twelve months then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
Average
|
|
|
Aggregate
|
|
|
|
Number of
|
|
|
Average
|
|
|
Remaining
|
|
|
Instrinsic
|
|
|
|
Options
|
|
|
Exercise
|
|
|
Contractual
|
|
|
Value
|
|
|
|
Granted
|
|
|
Price
|
|
|
Term (Years)
|
|
|
(000s)
|
|
|
Non-statutory stock options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, beginning of period
|
|
|
2,445,800
|
|
|
$
|
5.44
|
|
|
|
|
|
|
|
|
|
Options granted
|
|
|
418,000
|
|
|
$
|
26.84
|
|
|
|
|
|
|
|
|
|
Options forfeited
|
|
|
(97,000
|
)
|
|
$
|
10.46
|
|
|
|
|
|
|
|
|
|
Options exercised
|
|
|
(309,020
|
)
|
|
$
|
4.10
|
|
|
|
|
|
|
|
|
|
Options expired
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period
|
|
|
2,457,780
|
|
|
$
|
9.05
|
|
|
|
7.20
|
|
|
$
|
39,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, end of period
|
|
|
1,142,613
|
|
|
$
|
4.35
|
|
|
|
5.75
|
|
|
$
|
23,199
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested or expected to vest, end of
period
|
|
|
2,439,080
|
|
|
$
|
8.91
|
|
|
|
7.18
|
|
|
$
|
39,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted-average grant date fair value of share options
granted during the years ended December 31, 2006, 2005 and
2004 was $14.47, $8.00 and $3.14, respectively. The total
intrinsic value of share options exercised during the years
ended December 31, 2006, 2005 and 2004 was approximately
$7.1 million, $0 and $0, respectively.
A summary of the status of the Companys non-vested share
grants at December 31, 2006 and changes during the year
ended December 31, 2006 is presented in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
Number of
|
|
|
Grant Date Fair
|
|
Nonvested Shares
|
|
Shares
|
|
|
Value per Share
|
|
|
Nonvested at beginning of period
|
|
|
591,875
|
|
|
$
|
6.98
|
|
Granted during period
|
|
|
|
|
|
|
|
|
Vested during period
|
|
|
(230,625
|
)
|
|
|
6.98
|
|
Forfeited during period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested at end of period
|
|
|
361,250
|
|
|
$
|
6.98
|
|
|
|
|
|
|
|
|
|
|
73
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
As of December 31, 2006, there was $8.8 million of
total unrecognized compensation related to non-vested
share-based compensation arrangements granted under the Plan.
That cost is expected to be recognized over a weighted-average
period of 3.06 years. The total fair value of share-based
awards vested during the years ended December 31, 2006,
2005 and 2004 was approximately $12.3 million,
$5.3 million and $2.6 million, respectively.
Cash received from share option exercises under the incentive
plan was approximately $671,000, $0 and $0 for the years ended
December 31, 2006, 2005 and 2004, respectively. The actual
tax benefit realized for the tax deductions from options
exercised was $4.0 million, $0 and $0, respectively, for
the years ended December 31, 2006, 2005 and 2004.
The Company has a history of issuing Treasury and newly-issued
shares to satisfy share option exercises.
|
|
11.
|
Related
Party Transactions
|
Basic had receivables from employees of approximately $94,000
and $65,000 as of December 31, 2006 and December 31,
2005, respectively. During 2006, Basic entered into a lease
agreement with Darle Vuelta Cattle Co., LLC, an affiliate of the
Chief Executive Officer, for approximately $69,000. The term of
the lease is five years and will continue on a
year-to-year
basis unless terminated by either party.
Basic has a 401(k) profit sharing plan that covers substantially
all employees with more than 90 days of service. Employees
may contribute up to their base salary not to exceed the annual
Federal maximum allowed for such plans. Basic makes a matching
contribution proportional to each employees contribution.
Employee contributions are fully vested at all times. Employer
matching contributions vest incrementally, with full vesting
occurring after five years of service. Employer contributions to
the 401(k) plan approximated $2.5 million, $468,000 and
$363,000 in 2006, 2005 and 2004, respectively.
|
|
13.
|
Deferred
Compensation Plan
|
In April 2005, Basic established a deferred compensation plan
for certain employees. Participants may defer up to 50% of their
salary and 100% of any cash bonuses. Basic makes matching
contributions of 100% of the first 3% of the participants
deferred pay and 50% of the next 2% of the participants
deferred pay to a maximum match of $8,800 per year.
Employer matching contributions and earnings thereon are subject
to a five-year vesting schedule with full vesting occurring
after five years of service. Employer contributions to the
deferred compensation plan approximated $199,000, $56,000, and
$0 in 2006, 2005 and 2004, respectively.
Basic presents earnings per share information in accordance with
the provisions of Statement of Financial Accounting Standards
No. 128, Earnings per Share
(SFAS No. 128). Under
SFAS No. 128, basic earnings per common share are
determined by dividing net earnings applicable to common stock
by the weighted average number of common shares actually
outstanding during the year. Diluted earnings per common share
is based on the
74
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
increased number of shares that would be outstanding assuming
conversion of dilutive outstanding securities using the as
if converted method. The following table sets forth the
computation of basic and diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Numerator (both basic and
diluted):
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
98,830
|
|
|
$
|
44,781
|
|
|
$
|
12,932
|
|
Discontinued operations, net of tax
|
|
|
|
|
|
|
|
|
|
|
(71
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common
stockholders
|
|
$
|
98,830
|
|
|
$
|
44,781
|
|
|
$
|
12,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for basic earnings per
share
|
|
|
34,471,771
|
|
|
|
28,580,911
|
|
|
|
28,094,435
|
|
Stock options
|
|
|
1,054,040
|
|
|
|
789,991
|
|
|
|
389,975
|
|
Unvested restricted stock
|
|
|
244,153
|
|
|
|
638,442
|
|
|
|
837,500
|
|
Common stock warrants
|
|
|
2,823,029
|
|
|
|
3,159,035
|
|
|
|
1,333,310
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted earnings
per share
|
|
|
38,592,993
|
|
|
|
33,168,379
|
|
|
|
30,655,220
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per common
share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
2.87
|
|
|
$
|
1.57
|
|
|
$
|
0.46
|
|
Discontinued operations, net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common
stockholders
|
|
$
|
2.87
|
|
|
$
|
1.57
|
|
|
$
|
0.46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per common
share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
2.56
|
|
|
$
|
1.35
|
|
|
$
|
0.42
|
|
Discontinued operations, net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common
stockholders
|
|
$
|
2.56
|
|
|
$
|
1.35
|
|
|
$
|
0.42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15.
|
Assets
Held for Sale and Discontinued Operations
|
In August, 2003 Basics management and board of directors
made the decision to dispose of its fluid services operations in
Alaska it acquired in the FESCO acquisition prior to closing of
the acquisition. After this disposal Basic no longer had any
operations in Alaska.
The following are the results of operations, since their
acquisition in October 2003, from the discontinued operations
(in thousands):
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31, 2004
|
|
|
Revenues
|
|
$
|
1,705
|
|
Operating costs
|
|
|
(1,814
|
)
|
Income taxes deferred
|
|
|
38
|
|
|
|
|
|
|
Loss from discontinued operations,
net of tax
|
|
$
|
(71
|
)
|
|
|
|
|
|
75
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
16.
|
Business
Segment Information
|
Basics reportable business segments are well servicing,
fluid services, drilling and completion services and well site
construction services. The following is a description of the
segments:
Well Servicing: This business segment
encompasses a full range of services performed with a mobile
well servicing rig, including the installation and removal of
downhole equipment and elimination of obstructions in the well
bore to facilitate the flow of oil and gas. These services are
performed to establish, maintain and improve production
throughout the productive life of an oil and gas well and to
plug and abandon a well at the end of its productive life. Basic
well servicing equipment and capabilities are essential to
facilitate most other services performed on a well.
Fluid Services: This segment utilizes a fleet
of trucks and related assets, including specialized tank trucks,
storage tanks, water wells, disposal facilities and related
equipment. Basic employs these assets to provide, transport,
store and dispose of a variety of fluids. These services are
required in most workover, drilling and completion projects as
well as part of daily producing well operations.
Drilling and Completion Services: This segment
utilizes a fleet of pressure pumping units, air compressor
packages specially configured for underbalanced drilling
operations, cased-hole wireline units and an array of
specialized rental equipment and fishing tools. The largest
portion of this business consists of pressure pumping services
focused on cementing, acidizing and fracturing services in niche
markets.
Well Site Construction Services: This segment
utilizes a fleet of power units, dozers, trenchers, motor
graders, backhoes and other heavy equipment. Basic employs these
assets to provide services for the construction and maintenance
of oil and gas production infrastructure, such as preparing and
maintaining access roads and well locations, installation of
small diameter gathering lines and pipelines and construction of
temporary foundations to support drilling rigs.
Basics management evaluates the performance of its
operating segments based on operating revenues and segment
profits. Corporate expenses include general corporate expenses
associated with managing all reportable operating segments.
Corporate assets consist principally of working capital and debt
financing costs.
76
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The following table sets forth certain financial information
with respect to Basics reportable segments (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and
|
|
|
Well Site
|
|
|
|
|
|
|
|
|
|
Well
|
|
|
Fluid
|
|
|
Completion
|
|
|
Construction
|
|
|
Corporate
|
|
|
|
|
|
|
Servicing
|
|
|
Services
|
|
|
Services
|
|
|
Services
|
|
|
and Other
|
|
|
Total
|
|
|
Year ended December 31,
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
330,725
|
|
|
$
|
194,636
|
|
|
$
|
154,412
|
|
|
$
|
50,375
|
|
|
$
|
|
|
|
$
|
730,148
|
|
Direct operating costs
|
|
|
(186,428
|
)
|
|
|
(118,378
|
)
|
|
|
(74,981
|
)
|
|
|
(35,067
|
)
|
|
|
|
|
|
|
(414,854
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profits
|
|
$
|
144,297
|
|
|
$
|
76,258
|
|
|
$
|
79,431
|
|
|
$
|
15,308
|
|
|
$
|
|
|
|
$
|
315,294
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$
|
28,930
|
|
|
$
|
16,090
|
|
|
$
|
11,070
|
|
|
$
|
3,602
|
|
|
$
|
2,395
|
|
|
$
|
62,087
|
|
Capital expenditures, (excluding
acquisitions)
|
|
$
|
48,727
|
|
|
$
|
27,100
|
|
|
$
|
18,646
|
|
|
$
|
6,067
|
|
|
$
|
4,034
|
|
|
$
|
104,574
|
|
Identifiable assets
|
|
$
|
243,678
|
|
|
$
|
161,555
|
|
|
$
|
129,471
|
|
|
$
|
32,372
|
|
|
$
|
229,184
|
|
|
$
|
796,260
|
|
Year ended December 31,
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
221,993
|
|
|
$
|
132,280
|
|
|
$
|
59,832
|
|
|
$
|
45,647
|
|
|
$
|
|
|
|
$
|
459,752
|
|
Direct operating costs
|
|
|
(137,392
|
)
|
|
|
(82,551
|
)
|
|
|
(30,900
|
)
|
|
|
(32,000
|
)
|
|
|
|
|
|
|
(282,843
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profits
|
|
$
|
84,601
|
|
|
$
|
49,729
|
|
|
$
|
28,932
|
|
|
$
|
13,647
|
|
|
$
|
|
|
|
$
|
176,909
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$
|
18,671
|
|
|
$
|
9,415
|
|
|
$
|
3,644
|
|
|
$
|
2,808
|
|
|
$
|
2,534
|
|
|
$
|
37,072
|
|
Capital expenditures, (excluding
acquisitions)
|
|
$
|
42,838
|
|
|
$
|
21,602
|
|
|
$
|
8,361
|
|
|
$
|
6,443
|
|
|
$
|
3,851
|
|
|
$
|
83,095
|
|
Identifiable assets
|
|
$
|
169,487
|
|
|
$
|
100,959
|
|
|
$
|
45,850
|
|
|
$
|
28,376
|
|
|
$
|
152,621
|
|
|
$
|
497,293
|
|
Year ended December 31,
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
142,551
|
|
|
$
|
98,683
|
|
|
$
|
29,341
|
|
|
$
|
40,927
|
|
|
$
|
|
|
|
$
|
311,502
|
|
Direct operating costs
|
|
|
(98,058
|
)
|
|
|
(65,167
|
)
|
|
|
(17,481
|
)
|
|
|
(31,454
|
)
|
|
|
|
|
|
|
(212,160
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profits
|
|
$
|
44,493
|
|
|
$
|
33,516
|
|
|
$
|
11,860
|
|
|
$
|
9,473
|
|
|
$
|
|
|
|
$
|
99,342
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$
|
14,125
|
|
|
$
|
8,316
|
|
|
$
|
2,402
|
|
|
$
|
1,857
|
|
|
$
|
1,976
|
|
|
$
|
28,676
|
|
Capital expenditures, (excluding
acquisitions)
|
|
$
|
27,918
|
|
|
$
|
16,436
|
|
|
$
|
3,670
|
|
|
$
|
4,748
|
|
|
$
|
2,902
|
|
|
$
|
55,674
|
|
Identifiable assets
|
|
$
|
126,208
|
|
|
$
|
87,349
|
|
|
$
|
24,246
|
|
|
$
|
24,064
|
|
|
$
|
105,993
|
|
|
$
|
367,860
|
|
The following table reconciles the segment profits reported
above to the operating income as reported in the consolidated
statements of operations (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Segment profits
|
|
$
|
315,294
|
|
|
$
|
176,909
|
|
|
$
|
99,342
|
|
General and administrative expenses
|
|
|
(81,318
|
)
|
|
|
(55,411
|
)
|
|
|
(37,186
|
)
|
Depreciation and amortization
|
|
|
(62,087
|
)
|
|
|
(37,072
|
)
|
|
|
(28,676
|
)
|
Gain (loss) on disposal of assets
|
|
|
(277
|
)
|
|
|
222
|
|
|
|
(2,616
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
171,612
|
|
|
$
|
84,648
|
|
|
$
|
30,864
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
77
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The accrued expenses are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Compensation related
|
|
$
|
14,006
|
|
|
$
|
10,576
|
|
Workers compensation
self-insured risk reserve
|
|
|
8,497
|
|
|
|
7,461
|
|
Health self-insured risk reserve
|
|
|
5,289
|
|
|
|
2,200
|
|
Accrual for receipts
|
|
|
3,608
|
|
|
|
1,841
|
|
Authority for expenditure accrual
|
|
|
1,325
|
|
|
|
3,052
|
|
Ad valorem taxes
|
|
|
106
|
|
|
|
935
|
|
Sales tax
|
|
|
1,886
|
|
|
|
2,407
|
|
Insurance obligations
|
|
|
489
|
|
|
|
673
|
|
Purchase order accrual
|
|
|
41
|
|
|
|
96
|
|
Professional fee accrual
|
|
|
216
|
|
|
|
1,079
|
|
Diesel tax accrual
|
|
|
|
|
|
|
385
|
|
Contingent earnout obligation
|
|
|
2,189
|
|
|
|
|
|
Retainers
|
|
|
181
|
|
|
|
1,042
|
|
Fuel accrual
|
|
|
460
|
|
|
|
368
|
|
Accrued interest
|
|
|
3,620
|
|
|
|
391
|
|
Contingent liability
|
|
|
|
|
|
|
1,000
|
|
Franchise Tax Payable
|
|
|
1,789
|
|
|
|
|
|
Other
|
|
|
17
|
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
43,719
|
|
|
$
|
33,548
|
|
|
|
|
|
|
|
|
|
|
|
|
18.
|
Supplemental
Schedule of Cash Flow Information
|
The following table reflects non-cash financing and investing
activity during:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Capital leases issued for equipment
|
|
$
|
26,420
|
|
|
$
|
10,334
|
|
|
$
|
10,472
|
|
Exercise of stock options
|
|
$
|
5,144
|
|
|
$
|
|
|
|
$
|
|
|
Contingent earnout accrual
|
|
$
|
2,256
|
|
|
$
|
|
|
|
$
|
|
|
Asset retirement obligation
additions
|
|
$
|
767
|
|
|
$
|
74
|
|
|
$
|
21
|
|
Basic paid income taxes of approximately $43.2 million,
$1.3 million and $0 during the years ended
December 31, 2006, 2005 and 2004, respectively.
78
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
19.
|
Quarterly
Financial Data (Unaudited)
|
The following table summarizes results for each of the four
quarters in the years ended December 31, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Year
|
|
|
Year ended December 31,
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
154,306
|
|
|
$
|
183,833
|
|
|
$
|
194,555
|
|
|
$
|
197,454
|
|
|
$
|
730,148
|
|
Segment profits
|
|
$
|
64,894
|
|
|
$
|
80,969
|
|
|
$
|
84,989
|
|
|
$
|
84,442
|
|
|
$
|
315,294
|
|
Income from continuing operations
|
|
$
|
19,681
|
|
|
$
|
24,487
|
|
|
$
|
27,328
|
|
|
$
|
27,334
|
|
|
$
|
98,830
|
|
Net income available to common
stockholders
|
|
$
|
19,681
|
|
|
$
|
24,487
|
|
|
$
|
27,328
|
|
|
$
|
27,334
|
|
|
$
|
98,830
|
|
Basic earnings per share of common
stock(a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$
|
0.59
|
|
|
$
|
0.73
|
|
|
$
|
0.81
|
|
|
$
|
0.72
|
|
|
$
|
2.87
|
|
Net income available to common
stockholders
|
|
$
|
0.59
|
|
|
$
|
0.73
|
|
|
$
|
0.81
|
|
|
$
|
0.72
|
|
|
$
|
2.87
|
|
Diluted earnings per share of
common stock(a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$
|
0.53
|
|
|
$
|
0.64
|
|
|
$
|
0.71
|
|
|
$
|
0.70
|
|
|
$
|
2.56
|
|
Net income available to common
stockholders
|
|
$
|
0.53
|
|
|
$
|
0.64
|
|
|
$
|
0.71
|
|
|
$
|
0.70
|
|
|
$
|
2.56
|
|
Weighted average common shares
outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
33,262
|
|
|
|
33,434
|
|
|
|
33,537
|
|
|
|
37,766
|
|
|
|
34,472
|
|
Diluted
|
|
|
36,902
|
|
|
|
38,526
|
|
|
|
38,442
|
|
|
|
39,116
|
|
|
|
38,593
|
|
Year ended December 31,
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
93,813
|
|
|
$
|
109,818
|
|
|
$
|
120,771
|
|
|
$
|
135,350
|
|
|
$
|
459,752
|
|
Segment profits
|
|
$
|
33,416
|
|
|
$
|
42,238
|
|
|
$
|
45,791
|
|
|
$
|
55,464
|
|
|
$
|
176,909
|
|
Income from continuing operations
|
|
$
|
5,801
|
|
|
$
|
10,747
|
|
|
$
|
12,335
|
|
|
$
|
15,898
|
|
|
$
|
44,781
|
|
Net income available to common
stockholders
|
|
$
|
5,801
|
|
|
$
|
10,747
|
|
|
$
|
12,335
|
|
|
$
|
15,898
|
|
|
$
|
44,781
|
|
Basic earnings per share of common
stock(a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$
|
0.21
|
|
|
$
|
0.38
|
|
|
$
|
0.44
|
|
|
$
|
0.54
|
|
|
$
|
1.57
|
|
Net income available to common
stockholders
|
|
$
|
0.21
|
|
|
$
|
0.38
|
|
|
$
|
0.44
|
|
|
$
|
0.54
|
|
|
$
|
1.57
|
|
Diluted earnings per share of
common stock(a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$
|
0.18
|
|
|
$
|
0.33
|
|
|
$
|
0.38
|
|
|
$
|
0.46
|
|
|
$
|
1.35
|
|
Net income (loss) available to
common stockholders
|
|
$
|
0.18
|
|
|
$
|
0.33
|
|
|
$
|
0.38
|
|
|
$
|
0.46
|
|
|
$
|
1.35
|
|
Weighted average common shares
outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
28,186
|
|
|
|
28,328
|
|
|
|
28,318
|
|
|
|
29,481
|
|
|
|
28,581
|
|
Diluted
|
|
|
32,157
|
|
|
|
32,783
|
|
|
|
32,802
|
|
|
|
34,436
|
|
|
|
33,168
|
|
|
|
|
(a) |
|
The sum of individual quarterly net income per share may not
agree to the total for the year to due each periods
computation based on the weighted average number of common
shares outstanding during each period. |
79
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
On January 3, 2007, Basic acquired two barge-mounted
workover rigs and related equipment from Parker Drilling
Offshore USA, LLC for total consideration of $20.5 million
cash. The acquired rigs will operate in the inland waters of
Louisiana and Texas as part of Basic Marine Services.
On January 17, 2007, Basic acquired substantially all of
the operating assets of Davis Tool Company, Inc. for total
consideration of $4.9 million cash. This acquisition will
operate in Basics drilling and completion line of business.
On March 6, 2007, Basic acquired all of the outstanding
capital stock of JetStar Consolidated Holdings, Inc. for a total
acquisition price, net of estimated working capital, of
approximately $118 million. The total acquisition price is
comprised of approximately 1.9 million shares of Basic
common stock, $45 million in cash to JetStarss
shareholders, and $38 million for repayment of JetStar
outstanding debt. This acquisition will operate in the
Basics drilling and completion line of business.
On March 13, 2007, Basic signed a definitive agreement to
acquire all of the outstanding capital stock of Sledge Drilling
Holding Corp. (Sledge) for total consideration of
approximately $51 million, including $10 million in
shares of Basic common stock and repayment of Sledges
outstanding debt, plus certain working capital adjustments at
closing. The transaction is expected to close in the second
quarter of 2007 but closing is subject to completion of due
diligence by Basic and other customary closing conditions.
On February 6, 2007, Basic amended and restated its
existing credit agreement by entering into a Fourth Amended and
Restated Credit Agreement with a syndicate of lenders. The
amendments contained in the 2007 Credit Facility included:
|
|
|
|
|
eliminating the $90 million class of Term B Loans;
|
|
|
|
creating a new class of Revolving Loans, which increased the
lenders total revolving commitments from $150 million
to $225 million
|
|
|
|
increasing the Incremental Revolving Commitments
under the 2007 Credit Facility from $75.0 million to an
aggregate principal amount of $100 million;
|
|
|
|
changing the applicable margins for Alternative Base Rate or
Eurodollar revolving loans;
|
|
|
|
amending our negative covenants relating to our ability to incur
indebtedness and liens, to add tests based on a percentage of
our consolidated tangible assets in addition to fixed dollar
amounts, or to increase applicable dollar limits on baskets or
other tests for permitted indebtedness or liens;
|
|
|
|
amending our negative covenants relating to our ability to pay
dividends, or repurchase or redeem our capital stock, in order
to conform more closely with permitted payments under our senior
notes; and
|
|
|
|
eliminating certain restrictions on our ability to create or
incur certain lease obligations.
|
|
|
(c)
|
Employment
Agreements
|
On January 23, 2007, Basic amended its employment agreement
with Kenneth U. Huseman, President and Chief Executive Officer.
The amendment eliminated a minimum annual bonus of $50,000 and
increased his salary to $525,000 per year.
80
Schedule II
Valuation and Qualifying Accounts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions
|
|
|
|
|
|
|
|
|
|
Balance at
|
|
|
Charged to
|
|
|
Charged to
|
|
|
|
|
|
Balance at
|
|
|
|
Beginning of
|
|
|
Costs and
|
|
|
Other
|
|
|
|
|
|
End of
|
|
Description
|
|
Period
|
|
|
Expenses(a)
|
|
|
Accounts(b)
|
|
|
Deductions(c)
|
|
|
Period
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Bad Debt
|
|
$
|
2,775
|
|
|
$
|
1,820
|
|
|
$
|
|
|
|
$
|
(632
|
)
|
|
$
|
3,963
|
|
Year Ended December 31,
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Bad Debt
|
|
$
|
3,108
|
|
|
$
|
1,651
|
|
|
$
|
|
|
|
$
|
(1,984
|
)
|
|
$
|
2,775
|
|
Year Ended December 31,
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Bad Debt
|
|
$
|
1,958
|
|
|
$
|
1,200
|
|
|
$
|
|
|
|
$
|
(50
|
)
|
|
$
|
3,108
|
|
|
|
|
(a) |
|
Charges relate to provisions for doubtful accounts |
|
(b) |
|
Reflects the impact of acquisitions |
|
(c) |
|
Deductions relate to the write-off of accounts receivable deemed
uncollectible |
81
|
|
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 their evaluation as of the end of the fiscal year ended
December 31, 2006, our principal executive officer and
principal financial officer have concluded that our disclosure
controls and procedures (as defined in
Rules 13a-15(e)
and
15d-15(e)
under the Exchange Act) are effective to ensure that information
required to be disclosed in reports that we file or submit under
the Exchange Act are recorded, processed, summarized and
reported within the time periods specified in the SECs
rules and forms.
Changes
in Internal Control Over Financial Reporting
During the most recent fiscal quarter, there have been no
changes in our internal control over financial reporting that
have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.
Design
and Evaluation of Internal Control over Financial
Reporting
Managements Report on Internal Control over Financial
Reporting and the Report of the Independent Registered Public
Accounting Firm are set forth in Part II, Item 8 of
this report and are incorporated herein by reference.
|
|
ITEM 9B.
|
OTHER
INFORMATION
|
None.
PART III
Pursuant to paragraph 3 of General Instruction G to
Form 10-K,
the information required by Item 10, to the extent not set
forth in Executive Officers and Other Key Employees
in Item 4, and Items 11 through 14 of Part III of
this Report is incorporated by reference from our definitive
proxy statement involving the election of directors and the
approval of independent auditors, which is to be filed pursuant
to Regulation 14A within 120 days after the end of our
fiscal year ended December 31, 2006.
PART IV
|
|
ITEM 15.
|
EXHIBITS AND
FINANCIAL STATEMENT SCHEDULES
|
(a) Financial Statements, Schedules and
Exhibits (1) Financial Statements Basic
Energy Services, Inc. and Subsidiaries:
The Financial Statements listed in the Index to Consolidated
Financial Statements are filed as part of this report on
Form 10-K
(see Part II,
Item 8-Financial
Statements and Supplementary Data).
(2) Financial Statement Schedules
With the exception of Schedule II Valuation and
Qualifying Accounts, all other consolidated financial statement
schedules have been omitted because they are not required, are
not applicable, or the required information has been included
elsewhere within this
Form 10-K.
82
(3) Exhibits
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
2
|
.1*
|
|
Agreement and Plan of Merger,
dated as of January 8, 2007, by and among Basic Energy
Services, Inc., JS Acquisition LLC and JetStar Consolidated
Holdings, Inc. (Incorporated by reference to Exhibit 2.1 of
the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on March 8, 2007)
|
|
2
|
.2*
|
|
Amendment to Merger Agreement,
dated as of March 5, 2007, by and among Basic Energy
Services, Inc., JS Acquisition LLC and JetStar Consolidated
Holdings, Inc. (Incorporated by reference to Exhibit 2.2 of
the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on March 8, 2007)
|
|
3
|
.1*
|
|
Amended and Restated Certificate
of Incorporation of the Company, dated September 22, 2005.
(Incorporated by reference to Exhibit 3.1 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
3
|
.2*
|
|
Amended and Restated Bylaws of the
Company, dated December 14, 2005. (Incorporated by
reference to Exhibit 3.1 to the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on December 14, 2005)
|
|
4
|
.1*
|
|
Specimen Stock Certificate
representing common stock of the Company. (Incorporated by
reference to Exhibit 3.1 of the Companys Registration
Statement on
Form S-1
(SEC File
No. 333-127517),
filed on November 4, 2005)
|
|
4
|
.2*
|
|
Indenture dated April 12,
2006, among Basic Energy Services, Inc., the guarantors party
thereto, and The Bank of New York Trust Company, N.A., as
trustee. (Incorporated by reference to Exhibit 4.1 of the
Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on April 13, 2006)
|
|
4
|
.3*
|
|
Form of 7.125% Senior Note
due 2016. (Incorporated by reference to Exhibit 4.2 of the
Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on April 13, 2006)
|
|
4
|
.4*
|
|
First Supplemental Indenture dated
as of July 14, 2006 to Indenture dated as of April 12,
2006 among the Company, as Issuer, the Subsidiary Guarantors
named therein and The Bank of New York Trust Company, N.A., as
trustee. (Incorporated by reference to Exhibit 4.1 of the
Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on July 20, 2006)
|
|
10
|
.1*
|
|
Form of Indemnification Agreement.
(Incorporated by reference to Exhibit 10.1 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.2*
|
|
Second Amended and Restated
Stockholders Agreement dated as of April 2, 2004
among the Company and the stockholders listed therein.
(Incorporated by reference to Exhibit 10.7 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on August 12, 2005)
|
|
10
|
.3*
|
|
Stock Purchase Agreement dated as
of September 18, 2003, as amended on October 1, 2003,
among the Company, FESCO Holdings, Inc. and the sellers named
therein. (Incorporated by reference to Exhibit 10.8 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on August 12, 2005)
|
|
10
|
.4*
|
|
Asset Purchase Agreement dated as
of August 14, 2003 among the Company and PWI, Inc.
(Incorporated by reference to Exhibit 10.9 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on August 12, 2005)
|
|
10
|
.5*
|
|
Fourth Amended and Restated Credit
Agreement dated as of October 3, 2003, amended and restated
as of February 6, 2007, among Basic Energy Services, Inc.,
the subsidiary guarantors party thereto, Bank of America, N.A.,
as syndication agent, Capital One, National Association, as
documentation agent, BNP Paribas, as documentation agent, UBS
AG, Stamford Branch, as issuing bank, administrative agent and
collateral agent, and the lenders party thereto. (Incorporated
by reference to Exhibit 10.1 to the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on February 12, 2007)
|
|
10
|
.6*
|
|
Second Amended and Restated 2003
Incentive Plan. (Incorporated by reference to Exhibit 10.11
of the Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on August 12, 2005)
|
|
10
|
.7*
|
|
Form of Non-Qualified Option Grant
Agreement (Executive Officer Pre-March 1,
2005). (Incorporated by reference to Exhibit 10.12 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
83
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
10
|
.8*
|
|
Form of Non-Qualified Option Grant
Agreement (Executive Officer Post-March 1,
2005). (Incorporated by reference to Exhibit 10.13 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.9*
|
|
Form of Non-Qualified Option Grant
Agreement (Non-Employee Director Pre-March 1,
2005). (Incorporated by reference to Exhibit 10.14 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.10*
|
|
Form of Non-Qualified Option Grant
Agreement (Non-Employee Director Post-March 1,
2005). (Incorporated by reference to Exhibit 10.15 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.11*
|
|
Form of Restricted Stock Grant
Agreement. (Incorporated by reference to Exhibit 10.16 of
the Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.12*
|
|
Form of Amendment to Nonqualified
Stock Option Agreement, dated as of December 31, 2005, by
and between the Company and the optionees party thereto.
(Incorporated by reference to Exhibit 3.1 to the
Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2006)
|
|
10
|
.13*
|
|
Form of Nonqualified Stock Option
Agreement (Director form effective March 2006). (Incorporated by
reference to Exhibit 10.7 to the Companys Quarterly
Report on
Form 10-Q
(SEC File
No. 001-32693),
filed on May 12, 2006)
|
|
10
|
.14*
|
|
Form of Nonqualified Stock Option
Agreement (Employee form effective March 2006). (Incorporated by
reference to Exhibit 10.8 to the Companys Quarterly
Report on
Form 10-Q
(SEC File
No. 001-32693),
filed on May 12, 2006)
|
|
10
|
.15*
|
|
Workover Unit Package Contract and
Acceptance Agreement, dated as of May 17, 2005, between
Basic Energy Services, L.P. and Taylor Rigs, LLC. (Incorporated
by reference to Exhibit 10.17 of the Companys
Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on November 4, 2005)
|
|
10
|
.16*
|
|
Share Exchange Agreement, dated as
of September 22, 2003, among BES Holding Co. and the
Stockholders named therein. (Incorporated by reference to
Exhibit 10.18 of the Companys Registration Statement
on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.17*
|
|
Form of Share Tender and
Repurchase Agreement. (Incorporated by reference to
Exhibit 10.19 of the Companys Registration Statement
on
Form S-1
(SEC File
No. 333-127517),
filed on November 4, 2005)
|
|
10
|
.18*
|
|
Workover Unit Package Contract and
Acceptance Agreement, dated as of November 10, 2005,
between Basic Energy Services, L.P. and Taylor Rigs, LLC.
(Incorporated by reference to Exhibit 10.20 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on November 16, 2005)
|
|
10
|
.19*
|
|
Asset Purchase Agreement dated as
of February 21, 2006 among Basic Energy Services, LP, Basic
Energy Services GP, LLC, G&L Tool, Ltd., DLH Management, LLC
and LJH, Ltd. (Incorporated by reference to Exhibit 10.1 of
the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on March 2, 2006)
|
|
10
|
.20*
|
|
Contingent Earn Out Agreement
dated as of February 28, 2006 among Basic Energy Services,
LP and G&L Tool, Ltd. (Incorporated by reference to
Exhibit 10.2 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on March 2, 2006)
|
|
10
|
.21*
|
|
Registration Rights Agreement
dated April 12, 2006, among the Company, the guarantors
party thereto and the initial purchasers party thereto.
(Incorporated by reference to Exhibit 10.2 of the
Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on April 13, 2006)
|
|
10
|
.22*
|
|
Summary of 2006 salaries and other
compensation for named executive officers and certain employees
(Incorporated by reference to Item 1.01 of the
Companys
Form 8-K
filed on March 8, 2006)
|
|
10
|
.23*
|
|
Fee Reimbursement Agreement, dated
as of July 24, 2006, by and among the Company, Southwest
Partners II, L.P., Southwest Partners, III, L.P. and
Fortress Holdings, LLC. (Incorporated by reference to
Exhibit 10.23 of the Companys Registration Statement
on
Form S-1
(SEC File
No. 333-136019),
filed on July 25, 2006)
|
84
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
10
|
.24*
|
|
Employment Agreement of Kenneth V.
Huseman, effective as of December 31, 2006. (Incorporated
by reference to Exhibit 10.1 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2007)
|
|
10
|
.25*
|
|
Employment Agreement of Alan
Krenek, effective as of December 31, 2006. (Incorporated by
reference to Exhibit 10.2 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2007)
|
|
10
|
.26*
|
|
Employment Agreement of Charles W.
Swift, effective as of December 31, 2006. (Incorporated by
reference to Exhibit 10.3 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2007)
|
|
10
|
.27*
|
|
Employment Agreement of Dub
William Harrison, effective as of December 31, 2006.
(Incorporated by reference to Exhibit 10.4 of the
Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2007)
|
|
10
|
.28*
|
|
Employment Agreement of James E.
Tyner, effective as of December 31, 2006. (Incorporated by
reference to Exhibit 10.5 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2007)
|
|
10
|
.29*
|
|
Employment Agreement of Thomas
Monroe Patterson, effective as of December 31, 2006.
(Incorporated by reference to Exhibit 10.6 of the
Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2007)
|
|
10
|
.30*
|
|
Employment Agreement of Mark David
Rankin, effective as of December 31, 2006. (Incorporated by
reference to Exhibit 10.7 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2007)
|
|
10
|
.31*
|
|
First Amendment to Employment
Agreement of Kenneth V. Huseman, effective as of
January 23, 2007. (Incorporated by reference to
Exhibit 10.1 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 29, 2007)
|
|
10
|
.32*
|
|
Registration Rights Agreement,
dated as of March 6, 2007, by and among Basic Energy
Services, Inc. and the JetStar Stockholders
Representative. (Incorporated by reference to Exhibit 10.1
of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on March 8, 2007)
|
|
21
|
.1
|
|
Subsidiaries of the Company
|
|
23
|
.1
|
|
Consent of KPMG LLP
|
|
31
|
.1
|
|
Certification by Chief Executive
Officer required by
Rule 13a-14(a)
and
15d-14(a)
under the Exchange Act
|
|
31
|
.2
|
|
Certification by Chief Financial
Officer required by
Rule 13a-14(a)
and
15d-14(a)
under the Exchange Act
|
|
32
|
.1
|
|
Certification by Chief Executive
Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
|
32
|
.2
|
|
Certification of Chief Financial
Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
|
|
|
* |
|
Incorporated by reference |
|
|
|
Management contract or compensatory plan or arrangement |
85
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.
BASIC ENERGY SERVICES, INC.
|
|
|
|
By:
|
/s/ Kenneth
V. Huseman
|
Name: Kenneth V. Huseman
|
|
|
|
Title:
|
President, Chief Executive Officer and
|
Director
Date: March 16, 2007
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
|
|
|
|
|
|
|
Signature
|
|
Date
|
|
|
|
/s/ Kenneth
V. Huseman
Kenneth
V. Huseman
|
|
President, Chief Executive Officer
and Director (Principal Executive Officer)
|
|
March 16, 2007
|
|
|
|
|
|
/s/ Alan
Krenek
Alan
Krenek
|
|
Chief Financial Officer
(Principal
Financial Officer and Principal
Accounting Officer)
|
|
March 16, 2007
|
|
|
|
|
|
/s/ Steven
A. Webster
Steven
A. Webster
|
|
Chairman of the Board
|
|
March 16, 2007
|
|
|
|
|
|
/s/ James
S.
DAgostino, Jr.
James
S. DAgostino, Jr.
|
|
Director
|
|
March 16, 2007
|
|
|
|
|
|
/s/ William
E. Chiles
William
E. Chiles
|
|
Director
|
|
March 16, 2007
|
|
|
|
|
|
/s/ Robert
F. Fulton
Robert
F. Fulton
|
|
Director
|
|
March 16, 2007
|
|
|
|
|
|
/s/ Sylvester
P. Johnson, IV
Sylvester
P. Johnson, IV
|
|
Director
|
|
March 16, 2007
|
|
|
|
|
|
/s/ H.H.
Wommack, III
H.H.
Wommack, III
|
|
Director
|
|
March 16, 2007
|
|
|
|
|
|
/s/ Thomas
P. Moore, Jr.
Thomas
P. Moore, Jr.
|
|
Director
|
|
March 16, 2007
|
86
EXHIBIT INDEX
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
2
|
.1*
|
|
Agreement and Plan of Merger,
dated as of January 8, 2007, by and among Basic Energy
Services, Inc., JS Acquisition LLC and JetStar Consolidated
Holdings, Inc. (Incorporated by reference to Exhibit 2.1 of
the Companys Current Report on
Form 8-K
(SEC File No. 001-32693), filed on March 8, 2007)
|
|
2
|
.2*
|
|
Amendment to Merger Agreement,
dated as of March 5, 2007, by and among Basic Energy
Services, Inc., JS Acquisition LLC and JetStar Consolidated
Holdings, Inc. (Incorporated by reference to Exhibit 2.2 of
the Companys Current Report on
Form 8-K
(SEC File No. 001-32693), filed on March 8, 2007)
|
|
3
|
.1*
|
|
Amended and Restated Certificate
of Incorporation of the Company, dated September 22, 2005.
(Incorporated by reference to Exhibit 3.1 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
3
|
.2*
|
|
Amended and Restated Bylaws of the
Company, dated December 14, 2005. (Incorporated by
reference to Exhibit 3.1 to the Companys Current
Report on
Form 8-K
(SEC File No. 001-32693), filed on December 14, 2005)
|
|
4
|
.1*
|
|
Specimen Stock Certificate
representing common stock of the Company. (Incorporated by
reference to Exhibit 3.1 of the Companys Registration
Statement on
Form S-1
(SEC File No.
333-127517),
filed on November 4, 2005)
|
|
4
|
.2*
|
|
Indenture dated April 12,
2006, among Basic Energy Services, Inc., the guarantors party
thereto, and The Bank of New York Trust Company, N.A., as
trustee. (Incorporated by reference to Exhibit 4.1 of the
Companys Current Report on
Form 8-K
(SEC File No. 001-32693), filed on April 13, 2006)
|
|
4
|
.3*
|
|
Form of 7.125% Senior Note
due 2016. (Incorporated by reference to Exhibit 4.2 of the
Companys Current Report on
Form 8-K
(SEC File No. 001-32693), filed on April 13, 2006)
|
|
4
|
.4*
|
|
First Supplemental Indenture dated
as of July 14, 2006 to Indenture dated as of April 12,
2006 among the Company, as Issuer, the Subsidiary Guarantors
named therein and The Bank of New York Trust Company, N.A., as
trustee. (Incorporated by reference to Exhibit 4.1 of the
Companys Current Report on
Form 8-K
(SEC File No. 001-32693), filed on July 20, 2006)
|
|
10
|
.1*
|
|
Form of Indemnification Agreement.
(Incorporated by reference to Exhibit 10.1 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.2*
|
|
Second Amended and Restated
Stockholders Agreement dated as of April 2, 2004
among the Company and the stockholders listed therein.
(Incorporated by reference to Exhibit 10.7 of the
Companys Registration Statement on
Form S-1
(SEC File No.
333-127517),
filed on August 12, 2005)
|
|
10
|
.3*
|
|
Stock Purchase Agreement dated as
of September 18, 2003, as amended on October 1, 2003,
among the Company, FESCO Holdings, Inc. and the sellers named
therein. (Incorporated by reference to Exhibit 10.8 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on August 12, 2005)
|
|
10
|
.4*
|
|
Asset Purchase Agreement dated as
of August 14, 2003 among the Company and PWI, Inc.
(Incorporated by reference to Exhibit 10.9 of the
Companys Registration Statement on
Form S-1
(SEC File No.
333-127517),
filed on August 12, 2005)
|
|
10
|
.5*
|
|
Fourth Amended and Restated Credit
Agreement dated as of October 3, 2003, amended and restated
as of February 6, 2007, among Basic Energy Services, Inc.,
the subsidiary guarantors party thereto, Bank of America, N.A.,
as syndication agent, Capital One, National Association, as
documentation agent, BNP Paribas, as documentation agent, UBS
AG, Stamford Branch, as issuing bank, administrative agent and
collateral agent, and the lenders party thereto. (Incorporated
by reference to Exhibit 10.1 to the Companys Current
Report on
Form 8-K
(SEC File No. 001-32693), filed on February 12, 2007)
|
|
10
|
.6*
|
|
Second Amended and Restated 2003
Incentive Plan. (Incorporated by reference to Exhibit 10.11
of the Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on August 12, 2005)
|
|
10
|
.7*
|
|
Form of Non-Qualified Option Grant
Agreement (Executive Officer Pre-March 1,
2005). (Incorporated by reference to Exhibit 10.12 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.8*
|
|
Form of Non-Qualified Option Grant
Agreement (Executive Officer Post-March 1,
2005). (Incorporated by reference to Exhibit 10.13 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
10
|
.9*
|
|
Form of Non-Qualified Option Grant
Agreement (Non-Employee Director Pre-March 1,
2005). (Incorporated by reference to Exhibit 10.14 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.10*
|
|
Form of Non-Qualified Option Grant
Agreement (Non-Employee Director Post-March 1,
2005). (Incorporated by reference to Exhibit 10.15 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.11*
|
|
Form of Restricted Stock Grant
Agreement. (Incorporated by reference to Exhibit 10.16 of
the Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.12*
|
|
Form of Amendment to Nonqualified
Stock Option Agreement, dated as of December 31, 2005, by
and between the Company and the optionees party thereto.
(Incorporated by reference to Exhibit 3.1 to the Companys
Current Report on
Form 8-K
(SEC File No. 001-32693), filed on January 4, 2006)
|
|
10
|
.13*
|
|
Form of Nonqualified Stock Option
Agreement (Director form effective March 2006). (Incorporated by
reference to Exhibit 10.7 to the Companys Quarterly Report
on
Form 10-Q
(SEC File No. 001-32693), filed on May 12, 2006)
|
|
10
|
.14*
|
|
Form of Nonqualified Stock Option
Agreement (Employee form effective March 2006). (Incorporated by
reference to Exhibit 10.8 to the Companys Quarterly Report
on
Form 10-Q
(SEC
File No. 001-32693),
filed on May 12, 2006)
|
|
10
|
.15*
|
|
Workover Unit Package Contract and
Acceptance Agreement, dated as of May 17, 2005, between
Basic Energy Services, L.P. and Taylor Rigs, LLC. (Incorporated
by reference to Exhibit 10.17 of the Companys
Registration Statement on
Form S-1
(SEC File No.
333-127517),
filed on November 4, 2005)
|
|
10
|
.16*
|
|
Share Exchange Agreement, dated as
of September 22, 2003, among BES Holding Co. and the
Stockholders named therein. (Incorporated by reference to
Exhibit 10.18 of the Companys Registration Statement
on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.17*
|
|
Form of Share Tender and
Repurchase Agreement. (Incorporated by reference to
Exhibit 10.19 of the Companys Registration Statement
on
Form S-1
(SEC File
No. 333-127517),
filed on November 4, 2005)
|
|
10
|
.18*
|
|
Workover Unit Package Contract and
Acceptance Agreement, dated as of November 10, 2005,
between Basic Energy Services, L.P. and Taylor Rigs, LLC.
(Incorporated by reference to Exhibit 10.20 of the
Companys Registration Statement on
Form S-1
(SEC File No.
333-127517),
filed on November 16, 2005)
|
|
10
|
.19*
|
|
Asset Purchase Agreement dated as
of February 21, 2006 among Basic Energy Services, LP, Basic
Energy Services GP, LLC, G&L Tool, Ltd., DLH Management, LLC
and LJH, Ltd. (Incorporated by reference to Exhibit 10.1 of
the Companys Current Report on
Form 8-K
(SEC File No. 001-32693), filed on March 2, 2006)
|
|
10
|
.20*
|
|
Contingent Earn Out Agreement
dated as of February 28, 2006 among Basic Energy Services,
LP and G&L Tool, Ltd. (Incorporated by reference to
Exhibit 10.2 of the Companys Current Report on
Form 8-K
(SEC File No. 001-32693), filed on March 2, 2006)
|
|
10
|
.21*
|
|
Registration Rights Agreement
dated April 12, 2006, among the Company, the guarantors
party thereto and the initial purchasers party thereto.
(Incorporated by reference to Exhibit 10.2 of the
Companys Current Report on
Form 8-K
(SEC File No. 001-32693), filed on April 13, 2006)
|
|
10
|
.22*
|
|
Summary of 2006 salaries and other
compensation for named executive officers and certain employees
(Incorporated by reference to Item 1.01 of the
Companys
Form 8-K
filed on March 8, 2006)
|
|
10
|
.23*
|
|
Fee Reimbursement Agreement, dated
as of July 24, 2006, by and among the Company, Southwest
Partners II, L.P., Southwest Partners, III, L.P. and
Fortress Holdings, LLC. (Incorporated by reference to
Exhibit 10.23 of the Companys Registration Statement
on
Form S-1
(SEC File
No. 333-136019),
filed on July 25, 2006)
|
|
10
|
.24*
|
|
Employment Agreement of Kenneth V.
Huseman, effective as of December 31, 2006. (Incorporated
by reference to Exhibit 10.1 of the Companys Current
Report on
Form 8-K
(SEC File No. 001-32693), filed on January 4, 2007)
|
|
10
|
.25*
|
|
Employment Agreement of Alan
Krenek, effective as of December 31, 2006. (Incorporated by
reference to Exhibit 10.2 of the Companys Current
Report on
Form 8-K
(SEC File No. 001-32693), filed on January 4, 2007)
|
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
10
|
.26*
|
|
Employment Agreement of Charles W.
Swift, effective as of December 31, 2006. (Incorporated by
reference to Exhibit 10.3 of the Companys Current
Report on
Form 8-K
(SEC File No. 001-32693), filed on January 4, 2007)
|
|
10
|
.27*
|
|
Employment Agreement of Dub
William Harrison, effective as of December 31, 2006.
(Incorporated by reference to Exhibit 10.4 of the
Companys Current Report on
Form 8-K
(SEC File No. 001-32693), filed on January 4, 2007)
|
|
10
|
.28*
|
|
Employment Agreement of James E.
Tyner, effective as of December 31, 2006. (Incorporated by
reference to Exhibit 10.5 of the Companys Current
Report on
Form 8-K
(SEC File No. 001-32693), filed on January 4, 2007)
|
|
10
|
.29*
|
|
Employment Agreement of Thomas
Monroe Patterson, effective as of December 31, 2006.
(Incorporated by reference to Exhibit 10.6 of the
Companys Current Report on
Form 8-K
(SEC File No. 001-32693), filed on January 4, 2007)
|
|
10
|
.30*
|
|
Employment Agreement of Mark David
Rankin, effective as of December 31, 2006. (Incorporated by
reference to Exhibit 10.7 of the Companys Current
Report on
Form 8-K
(SEC File No. 001-32693), filed on January 4, 2007)
|
|
10
|
.31*
|
|
First Amendment to Employment
Agreement of Kenneth V. Huseman, effective as of
January 23, 2007. (Incorporated by reference to
Exhibit 10.1 of the Companys Current Report on
Form 8-K
(SEC File No. 001-32693), filed on January 29, 2007)
|
|
10
|
.32*
|
|
Registration Rights Agreement,
dated as of March 6, 2007, by and among Basic Energy
Services, Inc. and the JetStar Stockholders
Representative. (Incorporated by reference to Exhibit 10.1
of the Companys Current Report on
Form 8-K
(SEC File No. 001-32693), filed on March 8, 2007)
|
|
21
|
.1
|
|
Subsidiaries of the Company
|
|
23
|
.1
|
|
Consent of KPMG LLP
|
|
31
|
.1
|
|
Certification by Chief Executive
Officer required by
Rule 13a-14(a)
and
15d-14(a)
under the Exchange Act
|
|
31
|
.2
|
|
Certification by Chief Financial
Officer required by
Rule 13a-14(a)
and
15d-14(a)
under the Exchange Act
|
|
32
|
.1
|
|
Certification by Chief Executive
Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
|
32
|
.2
|
|
Certification of Chief Financial
Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
|
|
|
* |
|
Incorporated by reference |
|
|
|
Management contract or compensatory plan or arrangement |