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 |
For the fiscal year ended December 31, 2005
OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934 |
For the transition period from to
Commission File No. 001-32693
Basic Energy Services, Inc.
(Exact name of registrant as specified in its charter)
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Delaware
(State or other jurisdiction of incorporation or organization)
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54-2091194
(I.R.S. Employer Identification No.) |
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400 W. Illinois, Suite 800
Midland, Texas
(Address of principal executive offices)
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79701
(Zip code) |
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
(Title of Class)
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New York Stock Exchange
(Name of each exchange on which registered) |
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 o Non-Accelerated Filer þ
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 $407,580,173 as of
March 20, 2006 (based on a closing price of $26.99
per share and
15,101,155 shares held by non-affiliates).
33,706,703 shares of the registrants Common Stock were outstanding as of March 20, 2006.
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
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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. |
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 Oil & Gas Journal magazine, 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.
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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 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 12% of
the overall available U.S. fleet, with our two larger competitors controlling approximately 32% and
19%, 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 (48% of our revenues in 2005)
currently operates our fleet of over 320 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 (29% of our revenues in 2005)
currently utilizes our fleet of over 475 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 (13% of our revenues in 2005) currently operates our fleet of 56 pressure pumping
units, 25 air compressor packages specially configured for underbalanced drilling
operations and 12 cased-hole wireline units. These services are designed to initiate or
stimulate oil and gas production. 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 (10% of our revenues in 2005) currently utilizes our fleet of over 200 operated
power units, which include 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. |
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 320 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
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range of services performed on a well throughout its life, such as completion, maintenance,
workover and plugging and abandonment services.
Modern and Active Fleet. We operate a modern and active fleet of well servicing rigs. We
believe over 95% of the active U.S. well servicing rig fleet was built prior to 1985. Approximately
86 of our rigs at December 31, 2005 were either 2000 model year or newer, or have undergone major
refurbishments during the last four years. As of December 31, 2005, we have taken delivery of 35
newbuild well servicing rigs since October 2004 as part of a
102-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 46 of our rigs since the beginning of 2001. Approximately 98% of our fleet
was active or available for work and the remainder was awaiting refurbishment at December 31, 2005.
We believe only approximately 66% of the well servicing rig fleet of our two major competitors are
active and available for work. 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
and Louisiana and the Rocky Mountain states. We operate in states that accounted for approximately 57%
of the approximately 900,000 existing onshore oil and gas wells in the 48 contiguous states and
approximately 77% of onshore oil production and 72% of onshore gas production in 2005. 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 71 service locations 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 seven regional 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 28 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 seven
regional or product line managers, our 66 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
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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 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, as demonstrated by our 2003
acquisitions of FESCO Holdings, Inc., PWI Inc. and New Force Energy Services, Inc., which expanded
our exposure to the active drilling environment of the Rocky Mountain states, the active well
services and drilling markets along the Gulf Coast and the pressure pumping business, respectively.
Additionally, in December 2004 we expanded our presence along the Gulf Coast with the acquisition
of three inland barges, two of which have been refurbished and were available for service in the
second quarter of 2005.
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 2005, we completed eight separate acquisitions for an aggregate purchase price
of $25.4 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 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, total expenditures for all
U.S. exploration and production activities (including offshore activities that we do
not serve) increased to an estimated $56 billion in 2003 and $62 billion in 2004 and
were expected to reach $66 billion in 2005, according to Oil & Gas Journal in April
2005. |
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A survey of 18 U.S. major integrated and 130 independent oil and gas companies by
World Oil Magazine projected the U.S. drilling activity in 2006 to be skewed more
towards independent players. Specifically, independent oil and gas
companies, which represent
over 90% of our revenues, are expected to drill almost 33% more wells
in 2006 than in
2005, while the major integrated producers are expected to drill only 16%
more wells over the same period. This trend is primarily driven by the increased acquisitions of proved oil and
gas properties by independent producers. When these types of properties are acquired,
purchasers typically intensify drilling, workover and well maintenance activities to
accelerate production from the newly acquired reserves. |
Increased spending by oil and gas operators is generally driven by oil and gas prices. The
table below sets forth average daily closing prices for the Cushing WTI Spot Oil Price and the
Energy Information Agency average wellhead price for natural gas since 1999:
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Cushing WTI Spot |
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Average Wellhead Price |
Period |
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Oil Price ($/bbl) |
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Natural Gas ($/mcf) |
1/1/99 - 12/31/99 |
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$ |
19.34 |
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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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7.28 |
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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 36% from year-end 2002
to year-end 2003, 11% from year-end 2003 to year-end 2004, and 22% from year-end 2004 to year-end
2005. In addition, the U.S. land-based workover rig count increased approximately 13% from year-end
2002 to year-end 2003, 10% from year-end 2003 to year-end 2004, and 17% from year-end 2004 to
year-end 2005, 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 expenditure spending tends 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 short 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.
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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.
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. |
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 323 well service rigs as of December 31, 2005, including 35 newbuilds since
October 2004 and 46 rebuilds since the beginning of 2001. We operate from more than 70 facilities
in Texas, Wyoming, Oklahoma, North Dakota, New Mexico, Louisiana, Colorado and Montana, most of
which are used jointly for our business segments. 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 are equipped with rigs, have been refurbished and
were placed into service in the second quarter of 2005. 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, 2005. 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 67 new well
servicing rigs that we have contracted for delivery from January 2006 through December 2007 as part
of a 102-rig newbuild commitment:
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Operating Division |
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Rated |
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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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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 |
Swab |
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N/A |
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3 |
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1 |
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8 |
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4 |
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0 |
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0 |
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0 |
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16 |
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Light Duty |
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<90 tons |
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6 |
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2 |
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0 |
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24 |
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2 |
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0 |
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3 |
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37 |
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Medium Duty |
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>90-<125 tons |
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91 |
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33 |
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17 |
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38 |
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15 |
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14 |
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1 |
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209 |
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Heavy Duty |
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³ 125 tons |
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27 |
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3 |
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6 |
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5 |
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6 |
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3 |
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2 |
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52 |
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24-Hour |
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³125 tons |
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1 |
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4 |
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0 |
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0 |
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0 |
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0 |
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0 |
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5 |
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Drilling Rigs |
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³125 tons |
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0 |
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0 |
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0 |
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0 |
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0 |
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2 |
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0 |
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2 |
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Inland Barge |
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³125 tons |
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0 |
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0 |
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2 |
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0 |
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0 |
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0 |
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0 |
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2 |
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Total |
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128 |
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43 |
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33 |
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|
71 |
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|
23 |
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|
19 |
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6 |
|
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|
323 |
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6
Management currently estimates that there are approximately 3,500 onshore well servicing 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 20% lower than
this estimate. Based on information from U.S. contractors reporting their utilization to
Weatherford-AESC, there were 2,671 well servicing rigs working in December 2005. This figure
represents a projected utilization rate of 90% 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 own a
combined 2,047 rigs of which 1,346 are operated and 701 are stacked. These two competitors total
rigs represent approximately 58% of the industrys total fleet. We have the third-largest fleet
with over 320 rigs, or over 10% of the overall 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 50 rigs (with a total of only 134 rigs) and a total of an estimated 120
companies own the approximately 900 estimated remaining well servicing rigs, or approximately 26%
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
7
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
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:
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transportation of fluids used in drilling and workover operations and of
salt water produced as a by-product of oil and gas production; |
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sale and transportation of fresh and brine water used in drilling and workover activities; |
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rental of portable frac tanks and test tanks used to store fluids on well sites; and |
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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, 2005:
8
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Operating Division |
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Northern |
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Permian |
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Ark-La- |
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South |
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Mid- |
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Rockies |
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Basin |
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Tex |
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Texas |
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Continent |
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Total |
Fluid Services Trucks |
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87 |
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122 |
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112 |
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118 |
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38 |
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477 |
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Salt Water Disposal Wells |
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12 |
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10 |
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9 |
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8 |
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39 |
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Fresh/Brine Water Stations |
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28 |
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3 |
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1 |
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32 |
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Fluid Storage Tanks |
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219 |
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265 |
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422 |
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248 |
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71 |
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1,225 |
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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 and Support Trucks. We currently own and operate over 475 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. Our hot oil
trucks are used to remove paraffin, a by-product of oil production in many fields, from the well
bore. If paraffin is
9
left untreated, it can inhibit a wells production. Our support trucks are used to move our
fluid storage tanks and other equipment to and from the job sites of our customers.
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.
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.
These locations also allows us to expand our customer base.
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 water, brine,
drilling mud 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 10 to 40 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:
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niche pressure pumping, such as cementing, acidizing, fracturing, coiled tubing and pressure testing; |
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cased-hole wireline services; and |
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underbalanced drilling in low pressure and fluid sensitive reservoirs. |
This segment currently operates 56 pressure pumping units 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, 2005, we also operated 25 air compressor packages,
including foam circulation units, for underbalanced drilling and 12 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
10
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.
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 on single-truck, lower horsepower cementing, acidizing
and fracturing services in niche 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, 2005:
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Operating Division |
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Northern |
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Southern |
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Ark-La-Tex |
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Mid-Continent |
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Rockies |
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Rockies |
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Total |
Pressure Pumping Units |
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12 |
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41 |
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3 |
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56 |
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Coiled Tubing Units |
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3 |
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3 |
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Air/Foam Packages |
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25 |
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25 |
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Wireline Units |
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12 |
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12 |
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Currently, there are only three pressure pumping companies that provide their services on a
national basis. These three companies also control a majority of the activities in the U.S. market.
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
11
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 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.
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. |
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 division 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. We believe that our existing infrastructure
will allow us to expand these operations.
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.
12
Properties
Our principal executive offices are currently located at 400 W. Illinois, Suite 800,
Midland, Texas 79701. During 2005 we also purchased and are currently renovating a facility in
Midland County, Texas to consolidate our corporate office and to expand our refurbishment
capacities. We currently conduct our business from 71 area offices, 32 of which we own and 39 of
which we lease. Each office typically includes a yard, administrative office and maintenance
facility. Of our 71 area offices, 45 are located in Texas, five are in Wyoming, eight are in
Oklahoma, three are in New Mexico, three are in Louisiana, three are in Colorado, two are in
Montana and two are in North Dakota.
Customers
We serve numerous major and independent oil and gas companies that are active in our core
areas of operations. During 2005, we provided services to more than 1,000 customers, with our top
five customers comprising only 16% 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. |
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.
13
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 59% of the U.S. total 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 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 well site servicing 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.
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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.
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 are in the process of updating SPCC plans for several of our facilities and
currently expect to complete and implement these plans by the end of 2005. 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
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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 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, 2005, we employed approximately 3,280 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.
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ITEM 1A. RISK FACTORS
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 prices
exceeding $60 per barrel and $14.00 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
$31.08, $41.51 and $56.64 per barrel in 2003, 2004 and 2005, respectively, and the average wellhead
price for natural gas, as recorded by the Energy Information Agency, was $4.98, $5.49 and $7.28 per
mcf for 2003, 2004 and 2005, respectively. Commodity prices have increased significantly in recent
years, and these prices may not remain at current levels.
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
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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.
Our auditors have previously identified material weaknesses in our internal controls, and if we
fail to develop or maintain an effective system of internal controls, we may not be able to
accurately report our financial results or prevent fraud. As a result, investors could lose
confidence in our financial reporting, which would harm our business and the trading price of our
common stock.
Effective internal controls, including internal control over financial reporting and
disclosure controls and procedures, are necessary for us to provide reliable financial reports and
effectively prevent fraud and to operate successfully as a public company. If we cannot provide
reliable financial reports or prevent fraud, our reputation and operating results could be
materially harmed. We have in the past discovered, and may in the future discover, areas of our
internal controls that need improvement.
In July 2004, our independent auditors advised our board of directors that they had identified
material weaknesses in our internal controls in connection with the audit of our 2003 consolidated
financial statements. The material weaknesses noted consisted of an inadequacy of our procedures or
errors regarding account reconciliations not being performed timely or properly; formal procedures
for establishing certain accounting assumptions, estimates and/or conclusions; and recording of
certain expenses in the incorrect period. Our auditors also noted certain other items specific to
our operations that they did not consider to be material weaknesses.
To improve our financial accounting organization and processes, we have established an
internal audit department and have added new personnel and positions in our accounting and finance
organization. We also implemented a new accounting software system throughout our operations during
the third quarter of 2004 and adopted additional policies and procedures to address the items noted
by our auditors and generally to strengthen our financial reporting system. We believe that as of
December 31, 2005, we have remediated the material weaknesses
previously identified. However, the process of designing and implementing an effective financial reporting system is a continuous
effort that requires us to anticipate and react to changes in our business and the economic and
regulatory environments and to expend significant resources to maintain a financial reporting
system that is adequate to satisfy our reporting obligations.
We have had only limited operating experience with the improvements we have made to date. We
may not be able to implement and maintain adequate controls over our financial processes and
reporting in the future, which may require us to restate our financial statements in the future. In
addition, we may discover additional past, ongoing or future weaknesses or significant deficiencies
in our financial reporting system in the future. Any failure to implement required new or improved
controls, or difficulties encountered in their implementation, could cause us to fail to meet our
reporting obligations or result in material misstatements in our financial statements. Any such
failure also could adversely affect the results of the periodic management evaluations and annual
auditor attestation reports regarding the effectiveness of our internal control over financial
reporting that will be required when the SECs rules under Section 404 of the Sarbanes Oxley Act
of 2002 become applicable to us beginning with our Annual Report on Form 10-K for the year ending
December 31, 2006 to be filed in the first quarter of 2007. Inferior internal controls could also
cause investors to lose confidence in our reported financial information, which could result in a
lower trading price of our common stock.
We may require additional capital in the future, which may not be available to us.
Our business is capital intensive, requiring specialized equipment to provide our services. We
may need to raise additional funds through public or private debt or equity financings. Adequate
funds may not be available when needed or may not be available on favorable terms. If we raise
additional funds by issuing equity securities, dilution to existing stockholders may result. If
funding is insufficient at any time in the future, we may be unable to fund maintenance
requirements, acquisitions, take advantage of business opportunities or respond to competitive
pressures, any of which could harm our business.
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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 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 2004, our top five customers accounted for 15.9% and 20.7%, 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 102-rig commitment for rigs to be delivered through the end
of December 2007, of which 35 rigs have been delivered as of
December 31, 2005. 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 other than coverage of $1 million for Mr. Huseman.
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. |
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 of our employees and,
with certain exceptions, we generally maintain no physical property
damage coverage on our workover rig fleet, with the exception 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 $125,000,
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 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 rise
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, 2005, our total debt, the majority of which bears interest at variable rates, was $126.9
million, including the aggregate principal amount due under the term loan portion of our senior
credit facility of $90.0 million, outstanding balance due under credit revolver of $16.0 million and
capital lease obligations in the aggregate amount of $20.9 million. For the year ended December 31,
2005, we made cash interest payments totaling $11.6 million. The
impact of a 1% increase in interest rates on this amount of debt
would result in increased
interest expense (excluding the effects of our interest
rate hedges) of approximately $1.1 million annually, or a
decrease in net income of approximately $687,000.
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. |
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 existing credit facility imposes restrictions on us that may affect our ability to successfully
operate our business.
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Our senior credit facility limits our ability to take various actions, such as: |
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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; and |
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limitation on dividends and distributions. |
In addition, our senior 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. 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 senior credit facility. Please read Managements Discussion and Analysis of Financial
Condition and Results of Operations Liquidity and Capital Resources Credit Facilities 2005
Credit Facility for a discussion of our senior credit facility.
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 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
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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
DLJ Merchant Banking effectively controls the outcome of stockholder voting and may exercise
this voting power in a manner adverse to our other stockholders.
As of Janurary 26, 2006, DLJ Merchant Banking effectively owned approximately 47.4% of our
outstanding common stock. Accordingly, DLJ Merchant Banking is in a position to effectively control
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. Please read Security Ownership of Certain Beneficial Owners and
Management for a discussion of DLJ Merchant Bankings ownership interests in us and Certain
Relationships and Related Party Transactions Transactions with DLJ Merchant Banking for a
description of DLJ Merchant Banking.
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:
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a classified board of directors, so that only approximately one-third of our
directors are elected each year; |
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limitations on the removal of directors; |
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the prohibition of stockholder action by written consent; and |
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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
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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.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
On September 3, 2004, David Hudson, Jr. et al commenced a civil action against us in the
District Court of Panola County, Texas, 123rd Judicial District, David Hudson, Jr., et
al v. Basic Energy Services Company, Cause No. 2004-A-137. The complaint alleges that our operation
of a saltwater disposal well has contaminated both the groundwater and the soil in the surrounding
area. The relief requested in the complaint is monetary damages, injunctive relief, environmental
remediation and a court order requiring us to provide drinking water to the community. In response
to the complaint, we have retained counsel and filed a general denial. We are in the beginning
stages of discovery and settlement negotiations are underway. Should negotiations fail, we intend
to defend ourselves vigorously in this action.
On October 18, 2005, Clifford Golden et al. commenced a civil action against us in the 123rd
Judicial District Court of Panola County, Texas, Clifford Golden et al. v. Basic Energy Services,
LP. The factual basis for this complaint and relief are similar to the Hudson litigation,
including claims that our operation of a saltwater disposal well has contaminated both the
groundwater and the soil in the surrounding area. In addition, this complaint alleges a wrongful
death and personal injuries to unspecified persons. In response to this complaint, we have retained
counsel and intend to defend ourselves vigorously in this action.
On December 6, 2004, Karon Smith, et al commenced a civil action against us in the District
Court of Hidalgo County, Texas, 206th Judicial District, Karon Smith, et al v. Basic Energy
Services GP L.L.C., Cause No. C-42767-04-D. The complaint alleged that (i) one of our fluid
services truck drivers disposed of oil-based waste at the plaintiffs waste disposal facility,
which was not equipped to accept oil-based waste, and (ii) the disposal of such oil-based waste
resulted in plaintiffs facility losing contracts to accept waste. On July 25, 2005, the jury in
this case returned a verdict in favor of the plaintiff and awarded damages in the amount of $1.2
million. Our insurance company denied coverage of liability in this lawsuit. In March 2006, we
believe that we reached a settlement of this matter in connection
with a mediation for $1.0 million, which we have accrued as of December 31, 2005.
We are pursuing coverage claims with our insurer.
We are subject to other claims in the ordinary course of business. However, we believe that
the ultimate dispositions of the above mentioned and other current legal proceedings will not have
a material adverse effect on our financial condition or results of operations.
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.
23
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,
2005 and their respective ages and positions are as
follows:
|
|
|
|
|
|
|
Name |
|
Age |
|
Position |
Kenneth V. Huseman
|
|
|
54 |
|
|
President, Chief Executive Officer and Director |
James J. Carter
|
|
|
60 |
|
|
Executive Vice President and Secretary |
Alan Krenek
|
|
|
50 |
|
|
Vice President, Chief Financial Officer and Treasurer |
Dub W. Harrison
|
|
|
47 |
|
|
Vice President Equipment & Safety |
Mark D. Rankin
|
|
|
52 |
|
|
Vice President Business Development |
James E. Tyner
|
|
|
55 |
|
|
Vice President Human Resources |
Charles W. Swift
|
|
|
56 |
|
|
Vice President Permian Basin |
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 27 years of well
servicing experience. He has been our President, Chief Executive Officer and Director since 1999.
Prior to joining us, he was Chief Operating Officer at Key Energy Services from 1996 to 1999. At
Key Energy Services, Mr. Huseman expanded the number of rigs from less than 200 to 1,400, the
shallow drilling business from 4 to 78 rigs and executed over 50 acquisitions. He was a Divisional
Vice President at WellTech, Inc., from 1993 to 1996 where he closed two acquisitions for a total of
42 rigs, moved WellTech from the second largest to the largest player in the market and started a
turnaround of operations in Argentina. He was a Vice President of Operations at Pool Energy
Services Co. from 1982 to 1993, 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.
James J. Carter (Executive Vice President and Secretary) has spent 24 years in the well services
industry. He has been our Executive Vice President since
January 2005. He served as our Chief
Financial Officer from December 2000 until January 2005. From 1999 to 2000, Mr. Carter worked in a
consulting and brokerage capacity, with a well services industry specialization. He worked at
another well servicing company in financial management from 1996 to 1999, where he managed the
financial turnaround of its Argentina operations, negotiated and closed acquisitions in various
domestic markets and negotiated insurance coverages and vehicle leases. He worked in financial
management positions at Pool Energy Services Co. from 1978 to 1993, where he managed operations
analysis and financial support at the corporate level and managed financial operations in
California and south Texas. Mr. Carter graduated with a B.S. degree in Accounting from Indiana
University and an M.B.A. from Memphis University.
Alan Krenek (Vice President, Chief Financial Officer and Treasurer) has 17 years of related
industry experience. He has been our Vice President, Chief Financial Officer and Treasurer since
January 2005. 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. From December 1999 to November 2001,
he acted as the Vice President of Finance and later the Chief Financial Officer of Digital Commerce
Corporation, a business-to-government internet-based marketplace solutions company that filed for
Chapter 11 bankruptcy protection in June 2001. From January 1997 to December 1999, Mr. Krenek was
the Vice President, Finance of Global TeleSystems, Inc. From September 1995 to December 1996, he
served as Corporate Controller of Landmark Graphics Corporation where he was responsible for SEC
reporting, general accounting, financial policies and procedures and purchasing functions. 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.
Dub W. Harrison (Vice President Equipment & Safety) has spent 29 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 28 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. 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 December 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. and M.S. from Mississippi State University.
Charles W. Swift (Vice President Permian) has 33 years of related industry experience including
25 years specifically in the domestic well service business. He has been 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 the well service and fluid services businesses. Mr. Swift graduated with a B.B.A. degree
in International Trade from Texas Tech University.
24
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 fourth quarter of 2005.
|
|
|
|
|
|
|
|
|
|
|
High |
|
Low |
Three Months Ended |
|
|
|
|
|
|
|
|
December 31, 2005. |
|
$ |
22.00 |
|
|
$ |
19.20 |
|
As
of March 20, 2006, we had 33,706,703 shares of common stock outstanding held by
approximately 42 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, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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) |
|
|
2,445,800 |
|
|
$ |
5.44 |
|
|
|
1,727,950 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity compensation plans not
approved by security holders |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
2,445,800 |
|
|
$ |
5.44 |
|
|
|
1,727,950 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Consists of the Basic Energy Services, Inc. Second Amended
and Restated 2003 Incentive Plan (as amended effective April 22, 2005) |
25
Recent Sales of Unregistered Securities
During the past three years, we have issued unregistered securities to a limited number
of persons, as described below. None of these transactions involved any underwriters or public
offerings, and we believe that each of these transactions was exempt from registration requirements
pursuant to Section 3(a)(9) or Section 4(2) of the Securities Act of 1933, as amended, Regulation D
promulgated thereunder or Rule 701 of the Securities Act of 1933. The recipients of these
securities represented their intention to acquire the securities for investment only and not with a
view to or for sale in connection with any distribution thereof, and appropriate legends were
affixed to the share certificates and instruments issued in these transactions. No remuneration or
commission was paid or given directly or indirectly. The following information gives effect to a
5-for-1 stock split effected as a stock dividend on September 26, 2005:
On January 24, 2003, we issued one share of our common stock in exchange for each share of
then-outstanding common stock of our predecessor, Basic Energy Services, Inc., and shares of our
Series A 10% Cumulative Preferred Stock in exchange for all of the then-outstanding shares of its
Series A 10% Cumulative Preferred Stock, and assumed all of the outstanding warrants and options
then outstanding by this predecessor.
On May 5, 2003, we issued an aggregate of 771,740 shares of common stock upon the exercise of
all of our EBITDA Contingent Warrants, which were issued during December 2000 and August 2001 to
our prior stockholders and certain members of management for aggregate consideration of $1,543.48.
On May 5, 2003, we granted options to purchase an aggregate of 605,000 shares of common stock
under our Amended and Restated 2003 Incentive Plan to employees and directors at an exercise price
of $4.00 per share. We received no payments from the optionees upon issuance of the options.
On October 1, 2003, we granted options to purchase an aggregate of 37,500 shares of common
stock under our 2003 Incentive Plan to a new director at an exercise price of $5.1584 per share. We
received no payments from the optionee upon issuance of the options.
On October 3, 2003, we issued an aggregate of 3,650,000 shares of common stock, including
730,000 shares of common stock issued into escrow, to the former stockholders of FESCO Holdings,
Inc. as consideration for all of the outstanding shares of FESCO Holdings, Inc. The implied value
per share in connection with the share exchange was $5.1584 per share.
On October 3, 2003, we issued an aggregate of 3,304,085 shares of common stock in exchange for
all of the outstanding shares of our Series A 10% Cumulative Preferred Stock and accrued dividends.
The implied value per share in connection with the share exchange was $5.1584 per share.
On February 23, 2004, our board of directors approved the issuance of 837,500 shares of
restricted stock to our officers under our 2003 Incentive Plan. These shares, as issued effective
April 22, 2004 after stockholder approval of our Amended and Restated 2003 Incentive Plan, are
subject to vesting in one-fourth increments for all officers other than Mr. Carter on February 24,
2005, 2006, 2007 and 2008, and with respect to shares owned by Mr. Carter, vesting one-half on
February 24, 2005 and 2006. We received no payments from the recipients upon the issuance of these
shares.
On March 1, 2004, we granted options to purchase an aggregate of 37,500 shares of common stock
under our 2003 Incentive Plan to a new director at an exercise price of $5.1584 per share. We
received no payments from the optionee upon issuance of the options.
On March 23, 2004, we granted options to purchase an aggregate of 50,000 shares of common
stock under our Amended and Restated 2003 Incentive Plan to employees at an exercise price of
$5.1584. We received no payments from optionees upon issuance of the options.
26
On January 26, 2005, we granted options to purchase an aggregate of 100,000 shares of common
stock under our Amended and Restated 2003 Incentive Plan to a new executive officer at an exercise
price of $5.1584. We received no payment from the optionee upon the issuance of the options.
On March 2, 2005, we granted options to purchase an aggregate of 865,000 shares of common
stock under our Amended and Restated 2003 Incentive Plan to employees at an exercise price of
$6.98.
On May 16, 2005, we granted options to purchase an aggregate of 5,000 shares of common stock
under our Amended and Restated 2003 Incentive Plan to employees at an exercise price of $6.98.
On December 16, 2005 we granted options to purchase an aggregate of 37,500 shares of common
stock under our Amended and Restated 2003 Incentive Plan to a new director at an exercise price of
$21.01.
Use of Proceeds from Registered Securities
In connection with our initial public offering, we issued and sold 5,000,000 shares of
our common stock, par value $0.01 per share, at $20.00 per share, generating aggregate offering
proceeds of $100.0 million. Further, selling stockholders sold 9,375,000 shares of our common stock
at $20.00 per share, generating aggregate offering proceeds to the selling stockholders of $187.5
million. The shares were issued pursuant to a registration statement on Form S-1 (File No.
333-127517) which was declared effective, as amended, on December 8, 2005. The registration
statement registered an aggregate of 14,375,000 shares of common stock at an aggregate offering
price of $287.5 million. Of these shares, 9,375,000 shares (representing $187.5 million of the
dollar amount registered) were registered on behalf of selling stockholders (including 1,875,000
shares subject to an option granted to the underwriters to cover over-allotments, if any) and
5,000,000 shares (representing $100.0 million of the dollar amount registered) were registered on
our behalf. The over-allotment option was exercised in full prior to the closing of the offering.
The offering of the common stock commenced on December 8, 2005 and 14,375,000 of the
registered shares were sold. The underwriters were led by Goldman, Sachs & Co. and Credit Suisse
First Boston LLC. The net cash proceeds to us from the sale of these shares was $91.5 million,
after deducting underwriting discounts and commissions of $6.5 million and total other offering
costs and expenses of approximately $2.0 million (for a total of $8.5 million in offering
expenses). The offering terminated after all the securities registered were sold.
We have used our net proceeds from the initial public offering: (i) to repay $70.0 million of
the term loan under our credit facility; (ii) to repurchase 135,326 shares of our common stock at
the initial offering price, less underwriting discounts and commissions, from nine officers on the
closing date of the initial public offering for an aggregate price of approximately $2.5 million;
and (iii) for working capital and general corporate purposes, with respect to the remaining
proceeds of approximately $19.0 million.
27
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table summarizes stock repurchase activity for the three months ended
December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuer Purchases of Equity Securities |
|
|
Total |
|
Average |
|
|
|
|
|
Maximum number of |
|
|
number of |
|
price |
|
Total number of share |
|
shares that may yet be |
|
|
shares |
|
paid per |
|
s purchased as part of |
|
purchased under the |
Period |
|
purchased(1) |
|
share |
|
publicly announced plan |
|
plan(2) |
October 1 October 31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
November 1 November 30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 1 December 31 |
|
|
135,326 |
|
|
$ |
18.70 |
|
|
|
135,326 |
|
|
|
78,656 |
|
|
Total |
|
|
135,326 |
|
|
$ |
18.70 |
|
|
|
135,326 |
|
|
|
78,656 |
|
|
|
|
|
(1) |
|
Prior to our initial public offering, we entered into Share Tender and Repurchase Agreements
with ten of our officers. In these agreements, we agreed to repurchase, and nine of the
officers agreed to sell, an aggregate of 135,326 shares of our common stock at the initial
public offering price, less underwriting discounts and commissions, on the closing date of our
initial public offering. These shares were repurchased to provide such officers the cash
amounts necessary to pay certain tax liabilities associated with the vesting of restricted
shares owned by them. We disclosed the repurchases contemplated by the Share Tender and
Repurchase Agreements in our registration statement on Form S-1 (File No. 333-127517) which
was declared effective, as amended, on December 8, 2005. |
|
(2) |
|
In addition to the repurchase of shares on the closing date of this offering, we agreed under
the Share Tender and Repurchase Agreements to repurchase, and nine of the officers irrevocably
agreed to sell, an aggregate of 78,656 shares of our common stock on February 24, 2006 at the
closing price per share of common stock on that date. These shares were also purchased to
provide such officers the cash amounts necessary to pay certain tax liabilities associated
with the vesting of restricted shares owned by them. The Share Tender and Repurchase
Agreements expired upon the consummation of the February 24, 2006 repurchase. |
28
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, |
|
|
|
2001 |
|
|
2002 |
|
|
2003 |
|
|
2004 |
|
|
2005 |
|
|
|
(dollars in thousands,
except per share data) |
|
Statement of Operations Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing |
|
$ |
62,943 |
|
|
$ |
73,848 |
|
|
$ |
104,097 |
|
|
$ |
142,551 |
|
|
$ |
221,993 |
|
Fluid services |
|
|
36,766 |
|
|
|
34,170 |
|
|
|
52,810 |
|
|
|
98,683 |
|
|
|
132,280 |
|
Drilling and completion services |
|
|
|
|
|
|
733 |
|
|
|
14,808 |
|
|
|
29,341 |
|
|
|
59,832 |
|
Well site construction services |
|
|
|
|
|
|
|
|
|
|
9,184 |
|
|
|
40,927 |
|
|
|
45,647 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
99,709 |
|
|
|
108,751 |
|
|
|
180,899 |
|
|
|
311,502 |
|
|
|
459,752 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing |
|
|
40,906 |
|
|
|
55,643 |
|
|
|
73,244 |
|
|
|
98,058 |
|
|
|
137,392 |
|
Fluid services |
|
|
21,363 |
|
|
|
22,705 |
|
|
|
34,420 |
|
|
|
65,167 |
|
|
|
82,551 |
|
Drilling and completion services |
|
|
|
|
|
|
512 |
|
|
|
9,363 |
|
|
|
17,481 |
|
|
|
30,900 |
|
Well site construction services |
|
|
|
|
|
|
|
|
|
|
6,586 |
|
|
|
31,454 |
|
|
|
32,000 |
|
General and administration (a) |
|
|
10,813 |
|
|
|
13,019 |
|
|
|
22,722 |
|
|
|
37,186 |
|
|
|
55,411 |
|
Depreciation and amortization |
|
|
9,599 |
|
|
|
13,414 |
|
|
|
18,213 |
|
|
|
28,676 |
|
|
|
37,072 |
|
Loss (gain) on disposal of assets |
|
|
(10 |
) |
|
|
351 |
|
|
|
391 |
|
|
|
2,616 |
|
|
|
(222 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
82,671 |
|
|
|
105,644 |
|
|
|
164,939 |
|
|
|
280,638 |
|
|
|
375,104 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
17,038 |
|
|
|
3,107 |
|
|
|
15,960 |
|
|
|
30,864 |
|
|
|
84,648 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest expense |
|
|
(3,303 |
) |
|
|
(4,750 |
) |
|
|
(5,174 |
) |
|
|
(9,550 |
) |
|
|
(12,660 |
) |
Gain (loss) on early extinguishment of debt |
|
|
(1,462 |
) |
|
|
|
|
|
|
(5,197 |
) |
|
|
|
|
|
|
(627 |
) |
Other income (expense) |
|
|
16 |
|
|
|
31 |
|
|
|
146 |
|
|
|
(398 |
) |
|
|
220 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes |
|
|
12,289 |
|
|
|
(1,612 |
) |
|
|
5,735 |
|
|
|
20,916 |
|
|
|
71,581 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax (expense) benefit |
|
|
(4,688 |
) |
|
|
382 |
|
|
|
(2,772 |
) |
|
|
(7,984 |
) |
|
|
(26,800 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations |
|
|
7,601 |
|
|
|
(1,230 |
) |
|
|
2,963 |
|
|
|
12,932 |
|
|
|
44,781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued operations, net of tax |
|
|
|
|
|
|
|
|
|
|
22 |
|
|
|
(71 |
) |
|
|
|
|
Cumulative effect of accounting change, net of tax |
|
|
|
|
|
|
|
|
|
|
(151 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
7,601 |
|
|
|
(1,230 |
) |
|
|
2,834 |
|
|
|
12,861 |
|
|
|
44,781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividend |
|
|
|
|
|
|
(1,075 |
) |
|
|
(1,525 |
) |
|
|
|
|
|
|
|
|
Accretion of preferred stock discount |
|
|
|
|
|
|
(374 |
) |
|
|
(3,424 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders |
|
$ |
7,601 |
|
|
$ |
(2,679 |
) |
|
$ |
(2,115 |
) |
|
$ |
12,861 |
|
|
$ |
44,781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings (loss) per share of common stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing
operations less preferred stock dividend and accretion |
|
$ |
0.50 |
|
|
$ |
(0.13 |
) |
|
$ |
(0.09 |
) |
|
$ |
0.46 |
|
|
$ |
1.57 |
|
Discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of accounting change |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders |
|
$ |
0.50 |
|
|
$ |
(0.13 |
) |
|
$ |
(0.09 |
) |
|
$ |
0.46 |
|
|
$ |
1.57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
earnings (loss) per share of common stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing
operations less preferred stock dividend and accretion |
|
$ |
0.50 |
|
|
$ |
(0.13 |
) |
|
$ |
(0.09 |
) |
|
$ |
0.42 |
|
|
$ |
1.35 |
|
Discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of accounting change |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
(loss) available to common stockholders |
|
$ |
0.50 |
|
|
$ |
(0.13 |
) |
|
$ |
(0.09 |
) |
|
$ |
0.42 |
|
|
$ |
1.35 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement
of Cash Flow Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from operating activities |
|
|
14,060 |
|
|
|
17,012 |
|
|
|
29,815 |
|
|
|
46,539 |
|
|
|
99,189 |
|
Cash flows from investing activities |
|
|
(60,305 |
) |
|
|
(45,303 |
) |
|
|
(84,903 |
) |
|
|
(73,587 |
) |
|
|
(107,679 |
) |
Cash flows from financing activities |
|
|
(50,770 |
) |
|
|
21,572 |
|
|
|
79,859 |
|
|
|
21,498 |
|
|
|
21,188 |
|
Capital expenditures: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquistions, net of cash acquired |
|
|
44,928 |
|
|
|
31,075 |
|
|
|
61,885 |
|
|
|
19,284 |
|
|
|
25,378 |
|
Property and equipment |
|
|
12,208 |
|
|
|
14,674 |
|
|
|
23,501 |
|
|
|
55,674 |
|
|
|
83,095 |
|
|
|
|
(a) |
|
Includes approximately $994,000, $1,587,000 and $2,890,000 of non-cash stock compensation
expense for the years ended December 31, 2003, 2004 and 2005, respectively. |
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, |
|
|
2001 |
|
2002 |
|
2003 |
|
2004 |
|
2005 |
|
|
(dollars in thousands) |
Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
7,645 |
|
|
$ |
926 |
|
|
$ |
25,697 |
|
|
$ |
20,147 |
|
|
$ |
32,845 |
|
Property and equipment, net |
|
|
78,602 |
|
|
|
108,487 |
|
|
|
188,243 |
|
|
|
233,451 |
|
|
|
309,075 |
|
Total assets |
|
|
126,207 |
|
|
|
156,502 |
|
|
|
302,653 |
|
|
|
367,601 |
|
|
|
496,957 |
|
Long-term debt |
|
|
45,258 |
|
|
|
39,706 |
|
|
|
142,116 |
|
|
|
170,915 |
|
|
|
119,241 |
|
Mandatorily redeemable cumulative
preferred stock |
|
|
|
|
|
|
12,093 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity |
|
|
58,938 |
|
|
|
72,558 |
|
|
|
107,295 |
|
|
|
121,786 |
|
|
|
258,575 |
|
30
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 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 37 separate acquisitions from January 1, 2001 to December 31, 2005. Our
weighted average number of well servicing rigs has increased from 126 in 2001 to 316 in the fourth
quarter of 2005, and our weighted average number of fluid service trucks has increased from 156 to
472 in the same period. In 2003, primarily through acquisitions, we significantly increased our
drilling and completion (principally pressure pumping) services and entered the well site
construction services segment. 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, |
|
|
2003 |
|
2004 |
|
2005 |
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing |
|
$ |
104.1 |
|
|
|
58 |
% |
|
$ |
142.6 |
|
|
|
46 |
% |
|
$ |
222.0 |
|
|
|
48 |
% |
Fluid services |
|
|
52.8 |
|
|
|
29 |
% |
|
|
98.7 |
|
|
|
32 |
% |
|
|
132.3 |
|
|
|
29 |
% |
Drilling and completion services |
|
|
14.8 |
|
|
|
8 |
% |
|
|
29.3 |
|
|
|
9 |
% |
|
|
59.8 |
|
|
|
13 |
% |
Well site construction services |
|
|
9.2 |
|
|
|
5 |
% |
|
|
40.9 |
|
|
|
13 |
% |
|
|
45.7 |
|
|
|
10 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
180.9 |
|
|
|
100 |
% |
|
$ |
311.5 |
|
|
|
100 |
% |
|
$ |
459.8 |
|
|
|
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; |
31
|
|
|
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 expect our business strategy will continue to include growth through selective
acquisitions. Our continued rate of growth will depend on our ability to identify attractive
acquisition opportunities and to acquire identified targets at commercially reasonable prices. We
will also continue integrating current or future acquisitions into our existing operations. 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 2003 through 2005, we grew significantly through acquisitions and
capital expenditures. During 2003, this growth was focused more on acquisitions of new lines of
related business and of regional platforms for our existing businesses. 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.
We discuss the aggregate purchase prices and related financing issues below in Liquidity
and Capital Resources and present the historical financial statements of certain significant
acquisitions in the historical financial statements included with this report.
Selected 2003 Acquisitions
The following is a summary of our four largest acquisitions during 2003. These
acquisitions are indicative of our strategic expansion into new lines of business.
New Force Energy Services, Inc.
On January 27, 2003, we completed the acquisition of the business and assets of New Force
Energy Services, Inc., a pressure pumping services company in north central Texas. This acquisition
added 31 pressure pumping units and associated support equipment and three new locations in north
central Texas and increased the services offered in our Permian Basin, North Texas and Ark-La-Tex
divisions. This transaction was structured as an asset purchase for a total purchase price of
approximately $7.7 million in cash and up to an additional $2.7 million in future contingent
earnest payments, of which $1.6 million had been earned as of December 31, 2005.
FESCO Holdings, Inc./First Energy Services Company
On October 3, 2003, we completed the acquisition of FESCO Holdings, Inc., which we refer to as
FESCO, a fluid and well site construction services provider that operates through its subsidiary
First Energy Services Company. FESCOs operations are concentrated in Wyoming, Montana, North
Dakota and Colorado and historically have been largely dependent on drilling activity in the Rocky
Mountain states. This transaction extended our operating presence in the Rocky Mountain states, a
region that we expect will experience increased levels of demand for well site and fluid services
due to increased drilling activity. We have supplemented FESCOs fluid services capabilities with
our well servicing capabilities and equipment to provide additional service offerings in the Rocky
Mountain states. The transaction was structured as a stock-for-stock merger for a total purchase
price of approximately $37.9 million, including $19.1 million of assumed FESCO debt.
32
PWI Inc.
On October 3, 2003, we completed the acquisition of substantially all the operating assets of
PWI Inc. and certain other affiliated entities, which we refer to as PWI, a provider of onshore
oilfield fluid, equipment rental, and well site construction services. These services include fluid
transportation and sales, disposal services, oilfield equipment rental, well site construction and
lease maintenance work. Through eight locations, PWI operated primarily in southeast Texas and
southwest Louisiana. The PWI acquisition substantially enhanced our existing onshore Gulf Coast
well servicing operations by adding fluid services and well site construction services to this
market. This acquisition provided us established operations in an active region and enables us to
cross-sell additional services in the area. We acquired the assets of PWI for $25.1 million in cash
and up to an additional $2.5 million in future contingent
earn-out payments. The contingent earn-out agreement was terminated
by the parties entering into an agreement to pay $75,000 per year for
four years beginning in October 2005.
Pennant Services Company
On October 3, 2003, we completed the acquisition of substantially all of the operating assets
of Pennant Services Company, a well servicing company with operations in Wyoming and Utah. This
acquisition added 13 well servicing rigs and associated workover equipment to our fleet, which have
been integrated with FESCOs operations to expand the range of services and equipment that we offer
to customers in the Rocky Mountain states. We acquired these assets for $7.4 million in cash.
Selected 2004 Acquisitions
During 2004, we made a number of smaller acquisitions and capital expenditures that we
anticipate will serve as a platform for future growth. These include:
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 complement 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.
33
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 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.
Segment Overview
Well Servicing
In
2005, our well servicing segment represented 48% 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. Through acquisitions and
individual equipment purchases, our fleet has more than tripled since the beginning of 2001.
The following is an analysis of our well servicing operations for each of the quarters and
years in the years ended December 31, 2003, 2004 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment |
|
|
|
|
Average |
|
|
|
|
|
Rig |
|
|
|
|
|
Profits |
|
|
|
|
Number of |
|
Rig |
|
Utilization |
|
Revenue Per |
|
Per Rig |
|
Segment |
|
|
Rigs |
|
Hours |
|
Rate |
|
Rig Hour |
|
Hour |
|
Profits % |
2003: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
|
252 |
|
|
|
128,200 |
|
|
|
71.2 |
% |
|
$ |
188 |
|
|
$ |
52 |
|
|
|
27.2 |
% |
Second Quarter |
|
|
252 |
|
|
|
131,000 |
|
|
|
72.7 |
% |
|
$ |
195 |
|
|
$ |
62 |
|
|
|
31.8 |
% |
Third Quarter |
|
|
252 |
|
|
|
133,200 |
|
|
|
73.9 |
% |
|
$ |
200 |
|
|
$ |
62 |
|
|
|
30.8 |
% |
Fourth Quarter |
|
|
270 |
|
|
|
131,500 |
|
|
|
68.1 |
% |
|
$ |
211 |
|
|
$ |
59 |
|
|
|
28.6 |
% |
Full Year |
|
|
257 |
|
|
|
523,900 |
|
|
|
71.4 |
% |
|
$ |
199 |
|
|
$ |
59 |
|
|
|
29.6 |
% |
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 |
% |
34
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 2003 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 $188 in the first quarter of 2003
to $329 in the fourth quarter of 2005 mainly as a result of this higher utilization, which has
contributed to our improved segment profits.
Fluid Services
In 2005, our fluid services segment represented 29% 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.
The following is an analysis of our fluid services operations for each of the quarters and
years in the years ended December 31, 2003, 2004 and 2005 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment |
|
|
|
|
Weighted |
|
|
|
|
|
Profits |
|
|
|
|
Average |
|
|
|
|
|
Per |
|
|
|
|
Number of |
|
Revenue Per |
|
Fluid |
|
|
|
|
Fluid Service |
|
Fluid Service |
|
Service |
|
Segment |
|
|
Trucks |
|
Truck |
|
Truck |
|
Profits % |
2003: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
|
202 |
|
|
$ |
51 |
|
|
$ |
16 |
|
|
|
32.4 |
% |
Second Quarter |
|
|
209 |
|
|
$ |
53 |
|
|
$ |
18 |
|
|
|
34.7 |
% |
Third Quarter |
|
|
223 |
|
|
$ |
50 |
|
|
$ |
18 |
|
|
|
35.3 |
% |
Fourth Quarter |
|
|
363 |
|
|
$ |
56 |
|
|
$ |
21 |
|
|
|
35.8 |
% |
Full Year |
|
|
249 |
|
|
$ |
212 |
|
|
$ |
74 |
|
|
|
34.8 |
% |
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 |
% |
35
We gauge activity levels in our fluid services segment based on revenue and segment profits
per fluid service truck.
We substantially increased our fluid services truck fleet as the result of the PWI and FESCO
acquisitions in the fourth quarter of 2003. Improved market conditions since 2003 have enabled us
to further increase our fluid services truck fleet through internal expansion.
The majority of the increase in revenue per fluid services truck from $51,000 in the first
quarter of 2003 to $79,000 in the fourth quarter of 2005 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 2005, our drilling and completion services segment represented 13% 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 and underbalanced drilling.
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 New Force and
Ark-La-Tex operations.
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.
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 for each of the quarters
and years in the years ended December 31, 2003, 2004 and 2005 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment |
|
|
Revenues |
|
Profits % |
2003: |
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
2,642 |
|
|
|
45.3 |
% |
Second Quarter |
|
$ |
3,454 |
|
|
|
32.7 |
% |
Third Quarter |
|
$ |
4,183 |
|
|
|
38.2 |
% |
Fourth Quarter |
|
$ |
4,529 |
|
|
|
33.6 |
% |
Full Year |
|
$ |
14,808 |
|
|
|
36.8 |
% |
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 |
% |
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment |
|
|
Revenues |
|
Profits % |
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 |
% |
We gauge the performance of our drilling and completion services segment based on the
segments operating revenues and segment profits. Improved market conditions since 2003 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 2005, our well site construction services segment represented 10% 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 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 for the quarter ended
December 31, 2003 (when we first entered this segment), each of the quarters and years in the years
ended December 31, 2004 and 2005 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment |
|
|
Revenues |
|
Profits % |
2003: |
|
|
|
|
|
|
|
|
Fourth Quarter |
|
$ |
9,184 |
|
|
|
28.3 |
% |
|
|
|
|
|
|
|
|
|
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 |
% |
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. To the extent we believe we have excess idle power units,
we may be able to divest ourselves of certain types of power units.
37
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.
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 $125,000 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 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
38
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.
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. We account for stock-based compensation using the intrinsic value
method presented by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to
Employees. However, in accordance with SFAS No. 148, Accounting for Stock-Based Compensation, an
amendment to SFAS No. 123,
39
we must estimate the fair value of our outstanding stock-based compensation awards for
disclosure purposes. In so doing, we use an option-pricing model
(Black-Scholes-Merton), which requires
various assumptions as to interest rates, volatility, dividend yields and expected lives of
stock-based awards.
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.
We used a market approach to estimate our enterprise value at the dates on which options were
granted. Our market approach uses estimates of EBITDA and cash flows multiplied by relevant market
multiples. We used market multiples of publicly traded energy service companies that were supplied
by investment bankers in order to estimate our enterprise value. The assumptions underlying the
estimates are consistent with our business plan. The risks associated with achieving our forecasts
were assessed in the multiples we utilized. Had different multiples been utilized, the valuations
would have been different.
As disclosed in Note 2 to our December 31, 2005 financial statements, we granted stock options
as follows for the twelve-month period ended December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
Weighted |
|
Weighted |
|
|
Number of |
|
Average Exercise |
|
Average Fair |
|
Average Intrinsic |
Grants Made |
|
Options Granted |
|
Price |
|
Value Per Share |
|
Value Per Share |
January 2005 |
|
|
100,000 |
|
|
$ |
5.16 |
|
|
$ |
9.63 |
|
|
$ |
4.47 |
|
March 2005 |
|
|
865,000 |
|
|
$ |
6.98 |
|
|
$ |
12.78 |
|
|
$ |
5.80 |
|
May 2005 |
|
|
5,000 |
|
|
$ |
6.98 |
|
|
$ |
15.48 |
|
|
$ |
8.50 |
|
December 2005 |
|
|
37,500 |
|
|
$ |
21.01 |
|
|
$ |
21.01 |
|
|
$ |
0.00 |
|
The reasons for the differences between the fair value per share at the option grant date and
the IPO price of $20.00 are as follows:
|
|
|
During the three months ended March 31, 2005, we closed
four acquisitions
which added two well servicing rigs, 12 fluid hauling trucks/trailers, two salt water
disposal wells and other equipment. Industry conditions also improved in the first
quarter. As a result of this, our revenues exceeded the first quarter projected revenues
by 12%. In addition, we placed an order for six new well servicing rigs which were
delivered throughout the remainder of 2005. |
|
|
|
|
During the three months ended June 30, 2005, we closed two acquisitions
which added six well servicing rigs and additional pressure pumping equipment. Demand for
our equipment and services continued to strengthen during this quarter. Our well
servicing rig revenue per hour increased by 10% from the first quarter of 2005. Based on
the market outlook, we placed an order for an additional 24 new well servicing rigs, five
of which were put into service later in 2005. |
|
|
|
|
We increased our projected EBITDA and cash flows for 2005 and 2006 due to
the acquisitions and improved operating results. |
|
|
|
|
Market prices of publicly traded energy service companies have increased
significantly from January 1, 2005 due to increases in demand caused by increasing
commodity prices. |
Based on the IPO price of $20.00, the intrinsic value of the options granted in the last
twelve months was $12.8 million, all of which related to unvested options. We have recorded
deferred compensation related to these options of $5.5 million, which is being recorded to
compensation expense over the service period.
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
40
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. 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, 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, 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.
41
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 (Benefit). 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 revenues per rig and fluid
service truck, and higher operating margins on our drilling and completion services equipment.
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Revenues. Revenues increased 72% to $311.5 million in 2004 from $180.9 million in 2003.
This increase was primarily due to major acquisitions that we made in the fourth quarter of 2003,
increased oilfield service activity resulting from continued strong oil and gas prices, the
purchase of additional revenue generating equipment and the higher utilization derived from the
redeployment of equipment to take advantage of increasing activity in some of our markets. We
operated a weighted average of 279 rigs in 2004 compared to 257 in 2003, and 386 fluid service
trucks in 2004 compared to 249 in 2003, which also contributed to the increase.
Well servicing revenues increased 37% to $142.6 million in 2004 compared to $104.1 million in
2003. Our full-fleet utilization rate was 77.8% and revenue per rig hour was $230 in 2004 compared
to 71.4% and $199, respectively, for 2003. The higher rig utilization was due to the general
increase in activity caused by continued higher oil and gas prices and more aggressive deployment
of our fleet in areas of increasing activity. The increasing rate per hour reflects price increases
implemented by us combined with a changing geographic mix of activity.
42
Fluid services revenues increased 87% to $98.7 million in 2004 from $52.8 million in 2003.
During 2004, our average revenues per fluid service truck totaled $256,000, versus average revenues
of $212,000 per truck during the same period in 2003.
Drilling and completion service revenues were $29.3 million during 2004 as compared to $14.8
million during 2003. Our significant entry into this segment occurred in late January 2003 with the
acquisition of New Force and other acquisitions occurring during the fourth quarter of 2003. The
increase in revenues between periods is primarily the result of the addition of equipment and an
increase in rates due to higher utilization.
Well site construction service revenues were $40.9 million in 2004, as compared to $9.2
million in 2003. We entered this segment in the fourth quarter of 2003 with our acquisition of
FESCO and PWI. This service line has benefited from the increase in drilling activity, primarily in
the Rocky Mountains.
Direct Operating Expenses. Direct operating expenses, which primarily consist of labor and
repair and maintenance, increased 72% to $212.2 million in 2004 from $123.6 million in 2003 as a
result of operating additional rigs and trucks, as well as higher utilization of our equipment.
Direct operating expenses as a percentage of revenues for 2004 remained virtually unchanged from the
68.0% in 2003, as fixed operating costs such as field supervision, insurance and vehicle expenses
were spread over a higher revenue base, and this was offset by unit increases in fuel and steel.
The addition of our construction services line also contributed to the static margin as this
service line generates a lower margin than our other service lines.
Direct operating expenses for the well servicing segment increased 34% to $98.1 million in
2004 as compared to $73.2 million in 2003 due to increased activity. Segment profits increased to
31.2% of revenues in 2004 compared to 29.6% during 2003, as higher activity levels and rate
increases were able to offset cost increases for fuel and supplies.
Direct operating expenses for the fluid services segment increased 89% to $65.2 million in
2004 from $34.4 million in 2003. Segment profits for the fluid services segment decreased to 34.0%
in 2004 from 34.8% in 2003. This was the result of higher fuel and disposal costs, which were
partially offset by an increase in drilling related activity.
Direct operating expenses for the drilling and completion services segment were $17.5 million
in 2004 as compared to $9.4 million in 2003, and the segment profits for this segment were 40.4%
for 2004. Our significant entry into this segment occurred in late January 2003 with the
acquisition of New Force and other acquisitions occurring throughout the remainder of 2003.
Direct operating expenses for our well site construction services segment in 2004 were $31.5
million, and the segment profits for this segment were 23.1% for this period as compared to $6.6
million in direct operating expenses and segment profits of 28.3% for the same period in 2003. We
entered this segment in October 2003, as previously discussed.
General and Administrative Expenses. General and administrative expenses increased 63.7% to
$37.2 million in 2004 from $22.7 million in 2003, which included $1.6 million and $1.0 million of
stock-based compensation expense in 2004 and 2003, respectively. The increase primarily reflects
higher salary and office expenses related to the expansion of our business into the Rocky Mountains
and the Gulf Coast region in the fourth quarter of 2003, the addition of our North Texas pressure
pumping business (in our drilling and completion segment), and additional administrative personnel
to support new service locations and growth of the company.
Depreciation and Amortization Expenses. Depreciation and amortization expenses were $28.7
million for 2004 and $18.2 million for 2003, reflecting the increase in the size and investment in
our asset base. We invested $19.3 million for acquisitions in 2004 and an additional $55.7 million
for capital expenditures in 2004 (excluding capital leases).
Interest Expense. Interest expense increased 85.6% to $9.7 million in 2004 from $5.2 million
in 2003. The increase was due to an increase in long-term debt which was primarily used in
connection with our acquisitions,
43
most of which was added in the fourth quarter of 2003, and capital expenditures for property
and equipment. In addition, both prime and LIBOR interest rates increased in 2004, and our term
loan interest rate is tied directly to these rates. Our 2003 interest expense was favorably
impacted by the reduced interest rate we received in our January 2003 refinancing, as well as an
additional reduction in interest rates in our October 2003 refinancing. As part of the refinancings
in January 2003 and October 2003, we recognized a loss of $5.2 million from the early
extinguishment of debt. As part of our 2004 refinancing, we further reduced our base interest rate
by 50 basis points. See Liquidity and Capital Resources.
Income Tax Expense (Benefit). Income taxes increased to an $8.0 million expense in 2004 from
a $2.8 million expense in 2003. The change was due to improved profitability offset in part by a
decrease in the effective tax rate in 2004. The effective tax rate in 2004 was approximately 38.2%
as compared to 48.3% in 2003. The decrease in the effective tax rate in 2004 was due primarily to
an adjustment of the federal tax rate from 34% in previous years to 35% in 2003, and the associated
effects on our deferred tax liability.
Discontinued Operations. As part of the FESCO acquisition in October 2003, we acquired
certain fluid services assets in Alaska that, prior to completing the acquisition, we decided to
sell. Accordingly, these assets were treated as held for sale and therefore the financial results
for the assets are reflected as discontinued operations. These assets were sold in the third
quarter of 2004 at their carrying value. At the time of sale, we charged the remaining liability
for a property lease to discontinued operations.
Cumulative Effect of Accounting Change. As of January 1, 2003, we adopted Statement of
Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligation (SFAS No.
143). 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 capitalize an equal amount as a cost of the asset depreciating it
over the life of the asset. As a result of this adoption we recorded an expense, net of tax of
approximately $151,000 in 2003.
Net Income. Our net income increased to $12.9 million in 2004 from a net income of
$2.8 million in 2003. This improvement was due primarily to the increase in revenues and margins in
2004 compared to 2003 detailed above.
Liquidity and Capital Resources
Currently, our primary capital resources are net cash flows from our operations,
utilization of capital leases as allowed under our credit facility and availability under our
credit facility, of which approximately $124.4 million was available at December 31, 2005. As of
December 31, 2005, we had cash and cash equivalents of $32.8 million compared to $20.1 million as
of December 31, 2004. 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 $99.2 million for the year ended December 31,
2005 as compared to $46.5 million in 2004, and $29.8 million in 2003. The increase in operating
cash flows in 2005 compared to 2004 was primarily due to expansion of our fleet and improvements in
the segment profits and utilization of our equipment. The increase in operating cash flows in 2004
over 2003 was primarily due to improvements in the segment profits and utilization of our equipment
and our acquisitions in late 2003. 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 2005 were $108.5 million as compared to $75.0 million
in 2004, and $85.4 million in 2003. In 2005 and 2004, the majority of our capital expenditures were
for the expansion of our fleet. In 2003 the majority of
44
our capital expenditures were for acquisitions. In 2003, we issued 3,650,000 shares of common
stock as part of the FESCO acquisition which added a non-cash cost to acquisitions of $18.8 million
and is in addition to the $85.4 million spent in 2003. In 2003, we experienced a significant
increase in our acquisition activity as compared to the previous periods which allowed us to expand
our services and regions where we operate. We also added assets through our capital lease program
of approximately $10.3 million, $10.5 million, and $10.8 million in 2005, 2004 and 2003,
respectively.
For 2006, we currently have planned approximately $93 million in cash capital expenditures,
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 2006. The $93
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. As of December 31, 2005, we had executed letters of
intent for acquisitions providing for an aggregate cash purchase price, including potential future
payments, of approximately $105 million.
We regularly engage in discussions related to potential acquisitions related to the well
services industry. At present, we have not entered into any agreement, commitment or understanding
with respect to any significant acquisition as significant is defined under SEC rules.
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 $29.0 million at December 31, 2005, the
availability under our credit facility of $124.4 million at December 31, 2005 and a cash balance of
$32.8 million at December 31, 2005. In 2005, we financed activities in excess of cash flow from
operations primarily through the use of bank debt and capital leases. During 2004 and 2003, we
utilized bank debt and the issuance of equity for cash as consideration for acquisitions.
We have significant contractual obligations in the future that will require capital resources.
Our primary contractual obligations are (1) our long-term debt, (2) our capital leases, (3) our
operating leases, and (4) our asset retirement obligations. The following table outlines our
contractual obligations as of December 31, 2005 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Obligations Due in Periods Ended |
|
|
|
|
Contractual |
|
December 31, |
|
|
|
|
Obligations |
|
Total |
|
|
2006 |
|
|
2007-2008 |
|
|
2009-2010 |
|
|
Thereafter |
|
Long-term debt (excluding capital leases) |
|
$ |
106,000 |
|
|
$ |
1,000 |
|
|
$ |
2,000 |
|
|
$ |
18,000 |
|
|
$ |
85,000 |
|
Capital leases |
|
|
20,887 |
|
|
|
6,646 |
|
|
|
11,142 |
|
|
|
3,099 |
|
|
|
|
|
Operating leases |
|
|
4,199 |
|
|
|
1,198 |
|
|
|
1,540 |
|
|
|
998 |
|
|
|
463 |
|
Asset retirement obligations |
|
|
569 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
569 |
|
|
|
|
Total |
|
$ |
131,655 |
|
|
$ |
8,844 |
|
|
$ |
14,682 |
|
|
$ |
22,097 |
|
|
$ |
86,032 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our long-term debt, excluding capital leases, consists primarily of term loan indebtedness
outstanding under our senior credit facility. 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, 2005, we had a maximum potential obligation of $1.2 million related to the contingent
earn-out agreements. See note 3 of the notes to our historical consolidated financial statements
for additional detail.
The table above also does not reflect $9.6 million of outstanding standby letters of credit
issued under our revolving line of credit. At December 31, 2005, of the $150.0 million in
financial commitments under the revolving line of credit under our senior credit facility, there
was only $124.4 million of available capacity due to the outstanding balance of $16.0 million and
the $9.6 million of outstanding standby letters of credit. In the normal
45
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.
Credit Facilities
2005 Credit Facility
On December 15, 2005, we amended and restated our 2004 Credit Facility by entering into a
Third Amended and Restated Credit Agreement with a syndicate of lenders (the 2005 Credit
Facility). Under the 2005 Credit Facility, Basic Energy Services, Inc. is the sole borrower and
each of our subsidiaries is a subsidiary guarantor. The 2005 Credit Facility provides for a $90
million Term B Loan (Term B Loan) and a $150 million revolving line of credit (Revolver). The
2005 Credit Facility includes provisions allowing us to request an increase in commitments of up to
$75 million at any time. Additionally, the 2005 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 $20 million of letters of credit and (3) $2.5 million of swing-line loans. The amounts
outstanding under the Term B Loan require 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 are due and payable on December 15, 2010. The 2005 Credit
Facility is secured by substantially all of our tangible and intangible assets. We incurred
approximately $1.8 million in costs in connection with the 2005 Credit Facility.
At our option, borrowings under the Term B Loan bear 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 1.0% or (2) the London Interbank Offered Rate (LIBOR) rate plus 2.0%.
At our option, borrowings under the Revolver bear interest at either (1) the Alternative Base
Rate plus a margin ranging from 0.50% to 1.25% or (2) the LIBOR rate plus a margin ranging from
1.50% to 2.25%. 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 1.50% to
2.25% for participation fees and 0.125% for fronting fees. A commitment fee is due quarterly on the
available borrowings under the Revolver at rates ranging from 0.375% to 0.50%.
At December 31, 2005, we had outstanding $90.0 million under the Term B Loan and $16.0 million
under the Revolver.
Pursuant to the 2005 Credit Facility, we must apply proceeds from certain specified events to
reduce principal outstanding under the Term B Loan, to the extent outstanding, and then to the
Revolver, including:
|
|
|
assets sales greater than $2.0 million individually or $7.5 million in the
aggregate on an annual basis; and |
|
|
|
|
50% of the proceeds from any equity offering. |
The 2005 Credit Facility requires us to enter into an interest rate hedge, acceptable to the
lenders, until May 28, 2006 on at least $65 million of our then-outstanding indebtedness.
The 2005 Credit Facility contains various restrictive covenants and compliance requirements,
including the following:
|
|
|
limitations on the incurrence of additional indebtedness; |
46
|
|
|
restrictions on mergers, sales or transfer of assets without the lenders consent; |
|
|
|
|
limitation on dividends and distributions; and |
|
|
|
|
various financial covenants, including: |
|
|
|
a maximum leverage ratio of 3.50 to 1.00 reducing to 3.25 to 1.00, and |
|
|
|
|
a minimum interest coverage ratio of 3.00 to 1.00. |
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.
2003 Credit Facility
In October 2003, we refinanced our 2003 Refinancing Facility by entering into a $170 million
credit facility with a syndicate of lenders (the 2003 Credit Facility). The interest rates and
other terms were similar to our 2004 Credit Facility, but it provided for a $140 million Term B
loan and $30.0 million revolving line of credit, including $10.0 million of letters of credit. At
the date the 2003 Credit Facility was refinanced by the 2004 Credit Facility, the outstanding
principal balance was approximately $139 million. We incurred approximately $5.1 million in debt
issuance costs in obtaining the 2003 Credit Facility.
2003 Refinancing Facility
In January 2003, we refinanced our then-existing credit facilities by entering into a $62
million credit facility with a capital markets group for a combination of term and revolving loans,
and a $22 million revolving line of credit with a bank (collectively, the 2003 Refinancing
Facility). The interest rates on the loans under the 2003 Refinancing Facility were tied to a
variable index plus a margin. At the date the 2003 Refinancing Facility was terminated and
refinanced by the 2003 Credit Facility, the outstanding principal balance was approximately $54
million. We incurred approximately $2.5 million in debt issuance costs in obtaining the 2003
Refinancing 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, 2005, we had total capital leases of approximately $21.0 million.
Losses on Extinguishment of Debt
In 2005 we recognized a loss on the early extinguishment of debt of $627,000 in connection
with our 2005 Credit Facility discussed above. In 2003, we recognized a loss on the early
extinguishment of debt. We paid termination fees of approximately $1.7 million and wrote off
unamortized debt issuance costs of approximately $3.5 million, which resulted in a loss of
approximately $5.2 million. The 2003 Refinancing Facility was done (1) to
47
provide for a facility which would better accommodate acquisitions and (2) to realize better
interest rate margins and fees. The 2003 Credit Facility was primarily done to enable us to fund
the significant acquisitions in the fourth quarter in 2003, which could not be economically
negotiated under the facility related to the 2003 Refinancing Facility.
In 2003, we adopted Statement of Financial Accounting Standards No. 145 Rescission of FASB
Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections (SFAS
No. 145). The provisions of SFAS No. 145, which are currently applicable to us, rescind Statement
No. 4, which required all gains and losses from extinguishment of debt to be aggregated and
classified as an extraordinary item, and instead require that such gains and losses be reported in
income from operations. We now record gains and losses from the extinguishment of debt in income
from operations and have reclassified such gains and losses in the consolidated financial
statements for 2002 to conform to the presentation in 2003.
Credit Rating Agencies
Effective
November 22, 2005, in connection with the amendment and restatement of our
2004 Credit Facility, we have received credit ratings of Ba3 from Moodys and B+ from Standard &
Poors for our long-term debt under the 2004 Credit Facility. 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.
Preferred Stock
In October 2003, we converted our then-outstanding mandatorily redeemable preferred stock into
shares of our common stock as part of our debt refinancing process.
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, 2005, we had approximately $4.9 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 December 2004, the Financial Accounting Standards Board issued Statement of Financial
Accounting Standard No. 123R, Share-Based Payment (SFAS No. 123R). Basic will adopt the
provisions of SFAS No. 123R on January 1, 2006 using the modified prospective application.
Accordingly, Basic 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
Basics pro forma disclosure under SFAS No. 123. However, Basic 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. Basic will recognize
compensation expense for awards under its Second Amended and Restated 2003 Incentive Plan (the
Incentive Plan) beginning in January 1, 2006.
48
Basic estimates that the effect on net income and earnings per share in the periods following
adoption of SFAS No. 123R will be consistent with its pro forma disclosure under SFAS No. 123,
except that estimated forfeitures will be considered in the calculation of compensation expense
under SFAS No. 123R and volatility will be considered in determination of grant date fair value
under SFAS 123R. However, the actual effect on net income and earnings per share will vary
depending upon the number of options granted in future years compared to prior years and the number
of shares exercised under the Incentive Plan. Further, Basic will use the Black-Scholes-Merton
model to calculate fair value.
Impact of Inflation on Operations
Management is of the opinion that inflation has not had a significant impact on our business.
49
ITEM
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to changes in interest rates as a result of our credit facility. We had a
total of $106 million of indebtedness outstanding under our credit facility at December 31, 2005.
The impact of a 1% increase in interest rates on this amount of debt would result in increased
interest expense (excluding effects of our interest rate hedges) of approximately $1.1 million
annually, or a decrease in net income of approximately $687,000.
We do not hold or issue derivative instruments for trading purposes. We do, however, have an
interest rate derivate instrument that has been formally designated as a cash flow hedge
instrument. This instrument effectively converts the variable interest payments on $65 million of
our 2005 Term B Loan into fixed interest payments.
The table below provides scheduled principle payments and fair value information about our
market-risk sensitive instruments as of December 31, 2005 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Year of Maturity |
|
|
2006 |
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
Thereafter |
|
Total |
|
Fair Value |
|
|
|
Debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable rate |
|
$ |
1,000 |
|
|
$ |
1,000 |
|
|
$ |
1,000 |
|
|
$ |
1,000 |
|
|
$ |
17,000 |
|
|
$ |
85,000 |
|
|
$ |
106,000 |
|
|
$ |
106,000 |
|
Average interest rate(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Notional Amounts Outstanding (2) |
|
|
2006 |
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
Thereafter |
|
Total |
|
Fair Value |
|
|
|
Interest Rate Derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable to Fixed |
|
$ |
26,356 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
26,356 |
|
|
$ |
422 |
|
Average pay rate |
|
|
3.03 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.03 |
% |
|
|
N/A |
|
Average received rate |
|
|
4.83 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.83 |
% |
|
|
N/A |
|
|
|
|
(1) |
|
At our option, borrowings under the 2005 Revolver bear interest at either (a) the
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 our leverage ratio. At December 31, 2005, our margin on
Alternative Base Rates and LIBOR tranches was .75% and 1.75%, respectively. |
|
(2) |
|
The notional amounts of interest rate instruments do not represent amounts exchanged by the
parties and, thus, are not a measure of our exposure to credit loss. The amounts exchanged are
determined by reference to the notional amount and the other terms of the contract. The
variable component of the interest rate derivative is based on the LIBOR rate using the
forward yield curve as of March 6, 2006. |
50
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Basic Energy Services, Inc.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
Page |
|
|
|
|
52 |
|
|
|
|
53 |
|
|
|
|
54 |
|
|
|
|
55 |
|
|
|
|
56 |
|
|
|
|
57 |
|
|
|
|
85 |
|
51
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, 2005 and 2004, and the related consolidated statements of
operations and comprehensive income (loss), stockholders equity, and cash flows for each of the
years in the three-year period ended December 31, 2005. 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 schedules 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, 2005 and 2004, and the results of their operations and their cash flows for each of
the years in the three-year period ended December 31, 2005, 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 of the consolidated financial statements, effective January 1, 2003, the
Company changed its method of accounting for asset retirement obligations in accordance with
Statement of Financial Accounting Standards No. 143 Accounting for Asset Retirement Obligations.
KPMG LLP
Dallas, Texas
March 20, 2006
52
Basic Energy Services, Inc.
Consolidated Balance Sheets
(in thousands, except share data)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2005 |
|
|
2004 |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
32,845 |
|
|
$ |
20,147 |
|
Trade accounts receivable, net of allowance of
$2,775 and $3,108, respectively |
|
|
86,932 |
|
|
|
56,651 |
|
Accounts receivable - related parties |
|
|
65 |
|
|
|
103 |
|
Inventories |
|
|
1,648 |
|
|
|
1,176 |
|
Prepaid expenses |
|
|
3,112 |
|
|
|
1,798 |
|
Other current assets |
|
|
2,060 |
|
|
|
2,454 |
|
Deferred tax assets |
|
|
6,020 |
|
|
|
4,899 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
132,682 |
|
|
|
87,228 |
|
|
|
|
|
|
|
|
|
Property and equipment, net |
|
|
309,075 |
|
|
|
233,451 |
|
|
|
|
|
|
|
|
|
|
Deferred debt costs, net of amortization |
|
|
4,833 |
|
|
|
4,709 |
|
Goodwill |
|
|
48,227 |
|
|
|
39,853 |
|
Other assets |
|
|
2,140 |
|
|
|
2,360 |
|
|
|
|
|
|
|
|
|
|
$ |
496,957 |
|
|
$ |
367,601 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
13,759 |
|
|
$ |
11,388 |
|
Accrued expenses |
|
|
33,548 |
|
|
|
20,486 |
|
Income taxes payable |
|
|
7,210 |
|
|
|
|
|
Current portion of long-term debt |
|
|
7,646 |
|
|
|
11,561 |
|
Other current liabilities |
|
|
1,124 |
|
|
|
545 |
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
63,287 |
|
|
|
43,980 |
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
119,241 |
|
|
|
170,915 |
|
Deferred income |
|
|
17 |
|
|
|
44 |
|
Deferred tax liabilities |
|
|
53,770 |
|
|
|
30,247 |
|
Other long-term liabilities |
|
|
2,067 |
|
|
|
629 |
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity: |
|
|
|
|
|
|
|
|
Common stock; $.01 par value; 80,000,000 shares authorized;
33,931,935 shares issued, 33,785,359 shares outstanding at December 31, 2005 and
28,931,935 shares issued and outstanding at December 31, 2004, respectively |
|
|
339 |
|
|
|
58 |
|
Additional paid-in capital |
|
|
239,218 |
|
|
|
142,802 |
|
Deferred compensation |
|
|
(7,341 |
) |
|
|
(4,990 |
) |
Retained earnings (deficit) |
|
|
28,654 |
|
|
|
(16,127 |
) |
Treasury stock, 146,576 shares at December 31, 2005, at cost |
|
|
(2,531 |
) |
|
|
|
|
Accumulated other comprehensive income |
|
|
236 |
|
|
|
43 |
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
258,575 |
|
|
|
121,786 |
|
|
|
|
|
|
|
|
|
|
$ |
496,957 |
|
|
$ |
367,601 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
53
Basic Energy Services, Inc.
Consolidated Statements of Operations and Comprehensive Income
(Dollars in thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31 |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing |
|
$ |
221,993 |
|
|
$ |
142,551 |
|
|
$ |
104,097 |
|
Fluid services |
|
|
132,280 |
|
|
|
98,683 |
|
|
|
52,810 |
|
Drilling and completion services |
|
|
59,832 |
|
|
|
29,341 |
|
|
|
14,808 |
|
Well site construction services |
|
|
45,647 |
|
|
|
40,927 |
|
|
|
9,184 |
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
459,752 |
|
|
|
311,502 |
|
|
|
180,899 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing |
|
|
137,392 |
|
|
|
98,058 |
|
|
|
73,244 |
|
Fluid services |
|
|
82,551 |
|
|
|
65,167 |
|
|
|
34,420 |
|
Drilling and completion services |
|
|
30,900 |
|
|
|
17,481 |
|
|
|
9,363 |
|
Well site construction services |
|
|
32,000 |
|
|
|
31,454 |
|
|
|
6,586 |
|
General and administrative, including stock-based compensation
of $2,890, $1,587, and $994 in 2005, 2004 and 2003, respectively |
|
|
55,411 |
|
|
|
37,186 |
|
|
|
22,722 |
|
Depreciation and amortization |
|
|
37,072 |
|
|
|
28,676 |
|
|
|
18,213 |
|
(Gain) loss on disposal of assets |
|
|
(222 |
) |
|
|
2,616 |
|
|
|
391 |
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
375,104 |
|
|
|
280,638 |
|
|
|
164,939 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
84,648 |
|
|
|
30,864 |
|
|
|
15,960 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
(13,065 |
) |
|
|
(9,714 |
) |
|
|
(5,234 |
) |
Interest income |
|
|
405 |
|
|
|
164 |
|
|
|
60 |
|
Loss on early extinguishment of debt |
|
|
(627 |
) |
|
|
|
|
|
|
(5,197 |
) |
Other income (expense) |
|
|
220 |
|
|
|
(398 |
) |
|
|
146 |
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes |
|
|
71,581 |
|
|
|
20,916 |
|
|
|
5,735 |
|
Income tax expense |
|
|
(26,800 |
) |
|
|
(7,984 |
) |
|
|
(2,772 |
) |
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
44,781 |
|
|
|
12,932 |
|
|
|
2,963 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued operations, net of tax |
|
|
|
|
|
|
(71 |
) |
|
|
22 |
|
Cumulative effect of accounting change, net of tax |
|
|
|
|
|
|
|
|
|
|
(151 |
) |
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
44,781 |
|
|
|
12,861 |
|
|
|
2,834 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividend |
|
|
|
|
|
|
|
|
|
|
(1,525 |
) |
Accretion of preferred stock discount |
|
|
|
|
|
|
|
|
|
|
(3,424 |
) |
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders |
|
$ |
44,781 |
|
|
$ |
12,861 |
|
|
$ |
(2,115 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share of common stock: |
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations |
|
$ |
1.57 |
|
|
$ |
0.46 |
|
|
$ |
(0.09 |
) |
Discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders |
|
$ |
1.57 |
|
|
$ |
0.46 |
|
|
$ |
(0.09 |
) |
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share of common stock: |
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations |
|
$ |
1.35 |
|
|
$ |
0.42 |
|
|
$ |
(0.09 |
) |
Discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders |
|
$ |
1.35 |
|
|
$ |
0.42 |
|
|
$ |
(0.09 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
44,781 |
|
|
$ |
12,861 |
|
|
$ |
2,834 |
|
Unrealized gains on hedging activities |
|
|
193 |
|
|
|
43 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income: |
|
$ |
44,974 |
|
|
$ |
12,904 |
|
|
$ |
2,834 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
54
Basic Energy Services, Inc.
Consolidated Statements of Stockholders Equity
(in thousands, except share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
|
|
|
|
|
|
|
|
Retained |
|
|
Other |
|
|
Total |
|
|
|
Common Stock |
|
|
Paid-In |
|
|
Deferred |
|
|
Treasury |
|
|
Earnings |
|
|
Comprehensive |
|
|
Stockholders |
|
|
|
Shares |
|
|
Amount |
|
|
Capital |
|
|
Compensation |
|
|
Stock |
|
|
(Deficit) |
|
|
Income |
|
|
Equity |
|
Balance - December 31, 2002 |
|
|
20,368,610 |
|
|
$ |
41 |
|
|
$ |
97,294 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(24,777 |
) |
|
$ |
|
|
|
$ |
72,558 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of EBITDA contingent
warrants |
|
|
771,740 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
EBITDA contingent warrants |
|
|
|
|
|
|
|
|
|
|
3,571 |
|
|
|
|
|
|
|
|
|
|
|
(2,660 |
) |
|
|
|
|
|
|
911 |
|
FESCO Holdings, Inc. acquisition |
|
|
3,650,000 |
|
|
|
7 |
|
|
|
18,820 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18,827 |
|
Stock-based compensation awards |
|
|
|
|
|
|
|
|
|
|
380 |
|
|
|
(380 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of deferred
compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
83 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
83 |
|
Preferred stock conversion to
common stock |
|
|
3,304,085 |
|
|
|
6 |
|
|
|
16,459 |
|
|
|
|
|
|
|
|
|
|
|
564 |
|
|
|
|
|
|
|
17,029 |
|
Accretion of preferred stock
discount |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,424 |
) |
|
|
|
|
|
|
(3,424 |
) |
Preferred stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,525 |
) |
|
|
|
|
|
|
(1,525 |
) |
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,834 |
|
|
|
|
|
|
|
2,834 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
55
Basic Energy Services, Inc.
Consolidated Statements of Cash Flows
( in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
44,781 |
|
|
$ |
12,861 |
|
|
$ |
2,834 |
|
Adjustments to reconcile net income to net cash
provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
37,072 |
|
|
|
28,676 |
|
|
|
18,213 |
|
Accretion on asset retirement obligation |
|
|
42 |
|
|
|
33 |
|
|
|
28 |
|
Change in allowance for doubtful accounts |
|
|
(333 |
) |
|
|
1,150 |
|
|
|
1,279 |
|
Non-cash interest expense |
|
|
1,062 |
|
|
|
970 |
|
|
|
694 |
|
Non-cash compensation |
|
|
2,890 |
|
|
|
1,587 |
|
|
|
994 |
|
Loss on early extinguishment of debt |
|
|
627 |
|
|
|
|
|
|
|
3,588 |
|
(Gain) loss on disposal of assets |
|
|
(222 |
) |
|
|
2,616 |
|
|
|
391 |
|
Deferred income taxes |
|
|
18,301 |
|
|
|
7,984 |
|
|
|
2,840 |
|
Other non-cash items |
|
|
|
|
|
|
|
|
|
|
(11 |
) |
Non-cash effect of discontinued operations |
|
|
|
|
|
|
|
|
|
|
13 |
|
Cumulative effect of accounting change |
|
|
|
|
|
|
|
|
|
|
151 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in operating assets and liabilities, net of acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(27,577 |
) |
|
|
(13,841 |
) |
|
|
(12,120 |
) |
Inventories |
|
|
(262 |
) |
|
|
394 |
|
|
|
125 |
|
Prepaid expenses and other current assets |
|
|
304 |
|
|
|
446 |
|
|
|
(1,243 |
) |
Other assets |
|
|
(49 |
) |
|
|
(569 |
) |
|
|
1,261 |
|
Accounts payable |
|
|
2,174 |
|
|
|
3,416 |
|
|
|
2,863 |
|
Income tax payable |
|
|
7,013 |
|
|
|
|
|
|
|
|
|
Deferred income and other liabilities |
|
|
374 |
|
|
|
127 |
|
|
|
(11 |
) |
Accrued expenses |
|
|
12,992 |
|
|
|
689 |
|
|
|
7,926 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
99,189 |
|
|
|
46,539 |
|
|
|
29,815 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of property and equipment |
|
|
(83,095 |
) |
|
|
(55,674 |
) |
|
|
(23,501 |
) |
Proceeds from sale of assets |
|
|
2,436 |
|
|
|
2,484 |
|
|
|
660 |
|
Payments for other long-term assets |
|
|
(1,642 |
) |
|
|
(1,113 |
) |
|
|
(177 |
) |
Payments for businesses, net of cash acquired |
|
|
(25,378 |
) |
|
|
(19,284 |
) |
|
|
(61,885 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(107,679 |
) |
|
|
(73,587 |
) |
|
|
(84,903 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from debt |
|
|
16,000 |
|
|
|
43,500 |
|
|
|
203,012 |
|
Payments of debt |
|
|
(81,924 |
) |
|
|
(21,236 |
) |
|
|
(115,603 |
) |
Proceeds from common stock, net of $2,044 of offering costs |
|
|
91,456 |
|
|
|
|
|
|
|
|
|
Purchase of treasury stock |
|
|
(2,531 |
) |
|
|
|
|
|
|
|
|
Collections of notes receivable |
|
|
|
|
|
|
|
|
|
|
9 |
|
Proceeds from exercise of EBITDA contingent warrants |
|
|
|
|
|
|
|
|
|
|
2 |
|
Deferred loan costs and other financing activities |
|
|
(1,813 |
) |
|
|
(766 |
) |
|
|
(7,561 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
21,188 |
|
|
|
21,498 |
|
|
|
79,859 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and equivalents |
|
|
12,698 |
|
|
|
(5,550 |
) |
|
|
24,771 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents - beginning of year |
|
|
20,147 |
|
|
|
25,697 |
|
|
|
926 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents - end of year |
|
$ |
32,845 |
|
|
$ |
20,147 |
|
|
$ |
25,697 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
56
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
1. Nature of Operations and Basis of Presentation
Organization and Restructuring
Basic Energy Services, Inc. (predecessor entity), a Delaware corporation (Historical Basic)
commenced operations in 1992. Effective January 24, 2003, Historical Basic changed its corporate
structure to a holding company format. The purpose of this corporate restructuring was to provide
greater operational, administrative and financial flexibility to Historical Basic, as well as
improved economics. In connection with this restructuring, Historical Basic merged with a newly
formed subsidiary of BES Holding Co. (New Basic), a Delaware corporation incorporated on January
7, 2003 as a wholly-owned subsidiary of New Basic. The merger was structured as a tax-free
reorganization to Historical Basic stockholders. As a result of the merger, each share of
outstanding common stock of Historical Basic was exchanged for one share of common stock of New
Basic, and each share of outstanding Series A 10% Cumulative Preferred Stock of Historical Basic
was exchanged for one share of Series A 10% Cumulative Preferred Stock of New Basic, and with
respect to any accrued and unpaid dividends, shares of additional preferred stock with a
liquidation preference equal to such accrued and unpaid dividends. Historical Basic survived the
merger and was subsequently converted to a Delaware limited partnership now known as Basic Energy
Services, L.P., which is currently an indirect wholly-owned subsidiary of New Basic. On April 2,
2004, BES Holding Co. changed its name to Basic Energy Services, Inc. Historical Basic prior to
January 24, 2003 and New Basic thereafter are referred to in these Notes to Consolidated Financial
Statements as Basic.
Basis of Presentation
The historical consolidated financial statements presented herein of Basic prior to its
formation are the historical results of Historical Basic since the ownership of Basic and
Historical Basic at the merger date were identical. The financial results of New Basic and
Historical Basic are combined to present the consolidated financial statements of Basic.
Nature of Operations
Basic 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 and Louisiana, and the Rocky Mountain states.
57
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
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 inter-company 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.
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.
58
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
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
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 rigs and equipment |
|
3-15 years |
Fluid service equipment |
|
5-10 years |
Brine/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 |
Software and computers |
|
3 years |
Aircraft |
|
20 years |
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.
59
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
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 2005, 2004 or 2003.
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 straight line method which
approximates the effective interest method over the terms of the related debt.
Deferred debt costs of approximately $7.0 million at December 31, 2005 and $5.8 million at
December 31, 2004, respectively, represent debt issuance costs and are recorded net of accumulated
amortization of $2.2 million, and $1.1 million at December 31, 2005 and December 31, 2004,
respectively. Amortization of deferred debt costs totaled approximately $1,062,000, $907,000 and
$694,000 for the years ended December 31, 2005, 2004 and 2003, respectively.
In
2005, Basic recognized a loss on early extinguishment of debt related to deferred debt costs.
(See note 5)
Goodwill
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.
60
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
Intangible assets subject to amortization under SFAS No. 142 consist of non-compete
agreements. Amortization expense for the non-compete agreements is calculated using the
straight-line method over the period of the agreement, ranging from three to five years. The
weighted average amortization period for non-compete agreements acquired during 2005 and 2004 is 60
months.
The gross carrying amount of non-compete agreements subject to amortization totaled
approximately $2.7 million and $3.7 million at December 31, 2005 and 2004, respectively.
Accumulated amortization related to these intangible assets totaled approximately $1.6 and $2.4
million at December 31, 2005 and 2004, respectively. Amortization expense for the years ended
December 31, 2005, 2004 and 2003 was approximately $519,000, $457,000, and $364,000, respectively.
Amortization expense for the next five succeeding years is estimated to be
approximately $461,000, $325,000, $ 223,000, $122,000, and $22,000 in 2006, 2007, 2008, 2009,
and 2010 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, 2005 is $9.9 million, $20.6 million, $14.0 million and $3.7 million,
respectively. The change in the carrying amount of goodwill for the year ended December 31, 2005
of $8.4 million relates to goodwill from acquisitions and payments pursuant to contingent earn-out
agreements, with approximately $1.1 million, $2.2 million and $5.1 million of goodwill additions
relating to the well servicing, fluid services and drilling and completion units, respectively.
Stock-Based Compensation
Basic accounts for stock-based compensation using the intrinsic value method prescribed by
Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (APB No.
25). Accordingly, Basic has adopted the disclosure provisions of Statement of Financial
Accounting Standards No. 123, Accounting for Stock-Based Compensation (SFAS No. 123).
Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation
(SFAS No. 123) sets forth alternative accounting and disclosure requirements for stock-based
compensation arrangements. Companies may continue to follow the provisions of APB No. 25 to measure
and recognize employee stock-based compensation; however, SFAS No. 123 requires disclosure of pro
forma net income and earnings per share that would have been reported under the fair value based
recognition provisions of SFAS No. 123. The following table illustrates the effect on net income if
Basic had applied the fair value recognition provisions of SFAS No. 123 to stock-based employee
compensation.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Net income (loss) available to common stockholders - as reported |
|
$ |
44,781 |
|
|
$ |
12,861 |
|
|
$ |
(2,115 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Add: Stock-based employee compensation expense
included in statement of operations, net of tax |
|
|
1,806 |
|
|
|
986 |
|
|
|
523 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deduct: Stock-based employee compensation expense determined
under fair-value based method for all awards, net of tax |
|
|
(2,231 |
) |
|
|
(1,283 |
) |
|
|
(779 |
) |
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders - pro forma basis |
|
$ |
44,356 |
|
|
$ |
12,564 |
|
|
$ |
(2,371 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share of common stock: |
|
|
|
|
|
|
|
|
|
|
|
|
As reported |
|
$ |
1.57 |
|
|
$ |
0.46 |
|
|
$ |
(0.09 |
) |
Pro forma |
|
$ |
1.55 |
|
|
$ |
0.45 |
|
|
$ |
(0.11 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share of common stock: |
|
|
|
|
|
|
|
|
|
|
|
|
As reported |
|
$ |
1.35 |
|
|
$ |
0.42 |
|
|
$ |
(0.09 |
) |
Pro forma |
|
$ |
1.34 |
|
|
$ |
0.41 |
|
|
$ |
(0.11 |
) |
61
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
Under SFAS No. 123, the fair value of each stock option grant is estimated on the date of
grant using the Black-Scholes-Merton option pricing model with the following weighted average assumptions
used for grants during the years ended December 31, 2005, 2004, and 2003:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
2004 |
|
2003 |
Risk-free interest rate |
|
|
4.5 |
% |
|
|
4.4 |
% |
|
|
2.9 |
% |
Expected life |
|
|
9.9 |
|
|
|
10.0 |
|
|
|
10.0 |
|
Expected volatility |
|
|
0.5 |
% |
|
|
0.0 |
% |
|
|
0.0 |
% |
Expected dividend yield |
|
|
|
|
|
|
|
|
|
|
|
|
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.
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
2005, 2004, or 2003.
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.
62
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
Basic had no derivative contacts in 2003. 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 are initially recorded in other comprehensive income, then
recognized in income in the same period(s) in which the hedged transaction affects income.
Ineffective portions of a cash flow hedging derivatives change in fair value are recognized
currently in earnings. Basic had no ineffectiveness related to its cash flow hedge in 2005 or
2004.
|
|
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 on 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. On January 1, 2003, Basic recorded additional costs, net of accumulated depreciation
of approximately $102,000, an asset retirement obligation of approximately $340,000, and an
after-tax charge of approximately $151,000 for the cumulative effect on prior years depreciation
of the additional costs and the accretion expense on the liability related to the expected
abandonment costs.
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, 2005 and
2004 (in thousands):
|
|
|
|
|
Balance, December 31, 2003 |
|
$ |
415 |
|
|
|
|
|
|
Additional asset retirement obligations recognized through acquisitions |
|
|
36 |
|
|
Accretion expense |
|
|
33 |
|
|
Settlements |
|
|
(11 |
) |
|
|
|
|
|
Balance, December 31, 2004 |
|
$ |
473 |
|
|
|
|
|
|
Additional asset retirement obligations recognized through acquisitions |
|
|
74 |
|
|
Accretion expense |
|
|
42 |
|
|
Settlements |
|
|
(20 |
) |
|
|
|
|
|
Balance, December 31, 2005 |
|
$ |
569 |
|
|
|
|
|
The pro forma net income (loss) and related per share amounts assuming SFAS no. 143 had been
applied in 2003 are as follows (in thousands, except per share data):
|
|
|
|
|
|
|
2003 |
Pro forma net income (loss) available
to common shareholders (a) |
|
$ |
(1,964 |
) |
|
|
|
|
|
Pro forma earnings per share of common stock
Basic |
|
|
|
|
Basic |
|
$ |
(0.09 |
) |
Diluted |
|
$ |
(0.09 |
) |
|
|
|
(a) |
|
The net income available to common stockholders in 2003 has been adjusted
to remove the $151,000 cumulative effect of accounting change attributable to SFAS No. 143. |
63
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
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.
Recent Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board issued Statement of Financial
Accounting Standard No. 123R, Share-Based Payment (SFAS No. 123R). Basic will adopt the
provisions of SFAS No. 123R on January 1, 2006 using the modified prospective application.
Accordingly, Basic 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
Basics pro forma disclosure under SFAS No. 123. However, Basic 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. Basic will recognize
compensation expense for awards under its Second Amended and Restated 2003 Incentive Plan (the
Incentive Plan) beginning in January 1, 2006.
Basic estimates that the effect on net income and earnings per share in the periods following
adoption of SFAS No. 123R will be consistent with its pro forma disclosure under SFAS No. 123,
except that estimated forfeitures will be considered in the calculation of compensation expense
under SFAS No. 123R and volatility will be considered in determination of grant date fair value
under SFAS 123R. However, the
64
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
actual effect on net income and earnings per share will vary
depending upon the number of options granted in future years compared to prior years and the number
of shares exercised under the Incentive Plan. Further, Basic will use the Black-Scholes-Merton
model to calculate fair value.
3. Acquisitions
In 2005, 2004 and 2003, 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) |
|
New Force Energy Services |
|
January 27, 2003 |
|
$ |
7,665 |
|
S & S Bulk Cement |
|
April 17, 2003 |
|
|
195 |
|
Briscoe Oil Tools |
|
June 13, 2003 |
|
|
260 |
|
FESCO Holdings, Inc. (a) |
|
October 3, 2003 |
|
|
19,093 |
|
PWI, Inc. |
|
October 3, 2003 |
|
|
25,104 |
|
Pennant Service Company |
|
October 3, 2003 |
|
|
7,387 |
|
Graham Acidizing |
|
December 1, 2003 |
|
|
2,181 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total 2003 |
|
|
|
|
|
$ |
61,885 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
This acquisition was funded through the issuance of Basics common stock. The total cash
paid represents the retirement of debt at closing and transaction costs incurred net of the cash
acquired. |
65
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
The operations of each of the acquisitions listed above are included in Basics statement of
operations as of each respective closing date. The acquisitions of New Force Energy Services
(New Force), FESCO Holding, Inc. (FESCO) and PWI, Inc. and certain other affiliated entities
(PWI) in 2003 are deemed significant and discussed below in further detail.
New Force Energy Services
On January 27, 2003, Basic acquired substantially all of the assets of New Force for $7.7
million plus a $2.7 million contingent earn-out payment. The contingent earn-out payment will be
paid upon the New Force assets meeting certain financial objectives in the future. The preliminary
cash cost of the New Force acquisition was $7.7 million (including other direct acquisition costs)
which was allocated $6.3 million to property and equipment, $1.3 million to goodwill, $105,000 to
inventory and $10,000 to non-compete agreements.
FESCO Holdings, Inc.
On October 3, 2003, Basic acquired all the capital stock of FESCO. As consideration for the
acquisition of FESCO, Basic issued 3,650,000 shares of its common stock, based on an estimated fair
value of the stock of $5.16 per share (a total fair value of approximately $18.8 million), and paid
approximately $19.1 million in net cash at the closing, representing the retirement of debt of
FESCO at closing and the payment of transaction costs incurred, net of the cash held by FESCO. In
addition to assuming the working capital of FESCO, Basic incurred other direct acquisition costs
and assumed certain other liabilities of FESCO, resulting in Basic recording an aggregate purchase
price of approximately $37.9 million. The following table summarizes the estimated fair value of
the assets acquired and liabilities assumed at the date of acquisition (in thousands):
|
|
|
|
|
Current assets, excluding cash |
|
$ |
12,855 |
|
Property and equipment |
|
|
32,344 |
|
Other assets |
|
|
38 |
|
|
|
|
|
|
|
|
|
|
Total assets acquired |
|
|
45,237 |
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
|
5,592 |
|
Deferred tax liability |
|
|
1,725 |
|
|
|
|
|
|
|
|
|
|
Total liabilities assumed |
|
|
7,317 |
|
|
|
|
|
|
|
|
|
|
Net assets acquired |
|
$ |
37,920 |
|
|
|
|
|
PWI, Inc.
On October 3, 2003, Basic acquired substantially all the assets of PWI for $25.1 million plus
a $2.5 million contingent earn-out payment. The contingent
earn-out agreement was terminated by the parties entering into an
agreement to pay $75,000 per year for four years beginning in October
2005. The cash cost of the PWI
acquisition was $25.1 million (including other direct acquisition costs) which was allocated $16.4
million to property and equipment, $8.6 million to goodwill, $250,000 to non-compete agreements and
$200,000 to liabilities assumed.
Contingent Earn-out Arrangements and Final Purchase Price Allocations
Contingent earn-out arrangements are generally arrangements entered in 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
66
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
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 acquisition.
The following presents a summary of acquisitions that have a contingent earn-out arrangement
in effect as of December 31, 2005 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Termination |
|
Maximum |
|
|
|
|
|
|
date of |
|
exposure of |
|
|
|
|
|
|
contingent |
|
contingent |
|
|
Amount paid or |
|
|
|
earn-out |
|
earn-out |
|
|
accrued through |
|
Acquisition |
|
arrangement |
|
arrangement |
|
|
December 31, 2005 |
|
|
Advantage Services, Inc. |
|
October 9, 2005 |
|
$ |
250 |
|
|
$ |
219 |
|
New Force
Energy Services |
|
January 27, 2008 |
|
|
2,700 |
|
|
|
1,639 |
|
S&S Bulk Cement |
|
April 20, 2008 |
|
|
115 |
|
|
|
115 |
|
Briscoe Oil Tools |
|
June 12, 2008 |
|
|
125 |
|
|
|
82 |
|
Rolling Plains |
|
April 30, 2009 |
|
|
* |
|
|
|
588 |
|
Premier Vacuum Services, Inc. |
|
February 1, 2010 |
|
|
900 |
|
|
|
226 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
4,090 |
|
|
$ |
2,869 |
|
|
|
|
* |
|
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 |
The following unaudited pro forma results of operations have been prepared as though the New Force, FESCO and PWI acquisitions had been completed on January 1,
2003. 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).
|
|
|
|
|
|
|
Year ended |
|
|
December 31, 2003 |
|
|
(Unaudited) |
Revenues |
|
$ |
228,059 |
|
|
|
|
|
|
Income (loss) from continuing operations
less preferred stock dividends and accretion |
|
$ |
(1,182 |
) |
Earnings per common share - basic |
|
$ |
(0.05 |
) |
Earnings per common share - diluted |
|
$ |
(0.05 |
) |
Basic does not believe the pro-forma effect of the remainder of the acquisitions
completed in 2003, 2004, or 2005 is material, either individually or when aggregated, to the
reported results of operations.
67
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
4. Property and Equipment
Property and equipment consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
|
|
2005 |
|
|
2004 |
|
Land |
|
$ |
1,902 |
|
|
$ |
1,573 |
|
Buildings and improvements |
|
|
8,634 |
|
|
|
6,615 |
|
Well service units and equipment |
|
|
199,070 |
|
|
|
138,957 |
|
Fluid services equipment |
|
|
59,104 |
|
|
|
53,111 |
|
Brine and fresh water stations |
|
|
7,746 |
|
|
|
7,722 |
|
Frac/test tanks |
|
|
31,475 |
|
|
|
19,707 |
|
Pressure pumping equipment |
|
|
31,101 |
|
|
|
14,971 |
|
Construction equipment |
|
|
24,224 |
|
|
|
21,964 |
|
Disposal facilities |
|
|
16,828 |
|
|
|
14,079 |
|
Vehicles |
|
|
23,329 |
|
|
|
18,881 |
|
Rental equipment |
|
|
6,519 |
|
|
|
4,885 |
|
Aircraft |
|
|
3,236 |
|
|
|
3,335 |
|
Other |
|
|
8,602 |
|
|
|
7,780 |
|
|
|
|
|
|
|
|
|
|
|
421,770 |
|
|
|
313,580 |
|
Less accumulated depreciation and amortization |
|
|
112,695 |
|
|
|
80,129 |
|
|
|
|
|
|
|
|
Property and equipment, net |
|
$ |
309,075 |
|
|
$ |
233,451 |
|
|
|
|
|
|
|
|
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, |
|
|
|
2005 |
|
|
2004 |
|
Light vehicles |
|
$ |
17,912 |
|
|
$ |
12,993 |
|
Fluid services equipment |
|
|
14,011 |
|
|
|
10,558 |
|
Construction equipment |
|
|
1,300 |
|
|
|
840 |
|
|
|
|
|
|
|
|
|
|
|
33,223 |
|
|
|
24,391 |
|
Less accumulated amortization |
|
|
8,474 |
|
|
|
7,201 |
|
|
|
|
|
|
|
|
|
|
$ |
24,749 |
|
|
$ |
17,190 |
|
|
|
|
|
|
|
|
Amortization of assets held under capital leases of approximately $1.8 million, $1.8
million, and $2.5 million for the years ended December 31, 2005, 2004, and 2003, respectively, is
included in depreciation and amortization expense in the consolidated statements of operations.
5. Long-Term Debt
Long-term debt consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
|
|
2005 |
|
|
2004 |
|
Credit Facilities: |
|
|
|
|
|
|
|
|
Term B Loan |
|
$ |
90,000 |
|
|
$ |
166,500 |
|
Revolver |
|
|
16,000 |
|
|
|
|
|
Capital leases and other notes |
|
|
20,887 |
|
|
|
15,976 |
|
|
|
|
|
|
|
|
|
|
|
126,887 |
|
|
|
182,476 |
|
Less current portion |
|
|
7,646 |
|
|
|
11,561 |
|
|
|
|
|
|
|
|
|
|
$ |
119,241 |
|
|
$ |
170,915 |
|
|
|
|
|
|
|
|
68
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
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 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 $20 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, 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, 2005,
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, 2005 Basic, under its Revolver, had outstanding $16 million of borrowings and
$9.6 million of letters of credit and no amounts outstanding in swing-line loans. At December 31,
2005 Basic had availability under its Revolver of $124.4 million.
Pursuant to the 2005 Credit Facility, Basic must apply proceeds to reduce principal
outstanding under the 2005 Term B 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, acceptable
to the lenders, through May 28, 2006 on at least $65 million of Basics then outstanding
indebtedness. 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, 2005 and December 31,
2004, Basic was in compliance with its covenants.
2004 Credit Facility
On December 21, 2004, Basic entered into a $220 million Second Amended and Restated Credit
Agreement with a syndicate of lenders (2004 Credit Facility) which refinanced all of its then
existing credit facilities. 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
69
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
(a) the borrowing of funds (b) issuance of up to $20 million of letters of
credit and (c) $2.5 million of swing-line loans (next day borrowing). The amounts outstanding
under the 2004 Term B Loan required quarterly amortization at various amounts during each quarter
with all amounts outstanding on October 3, 2009 being due and payable in full. All the outstanding
amounts under the 2004 Revolver were due and payable on October 3, 2008. The 2004 Credit Facility was
secured by substantially all of Basics tangible and intangible assets. Basic incurred
approximately $766,000 in debt issuance costs in obtaining the 2004 Credit Facility.
At Basics option, borrowings under the 2004 Term B Loan bore interest at either (a) the
Alternative Base Rate (i.e. the higher of the banks prime rate or the federal funds rate plus .5% per annum) plus 2% or (b) LIBOR plus 3%. At December 31, 2004, Basics weighted average
interest rate on its 2004 Term B Loan was 5.5%.
At Basics option,
borrowings under the 2004 Revolver bore interest at either the (a) the
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 1.5% to 2.0% or (b) the LIBOR rate plus a margin ranging
from 2.5% to 3.0%. The margins varied depending on Basics leverage ratio. At December 31, 2004,
Basics margin on Alternative Base Rates and LIBOR tranches was 2.0% and 3.0%, respectively. Fees
on the letters of credit were due quarterly on the outstanding amount of the letters of credit at a
rate ranging from 2.5% to 3.0% for participation fees and .125% for fronting fees. A commitment
fee was due quarterly on the available borrowings under the 2004 Revolver at rates ranging from .375% to .5%.
At December 31, 2004,
Basic, under its 2004 Revolver, had outstanding $8.3 million of letters of
credit and no amounts outstanding in swing-line loans. At December 31, 2004, Basic had
availability under its 2004 Revolver of $41.7 million.
2003 Credit Facility
On October 3, 2003, Basic entered into a $170 million credit facility with a syndicate of
lenders (2003 Credit Facility) which refinanced all of its then existing credit facilities. The
2003 Credit Facility provided for a $140 million Term B Loan (2003 Term B Loan) and a $30 million
revolving line of credit (2003 Revolver). The commitment
under the 2003 Revolver allowed for (a) the
borrowing of funds (b) issuance of up to $10 million of letters of credits and (c) $2.5 million of
swing-line loans (next day borrowing). The amounts outstanding under the 2003 Term B Loan required
quarterly amortization at various amounts during each quarter with all amounts outstanding on
October 3, 2009 being due and payable in full. All the
outstanding amounts under the 2003 Revolver were
due and payable on October 3, 2008. The 2003 Credit Facility was secured by substantially all of
Basics tangible and intangible assets. Basic incurred approximately $5.1 million in debt issuance
costs in obtaining the 2003 Credit Facility.
At Basics option, borrowings under the 2003 Term B Loan bore interest at either (a) the
Alternative Base Rate (i.e. the higher of the banks prime rate of the federal funds rate plus .5% per annum) plus 2.5% or (b) the LIBOR rate plus 3.5%. At December 31, 2003, Basics weighted
average interest rate on its 2003 Term B Loan was 4.67%.
At Basics option,
borrowings under the 2003 Revolver bore interest at either the (a) the
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 1.5% to 2.0% or (b) the Libor rate plus a margin ranging
from 2.5% to 3.0%. The margins varied depending on Basics leverage ration. At December 31, 2003,
Basics margin on Alternative Base Rates and LIBOR tranches was 2.0% and 3.0%, respectively. Fees
on the letters of credit were due quarterly on the outstanding amount of the letters of credit at a
rate ranging from 2.5% to 3.0% for participations fees and .125% for fronting fees. A commitment
fee was due quarterly on the available borrowings under the 2003 Revolver at rates ranging from .5% to .375%.
70
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
At December 31, 2003,
Basic, under its 2003 Revolver, had $5.3 million of outstanding letters of
credit and no amounts outstanding in swing-line loans. At December 31, 2003, Basic had
availability under its 2003 Revolver of $24.7 million.
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, 2005, the aggregate maturities of debt, including capital leases, for the
next five years and thereafter are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Debt |
|
|
Capital Leases |
|
2006 |
|
$ |
1,000 |
|
|
$ |
6,646 |
|
2007 |
|
|
1,000 |
|
|
|
6,024 |
|
2008 |
|
|
1,000 |
|
|
|
5,118 |
|
2009 |
|
|
1,000 |
|
|
|
2,713 |
|
2010 |
|
|
17,000 |
|
|
|
386 |
|
Thereafter |
|
|
85,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
106,000 |
|
|
$ |
20,887 |
|
|
|
|
|
|
|
|
Basics interest expense consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Cash payments for interest |
|
$ |
11,421 |
|
|
$ |
8,159 |
|
|
$ |
3,934 |
|
Commitment and other fees paid |
|
|
185 |
|
|
|
25 |
|
|
|
109 |
|
Amortization of debt issuance costs |
|
|
1,062 |
|
|
|
970 |
|
|
|
694 |
|
Other |
|
|
397 |
|
|
|
560 |
|
|
|
497 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
13,065 |
|
|
$ |
9,714 |
|
|
$ |
5,234 |
|
|
|
|
|
|
|
|
|
|
|
Losses on Extinguishment of Debt
In 2005, Basic recognized a loss on the early extinguishment of debt. Basic wrote-off
unamortized debt issuance costs of approximately $627,000.
In 2003, Basic recognized a loss on the early extinguishment of debt. Basic paid termination
fees of approximately $1.7 million and wrote-off unamortized debt issuance costs of approximately
$3.5 million which resulted in a loss of approximately $5.2 million.
In 2003, Basic adopted Statement of Financial Accounting Standards No. 145 Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections (SFAS
No. 145). The provisions of SFAS No. 145, which are currently applicable to Basic, rescind
Statement No. 4, which required all gains and losses from extinguishment of debt to be aggregated
and classified as an extraordinary item, and instead require that such gains and losses be reported
as ordinary income or loss. Basic now records gains and losses from the extinguishment of debt as
ordinary income or loss.
71
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
6. Income Taxes
Income tax provision (benefit) was allocated as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Income from continuing operations |
|
$ |
26,800 |
|
|
$ |
7,984 |
|
|
$ |
2,772 |
|
Discontinued operations |
|
|
|
|
|
|
(38 |
) |
|
|
13 |
|
Cumulative effect of accounting change |
|
|
|
|
|
|
|
|
|
|
(88 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
26,800 |
|
|
$ |
7,946 |
|
|
$ |
2,697 |
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit) attributable to income (loss) from continuing
operations consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Current |
|
$ |
8,499 |
|
|
$ |
|
|
|
$ |
(68 |
) |
Deferred |
|
|
18,301 |
|
|
|
7,984 |
|
|
|
2,840 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
26,800 |
|
|
$ |
7,984 |
|
|
$ |
2,772 |
|
|
|
|
|
|
|
|
|
|
|
Basic paid federal income taxes of $1,325,000 during 2005. No federal income taxes
were paid or received in 2004. In 2003 Basic received an income tax refund, net, of approximately
$1.5 million.
Reconciliation
between the amount determined by applying the federal statutory rate
of 35% to the income (loss) from continuing operations with the provision
(benefit) for income taxes is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Statutory federal income tax |
|
$ |
25,053 |
|
|
$ |
7,321 |
|
|
$ |
2,007 |
|
Meals and entertainment |
|
|
324 |
|
|
|
265 |
|
|
|
166 |
|
State taxes, net of federal benefit |
|
|
1,415 |
|
|
|
421 |
|
|
|
138 |
|
Change in tax rates |
|
|
|
|
|
|
|
|
|
|
542 |
|
Changes in estimates and other |
|
|
8 |
|
|
|
(23 |
) |
|
|
(81 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
26,800 |
|
|
$ |
7,984 |
|
|
$ |
2,772 |
|
|
|
|
|
|
|
|
|
|
|
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, |
|
|
|
2005 |
|
|
2004 |
|
Current deferred taxes: |
|
|
|
|
|
|
|
|
Receivables allowance |
|
$ |
1,025 |
|
|
$ |
1,148 |
|
Interest rate derivative |
|
|
(186 |
) |
|
|
|
|
EBITDA contingent warrants |
|
|
|
|
|
|
337 |
|
Accrued liabilities |
|
|
5,181 |
|
|
|
3,414 |
|
|
|
|
|
|
|
|
Net current deferred tax asset |
|
$ |
6,020 |
|
|
$ |
4,899 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent deferred taxes: |
|
|
|
|
|
|
|
|
Operating loss and tax credit carryforwards |
|
$ |
1,856 |
|
|
$ |
20,782 |
|
Property and equipment |
|
|
(55,768 |
) |
|
|
(51,194 |
) |
Goodwill and intangibles |
|
|
(1,208 |
) |
|
|
(602 |
) |
Deferred Compensation |
|
|
1,140 |
|
|
|
617 |
|
Asset retirement obligation |
|
|
210 |
|
|
|
175 |
|
Other |
|
|
|
|
|
|
(25 |
) |
|
|
|
|
|
|
|
Net noncurrent deferred tax liability |
|
$ |
(53,770 |
) |
|
$ |
(30,247 |
) |
|
|
|
|
|
|
|
72
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
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, 2005 or 2004.
As of December 31, 2005, Basic had approximately $4.9 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.
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.
On
September 3, 2004, a group of plaintiffs commenced a civil action
against Basic in the District Court of Panola County,
Texas,
123rd Judicial District. The complaint alleges that
Basics operation of a saltwater
disposal well has contaminated both the groundwater and the soil in the surrounding area. The
relief requested in the complaint is monetary damages, injunctive relief, environmental
remediation and a court order requiring Basic to provide drinking water to the community. In
response to the complaint, Basic has retained counsel and filed a
general denial. Basic is in the
beginning stages of discovery and settlement negotiations are
underway. Should negotiations
fail, Basic intends to defend itself vigorously in this action.
On
October 18, 2005, a group of plaintiffs commenced a civil action against Basic in the 123rd
Judicial District Court of Panola County, Texas. The factual basis for this complaint and
relief claims that Basics operation of a saltwater disposal well has contaminated both
the groundwater and the soil in the surrounding area. In addition, this complaint alleges a
wrongful death and personal injuries to unspecified persons. In response to this complaint,
Basic has retained counsel and intends to defend itself vigorously in this action.
On July 25, 2005, a jury returned a verdict in favor of a salt water disposal operator who had
filed suit against Basic. The jury awarded the plaintiff $1.2 million in damages. Basics
insurance company denied coverage of liability. Basic believes that
it has reached a settlement of this matter in connection with a
mediation in March
2006 for $1.0 million. As of December 31, 2005, Basic accrued a $1.0 million loss for this
contingency.
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.
73
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
As of December 31, 2005, the future minimum lease payments under non-cancelable operating
leases are as follows (in thousands):
|
|
|
|
|
Year ended December 31, |
|
|
|
|
2006 |
|
$ |
1,198 |
|
2007 |
|
|
816 |
|
2008 |
|
|
724 |
|
2009 |
|
|
570 |
|
2010 |
|
|
428 |
|
Thereafter |
|
|
463 |
|
Rent expense approximated $7.0 million, $5.6 million, and $3.0 million for 2005, 2004,
and 2003, 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 March 1, 2004 through February 2007, Mr. Huseman will be entitled to an annual
salary of $325,000 and an annual bonus ranging from $50,000 to $325,000 based on the level of
performance objectives achieved by Basic. 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. Similarly, following a change of control of Basic, Mr. Huseman would be entitled to a
lump sum payment of two times his base salary plus his current annual incentive target bonus for
the full year in which the change of control occurred.
Basic has entered into employment agreements with various other executive officers of Basic
that range in term up through 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 six
months annual salary, or 12 to 36 months annual salary if termination is on or following a change
of control of Basic.
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 $125,000, 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 historical claims history.
At December 31, 2005 and December 31, 2004, self-insured risk accruals, net of related
recoveries/receivables totaled approximately $9.5 million and $6.6 million, respectively.
74
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
8. Mandatorily Redeemable Preferred Stock and Stockholders Equity
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 are exercisable in
whole or in part after June 30, 2002 and prior to February 13, 2007.
In
May 2003, the holders of the exercisable EBITDA Contingent Warrants purchased 771,740 shares
of Basics common stock as a price of $.01 per share. See note 11. In October, 2003 Basic issued
3,650,000 shares of its common stock to acquire all the capital sock of FESCO. See note 3.
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 $1.6 million and $1.3 million for the years ended December 31, 2005 and
2004, respectively.
On August 3, 2005, the board of directors of Basic approved a resolution to effect a 5-for-1
stock split of the Companys common stock in the form of a stock dividend resulting in 28,931,935
shares of common stock outstanding, and to amend the Companys certificate of incorporation to
increase the authorized common stock to 80,000,000 shares. The earnings per share information and
all common stock information have been retroactively restated for all periods presented to reflect
this stock split. On September 22, 2005 the pricing committee set the record date and distribution
date for the stock dividend, and the stock dividend was paid on September 26, 2005 to holders of
record on September 23, 2005. The Company retained the current par value of $.01 per share for all
common shares.
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.
Preferred Stock
In June 2002, Basic issued 150,000 shares of mandatorily redeemable Series A 10% Cumulative
Preferred Stock (Series A Preferred Stock) to a group of investors for $15 million or $100 per
share. After deducting fees, this resulted in net proceeds to Basic totaling approximately $14.9
million.
Dividends on each share of Series A Preferred Stock accrued on a daily basis at the rate of
10% per annum of the sum of the Liquidation Value ($100) thereof plus all accrued and unpaid
dividends thereon from and including the date of issuance of such share. All dividends which had
accrued on the Series A Preferred Stock were payable on March 31, June 30, September 30 and
December 31 of each year, beginning September 30, 2002. all dividends which had accrued on Series
A shares outstanding remained as accumulated dividends until paid to the holders thereof.
Basic could redeem all or any portion of the Series A Preferred Stock by paying a price per
share equal to the Liquidation Value ($100) plus all accrued and unpaid dividends plus a premium
equal to 1% of the sum of the Liquidation Value plus all accrued and unpaid dividends on or prior
to March 31, 2008. Basic was required to redeem all Series A Preferred Stock on March 31, 2008
(including accrued and unpaid dividends).
The difference between the $15 million face value of the Series A Preferred Stock and ultimate
redemption value of approximately $26,975,000 (assuming Basic paid no dividends in cash prior to
redemption) was being accreted to the face value of the Series A Preferred Stock from the date of
issuance to the mandatory redemption date of March 31, 2008 utilizing the effective interest
method.
75
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
In connection with the Series A Preferred Stock financing transaction, 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 to the holders of
Series A Preferred Stock, the relative fair value of which (the initial fair value was
approximately $5.9 million, calculated using an option valuation model, and the relative fair value
was approximately $4.4 million) was recorded as a discount on the Series A Preferred and included
in additional pain-in capital. The Series A Preferred Stock discount, consisting of the warrant
fair value of $4.3 million and $58,000 of offering expenses, was being accreted to the Series A
Preferred Stock face value from the date of issuance to the mandatory redemption date of March 31,
2008 utilizing the effective interest method.
In January 2003, Basic issued an additional 9,020 shares of Series A Preferred Stock in lieu
of cash of approximately $902,000 for accrued dividends on the Series A Preferred Stock.
On October 3, 2003, all the Series A Preferred Stock, plus accrued dividends, was converted
into 3,304,085 shares of Basics common stock, at which time the estimated fair value of Basics
common stock was $5.16 per share, pursuant to a share exchange agreement dated September 22, 2003.
This conversion did not include the 3,750,000 common stock warrants which remain outstanding at
December 31, 2005. The excess of the consideration received by the preferred shareholders over the
book value of the preferred stock at the conversion date has been treated as a reduction in net
income available to common stockholders.
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 imposes transfer restrictions on the stockholders prior to
December 21, 2007 (or earlier upon either (i) DLJ Merchant Banking and its affiliates ceasing to
own at least 25% of its percentage based on their initial equity positions, or (ii) the end of a
contractual lock-up period imposed by underwriters after in initial public offering). During this
period, stockholders are generally prohibited from transferring shares to persons other than
permitted assignees. 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 also provided for demand registration rights after an initial
public offering, and piggyback registration rights both in and after an initial public offering of
Basics common stock.
10. Incentive Plan
In May 2003, Basics board of directors and stockholders approved the Basic 2003 Incentive Plan
(the Plan) (as amended effective April 22, 2005) 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
76
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
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 January 26, 2005, March 2, 2005, May 16, 2005, and on December 16, 2005 the board of
directors granted various employees options to purchase 100,000, 865,000, 5,000 and 37,500 shares,
respectively, of common stock of Basic at exercise prices of $5.16, $6.98, $6.98, and $21.01 per
share, respectively. Of the 1,007,500 options granted in 2005, 970,000 options vest over a
five-year period and expire 10 years from the date they are granted. The remaining 37,500 options
vest over a three-year period and expire 10 years from the date they are granted. In connection
with the stock option grants, Basic recorded deferred compensation of approximately $5.2 million
which is being amortized over the related vesting period.
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 the stock options outstanding for the years ended
December 31, 2005, 2004, and 2003 and the changes during the years then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Number |
|
|
average |
|
|
Number |
|
|
average |
|
|
Number |
|
|
average |
|
|
|
of options |
|
|
price |
|
|
of options |
|
|
price |
|
|
of options |
|
|
price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-statutory stock options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, beginning of year |
|
|
1,463,300 |
|
|
$ |
4.17 |
|
|
|
1,290,800 |
|
|
$ |
4.03 |
|
|
|
700,800 |
|
|
$ |
4.00 |
|
Options granted |
|
|
1,007,500 |
|
|
$ |
7.32 |
|
|
|
197,500 |
|
|
$ |
5.16 |
|
|
|
642,500 |
|
|
$ |
4.06 |
|
Options forfeited |
|
|
(25,000 |
) |
|
$ |
6.98 |
|
|
|
(25,000 |
) |
|
$ |
5.16 |
|
|
|
(52,500 |
) |
|
$ |
4.00 |
|
Options exercised |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of year |
|
|
2,445,800 |
|
|
$ |
5.44 |
|
|
|
1,463,300 |
|
|
$ |
4.17 |
|
|
|
1,290,800 |
|
|
$ |
4.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, end of year |
|
|
1,126,665 |
|
|
|
|
|
|
|
872,440 |
|
|
|
|
|
|
|
421,675 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average fair value of
options granted during the year |
|
$ |
8.00 |
|
|
|
|
|
|
$ |
3.14 |
|
|
|
|
|
|
$ |
1.61 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes information about Basics stock options
outstanding and options exercisable at December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding |
|
Options Exercisable |
|
|
Number of |
|
|
|
|
|
|
|
Number of |
|
|
|
|
Options |
|
Weighted Average |
|
Weighted |
|
Options |
|
Weighted |
Range of |
|
Outstanding at |
|
Remaining |
|
Average |
|
Outstanding at |
|
Average |
Exercise Prices |
|
December 31, 2005 |
|
Contractual Life |
|
Exercise Price |
|
December 31, 2005 |
|
Exercise Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$4.00 |
|
|
1,253,300 |
|
|
6.43 years |
|
$ |
4.00 |
|
|
|
1,074,166 |
|
|
$ |
4.00 |
|
$5.16 |
|
|
310,000 |
|
|
8.48 years |
|
$ |
5.16 |
|
|
|
52,499 |
|
|
$ |
5.16 |
|
$6.98 |
|
|
845,000 |
|
|
9.17 years |
|
$ |
6.98 |
|
|
|
|
|
|
$ |
|
|
$21.01 |
|
|
37,500 |
|
|
9.96 years |
|
$ |
21.01 |
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,445,800 |
|
|
|
|
|
|
|
|
|
1,126,665 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11.
EBITDA Contingent Warrants
On
December 21, 2000, Basic issued EBITDA Contingent Warrants to purchase up to an aggregate of
(a) 1,149,705 shares, at $.01 per share, of its common stock as a dividend to stockholders of
record on December 18, 2000 and (b) 287,425 shares, at $0.01 per share, as part of an authorized
issuance to certain
77
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
members of
management of Basic. The determination of the ultimate number of EBITDA Contingent
Warrants that may be exercised was dependent of Basic achieving certain levels of financial
performance in 2001 and 2002. The warrants became exercisable no later than March 31, 2003 based
on the actual financial performance for 2001 and 2002 and expired on May 1, 2003.
On August 23, 2001, Basic issued additional EBITDA Contingent Warrants to purchase up to an
aggregate of 106,310 shares, at $0.01 per share, of Basics common stock as part of an authorized
issuance to certain members of its management. The determination of
the ultimate number of EBITDA
Contingent Warrants that may be exercised was dependent on Basics achieving certain levels of
financial performance in 2001 and 2002. The warrants became exercisable, and were not subject to
forfeiture for termination, no later than March 31, 2003 based on actual financial performance for
2001 and 2002 and expired on May 1, 2003.
In 2003, it was determined that Basic did not meet the financial performance objectives as set
forth in the EBITDA Contingent Warrant grants. However, the board of directors evaluated other
subjective matters regarding these grants and authorized the award of 574,860 warrants to the
stockholders and 196,880 warrants to certain members of management even though the performance
criteria was not met. As a result, Basic recognized the compensation expense of $911,000 related
to the portion of the warrants issued to management in 2003. In 2003, all holders of the warrants
exercised all of their rights and acquired common stock of Basic. The value of the warrants
associated with the common stock dividend was recorded in 2003 when the number of warrants to be
issued was known.
12. Related Party Transactions
Basic provided services and products for workover, maintenance and plugging of existing oil
and gas wells to Southwest Royalties, Inc., an affiliate of a director and other significant
stockholders of Basic, for approximately $0, $140,000, and $1.3 million in 2005, 2004, and 2003,
respectively. Basic had no receivables from this related party as of December 31, 2005 or 2004.
Basic had receivables from employees totaling $65,000 and $ 64,900 as of December 31, 2005 and 2004
respectively.
13. Profit Sharing Plan
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 $468,000, $363,000 and $180,000 in 2005,
2004, and 2003, respectively.
14. 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 20% of the participants deferrals. 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 $56,000,
$0, and $0 in 2005, 2004, and 2003, respectively.
15. Earnings Per Share
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 increased number of shares that would be
outstanding assuming conversion
78
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
of dilutive outstanding securities using the as if converted method. The following
table sets forth the computation of basic and diluted earnings per share. (in thousands, except
share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator (both basic and diluted): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
44,781 |
|
|
$ |
12,932 |
|
|
$ |
(1,986 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued operations, net of tax |
|
|
|
|
|
|
(71 |
) |
|
|
22 |
|
Cumulative effect of accounting change |
|
|
|
|
|
|
|
|
|
|
(151 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders |
|
$ |
44,781 |
|
|
$ |
12,861 |
|
|
$ |
(2,115 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common stock outstanding |
|
|
28,381,853 |
|
|
|
28,094,435 |
|
|
|
22,575,940 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested restricted stock |
|
|
199,058 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for basic earnings per share |
|
|
28,580,911 |
|
|
|
28,094,435 |
|
|
|
22,575,940 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options |
|
|
789,991 |
|
|
|
389,975 |
|
|
|
|
|
Unvested restricted stock |
|
|
638,442 |
|
|
|
837,500 |
|
|
|
|
|
Common stock warrants |
|
|
3,159,035 |
|
|
|
1,333,310 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted earnings per share |
|
|
33,168,379 |
|
|
|
30,655,220 |
|
|
|
22,575,940 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
less preferred stock dividends and accretion |
|
$ |
1.57 |
|
|
$ |
0.46 |
|
|
$ |
(0.09 |
) |
Discontinued operations, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders |
|
$ |
1.57 |
|
|
$ |
0.46 |
|
|
$ |
(0.09 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
less preferred stock dividends and accretion |
|
$ |
1.35 |
|
|
$ |
0.42 |
|
|
$ |
(0.09 |
) |
Discontinued operations, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders |
|
$ |
1.35 |
|
|
$ |
0.42 |
|
|
$ |
(0.09 |
) |
|
|
|
|
|
|
|
|
|
|
The diluted earnings per share calculation for 2003 excludes the effects of all stock
options and common stock warrants as the effects would be anti-dilutive as a result of the net
loss.
16. 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):
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
|
|
2004 |
|
|
2003 |
|
Revenues |
|
$ |
1,705 |
|
|
$ |
550 |
|
Operating costs |
|
|
(1,814 |
) |
|
|
(515 |
) |
Income taxes - deferred |
|
|
38 |
|
|
|
(13 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from discontinued operations, net of tax |
|
$ |
(71 |
) |
|
$ |
22 |
|
|
|
|
|
|
|
|
79
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
17. 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 focuses on 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. These services are carried out in niche markets for jobs requiring a single truck and lower
horsepower.
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.
80
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
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. 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, 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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
104,097 |
|
|
$ |
52,810 |
|
|
$ |
14,808 |
|
|
$ |
9,184 |
|
|
$ |
|
|
|
$ |
180,899 |
|
Direct operating costs |
|
|
(73,244 |
) |
|
|
(34,420 |
) |
|
|
(9,363 |
) |
|
|
(6,586 |
) |
|
|
|
|
|
|
(123,613 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profits |
|
$ |
30,853 |
|
|
$ |
18,390 |
|
|
$ |
5,445 |
|
|
$ |
2,598 |
|
|
$ |
|
|
|
$ |
57,286 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
$ |
9,100 |
|
|
$ |
5,201 |
|
|
$ |
2,575 |
|
|
$ |
850 |
|
|
$ |
487 |
|
|
$ |
18,213 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures,
(excluding acquisitions) |
|
$ |
13,217 |
|
|
$ |
6,298 |
|
|
$ |
676 |
|
|
$ |
2,412 |
|
|
$ |
898 |
|
|
$ |
23,501 |
|
Identifiable assets |
|
$ |
102,948 |
|
|
$ |
73,841 |
|
|
$ |
10,387 |
|
|
$ |
31,322 |
|
|
$ |
84,155 |
|
|
$ |
302,653 |
|
81
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
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, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Segment profits |
|
$ |
176,909 |
|
|
$ |
99,342 |
|
|
$ |
57,286 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses |
|
|
(55,411 |
) |
|
|
(37,186 |
) |
|
|
(22,722 |
) |
Depreciation and amortization |
|
|
(37,072 |
) |
|
|
(28,676 |
) |
|
|
(18,213 |
) |
Gain (loss) on disposal of assets |
|
|
222 |
|
|
|
(2,616 |
) |
|
|
(391 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
84,648 |
|
|
$ |
30,864 |
|
|
$ |
15,960 |
|
|
|
|
|
|
|
|
|
|
|
18. Accrued Expenses
The accrued expenses are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
|
|
|
|
|
|
|
|
Compensation related |
|
$ |
10,576 |
|
|
$ |
6,764 |
|
Workers compensation self-insured risk reserve |
|
|
7,461 |
|
|
|
5,469 |
|
Health self-insured risk reserve |
|
|
2,200 |
|
|
|
1,490 |
|
Accrual for receipts |
|
|
1,841 |
|
|
|
903 |
|
Authority for expenditure accrual |
|
|
3,052 |
|
|
|
879 |
|
Ad valorem taxes |
|
|
935 |
|
|
|
845 |
|
Sales tax |
|
|
2,407 |
|
|
|
692 |
|
Insurance obligations |
|
|
673 |
|
|
|
586 |
|
Purchase order accrual |
|
|
96 |
|
|
|
409 |
|
Professional fee accrual |
|
|
1,079 |
|
|
|
392 |
|
Diesel tax accrual |
|
|
385 |
|
|
|
336 |
|
Acquired contingent earnout obligation |
|
|
|
|
|
|
273 |
|
Retainers |
|
|
1,042 |
|
|
|
250 |
|
Fuel accrual |
|
|
368 |
|
|
|
317 |
|
Accrued interest |
|
|
391 |
|
|
|
232 |
|
Contingent liability |
|
|
1,000 |
|
|
|
|
|
Other |
|
|
42 |
|
|
|
649 |
|
|
|
|
|
|
|
|
|
|
$ |
33,548 |
|
|
$ |
20,486 |
|
|
|
|
|
|
|
|
19. Supplemental Schedule of Non-Cash Investing and Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, |
|
|
2005 |
|
2004 |
|
2003 |
|
|
|
|
|
|
(In thousands) |
|
|
|
|
Capital leases issued for equipment |
|
$ |
10,334 |
|
|
$ |
10,472 |
|
|
$ |
10,782 |
|
Preferred stock dividend |
|
$ |
|
|
|
$ |
|
|
|
$ |
1,525 |
|
Preferred stock issued to pay accrued dividends |
|
$ |
|
|
|
$ |
|
|
|
$ |
902 |
|
Accretion of preferred stock discount |
|
$ |
|
|
|
$ |
|
|
|
$ |
3,424 |
|
Common stock issued for FESCO acquisition |
|
$ |
|
|
|
$ |
|
|
|
$ |
18,827 |
|
Common stock issued for preferred stock |
|
$ |
|
|
|
$ |
|
|
|
$ |
17,029 |
|
Vehicle rebate accrual |
|
$ |
|
|
|
$ |
709 |
|
|
$ |
|
|
Asset retirement obligation additions |
|
$ |
74 |
|
|
$ |
21 |
|
|
$ |
|
|
82
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
20. Quarterly Financial Data (Unaudited)
The following table summarizes results for each of the four quarters in the years ended
December 31, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
Year |
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 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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2004: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
67,603 |
|
|
$ |
74,262 |
|
|
$ |
83,714 |
|
|
$ |
85,923 |
|
|
$ |
311,502 |
|
Segment profits |
|
$ |
21,548 |
|
|
$ |
23,717 |
|
|
$ |
26,605 |
|
|
$ |
27,472 |
|
|
$ |
99,342 |
|
Income from continuing operations |
|
$ |
2,633 |
|
|
$ |
3,369 |
|
|
$ |
3,800 |
|
|
$ |
3,130 |
|
|
$ |
12,932 |
|
Net income available to common stockholders |
|
$ |
2,685 |
|
|
$ |
3,405 |
|
|
$ |
3,641 |
|
|
$ |
3,130 |
|
|
$ |
12,861 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share of common stock (a): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations |
|
$ |
0.09 |
|
|
$ |
0.12 |
|
|
$ |
0.14 |
|
|
$ |
0.11 |
|
|
$ |
0.46 |
|
Net income available to common stockholders |
|
$ |
0.10 |
|
|
$ |
0.12 |
|
|
$ |
0.13 |
|
|
$ |
0.11 |
|
|
$ |
0.46 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share of common stock (a): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations |
|
$ |
0.09 |
|
|
$ |
0.11 |
|
|
$ |
0.12 |
|
|
$ |
0.10 |
|
|
$ |
0.42 |
|
Net income (loss) available to common stockholders |
|
$ |
0.09 |
|
|
$ |
0.11 |
|
|
$ |
0.12 |
|
|
$ |
0.10 |
|
|
$ |
0.42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
28,094 |
|
|
|
28,094 |
|
|
|
28,094 |
|
|
|
28,094 |
|
|
|
28,094 |
|
Diluted |
|
|
30,391 |
|
|
|
31,270 |
|
|
|
31,493 |
|
|
|
31,789 |
|
|
|
30,655 |
|
|
|
|
(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. |
21. Subsequent Events
On January 31, 2006, Basic acquired all of the outstanding capital stock of LeBus Oil Field
Service Co. for an acquisition price of $26 million, subject to adjustments. The acquisition will
operate in Basics fluid services line of business in the Ark-La-Tex division.
83
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
On February 28, 2006, Basic acquired substantially all of the operating assets of G&L
Tool, Ltd. for total consideration of $58 million cash. This acquisition will operate in Basics
drilling and completion line of business. The purchase agreement also contained an earn-out
agreement based on annual EBITDA targets.
84
BASIC ENERGY SERVICES, INC.
December 31, 2005, 2004, and 2003
Schedule II - Valuation and Qualifying Accounts
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions |
|
|
|
|
|
|
|
|
Balance at |
|
Charged to |
|
Charged to |
|
|
|
|
|
Balance at |
|
|
Beginning of |
|
Costs and |
|
Other |
|
Deductions |
|
End of |
Description |
|
Period |
|
Expenses (a) |
|
Accounts (b) |
|
(c) |
|
Period |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Bad Debt |
|
$ |
501 |
|
|
$ |
1,279 |
|
|
$ |
375 |
|
|
$ |
(197 |
) |
|
$ |
1,958 |
|
|
|
|
(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 |
85
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, 2005, 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.
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.
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, 2005.
86
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.
|
|
|
Exhibit |
|
|
No. |
|
Description |
1.1*
|
|
Underwriting Agreement,
dated December 8, 2005,
among Basic Energy
Services, Inc. (the
Company), the selling
stockholders named therein
and Goldman, Sachs & Co.
and Credit Suisse First
Boston LLC as
representatives of the
several underwriters named
therein. (Incorporated by
reference to Exhibit 1.1
to the Companys Current
Report on Form 8-K (SEC
File No. 001-32693), filed
on December 14, 2005) |
|
|
|
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) |
|
|
|
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*
|
|
Employment Agreement dated
as of March 1, 2004 with
Kenneth V. Huseman.
(Incorporated by reference
to Exhibit 10.2 of the
Companys Registration
Statement on Form S-1 (SEC
File No. 333-127517),
filed on August 12, 2005) |
|
|
|
10.3*
|
|
Employment Agreement dated
as of May 1, 2003 with Dub
W. Harrison.
(Incorporated by reference
to Exhibit 10.3 of the
Companys Registration
Statement on Form S-1 (SEC
File No. 333-127517),
filed on August 12, 2005) |
|
|
|
10.4*
|
|
Employment Agreement dated
as of May 1, 2003 with
Charles W. Swift.
(Incorporated by reference
to Exhibit 10.4 of the
Companys Registration
Statement on Form S-1 (SEC
File No. 333-127517),
filed on August 12, 2005) |
|
|
|
10.5*
|
|
Employment Agreement dated
as of May 1, 2003 with
James J. Carter.
(Incorporated by reference
to Exhibit 10.5 of the
Companys Registration
Statement on Form S-1 (SEC
File No. 333-127517),
filed on August 12, 2005) |
87
|
|
|
Exhibit |
|
|
No. |
|
Description |
10.6*
|
|
Employment Agreement dated
as of January 26, 2005
with Alan Krenek.
(Incorporated by reference
to Exhibit 10.6 of the
Companys Registration
Statement on Form S-1 (SEC
File No. 333-127517),
filed on August 12, 2005) |
|
|
|
10.7*
|
|
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) |
|
|
|
10.8*
|
|
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) |
|
|
|
10.9*
|
|
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) |
|
|
|
10.10*
|
|
Third Amended and Restated
Credit Agreement dated as
of October 3, 2003,
amended and restated as of
December 15, 2005, among
the Company, the
subsidiary guarantors
party thereto, Bank of
America, N.A., as
syndication agent,
Hibernia National Bank, as
co-documentation agent,
BNP Paribas, as
co-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
December 20, 2005) |
|
|
|
10.11*
|
|
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) |
|
|
|
10.12*
|
|
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) |
|
|
|
10.13*
|
|
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) |
|
|
|
10.14*
|
|
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) |
|
|
|
10.15*
|
|
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) |
|
|
|
10.16*
|
|
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) |
|
|
|
10.17*
|
|
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) |
|
|
|
10.18*
|
|
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) |
88
|
|
|
Exhibit |
|
|
No. |
|
Description |
10.19*
|
|
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) |
|
|
|
10.20*
|
|
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) |
|
|
|
10.21*
|
|
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) |
|
|
|
10.22*
|
|
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) |
|
|
|
10.23*
|
|
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) |
|
|
|
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 |
|
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32.1
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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 |
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32.2
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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 |
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* |
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Incorporated by reference |
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Management contract or compensatory plan or arrangement |
89
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
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BASIC ENERGY SERVICES, INC. |
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By: |
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/s/ Kenneth V. Huseman |
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Name:
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Kenneth V. Huseman |
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Title:
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President, Chief Executive Officer and Director |
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Date:
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March 22, 2006 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the capacities and on the
dates indicated.
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Signature |
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Date |
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/s/ Kenneth V. Huseman |
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President, Chief Executive Officer and Director |
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March 22, 2006 |
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(Principal Executive Officer)
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/s/ Alan
Krenek
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Chief Financial Officer (Principal Financial |
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March 22, 2006 |
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Officer and Principal Accounting Officer)
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/s/ Steven A. Webster
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Chairman of the Board
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March 22, 2006 |
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/s/ James S. DAgostino, Jr.
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Director
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March 22, 2006 |
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/s/ William E. Chiles
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Director
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March 22, 2006 |
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/s/ Robert F. Fulton
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Director
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March 22, 2006 |
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/s/ Sylvester P. Johnson, IV
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Director
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March 22, 2006 |
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/s/ H.H. Wommack, III
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Director
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March 22, 2006 |
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/s/ Thomas P. Moore, Jr.
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Director
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March 22, 2006 |
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90
EXHIBIT INDEX
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Exhibit |
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No. |
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Description |
1.1*
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Underwriting Agreement,
dated December 8, 2005,
among Basic Energy
Services, Inc. (the
Company), the selling
stockholders named therein
and Goldman, Sachs & Co.
and Credit Suisse First
Boston LLC as
representatives of the
several underwriters named
therein. (Incorporated by
reference to Exhibit 1.1
to the Companys Current
Report on Form 8-K (SEC
File No. 001-32693), filed
on December 14, 2005) |
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3.1*
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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) |
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3.2*
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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) |
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4.1*
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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) |
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10.1*
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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) |
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10.2*
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Employment Agreement dated
as of March 1, 2004 with
Kenneth V. Huseman.
(Incorporated by reference
to Exhibit 10.2 of the
Companys Registration
Statement on Form S-1 (SEC
File No. 333-127517),
filed on August 12, 2005) |
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10.3*
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Employment Agreement dated
as of May 1, 2003 with Dub
W. Harrison.
(Incorporated by reference
to Exhibit 10.3 of the
Companys Registration
Statement on Form S-1 (SEC
File No. 333-127517),
filed on August 12, 2005) |
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10.4*
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Employment Agreement dated
as of May 1, 2003 with
Charles W. Swift.
(Incorporated by reference
to Exhibit 10.4 of the
Companys Registration
Statement on Form S-1 (SEC
File No. 333-127517),
filed on August 12, 2005) |
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10.5*
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Employment Agreement dated as of May 1, 2003 with James J. Carter.
(Incorporated by reference to Exhibit 10.5 of the Companys
Registration Statement on Form S-1 (SEC File No. 333-127517),
filed on August 12, 2005) |
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Exhibit |
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No. |
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Description |
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10.6*
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Employment Agreement dated as of January 26, 2005 with Alan
Krenek. (Incorporated by reference to Exhibit 10.6 of the
Companys Registration Statement on Form S-1 (SEC File No.
333-127517), filed on August 12, 2005) |
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10.7*
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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) |
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10.8*
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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) |
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10.9*
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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) |
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10.10*
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Third Amended and Restated Credit Agreement dated as of October 3,
2003, amended and restated as of December 15, 2005, among the
Company, the subsidiary guarantors party thereto, Bank of America,
N.A., as syndication agent, Hibernia National Bank, as
co-documentation agent, BNP Paribas, as co-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 December 20, 2005) |
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10.11*
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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) |
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10.12*
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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) |
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10.13*
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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) |
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10.14*
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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) |
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10.15*
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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) |
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10.16*
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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) |
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10.17*
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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) |
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10.18*
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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) |
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Exhibit |
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No. |
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Description |
10.19*
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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) |
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10.20*
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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) |
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10.21*
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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) |
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10.22*
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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) |
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10.23*
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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) |
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21.1
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Subsidiaries of the Company. |
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23.1
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Consent of KPMG LLP |
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31.1
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Certification by Chief Executive Officer required by Rule 13a-14(a)
and 15d-14(a) under the Exchange Act |
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31.2
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Certification by Chief Financial Officer required by Rule 13a-14(a)
and 15d-14(a) under the Exchange Act |
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32.1
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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 |
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32.2
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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 |
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* |
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Incorporated by reference |
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Management contract or compensatory plan or arrangement |