e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
December 31,
2009
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OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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Commission file number
001-32693
Basic Energy Services,
Inc.
(Exact name of registrant as
specified in its charter)
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Delaware
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54-2091194
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(State or other jurisdiction
of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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500 W. Illinois, Suite 100
Midland, Texas
(Address of principal executive
offices)
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79701
(Zip code)
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Registrants telephone number, including area code:
(432) 620-5500
Securities registered pursuant to Section 12(b) of the
Act:
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Common Stock, $0.01 par
value per share
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New York Stock
Exchange
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(Title of Class)
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(Name of each exchange on which
registered)
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Securities registered pursuant to Section 12(g) of the
Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes o No þ
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
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 whether the registrant has submitted
electronically and posted on its corporate Website, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such
files). Yes o No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
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Large
accelerated
filer o
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Accelerated
filer þ
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Non-accelerated
filer o
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Smaller
reporting
company o
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(Do not check if a smaller reporting company)
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
$139,452,741 as of June 30, 2009, the last business day of
the registrants most recently completed second fiscal
quarter (based on a closing price of $6.83 per share and
20,417,678 shares held by non-affiliates).
There were 40,654,989 shares of the registrants
common stock outstanding as of February 22, 2010.
Documents incorporated by reference: Portions of
the definitive proxy statement for the registrants Annual
Meeting of Stockholders (to be filed within 120 days of the
close of the registrants fiscal year) are incorporated by
reference into Part III.
BASIC
ENERGY SERVICES, INC.
Index to
Form 10-K
i
CAUTIONARY
STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS
This annual report contains certain statements that are, or may
be deemed to be, forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933,
as amended, and Section 21E of the Securities Exchange Act
of 1934, as amended, or the Exchange Act. We have based these
forward-looking statements largely on our current expectations
and projections about future events and financial trends
affecting the financial condition of our business. These
forward-looking statements are subject to a number of risks,
uncertainties and assumptions, including, among other things,
the risk factors discussed in Item 1A of this annual report
and other factors, most of which are beyond our control.
The words believe, estimate,
expect, anticipate, project,
intend, plan, seek,
could, should, may,
potential 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 natural gas
prices, and any related changes in expenditures by our customers;
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the effects of future acquisitions on our business;
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changes in customer requirements in markets or industries we
serve;
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competition within our industry;
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general economic and market conditions;
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our access to current or future financing arrangements;
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our ability to replace or add workers at economic rates; and
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environmental and other governmental regulations.
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Our forward-looking statements speak only as of the date of this
annual report. Unless otherwise required by law, we undertake no
obligation to publicly update or revise any forward-looking
statements, whether as a result of new information, future
events or otherwise.
This annual report includes market share data, 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 Baker Hughes Incorporated,
the Association of Energy Service Companies (AESC),
and the Energy Information Administration of the
U.S. Department of Energy (EIA). Industry
surveys and publications, consultant surveys and forecasts
generally state that the information contained therein has been
obtained from sources believed to be reliable. Although we
believe such information is accurate and reliable, we have not
independently verified any of the data from third party sources
cited or used for our managements industry estimates, nor
have we ascertained the underlying economic assumptions relied
upon therein. For example, the number of onshore well servicing
rigs in the U.S. could be lower than our estimate to the
extent our two larger competitors have continued to report as
stacked rigs equipment that is not actually complete or subject
to refurbishment. Statements as to our position relative to our
competitors or as to market share refer to the most recent
available data.
1
PART I
ITEMS 1.
AND 2. BUSINESS AND PROPERTIES
General
We provide a wide range of well site services to oil and natural
gas drilling and producing companies, including well servicing,
fluid services and well site construction services, completion
and remedial services and contract drilling. These services are
fundamental to establishing and maintaining the flow of oil and
natural 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 major United States onshore
oil and natural gas producing regions located in Texas, New
Mexico, Oklahoma, Arkansas, Kansas, Louisiana, Wyoming, North
Dakota, Colorado, Utah and Montana. We provide our services to a
diverse group of over 2,000 oil and natural gas companies. We
operate the third-largest fleet of well servicing rigs (also
commonly referred to as workover rigs) in the United States,
representing 13% of the overall available U.S. fleet, with
our two larger competitors controlling approximately 24% and
19%, respectively, according to the AESC and other publicly
available data.
We revised our business segments beginning in the first quarter
of 2008, and in connection therewith restated the corresponding
items of segment information for earlier periods. Our current
operating segments are Well Servicing, Fluid Services,
Completion and Remedial Services, and Contract Drilling. These
segments were selected based on changes in managements
resource allocation and performance assessment in making
decisions regarding the Company. Contract Drilling was
previously included in our Well Servicing segment. Well Site
Construction Services is consolidated with our Fluid Services
segment. The following is a description of our current business
segments:
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Well Servicing. Our well servicing segment
(30% of our revenues in 2009) currently operates our fleet
of 405 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 natural gas.
These services are performed to establish, maintain and improve
production throughout the productive life of an oil and natural
gas well and to plug and abandon a well at the end of its
productive life. Our well servicing equipment and capabilities
also facilitate most other services performed on a well.
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Fluid Services. Our fluid services segment
(41% of our revenues in 2009) currently utilizes our fleet
of 791 fluid service trucks and related assets, including
specialized tank trucks, storage tanks, water wells, disposal
facilities, construction and other related equipment. These
assets provide, transport, store and dispose of a variety of
fluids, as well as provide well site construction and
maintenance services. These services are required in most
workover, completion and remedial projects and are routinely
used in daily producing well operations.
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Completion and Remedial Services. Our
completion and remedial services segment (26% of our revenues in
2009) currently operates our fleet of pressure pumping
units, an array of specialized rental equipment and fishing
tools, air compressor packages specially configured for
underbalanced drilling operations, and cased-hole wireline
units. The largest portion of this business segment consists of
pressure pumping services focused on cementing, acidizing and
fracturing services in niche markets. We entered the rental and
fishing tool business through an acquisition in the first
quarter of 2006.
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Contract Drilling. Our contract drilling
segment (3% of our revenues in 2009) currently operates
nine drilling rigs and related equipment. We use these assets to
penetrate the earth to a desired depth and initiate production
from a well. We greatly increased our presence in this line of
business through the Sledge Drilling acquisition in the second
quarter of 2007.
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Financial information about our segments is included in
Note 15, Business Segment Information, of the Notes
to Consolidated Financial Statements, included in Item 8,
Financial Statements and Supplementary Data, of this
Annual Report on
Form 10-K.
2
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
405 well servicing rigs represents the third-largest fleet
in the United States and the second largest in our geographic
footprint, and our goal is to be one of the top two providers of
well site services in each of our core operating areas. Our
market position allows us to expand the range of services
performed on a well throughout its life, such as drilling,
maintenance, workover, completion and plugging and abandonment
services.
Modern and Active Well Servicing Fleet. We
operate a modern and active fleet of well servicing rigs. We
believe over 75% of the active U.S. well servicing rig
fleet was built prior to 1985. Greater than 50% of our rigs at
December 31, 2009 were either 2000 model year or newer, or
have undergone major refurbishments during the last five years.
Driven by our desire to maintain one of the most efficient,
reliable and safest fleets in the industry, we took delivery of
our final two newbuild well service rigs during 2009 as part of
a 134-rig newbuild commitment which started in October 2004. 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 73 of our rigs since the beginning of 2005.
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 major
United States onshore oil and natural gas producing regions
located in Texas, New Mexico, Oklahoma, Arkansas, Kansas,
Louisiana, Wyoming, North Dakota, Colorado, Utah and Montana. We
operate in states that accounted for approximately 58% of the
approximately 900,000 existing onshore oil and natural gas wells
in the 48 contiguous states and approximately 82% of onshore oil
production and 90% of onshore natural gas production in 2009. 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 natural gas production
areas that include both the highest concentration of existing
oil and natural 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
2,000 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 115 area offices position us to market
our full range of well site services to our existing customers.
By utilizing a wider range of our services, our customers can
use fewer service providers, which enables them to reduce their
administrative costs and simplify their logistics. Furthermore,
offering a broader range of services allows us to capitalize on
our existing customer base and management structure to grow
within existing markets, generate more business from existing
customers, and increase our operating profits as we spread our
overhead costs over a larger revenue base.
Decentralized Management with Strong Corporate
Infrastructure. Our corporate group is
responsible for maintaining a unified infrastructure to support
our diversified operations through standardized financial and
accounting, safety, environmental and maintenance processes and
controls. Below our corporate level, we operate a decentralized
operational organization in which our nine regional or division
managers are responsible for their operations, including asset
management, cost control, policy compliance and training and
other aspects of quality control. With an average of over
30 years of industry experience, each regional manager has
extensive knowledge of the customer base, job requirements and
working conditions in each local market. Below our nine regional
or division managers, our 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.
3
Our
Business Strategy
We intend to increase our shareholder value by pursuing the
following strategies:
Establish and Maintain Leadership Position in Core Operating
Areas. We strive to establish and maintain market
leadership positions within our core operating areas. To achieve
this goal, we maintain close customer relationships, seek to
expand the breadth of our services and offer high quality
services and equipment that meet the scope of customer
specifications and requirements. In addition, our significant
presence in our core operating areas facilitates employee
retention and attraction, a key factor for success in our
business. Our significant presence in our 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. We typically
enter into new markets through the acquisition of businesses
with strong management teams that will allow us to expand within
these markets. Management of acquired companies often remain
with us and retain key positions within our organization, which
enhances our attractiveness as an acquisition partner. We have a
record of successfully implementing this strategy. During the
past three years, we have made 14 acquisitions including:
2007
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JetStar Consolidated Holdings, Inc., a pressure pumping company
operating in our completion and remedial line of business;
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Sledge Drilling Holding Corp., a contract drilling company
operating in our contract drilling line of business; and
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2008
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Azurite Services Company, Inc., Azurite Leasing Company, LLC and
Freestone Disposal, L.P. (collectively Azurite), a
fluid service business operating in our Ark-La-Tex and
Mid-Continent regions.
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In 2009 there were no significant acquisitions.
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 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 natural 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.
4
General
Industry Overview
Demand for services offered by our industry is a function of our
customers willingness to make operating and capital
expenditures to explore for, develop and produce hydrocarbons in
the U.S., which in turn is affected by current and expected
levels of oil and natural gas prices. As oil and natural gas
prices increased from 2005 through the first half of 2008, oil
and natural gas companies increased their drilling and workover
activities. In the last part of 2008, oil and natural gas prices
declined rapidly, resulting in decreased drilling and workover
activities. During 2009, oil prices increased, which resulted in
slight increases in drilling and workover activities in the
oil-driven markets as the year progressed. However, natural gas
prices continued to decline significantly through most of 2009 ,
which resulted in decreased activity in the natural gas-driven
markets.
The table below sets forth average closing prices for the
Cushing WTI Spot Oil Price and the EIA average wellhead price
for natural gas since 2005. The December 2009 average wellhead
price for natural gas was not available at the time this report
was filed; therefore the average price through November 2009 was
used:
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Cushing WTI Spot
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Average Wellhead Price
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Period
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Oil Price ($/bbl)
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Natural Gas ($/mcf)
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1/1/05 12/31/05
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56.64
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7.51
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1/1/06 12/31/06
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66.05
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6.42
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1/1/07 12/31/07
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72.34
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6.38
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1/1/08 12/31/08
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99.67
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8.07
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1/1/09 12/31/09
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61.65
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3.65
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Source: U.S. Department of Energy.
Increased expenditures for exploration and production activities
generally drives the increased demand for our services. Rising
oil and natural gas prices from 2005 through the first half of
2008 and the corresponding increase in onshore oil exploration
and production spending led to expanded drilling and well
service activity, as the U.S. land-based drilling rig count
increased approximately 4% during 2007. With the rapid decline
in oil and natural gas prices in the second half of 2008 there
was a decrease in the land-based drilling rig count of
approximately 3% during 2008 and 31% during 2009, according to
Baker Hughes. The decrease in oil and natural gas prices in
recent months coupled with the buildup of drilling and workover
rig counts in recent years is resulting in both lower
utilization of those rigs and decreases in the rates being
charged.
Exploration and production spending is generally categorized as
either an operating expenditure or a capital expenditure.
Activities designed to add hydrocarbon reserves are classified
as capital expenditures, while those associated with maintaining
or accelerating production are categorized as operating
expenditures.
Capital expenditures by oil and natural gas companies tend to be
relatively sensitive to volatility in oil or natural gas prices
because project decisions are tied to a return on investment
spanning a number of years. As such, capital expenditure
economics often require the use of commodity price forecasts
which may prove inaccurate in the amount of time required to
plan and execute a capital expenditure project (such as the
drilling of a deep well). When commodity prices are depressed
for even a short period of time, capital expenditure projects
are routinely deferred until prices return to an acceptable
level.
In contrast, both mandatory and discretionary operating
expenditures are substantially more stable than exploration and
drilling expenditures. Mandatory operating expenditure projects
involve activities that cannot be avoided in the short term,
such as regulatory compliance, safety, contractual obligations
and projects to maintain the well and related infrastructure in
operating condition (for example, repairs to a central tank
battery, downhole pump, saltwater disposal system or gathering
system). Discretionary operating expenditure projects may not be
critical to the short-term viability of a lease or field but
these projects are relatively insensitive to commodity price
volatility. Discretionary operating expenditure work is
evaluated according to a simple short-term payout criterion
which is far less dependent on commodity price forecasts.
Our business is influenced substantially by both operating and
capital expenditures by oil and natural gas companies. Because
existing oil and natural gas wells require ongoing spending to
maintain production,
5
expenditures by oil and natural gas companies for the
maintenance of existing wells are relatively stable and
predictable. In contrast, capital expenditures by oil and
natural gas companies for exploration and drilling are more
directly influenced by current and expected oil and natural 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 also 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 natural gas well, include:
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maintenance work involving removal, repair and replacement of
down-hole equipment and returning the well to production after
these operations are completed;
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hoisting tools and equipment required by the operation into and
out of the well, or removing equipment from the well bore, to
facilitate specialized production enhancement and well repair
operations performed by other oilfield service
companies; and
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plugging and abandonment services when a well has reached the
end of its productive life.
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Regardless of the type of work being performed on the well, our
personnel and rigs are often the first to arrive at the well
site and the last to leave. We generally charge our customers an
hourly rate for these services, which rate varies based on a
number of considerations including market conditions in each
region, the type of rig and ancillary equipment required, and
the necessary personnel.
Our fleet included 405 well servicing rigs as of
December 31, 2009, including 134 newbuilds since October
2004 and 73 rebuilds since the beginning of 2005. Our well
servicing rigs operate from facilities in Texas, Wyoming,
Oklahoma, North Dakota, New Mexico, Louisiana, Colorado,
Arkansas, Utah and Montana. Our well servicing rigs are mobile
units that generally operate within a radius of approximately 75
to 100 miles from their respective bases. The majority of
our well servicing segment consists of land-based equipment. We
also own four inland well servicing barges. 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, 2009. 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.
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Market Area
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Permian
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Gulf
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Ark-La-
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Mid-
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Rocky
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Rig Type
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Rated Capacity
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Basin
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Coast
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Tex
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Continent
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Mountain
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Stacked
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Total
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Swab
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N/A
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4
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1
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5
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4
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0
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0
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14
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Light Duty
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<90 tons
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3
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1
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0
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10
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0
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10
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24
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Medium Duty
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³90<125
tons
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107
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36
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20
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51
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50
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35
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299
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Heavy Duty
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³125
tons
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28
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4
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4
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3
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8
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9
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56
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24-Hour
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³125
tons
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2
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3
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0
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1
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0
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2
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8
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Inland Barge
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³125
tons
|
|
|
0
|
|
|
|
4
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
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|
|
Total
|
|
|
|
|
144
|
|
|
|
49
|
|
|
|
29
|
|
|
|
69
|
|
|
|
58
|
|
|
|
56
|
|
|
|
405
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
We operate a total of 405 well servicing rigs, the third
largest fleet in the United States. Based on their most recent
publicly available information, Key Energy Services is our
largest competitor with an estimated total of 743 domestic rigs
and Nabors is the second largest with an estimated 592 domestic
rigs. Our only other competitors operating more than 100 rigs
are Complete Production Services with an estimated 267 domestic
rigs and Forbes
6
Energy Services with an estimated 160 domestic rigs. Excluding
the rigs operated by Nabors in California where we do not
compete, we believe we have the second largest rig fleet in the
United States.
The total number of rigs owned by us and the four other
companies referenced above is approximately 2,167, or 70% of the
available fleet owned by member companies of the AESC, the major
trade association of well site service providers. The remaining
30% of the well servicing rigs are owned by more than 100 local
and regional companies. The December 2009 monthly activity
survey conducted by the AESC indicated that 53% of the rigs
owned were active.
Maintenance. Regular maintenance is generally
required throughout the life of a well to sustain optimal levels
of oil and natural 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
natural 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 natural gas prices. Demand
for our maintenance services is affected by changes in the total
number of producing oil and natural 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 natural gas
fields and, to a lesser degree, the actual prices received for
oil and natural gas. Well operators cannot delay all maintenance
work without a significant impact on production. Operators may,
however, choose to shut in producing wells temporarily when oil
or natural gas prices are too low to justify additional
expenditures, including maintenance.
Workover. In addition to periodic maintenance,
producing oil and natural gas wells occasionally require major
repairs or modifications called workovers, which are typically
more complex and more time consuming than maintenance
operations. Workover services include extensions of existing
wells to drain new formations either through perforating the
well casing to expose additional productive zones not previously
produced, deepening well bores to new zones or the drilling of
lateral well bores to improve reservoir drainage patterns. Our
workover rigs are also used to convert former producing wells to
injection wells through which water or carbon dioxide is then
pumped into the formation for enhanced oil recovery operations.
Workovers also include major subsurface repairs such as repair
or replacement of well casing, recovery or replacement of tubing
and removal of foreign objects from the well bore. These
extensive workover operations are normally performed by a
workover rig with additional 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 require additional
auxiliary equipment. The demand for workover services is
sensitive to oil and natural gas producers intermediate
and long-term expectations for oil and natural gas prices. As
oil and natural gas prices increase, the level of workover
activity tends to increase as oil and natural 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 natural 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
7
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
natural gas prices.
Plugging and Abandonment. Well servicing rigs
are also used in the process of permanently closing oil and
natural 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 natural 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, storage and construction services. These
services are required in most workover, completion and remedial
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
natural 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;
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|
operation of company-owned fresh water and brine source wells
and of non-hazardous wastewater disposal wells; and
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preparation, construction and maintenance of access roads,
drilling locations, and production facilities.
|
This segment utilizes our fleet of fluid service 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, 2009:
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|
|
|
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|
|
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|
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|
|
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Market Area
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|
Rocky
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|
Permian
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|
Ark-La-
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|
Gulf
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|
Mid-
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|
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|
Mountain
|
|
Basin
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|
Tex
|
|
Coast
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|
Continent
|
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Total
|
|
Fluid Service Trucks
|
|
|
101
|
|
|
|
248
|
|
|
|
221
|
|
|
|
146
|
|
|
|
75
|
|
|
|
791
|
|
Salt Water Disposal Wells
|
|
|
0
|
|
|
|
21
|
|
|
|
25
|
|
|
|
8
|
|
|
|
11
|
|
|
|
65
|
|
Fresh/Brine Water Stations
|
|
|
0
|
|
|
|
36
|
|
|
|
0
|
|
|
|
2
|
|
|
|
0
|
|
|
|
38
|
|
Fluid Storage Tanks
|
|
|
267
|
|
|
|
534
|
|
|
|
1,129
|
|
|
|
273
|
|
|
|
213
|
|
|
|
2,416
|
|
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, completion and
remedial 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 natural gas wells. Most oil and natural
gas fields produce residual salt water in conjunction with oil
or natural gas. Fluid service trucks pick up this fluid from
tank batteries at the well site and
8
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 outperform 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, completion and remedial activities also provide the
opportunity for higher operating margins from tank rentals and
fluid sales. Drilling and workover jobs typically require fresh
or brine water for drilling mud or circulating fluid used during
the job. Completion and workover procedures often also require
large volumes of water for fracturing operations, a process of
stimulating a well hydraulically to increase production. Spent
mud and flowback fluids are required to be transported from the
well site to an approved disposal facility.
Competitors in the fluid services industry are mostly small,
regionally focused companies. There are currently no companies
that have a dominant position on a nationwide basis. The level
of activity in the fluid services industry is comprised of a
relatively stable demand for services related to the maintenance
of producing wells and a highly variable demand for services
used in the drilling and completion of new wells. As a result,
the level of onshore drilling activity significantly affects the
level of activity in the fluid services industry. While there
are no industry-wide statistics, the Baker Hughes Land Drilling
Rig Count is an indirect indication of demand for fluid services
because it directly reflects the level of onshore drilling
activity.
Fluid Services. We currently own and operate
791 fluid service 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 service trucks are generally provided to
oilfield operators within a
50-mile
radius of our nearest yard.
Salt Water Disposal Well Services. We own
disposal wells that are permitted to dispose of salt water and
incidental non-hazardous oil and natural 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
natural gas wells produce varying amounts of salt water
throughout their productive lives. In the states in which we
operate, oil and natural gas wastes and salt water produced from
oil and natural 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, is used
to supply water necessary for the drilling and completion of oil
and natural gas wells. Our strategic locations, in combination
with our other fluid handling services, give us a competitive
advantage over other service providers in those areas in which
these other companies cannot provide these services.
Fluid Storage Tanks. Our fluid storage tanks
can store up to 500 barrels of fluid and are used by
oilfield operators to store various fluids at the well site,
including fresh water, brine and acid for frac jobs, flowback,
temporary production and mud storage. We transport the tanks on
our trucks to well locations that are usually within a
50-mile
radius of our nearest yard. Frac tanks are used during all
phases of the life of a producing well. We generally rent fluid
services tanks at daily rates for a minimum of three days. A
typical fracturing operation can be completed within four days
using 5 to 50 frac tanks.
9
Construction Services. We utilize a fleet of
power units, including dozers, trenchers, motor graders,
backhoes and other heavy equipment used in road construction. In
addition, we own rock pits in some markets in our Rocky Mountain
operations to ensure a reliable source of rock to support our
construction activities. 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.
Completion
and Remedial Services Segment
Our completion and remedial services segment provides oil and
natural gas operators with a package of services that include
the following:
|
|
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|
|
pressure pumping services, such as cementing, acidizing,
fracturing, coiled tubing, nitrogen and pressure testing;
|
|
|
|
rental and fishing tools;
|
|
|
|
cased-hole wireline services; and
|
|
|
|
underbalanced drilling in low pressure and fluid sensitive
reservoirs.
|
This segment currently operates 142 pressure pumping units, with
approximately 139,000 of horsepower capacity, to conduct a
variety of services designed to stimulate oil and natural gas
production or to enable cement slurry to be placed in or
circulated within a well. As of December 31, 2009, we also
operated 40 air compressor packages, including foam circulation
units, for underbalanced drilling, 15 wireline units for
cased-hole measurement and pipe recovery services and nine
snubbing units.
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
natural gas, usually in combination with water. Three primary
factors determine the productivity of a well that intersects a
hydrocarbon reservoir: porosity the percentage of
the reservoir volume represented by pore space in which the
hydrocarbons reside, permeability the natural
propensity for the flow of hydrocarbons toward the well bore,
and skin the degree to which the portion
of the reservoir in close proximity to the well bore has
experienced reduced permeability as a result of exposure to
drilling fluids or other contaminants. Well productivity can be
increased by artificially improving either permeability or skin
through stimulation methods.
Permeability can be increased through the use of fracturing
methods. The reservoir is subjected to fluids pumped into it
under high pressure. This pressure creates stress in the
reservoir and causes the rock to fracture thereby creating
additional channels through which hydrocarbons can flow. In most
cases, sand or another form of proppant is pumped with the fluid
as a means of holding open the newly created fractures.
The most common means of reducing near-well bore damage, or
skin, is the injection of a highly reactive solvent (such as
hydrochloric acid) solution into the area where the hydrocarbons
enter the well. This solution has the effect of dissolving
contaminants which have accumulated and are restricting flow.
This process is generically known as acidizing.
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 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
10
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.
The following table sets forth the type, number and location of
the completion and remedial services equipment that we operated
at December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market Area
|
|
|
|
|
|
|
|
|
|
|
Rocky
|
|
Permian
|
|
|
|
|
Ark-La-Tex
|
|
Mid-Continent
|
|
Gulf Coast
|
|
Mountain
|
|
Basin
|
|
Total
|
|
Pressure Pumping Units
|
|
|
21
|
|
|
|
118
|
|
|
|
0
|
|
|
|
3
|
|
|
|
0
|
|
|
|
142
|
|
Coiled Tubing Units
|
|
|
0
|
|
|
|
4
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
4
|
|
Air/Foam Packages
|
|
|
0
|
|
|
|
10
|
|
|
|
0
|
|
|
|
25
|
|
|
|
5
|
|
|
|
40
|
|
Wireline Units
|
|
|
0
|
|
|
|
15
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
15
|
|
Rental and Fishing Tool Stores
|
|
|
0
|
|
|
|
8
|
|
|
|
1
|
|
|
|
3
|
|
|
|
8
|
|
|
|
20
|
|
Snubbing Units
|
|
|
9
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
9
|
|
Our pressure pumping business focuses primarily on lower
horsepower cementing, acidizing and fracturing services markets.
Currently, there are several pressure pumping companies that
provide their services on a national basis. For the most part,
these companies have concentrated their assets in markets
characterized by complex work with higher horsepower
requirements. This has created an opportunity in the markets for
pressure pumping services in mature areas with less complex
characteristics and lower horsepower requirements. We, along
with a number of smaller, regional companies, have concentrated
our efforts on these markets. Two of our major well servicing
competitors also participate 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.
Our rental and fishing tool business provides a range of
specialized services and equipment that are utilized on a
non-routine basis for both drilling and well servicing
operations. Drilling and well servicing rigs are equipped with a
complement of tools to complete routine operations under normal
conditions for most projects in the geographic area where they
are employed. When downhole problems develop with drilling or
servicing operations, or conditions require non-routine
equipment, our customers will usually rely on a provider of
rental and fishing tools to augment equipment that is provided
with a typical drilling or well servicing rig package.
The term fishing applies to a wide variety of
downhole operations designed to correct a problem that has
developed when drilling or servicing a well. Most commonly the
problem involves equipment that has become lodged in the well
and cannot be removed without special equipment. Our customers
employ our technicians and our tools that are specifically
suited to retrieve the trapped equipment, or fish,
in order for operations to resume.
Cased-hole wireline services typically utilize a single truck
equipped with a spool of wireline that is used to lower and
raise a variety of specialized tools in and out of a cased
wellbore. These tools can be used to measure pressures and
temperatures as well as the condition of the casing and the
cement that holds the casing in place. Other applications for
wireline tools include placing equipment in or retrieving
equipment from the wellbore, or perforating the casing and
cutting off pipe that is stuck in the well so that the free
section can be recovered. Electric wireline contains a conduit
that allows signals to be transmitted to or from tools located
in the well. A simpler form of wireline, slickline, lacks an
electrical conduit and is used only to perform mechanical tasks
such as setting or retrieving various tools. Wireline trucks are
often used in place of a well servicing rig when there is no
requirement to remove tubulars from the well in order to make
repairs. Wireline trucks, like well servicing rigs, are utilized
throughout the life of a well.
Underbalanced drilling services, unlike pressure pumping and
wireline services, are not utilized universally throughout oil
and natural 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
11
drilling fluids instead of conventional drilling fluid. The most
common method of reducing the weight of 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.
Contract
Drilling Segment
Our contract drilling segment employs drilling rigs and related
equipment to penetrate the earth to a desired depth and initiate
production.
We own and operate nine land drilling rigs, which are currently
deployed in the Permian Basin of Texas and New Mexico. A land
drilling rig generally consists of engines, a drawworks, a mast,
pumps to circulate the drilling fluid (mud) under various
pressures, blowout preventers, drill string, and related
equipment. The engines power the different pieces of equipment,
including a rotary table or top drives that turns the drill
string, causing the drill bit to bore through the subsurface
rock layers. These jobs are typically bid by daywork
contracts, in which an agreed upon rate per day is charged to
the customer, or footage contracts, in which an
agreed upon rate per the number of feet drilled is charged to
the customer. The demand for drilling services is highly
dependent on the availability of new drilling locations
available to well operators, as well as sensitivity to
expectations relating to and changes in oil and natural gas
prices.
Our drilling rig services grew significantly in April 2007 with
the acquisition of Sledge Drilling, through which we acquired
six drilling rigs.
Properties
Our principal executive offices are located at
500 W. Illinois, Suite 100, Midland, Texas 79701.
We currently conduct our business from 115 area offices, 59 of
which we own and 56 of which we lease. Each office typically
includes a yard, administrative office and maintenance facility.
Of our 115 area offices, 71 are located in Texas, 11 are in
Oklahoma, nine are in New Mexico, six are in Wyoming, four are
in Colorado, four are in Louisiana, three are in North Dakota,
two are in Montana, two are in Kansas, two are in Arkansas and
one is in Utah.
Customers
We serve numerous major and independent oil and natural gas
companies that are active in our core areas of operations.
During 2009, no single customer comprised over 10% of our total
revenues. The majority of our business is with independent oil
and natural gas companies. While we believe we could redeploy
equipment in the current market environment if we lost any
material customers, 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
natural 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;
|
|
|
|
damage to or destruction of property, equipment and the
environment; and
|
|
|
|
suspension of operations.
|
In addition, claims for loss of oil and natural 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
12
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 damage awards, could
adversely affect the cost of, or our ability to obtain,
workers compensation and other forms of insurance, and
could have other material adverse effects on our financial
condition and results of operations.
Although we maintain insurance coverage of types and amounts
that we believe to be customary in the industry, we are not
fully insured against all risks, either because insurance is not
available or because of the high premium costs. We do maintain
employers liability, pollution, cargo, umbrella,
comprehensive commercial general liability, workers
compensation and limited physical damage insurance. There can be
no assurance, however, that any insurance obtained by us will be
adequate to cover any losses or liabilities, or that this
insurance will continue to be available or available on terms
which are acceptable to us. Liabilities for which we are not
insured, or which exceed the policy limits of our applicable
insurance, could have a material adverse effect on us.
Competition
Our competition includes small regional contractors as well as
larger companies with international operations. We believe our
two largest competitors, Key Energy Services, Inc. and Nabors
Well Services Co., combined own approximately 43% of the
U.S. marketable well servicing rigs according to the most
recent publicly available data including the Guiberson-AESC well
service rig count. Both of these competitors are public
companies or subsidiaries of public companies that operate in
most of the large oil and natural 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 natural 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 operations to develop stronger relationships with our
customers at the field level. We target areas that are
attractive to independent oil and natural 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 natural 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 natural gas companies. We
concentrate on providing services to a diverse group of large
and small independent oil and natural 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.
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 workplace 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.
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Environmental
Regulation and Climate Change
Regulatory
Matters, Including Climate Change
Our operations are subject to stringent federal, state and local
laws regulating the discharge of materials into the environment
or otherwise relating to health and safety or the protection of
the environment. Numerous governmental agencies, such as the
U.S. Environmental Protection Agency, commonly referred to
as the EPA, issue regulations to implement and
enforce these laws, which often require difficult and costly
compliance measures. Failure to comply with these laws and
regulations may result in the assessment of substantial
administrative, civil and criminal penalties, as well as the
issuance of injunctions limiting or prohibiting our activities.
In addition, some laws and regulations relating to protection of
the environment may, in certain circumstances, impose strict
liability for environmental contamination, rendering a person
liable for environmental damages and cleanup costs without
regard to negligence or fault on the part of that person. Strict
adherence with these regulatory requirements increases our cost
of doing business and consequently affects our profitability. We
believe that we are in substantial compliance with current
applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material
adverse impact on our operations. However, environmental laws
and regulations have been subject to frequent changes over the
years, and the imposition of more stringent requirements could
have a materially adverse effect upon our capital expenditures,
earnings or our competitive position.
The Comprehensive Environmental Response, Compensation and
Liability Act, referred to as CERCLA or the
Superfund law, and comparable state laws impose liability,
without regard to fault, on certain classes of persons that are
considered to be responsible for the release of a hazardous
substance into the environment. These persons include the
current or former owner or operator of the disposal site or
sites where the release occurred and companies that disposed or
arranged for the disposal of hazardous substances that have been
released at the site. Under CERCLA, these persons may be subject
to joint and several liability for the costs of investigating
and cleaning up hazardous substances that have been released
into the environment, for damages to natural resources and for
the costs of some health studies. In addition, companies that
incur liability frequently confront additional claims because it
is not uncommon for neighboring landowners and other third
parties to file claims for personal injury and property damage
allegedly caused by hazardous substances or other pollutants
released into the environment.
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 natural 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 our
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 EPA 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
14
applying for storm water discharge permit coverage and updating
storm water discharge management practices at some of our
facilities. We believe that we will be able to obtain, or be
included under, these permits, where necessary, and make minor
modifications to existing facilities and operations that would
not have a material effect on us.
The federal Clean Water Act and the federal Oil Pollution Act of
1990, which contains numerous requirements relating to the
prevention of and response to oil spills into waters of the
United States, require some owners or operators of facilities
that store or otherwise handle oil to prepare and implement
spill prevention, control and countermeasure plans, also
referred to as SPCC plans, relating to the possible
discharge of oil into surface waters. In the course of our
ongoing operations, we recently updated and implemented SPCC
plans for several of our facilities. We believe we are in
substantial compliance with these regulations.
Our underground injection operations are subject to the federal
Safe Drinking Water Act, as well as analogous state and local
laws and regulations. Under Part C of the Safe Drinking
Water Act, the EPA established the Underground Injection Control
program, which established the minimum program requirements for
state and local programs regulating underground injection
activities. The Underground Injection Control program includes
requirements for permitting, testing, monitoring, record keeping
and reporting of injection well activities, as well as a
prohibition against the migration of fluid containing any
contaminant into underground sources of drinking water. The
substantial majority of our saltwater disposal wells are located
in the State of Texas and regulated by the Texas Railroad
Commission, also known as the RRC. We also operate
salt water disposal wells in Oklahoma and Wyoming and are
subject to similar regulatory controls in those states.
Regulations in these states require us to obtain a permit from
the applicable regulatory agencies to operate each of our
underground injection wells. We believe that we have obtained
the necessary permits from these agencies for each of our
underground injection wells and that we are in substantial
compliance with permit conditions and commission rules.
Nevertheless, these regulatory agencies have the general
authority to suspend or modify one or more of these permits if
continued operation of one of our underground injection wells is
likely to result in pollution of freshwater, substantial
violation of permit conditions or applicable rules, or leaks to
the environment. Although we monitor the injection process of
our wells, any leakage from the subsurface portions of the
injection wells could cause degradation of fresh groundwater
resources, potentially resulting in cancellation of operations
of a well, issuance of fines and penalties from governmental
agencies, incurrence of expenditures for remediation of the
affected resource and imposition of liability by third parties
for property damages and personal injuries. In addition, our
sales of residual crude oil 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.
In response to certain scientific studies suggesting that
emissions of certain gases, commonly referred to as
greenhouse gases and including carbon dioxide and
methane, are contributing to the warming of the Earths
atmosphere and other climatic changes, the U.S. Congress
has been actively considering legislation to reduce such
emissions. On June 26, 2009, the U.S. House of
Representatives passed the American Clean Energy and Security
Act of 2009 (ACESA), which would establish an
economy-wide
cap-and-trade
program to reduce U.S. emissions of greenhouse
gases including carbon dioxide and methane that may
contribute to warming of the Earths
15
atmosphere and other climatic changes. ACESA would require a
17 percent reduction in greenhouse gas emissions from 2005
levels by 2020 and just over an 80 percent reduction of
such emissions by 2050. Under this legislation, the EPA would
issue a capped and steadily declining number of tradable
emissions allowances to major sources of greenhouse gas
emissions so that such sources could continue to emit greenhouse
gases into the atmosphere. These allowances would be expected to
escalate significantly in cost over time. The U.S. Senate
has begun work on its own legislation for restricting domestic
greenhouse gas emissions and President Obama has indicated his
support of legislation to reduce greenhouse gas emissions
through an emission allowance system. Although it is not
possible at this time to predict when the Senate may act on
climate change legislation or how any bill passed by the Senate
would be reconciled with ACESA, any future federal laws or
implementing regulations that may be adopted to address
greenhouse gas emissions could require us to incur increased
operating costs and could adversely affect demand for crude oil
and natural gas and the related demand for our services.
In addition, on December 7, 2009, the EPA announced its
finding that emissions of greenhouse gases presented an
endangerment to human health and the environment. These findings
by the EPA allow the agency to proceed with the adoption and
implementation of regulations that would restrict emissions of
greenhouse gases under existing provisions of the federal Clean
Air Act (CAA). In late September 2009, the EPA
proposed two sets of regulations in anticipation of finalizing
its endangerment finding that would require a reduction in
emissions of greenhouse gases from motor vehicles and, also,
could trigger permit review for greenhouse gas emissions from
certain stationary sources. In addition, on September 22,
2009, the EPA issued a final rule requiring the reporting of
greenhouse gas emissions from specified large greenhouse gas
emission sources in the United States beginning in 2011 for
emissions occurring in 2010. Although these initial regulations
may not require material reporting for our equipment and
facilities, additional EPA regulations expected to be adopted in
2010 could require reporting of greenhouse gas emissions for our
equipment and facilities, possibly beginning in 2012 for
emissions occurring in 2011.
The adoption and implementation of any regulations imposing
reporting obligations on, or limiting emissions of greenhouse
gases from, our equipment and operations could require us to
incur increased operating costs or could adversely affect demand
for crude oil and natural gas and the related demand for our
services. The potential increase in the costs of our operations
could include additional costs to operate and maintain our
equipment and facilities, install new emission controls on our
equipment and facilities, acquire allowances to authorize our
greenhouse gas emissions, pay any taxes related to our
greenhouse gas emissions and administer and manage a greenhouse
gas emissions program. While we may be able to include some or
all of such increased costs in the rates charged for our
services, any recovery of such costs is uncertain.
Even if such legislation is not adopted at the national level,
more than one-third of the states have begun taking actions to
control
and/or
reduce emissions of greenhouse gases, primarily through the
planned development of greenhouse gas emission inventories
and/or
regional greenhouse gas cap and trade programs. Although most of
the state-level initiatives have to date focused on large
sources of greenhouse gas emissions, such as coal-fired electric
plants, it is possible that smaller sources of emissions could
become subject to greenhouse gas emission limitations or
allowance purchase requirements in the future. Any one of these
climate change regulatory and legislative initiatives could have
a material adverse effect on our business, financial condition
and results of operations.
Other
Potential Impacts of Climate Change
Over the last hundred years or so, the instrumental temperature
record has evidenced a general increase in global mean
temperature. As a result, certain public advocacy groups
attribute this rise to a phenomenon termed global
warming. Proponents of this theory argue that man-made
greenhouse gases have produced observable changes in the
environment such as shrinkage of the Arctic ice caps, releases
of terrestrial carbon from permafrost regions and increases in
sea level. In addition, these individuals believe that global
warming will result in a continued increase in global average
temperatures over the course of this century, with a probable
increase in the frequency of extreme weather events, and changes
in rainfall patterns. Based on computer models promoted by these
groups, certain areas of the globe might benefit from such
changes, while other areas would experience costs. Severe global
climate change would likely result in reduced diversity of
ecosystems and the extinction of certain species.
16
There is considerable debate in public and private forums as to
whether global warming is actually occurring and, if it is, its
consequences. However, if global warming is occurring, it may
have an impact on our operations. For example, our operations
that depend on our ability to conduct services in the field may
be subject to more frequent severe weather events.
Unfortunately, there is currently no public consensus regarding
global warming and the scientific community is divided on the
subject. We are providing this disclosure regarding the
potential physical effects of global warming based on publicly
available information and opinions on the matter. As a
commercial enterprise, we are not in a position to validate or
repudiate the existence of global warming.
Employees
As of December 31, 2009, we employed approximately
3,800 people, with approximately 81% 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.
Additional
Information
We make available free of charge on our website,
www.basicenergyservices.com, our annual reports on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K
and amendments to those reports filed or furnished pursuant to
the Securities Exchange Act of 1934, as amended, as soon as
reasonably practicable after we electronically file such
information with, or furnish it to, the SEC.
The certifications by our Chief Executive Officer and Chief
Financial Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002 are filed as exhibits to this Annual
Report on
Form 10-K.
We have also filed with the New York Stock Exchange the most
recent Annual CEO Certification as required by
Section 303A.12(a) of the New York Stock Exchange Listed
Company Manual.
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
Our
business depends on domestic spending by the oil and natural gas
industry, and this spending and our business has been, and may
continue to be, adversely affected by industry and financial
market 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
natural gas in the United States. Customers expectations
for lower market prices for oil and natural gas, as well as the
availability of capital for operating and capital expenditures,
may cause them to 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 natural gas, domestic and worldwide economic conditions,
political instability in oil and natural gas producing countries
and merger and divestiture activity among oil and gas producers.
The volatility of the oil and natural 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
natural 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 natural gas prices, to the
extent existing production is not replaced and the number of
producing wells for us to service declines.
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Deterioration in the global economic environment has caused the
oilfield services industry to cycle into a downturn, and the
rate at which it may continue to slow, or return to former
levels, is uncertain. Adverse changes in capital markets and
declines in prices for oil and natural gas have caused many oil
and natural gas producers to announce reductions in capital
budgets for future periods. Limitations on the availability of
capital, or higher costs of capital, for financing expenditures
may cause these and other oil and natural gas producers to make
additional reductions to capital budgets in the future even if
commodity prices increase from current levels. These cuts in
spending will curtail drilling programs as well as discretionary
spending on well services, which may result in a reduction in
the demand for our services, the rates we can charge and our
utilization. In addition, certain of our customers could become
unable to pay their suppliers, including us. Any of these
conditions or events could adversely affect our operating
results.
If oil
and natural gas prices remain volatile, remain low or decline
further it could have an adverse effect on the demand for our
services.
The demand for our services is primarily determined by current
and anticipated oil and natural 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 natural gas prices (or the perception that oil and
natural 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. Continued low oil and natural gas prices, a further
decline in oil and natural 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 natural gas historically have been extremely
volatile and are expected to continue to be volatile. The
Cushing WTI Spot Oil Price averaged $72.34, $99.67 and $61.65
per barrel in 2007, 2008 and 2009, respectively, and the average
wellhead price for natural gas, as recorded by the EIA, was
$6.38, $8.07 and $3.65 per mcf for 2007, 2008 and 2009,
respectively. The December 2009 average wellhead price for
natural gas was not available at the time this report was filed;
therefore the average price through November 2009 was used.
We may
require additional capital in the future. We cannot assure you
that we will be able to generate sufficient cash internally or
obtain alternative sources of capital on favorable terms, if at
all. If we are unable to fund capital expenditures our business
may be adversely affected.
We anticipate that we will continue to make substantial capital
investments to purchase additional equipment to expand our
services, refurbish our well servicing rigs and replace existing
equipment. For the year ended December 31, 2008, we
invested approximately $91.9 million in cash for capital
expenditures, excluding acquisitions. For the year ended
December 31, 2009, we invested approximately
$43.4 million in cash for capital expenditures, excluding
acquisitions. Historically, we have financed these investments
through internally generated funds, debt and equity offerings,
our capital lease program and borrowing under a senior credit
facility. We repaid and terminated our senior credit facility
during 2009 and do not currently have a credit facility. These
significant capital investments require cash that we could
otherwise apply to other business needs. However, if we do not
incur these expenditures while our competitors make substantial
fleet investments, our market share may decline and our business
may be adversely affected. In addition, if we are unable to
generate sufficient cash internally or obtain alternative
sources of capital to fund our proposed capital expenditures and
acquisitions, take advantage of business opportunities or
respond to competitive pressures, it could materially adversely
affect our results of operations, financial condition and
growth. If we raise additional funds by issuing equity
securities, dilution to existing stockholders may result.
Adverse changes in the capital markets could make it difficult
to obtain capital or obtain it at attractive rates.
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
18
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, adverse
market conditions have lowered demand for well servicing rigs,
which resulted in excess equipment and lower utilization rates
during 2009. If the adverse market conditions persist,
utilization rates may go even lower.
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
natural gas companies. During 2008 and 2009, our top five
customers accounted for 18% and 23%, 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 may
not be able to grow successfully through future acquisitions or
successfully manage future growth, and we may not be able to
effectively integrate the businesses we do
acquire.
Our business strategy includes growth through the acquisitions
of other businesses. We may not be able to continue to identify
attractive acquisition opportunities or successfully acquire
identified targets. In addition, we may not be successful in
integrating our current or future acquisitions into our existing
operations, which may result in unforeseen operational
difficulties or diminished financial performance or require a
disproportionate amount of our managements attention. Even
if we are successful in integrating our current or future
acquisitions into our existing operations, we may not derive the
benefits, such as operational or administrative synergies, that
we expected from such acquisitions, which may result in the
commitment of our capital resources without the expected returns
on such capital. Furthermore, competition for acquisition
opportunities may escalate, increasing our cost of making
further acquisitions or causing us to refrain from making
additional acquisitions. We may also be limited in our ability
to incur additional indebtedness in connection with or to fund
future acquisitions under the indentures governing our
7.125% Senior Notes due 2016 and 11.625% Senior
Secured Notes due 2014.
Changes
in future market conditions could cause recorded goodwill to
become impaired, resulting in substantial write-downs that would
reduce our operating income.
We have actively pursued the acquisition of other businesses.
These investments are made after careful analysis and due
diligence of the potential business. After the acquisitions are
made, unforeseen market conditions could arise which adversely
affect the anticipated cash flows from the acquired businesses.
Goodwill accounts for less than 1% of our total assets. We
evaluate goodwill amounts for impairment annually, or more often
if conditions require. The annual impairment test is based on
several factors requiring judgment. Primarily, a significant
decrease in expected cash flows or an adverse change in equity
market conditions may indicate potential impairment of recorded
goodwill. Due to changes in the above mentioned factors, we
recognized a $204.0 million impairment of goodwill in 2009.
If the current economic conditions decline further, we may be
required to recognize a goodwill impairment in future periods.
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
natural gas. We may have problems finding enough skilled and
unskilled laborers in the future if the demand for our services
increases. 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
19
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.
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
natural gas industry, such as, but not limited to, accidents,
blowouts, explosions, craterings, fires and oil spills. These
conditions can cause:
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personal injury or loss of life;
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damage to or destruction of property, equipment and the
environment; and
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suspension of operations.
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The occurrence of a significant event or adverse claim in excess
of the insurance coverage that we maintain or that is not
covered by insurance could have a material adverse effect on our
financial condition and results of operations. In addition,
claims for loss of oil and natural 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 our 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.
As such, not all of our property is insured. We are also
self-insured up to retention limits with regard to workers
compensation and medical and dental coverage. 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 the risks to which we are
subject, 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 prohibitively expensive.
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 regulations 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.
20
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 natural 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 the
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.
Climate change regulation is one area of potential future
environmental law development. Studies have suggested that
emissions of certain gases, commonly referred to as
greenhouse gases, may be contributing to warming of
the Earths atmosphere. Methane, a primary component of
natural gas, and carbon dioxide, a byproduct of the burning of
natural gas, are examples of greenhouse gases. The
U.S. Congress is considering legislation to reduce
emissions of greenhouse gases. In addition, at least nine states
in the Northeast and five states in the West have developed
initiatives to regulate emissions of greenhouse gases, primarily
through the planned development of greenhouse gas emission
inventories
and/or
regional greenhouse gas cap and trade programs.
On December 7, 2009, the EPA announced its findings that
emissions of greenhouse gases present an
endangerment to human health and the environment. These findings
by the EPA allow the agency to proceed with the adoption and
implementation of regulations that would restrict emissions of
greenhouse gases under existing provisions of the CAA. In late
September 2009, the EPA proposed two sets of CAA regulations in
anticipation of finalizing its endangerment findings that would
require a reduction in emissions of greenhouse gases from motor
vehicles and, also, could trigger permit review for greenhouse
gas emissions from certain stationary sources. In addition, on
September 22, 2009, the EPA issued a final CAA rule
requiring the reporting of greenhouse gas emissions from
specified large greenhouse gas emission sources in the United
States beginning in 2011 for emissions occurring in 2010.
Although these initial regulations may not require material
reporting for our equipment and facilities, additional EPA
regulations expected to be adopted in 2010 could require
reporting of greenhouse gas emissions for our equipment and
facilities, possibly beginning in 2012 for emissions occurring
in 2011.
Also, on June 26, 2009, the U.S. House of
Representatives passed ACESA, which would establish an
economy-wide
cap-and-trade
program to reduce U.S. emissions of greenhouse
gases. ACESA would require a 17 percent reduction in
greenhouse gas emissions from 2005 levels by 2020 and just over
an 80 percent reduction of such emissions by 2050. Under
this legislation, the EPA would issue a capped and steadily
declining number of tradable emissions allowances to certain
major sources of greenhouse gas emissions so that such sources
could continue to emit greenhouse gases into the atmosphere.
These allowances would be expected to escalate significantly in
cost over time. The net effect of ACESA would be to impose
increasing costs on the combustion of carbon-based fuels such as
oil, refined petroleum products, and natural gas. The
U.S. Senate has begun work on its own legislation for
restricting domestic greenhouse gas emissions and the Obama
Administration has indicated its support of legislation to
reduce greenhouse gas emissions through an emission allowance
system.
Although it is not possible at this time to predict when the
Senate may act on climate change legislation or how any bill
passed by the Senate would be reconciled with ACESA, the
adoption and implementation of any CAA regulations, and any
future federal, state or local laws or implementing regulations
that may be adopted to address greenhouse gas emissions, could
require us to incur increased operating costs and could
adversely affect demand for crude oil and natural gas and our
services. The potential increase in the costs of our operations
could include additional costs to operate and maintain our
equipment and facilities, install new emission controls on our
equipment or facilities, measure and report our emissions,
acquire allowances to authorize our greenhouse gas emissions,
pay any taxes related to our greenhouse gas emissions and
administer and manage a greenhouse gas emissions program. While
we may be able to include some or all of such increased costs in
the rates charged for our services, any recovery of such costs
is uncertain.
Global warming, if occurring, may also impact our operations
directly, including through severe weather and, potentially,
reduce demand for oil and natural gas and our services.
21
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, 2009, our total debt was
$513.2 million, including the aggregate principal amount
due under our 7.125% Senior Notes due 2016 of
$225.0 million, the aggregate principal amount due under
our 11.625% Senior Secured Notes due 2014 of
$225.0 million and capital lease obligations in the
aggregate amount of $63.2 million. For the year ended
December 31, 2009, we made cash interest payments totaling
$21.4 million.
Our current and future indebtedness could have important
consequences. 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 instruments
governing any existing or future indebtedness, we could be in
default under the terms of 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, secured
lenders could foreclose on any of our assets securing their
loans and we or one or more of our subsidiaries could be forced
into bankruptcy or liquidation. If our indebtedness is
accelerated, or we enter into bankruptcy, we may be unable to
pay all of our indebtedness in full. Any of the foregoing
consequences could restrict our ability to grow our business and
cause the value of our common stock to decline.
The
indentures governing our 7.125% Senior Notes due 2016 and
our 11.625% Senior Secured Notes due 2014 impose, and
future credit facilities may impose, restrictions on us that may
affect our ability to successfully operate our
business.
The indentures governing our 7.125% Senior Notes due 2016
and our 11.625% Senior Secured Notes due 2014 include, and
we expect future credit facilities may include, limitations on
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 transfers of assets without
the lenders consent; and
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limitations on dividends and distributions.
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In addition, a future credit facility could require us to
maintain certain financial ratios and to satisfy certain
financial conditions, several of which could become more
restrictive over time and may require us to reduce our debt or
take some other action in order to comply with them. The failure
to comply with any of these financial conditions, including the
financial ratios or covenants, would cause a default under any
such credit facility. A default under any of our indebtedness,
if not waived, could result in the acceleration of such
indebtedness or other indebtedness, in which case the debt would
become immediately due and payable. In addition, a default or
22
acceleration of indebtedness could result in a default under or
acceleration of other indebtedness with cross-default or
cross-acceleration provisions. For example, a default under or
acceleration of our Senior Notes or Senior Secured Notes could
result in a cross-default under or cross-acceleration of the
other series of notes. In the event of any acceleration of our
indebtedness, we may not be able to pay our debt or borrow
sufficient funds to refinance it, and any holders of secured
indebtedness may seek to foreclose on the assets securing such
indebtedness. Even if new financing is available, it may not be
available on terms that are acceptable to us. These restrictions
could also limit our ability to obtain future financings, make
needed capital expenditures, withstand a downturn in our
business or the economy in general, or otherwise conduct
necessary corporate activities. We also may be prevented from
taking advantage of business opportunities that arise because of
the limitations imposed on us by the restrictive covenants under
a future credit facility or existing limitations on the
incurrence of additional indebtedness, including in connection
with acquisitions.
One of
our directors may have a conflict of interest because he is also
currently a managing partner of a private equity firm that makes
investments in the energy sector. The resolution of any 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 opportunities and other matters. The
resolution of any such conflict may not always be in our or our
stockholders best interest.
Risks
Relating to Our Relationship with DLJ Merchant Banking
Affiliates
of DLJ Merchant Banking will have a substantial influence on the
outcome of stockholder voting and may exercise this voting power
in a manner that may not be in the best interest of our other
stockholders.
As of February 22, 2010, DLJ Merchant Banking Partners III,
L.P. and affiliated funds (DLJ Merchant Banking),
which are managed by affiliates of Credit Suisse, a Swiss Bank,
and Credit Suisse Securities (USA) LLC, beneficially owned
approximately 44.4% of our outstanding common stock.
Accordingly, DLJ Merchant Banking is in a position to have a
substantial influence on the outcome of matters requiring a
stockholder vote, including the election of directors, adoption
of amendments to our certificate of incorporation or bylaws or
approval of transactions involving a change of control. The
interests of DLJ Merchant Banking may differ from those of our
other stockholders, and DLJ Merchant Banking may vote its common
stock in a manner that may adversely affect our other
stockholders.
Risks
Relating to Ownership of Our Common Stock
Our
certificate of incorporation and bylaws, as well as Delaware
law, contain provisions that could discourage acquisition bids
or merger proposals, which may adversely affect the market price
of our common stock.
Our certificate of incorporation authorizes our board of
directors to issue preferred stock without stockholder approval.
If our board of directors elects to issue preferred stock, it
could be more difficult for a third party to acquire us. In
addition, some provisions of our certificate of incorporation
and bylaws could make it more difficult for a third party to
acquire control of us, even if the change of control would be
beneficial to our stockholders, including:
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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;
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limitations on the ability of our stockholders to call special
meetings; and
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23
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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.
Investors must rely on sales of their common stock after price
appreciation, which may never occur, as the only way to realize
a return on their investment. Investors seeking cash dividends
should not purchase our common stock.
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ITEM 1B.
|
UNRESOLVED
STAFF COMMENTS
|
None.
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ITEM 3.
|
LEGAL
PROCEEDINGS
|
From time to time, Basic is a party to litigation or other legal
proceedings that Basic considers to be a part of the ordinary
course of business. Basic is not currently involved in any legal
proceedings that it considers probable or reasonably possible,
individually or in the aggregate, to result in a material
adverse effect on its financial condition, results of operations
or liquidity.
Executive
Officers of the Registrant
Our executive officers as of December 31, 2009 and their
respective ages and positions are as follows:
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Name
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Age
|
|
Position
|
|
Kenneth V. Huseman
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57
|
|
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President, Chief Executive Officer and Director
|
Alan Krenek
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54
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Senior Vice President, Chief Financial Officer, Treasurer and
Secretary
|
T.M. Roe Patterson
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35
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Senior Vice President Rig and Truck Operations
|
James F. Newman
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45
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Group Vice President Completion and Remedial Services
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Stephen J. McCoy
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54
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Vice President Contract Drilling
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Douglas B. Rogers
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46
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Vice President Marketing
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James E. Tyner
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59
|
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Vice President Human Resources
|
Set forth below is the description of the backgrounds of our
executive officers.
Kenneth V. Huseman (President Chief Executive
Officer and Director) has 31 years of well servicing
experience. He has been our President and Chief Executive
Officer and a Director since 1999. Prior to joining Basic, he
was Chief Operating Officer at Key Energy Services from 1996 to
1999. He was a Divisional Vice President at WellTech, Inc., from
1993 to 1996. From 1978 to 1993, he was employed at Pool Energy
Services Co., where he managed operations throughout the United
States, including drilling operations in Alaska.
Mr. Huseman graduated with a B.B.A. degree in Accounting
from Texas Tech University.
24
Alan Krenek (Senior Vice President, Chief Financial Officer,
Treasurer and Secretary) has 22 years of related
industry experience. He has been our Vice President, Chief
Financial Officer and Treasurer since January 2005. He became
Senior Vice President and Secretary in May 2006. From October
2002 to January 2005, he served as Vice President and Controller
of Fleetwood Retail Corp., a subsidiary in the manufactured
housing division of Fleetwood Enterprises, Inc. 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 and is a certified
public accountant.
T. M. Roe Patterson (Senior Vice
President Rig and Truck Operations) has
15 years of related industry experience. He has been our
Senior Vice President of Rig and Truck operations since
September 2008, and has been the Vice President of various
different groups within Basic since February 2006. Prior to
joining us, he was president of his own manufacturing and
oilfield service company, TMP Companies, Inc., from 2000 to
2006. He was a Contracts/Sales Manager for the Permian Division
of Patterson Drilling Company from 1996 to 2000. He was an
Engine Sales Manager for West Texas Caterpillar from 1995 to
1996. Mr. Patterson graduated with a B.S. degree in Biology
from Texas Tech University.
James F. Newman (Group Vice President Completion
and Remedial Services) has 25 years of related industry
experience and has been our Group Vice President of Completion
and Remedial Services since September 2008. Prior to joining
Basic, he co-founded Triple N Services in 1986 and served as its
President through May 2008. He initially served Basic as an Area
Manager in the plugging and abandonment operations.
Mr. Newman is a registered Professional Engineer and is
active in the Society of Professional Engineers. Mr. Newman
graduated with a B.S. in Petroleum Engineering from Colorado
School of Mines.
Stephen J. McCoy (Vice President Contract
Drilling) has 34 years of related industry experience.
Mr. McCoy has served as our Vice President
Contract Drilling since February 2009 after serving as our Vice
President Contracts since joining the company in
June 2008. Prior to joining us, he was the Chief Operating
Officer of H&M Resources from August 2007 to June 2008 and
handled various operating duties in drilling and operating wells
in the Permian Basin. He served as Vice President of Marketing
for Patterson-UTI over their Permian Basin Division and in other
various capacities from November 1996 until July of 2007 after
Patterson Drilling purchased Gene Sledge Drilling Company.
Mr. McCoy started with the Western Company in January 1978
before joining Cactus Drilling Corporation as a Contract
Representative in October 1978 until May 1991. He joined
Ranchland Rental Tools as Vice President of Marketing in 1991
and worked there through the mergers of Triumph Tools and Total
Energy and then as District Manager for Enterras drilling
tool division until joining Nabors Drilling as a Contracts
Manager in January 1996. Mr. McCoy graduated with a B.B.A.
degree in Business Management from Texas Tech University.
Douglas B. Rogers (Vice President Marketing)
has 27 years of related industry experience. He joined
Basic in 2007 and serves as Vice President Marketing after
serving as Vice President Contracts for the Drilling Division.
Mr. Rogers was Vice President Rocky Mountain Division for
Patterson-UTI Drilling Company from March 2003 to June 2007. He
also served as Western Division Sales Manager for Ambar
Lonestar Fluid Services, a division of Patterson-UTI Drilling
Company, from 1998 to 2003. He began his career in 1983 with
Permian Servicing Company, where he managed well servicing
operations. He continued in that capacity through Permian
Servicing Companys mergers with Xpert Well Service and
Pride Petroleum Service until joining Zia Drill/Nova Mud in
March 1997. Mr. Rogers graduated with a B.A. degree from
Eastern New Mexico University.
James E. Tyner (Vice President Human Resources)
has been a Vice President since January 2004. From 1999 to
June 2003, he was the General Manager of Human Resources at CMS
Panhandle Companies, where he directed delivery of HR Services.
Mr. Tyner was the Director of Human Resources
Administration and Payroll Services at Duke Energys Gas
Transmission Group from 1998 to 1999. From 1981 to 1998,
Mr. Tyner held various positions at Panhandle Eastern
Corporation. At Panhandle, he managed all Human Resources
functions and developed corporate policies and as a Certified
Safety Professional, he designed and implemented programs to
control workplace hazards. Mr. Tyner received a B.S. in
General Science and M.S. in Microbiology from Mississippi State
University.
25
PART II
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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 is traded on the New York Stock Exchange under
the symbol BAS. 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 each of the
quarters in the years ended December 31, 2008 and 2009,
respectively:
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High
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Low
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2008:
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First Quarter
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$
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22.39
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$
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17.95
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Second Quarter
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$
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32.82
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$
|
22.61
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Third Quarter
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$
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31.25
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$
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20.36
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Fourth Quarter
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$
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19.87
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$
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8.04
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2009:
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First Quarter
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$
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14.94
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|
$
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5.45
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Second Quarter
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$
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12.79
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$
|
6.53
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Third Quarter
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|
$
|
9.68
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$
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6.15
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Fourth Quarter
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$
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9.40
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$
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6.59
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|
As of February 22, 2010, we had 40,654,989 shares of
common stock outstanding held by approximately 282 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.
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, 2009:
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|
|
|
|
|
|
|
|
Number of
|
|
|
|
Number of
|
|
|
|
|
|
Securities
|
|
|
|
Securities to be
|
|
|
Weighted
|
|
|
Remaining
|
|
|
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Issued upon
|
|
|
Average Exercise
|
|
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Available for
|
|
|
|
Exercise of
|
|
|
Price of
|
|
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Future Issuance
|
|
|
|
Outstanding
|
|
|
Outstanding
|
|
|
Under Equity
|
|
Plan Category
|
|
Options
|
|
|
Options
|
|
|
Compensation Plans
|
|
|
Equity compensation plans approved by security holders(1)
|
|
|
1,480,925
|
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|
$
|
11.37
|
|
|
|
2,143,551
|
|
Equity compensation plans not approved by security holders
|
|
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|
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Total
|
|
|
1,480,925
|
|
|
$
|
11.37
|
|
|
|
2,143,551
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|
|
|
|
|
|
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|
|
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|
|
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|
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|
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(1) |
|
Consists of the Basic Energy Services, Inc. Fourth Amended and
Restated 2003 Incentive Plan (as amended effective May 26,
2009). |
Issuer
Purchases of Equity Securities
On October 13, 2008, Basic announced that its Board of
Directors had authorized the repurchase of up to
$50.0 million of Basics shares of common stock from
time to time in open market or private transactions, at
Basics
26
discretion. The stock repurchase program was suspended by the
Board of Directors during the first quarter of 2009. As of
September 30, 2009 and December 31, 2009,
approximately $35.2 million remained authorized for
purchase under this program.
The following table provides information relating to our
repurchase of shares of common stock during the three months
ended December 31, 2009 (dollars in thousands, except
average price paid per share):
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
Approximate Dollar
|
|
|
|
|
|
|
|
|
|
|
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|
Total Number of
|
|
|
Value of Shares
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Shares Purchased as
|
|
|
that May Yet be
|
|
|
|
|
|
|
Total Number of
|
|
|
Price Paid
|
|
|
Part of Publicly
|
|
|
Purchased Under the
|
|
|
|
|
Period
|
|
Shares Purchased(1)
|
|
|
per Share
|
|
|
Announced Program
|
|
|
Program
|
|
|
|
|
|
October 1, 2009 October 31, 2009
|
|
|
439
|
|
|
$
|
8.96
|
|
|
|
0
|
|
|
$
|
0
|
|
|
|
|
|
November 1, 2009 November 30, 2009
|
|
|
0
|
|
|
$
|
0.00
|
|
|
|
0
|
|
|
$
|
0
|
|
|
|
|
|
December 1, 2009 December 31, 2009
|
|
|
1,078
|
|
|
$
|
7.36
|
|
|
|
0
|
|
|
$
|
0
|
|
|
|
|
|
Total
|
|
|
1,517
|
|
|
$
|
7.82
|
|
|
|
0
|
|
|
$
|
0
|
|
|
|
|
|
|
|
|
(1) |
|
These shares were repurchased from various employees to provide
such employees the cash amounts necessary to pay certain tax
liabilities associated with the vesting of restricted shares
owned by them. The shares were repurchased on various dates
based on the closing price per share on the date of repurchase. |
27
Performance
Graph
The following is a line graph comparing cumulative, total
shareholder return from December 9, 2005 (the date of first
trading) through December 31, 2009 with (i) a general
market index (the Russell 2000 Index) and (ii) a group of
peers selected by the Company in the same line of business or
industry as the Company. The peer group is comprised of the
following companies: Key Energy Services, Inc., Complete
Production Services, Inc., Tetra Technologies, Inc., and Pioneer
Drilling Company.
The graph assumes investments of $100 on December 9, 2005
at the closing sale price, and the reinvestment of all
dividends, if any.
The graph shall not be deemed incorporated by reference by any
general statement incorporating by reference this report into
any filing under the Securities Act of 1933, as amended, or the
Securities Exchange Act of 1934, as amended, except to the
extent that the Company specifically incorporates this
information by reference, and shall not otherwise be deemed
filed under such Acts.
December 9,
2005 to December 31, 2009
Value of
$100 Invested December 9, 2005 at December 30, 2005,
December 29, 2006, December 31, 2007,
December 31, 2008, and December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic Energy
|
|
|
Peer
|
|
|
|
|
|
|
Services
|
|
|
Group
|
|
|
Russell 2000
|
December 9, 2005
|
|
|
$
|
100.00
|
|
|
|
$
|
100.00
|
|
|
|
$
|
100.00
|
|
December 30, 2005
|
|
|
$
|
92.79
|
|
|
|
$
|
97.03
|
|
|
|
$
|
98.43
|
|
December 29, 2006
|
|
|
$
|
114.65
|
|
|
|
$
|
108.25
|
|
|
|
$
|
114.36
|
|
December 31, 2007
|
|
|
$
|
102.09
|
|
|
|
$
|
85.52
|
|
|
|
$
|
111.22
|
|
December 31, 2008
|
|
|
$
|
60.65
|
|
|
|
$
|
32.87
|
|
|
|
$
|
72.51
|
|
December 31, 2009
|
|
|
$
|
41.40
|
|
|
|
$
|
58.29
|
|
|
|
$
|
90.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The foregoing graph is based on historical data and is not
necessarily indicative of future performance. This graph shall
not be deemed to be soliciting material or to be
filed with the SEC or subject to the Regulations 14A
or 14C under the Securities Exchange Act of 1934 or to the
liabilities of Section 18 under such act.
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,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands, except per share data)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
$
|
160,614
|
|
|
$
|
343,113
|
|
|
$
|
342,697
|
|
|
$
|
323,755
|
|
|
$
|
221,993
|
|
Fluid services
|
|
|
214,822
|
|
|
|
315,768
|
|
|
|
259,324
|
|
|
|
245,011
|
|
|
|
177,927
|
|
Completion and remedial services
|
|
|
134,818
|
|
|
|
304,326
|
|
|
|
240,692
|
|
|
|
154,412
|
|
|
|
59,832
|
|
Contract drilling
|
|
|
16,373
|
|
|
|
41,735
|
|
|
|
34,460
|
|
|
|
6,970
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
526,627
|
|
|
|
1,004,942
|
|
|
|
877,173
|
|
|
|
730,148
|
|
|
|
459,752
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
|
121,618
|
|
|
|
215,243
|
|
|
|
205,132
|
|
|
|
178,028
|
|
|
|
137,392
|
|
Fluid services
|
|
|
159,079
|
|
|
|
203,205
|
|
|
|
165,327
|
|
|
|
153,445
|
|
|
|
114,551
|
|
Completion and remedial services
|
|
|
95,287
|
|
|
|
165,574
|
|
|
|
125,948
|
|
|
|
74,981
|
|
|
|
30,900
|
|
Contract drilling
|
|
|
13,604
|
|
|
|
28,629
|
|
|
|
22,510
|
|
|
|
8,400
|
|
|
|
|
|
General and administration(a)
|
|
|
104,253
|
|
|
|
115,319
|
|
|
|
99,042
|
|
|
|
81,318
|
|
|
|
55,411
|
|
Depreciation and amortization
|
|
|
132,520
|
|
|
|
118,607
|
|
|
|
93,048
|
|
|
|
62,087
|
|
|
|
37,072
|
|
Loss (gain) on disposal of assets
|
|
|
2,650
|
|
|
|
76
|
|
|
|
477
|
|
|
|
277
|
|
|
|
(222
|
)
|
Goodwill impairment
|
|
|
204,014
|
|
|
|
22,522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
833,025
|
|
|
|
869,175
|
|
|
|
711,484
|
|
|
|
558,536
|
|
|
|
375,104
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
(306,398
|
)
|
|
|
135,767
|
|
|
|
165,689
|
|
|
|
171,612
|
|
|
|
84,648
|
|
Net interest expense
|
|
|
(32,386
|
)
|
|
|
(24,630
|
)
|
|
|
(25,136
|
)
|
|
|
(15,504
|
)
|
|
|
(12,660
|
)
|
Gain (loss) on early extinguishment of debt
|
|
|
(3,481
|
)
|
|
|
|
|
|
|
(230
|
)
|
|
|
(2,705
|
)
|
|
|
(627
|
)
|
Other income (expense)
|
|
|
1,198
|
|
|
|
12,235
|
|
|
|
176
|
|
|
|
169
|
|
|
|
220
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes
|
|
|
(341,067
|
)
|
|
|
123,372
|
|
|
|
140,499
|
|
|
|
153,572
|
|
|
|
71,581
|
|
Income tax (expense) benefit
|
|
|
87,529
|
|
|
|
(55,134
|
)
|
|
|
(52,766
|
)
|
|
|
(54,742
|
)
|
|
|
(26,800
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
(253,538
|
)
|
|
|
68,238
|
|
|
|
87,733
|
|
|
|
98,830
|
|
|
|
44,781
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders
|
|
$
|
(253,538
|
)
|
|
$
|
68,238
|
|
|
$
|
87,733
|
|
|
$
|
98,830
|
|
|
$
|
44,781
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per share of common stock:
|
|
$
|
(6.39
|
)
|
|
$
|
1.67
|
|
|
$
|
2.19
|
|
|
$
|
2.87
|
|
|
$
|
1.57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per share of common stock:
|
|
$
|
(6.39
|
)
|
|
$
|
1.64
|
|
|
$
|
2.13
|
|
|
$
|
2.56
|
|
|
$
|
1.35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands, except per share data)
|
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from operating activities
|
|
$
|
89,205
|
|
|
$
|
212,827
|
|
|
$
|
198,591
|
|
|
$
|
145,678
|
|
|
$
|
99,189
|
|
Cash flows from investing activities
|
|
|
(62,864
|
)
|
|
|
(197,302
|
)
|
|
|
(294,103
|
)
|
|
|
(241,351
|
)
|
|
|
(107,679
|
)
|
Cash flows from financing activities
|
|
|
(12,119
|
)
|
|
|
3,669
|
|
|
|
136,088
|
|
|
|
114,193
|
|
|
|
21,188
|
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquistions, net of cash acquired
|
|
|
7,816
|
|
|
|
110,913
|
|
|
|
199,673
|
|
|
|
135,568
|
|
|
|
25,378
|
|
Property and equipment
|
|
|
43,367
|
|
|
|
91,890
|
|
|
|
98,536
|
|
|
|
104,574
|
|
|
|
83,095
|
|
|
|
|
(a) |
|
Includes approximately $5,152, $4,149, $3,964, $3,429, and
$2,890, of non-cash stock compensation expense for the years
ended December 31, 2009, 2008, 2007, 2006, and 2005,
respectively. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
125,357
|
|
|
$
|
111,135
|
|
|
$
|
91,941
|
|
|
$
|
51,365
|
|
|
$
|
32,845
|
|
Property and equipment, net
|
|
|
666,642
|
|
|
|
740,879
|
|
|
|
636,924
|
|
|
|
475,431
|
|
|
|
309,075
|
|
Total assets
|
|
|
1,039,541
|
|
|
|
1,310,711
|
|
|
|
1,143,609
|
|
|
|
796,260
|
|
|
|
496,957
|
|
Long-term debt
|
|
|
475,845
|
|
|
|
454,260
|
|
|
|
406,306
|
|
|
|
250,742
|
|
|
|
119,241
|
|
Stockholders equity
|
|
|
340,149
|
|
|
|
595,004
|
|
|
|
524,821
|
|
|
|
379,250
|
|
|
|
258,575
|
|
|
|
ITEM 7.
|
MANAGEMENTS
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
|
Managements
Overview
We provide a wide range of well site services to oil and natural
gas drilling and producing companies, including well servicing,
fluid services, completion and remedial services and contract
drilling services. Our results of operations reflect the impact
of our acquisition strategy as a leading consolidator in the
domestic land-based well services industry. 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 32 separate
acquisitions from January 1, 2005 to December 31,
2009. Our weighted average number of well servicing rigs
increased from 305 in 2005 to 410 in the fourth quarter of 2009,
and our weighted average number of fluid service trucks
increased from 455 to 794 in the same period. We added 98 trucks
through the acquisition of Azurite Services Company, Inc.,
Azurite Leasing Company, LLC, and Freestone Disposal, LP
(collectively Azurite) in the third quarter of 2008.
We significantly increased our completion and remedial services
segment, principally through the acquisition of JetStar
Consolidated Holdings, Inc. in the first quarter of 2007. Our
weighted average number of drilling rigs increased from three in
the first quarter of 2007 to nine in the fourth quarter of 2009,
principally through the acquisition of Sledge Drilling Holding
Corp. in the second quarter of 2007. These acquisitions make
changes in revenues, expenses and income not directly comparable
between periods.
We revised our business segments beginning in the first quarter
of 2008, and in connection therewith, restated the corresponding
items of segment information for earlier periods. Our current
operating segments are Well Servicing, Fluid Services,
Completion and Remedial Services, and Contract Drilling. These
segments were selected based on changes in managements
resource allocation and performance assessment in making
decisions regarding the Company. Contract Drilling was
previously included in our Well Servicing segment. The Well Site
Construction Services is consolidated with our Fluid Services
segment.
30
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,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
$
|
160.6
|
|
|
|
30
|
%
|
|
$
|
343.1
|
|
|
|
34
|
%
|
|
$
|
342.7
|
|
|
|
39
|
%
|
Fluid services
|
|
$
|
214.8
|
|
|
|
41
|
%
|
|
|
315.8
|
|
|
|
32
|
%
|
|
|
259.3
|
|
|
|
29
|
%
|
Completion and remedial services
|
|
$
|
134.8
|
|
|
|
26
|
%
|
|
|
304.3
|
|
|
|
30
|
%
|
|
|
240.7
|
|
|
|
28
|
%
|
Contract drilling
|
|
$
|
16.4
|
|
|
|
3
|
%
|
|
|
41.7
|
|
|
|
4
|
%
|
|
|
34.5
|
|
|
|
4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
526.6
|
|
|
|
100
|
%
|
|
$
|
1,004.9
|
|
|
|
100
|
%
|
|
$
|
877.2
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our core businesses depend on our customers willingness to
make expenditures to produce, develop and explore for oil and
natural gas in the United States. Industry conditions are
influenced by numerous factors, such as the supply of and demand
for oil and natural gas, domestic and worldwide economic
conditions, political instability in oil producing countries and
merger and divestiture activity among oil and natural gas
producers. The volatility of the oil and natural 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 natural
gas reserves in our market areas also may have an impact on our
business, even in an environment of stronger oil and natural gas
prices. For a more comprehensive discussion of our industry
trends, see General Industry Overview included in
Items 1 and 2, Business and Properties, of this
Annual Report on
Form 10-K.
We derive a majority of our revenues from services supporting
production from existing oil and natural gas operations. Demand
for these production-related services, including well servicing
and fluid services, tends to remain relatively stable, even in
moderate oil and natural gas price environments, as ongoing
maintenance spending is required to sustain production. As oil
and natural 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 natural gas production from those wells.
Because our services are required to support drilling and
workover activities, our revenues will vary based on changes in
capital spending by our customers as oil and natural gas prices
increase or decrease.
In 2007, natural gas prices declined as an excess supply of
natural gas began to occur, mainly due to moderate
U.S. weather patterns. Utilization for our services
declined from 2006 levels as drilling activity flattened or
declined in several of our markets and new equipment entered the
marketplace balancing supply and demand for our services.
However, pricing for our services improved in 2007 from 2006,
mainly reflecting continued increases in labor costs, and offset
a portion the effect of the lower utilization of our services on
our total revenues. By the middle of 2008, oil and natural gas
prices reached historic highs. However, in the second half of
2008 there were significant decreases in oil and natural gas
prices, which caused significantly lower utilization of our
services in the fourth quarter of 2008. In 2009 natural gas
prices continued to decline from prices experienced in the
fourth quarter of 2008 while oil prices increased over the same
period. This resulted in lower demand for our services and
increased price competition during 2009. We expect oil prices in
2010 to remain above levels necessary to support increased
capital spending programs for workover and drilling programs as
well as routine maintenance. We believe that the outlook for
natural gas prices in 2010 will continue to be uncertain, which
will cause our customers to remain cautious in their spending
until natural gas prices gain strength and stability. We expect
that the supply of available equipment combined with higher
demand from our customers will cause utilization of our services
to increase throughout 2010. While we expect increases in demand
for our services, we do not anticipate improvements in our rate
structure until after the first half of 2010.
We will continue to evaluate opportunities to grow our business
through selective acquisitions and internal growth initiatives.
Our capital investment decisions are determined by an analysis
of the projected return on capital employed of each of those
alternatives, which is substantially driven by the cost to
acquire existing assets from a third party, the capital required
to build new equipment and the point in the oil and natural gas
commodity price cycle. Based on these factors, we make capital
investment decisions that we believe will support our long-term
31
growth strategy. While we believe our costs of integration for
prior acquisitions have been reflected in our historical results
of operations, integration of acquisitions may result in
unforeseen operational difficulties or require a
disproportionate amount of our managements attention.
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;
|
|
|
|
Completion and Remedial Services segment
profits as a percent of revenues; and
|
|
|
|
Contract Drilling rig operating days, revenue
per drilling day and 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 Segment Overview below.
Recent
Strategic Acquisitions and Expansions
During the period from 2007 through 2009, we grew significantly
through acquisitions and capital expenditures. During 2007, we
completed eight acquisitions, of which JetStar Consolidated
Holdings, Inc. and Sledge Drilling Holding Corp. were considered
significant. During 2008, we completed five acquisitions, of
which Azurite was considered significant. During 2009, we
completed one acquisition, which was not considered significant.
We discuss the aggregate purchase prices and related financing
issues below in Liquidity and Capital Resources and
present the pro forma effects of the acquisition of JetStar
Consolidated Holdings, Inc., Sledge Drilling Holding Corp., and
Azurite in Note 3 of our historical consolidated financial
statements included in this report.
Selected
2007 Acquisitions
During 2007, we made several acquisitions that complemented our
existing business segments. These included, among others:
Parker
Drilling Offshore USA, LLC
On January 3, 2007, we acquired two barge-mounted workover
rigs and related equipment from Parker Drilling Offshore USA,
LLC for total consideration of $20.5 million in cash. The
acquired rigs operate in the inland waters of Louisiana and
Texas as a part of Basic Marine Services.
JetStar
Consolidated Holdings, Inc.
On March 6, 2007, we acquired all of the outstanding
capital stock of JetStar Consolidated Holdings, Inc.
(JetStar) for an aggregate purchase price of
approximately $127.3 million, including $86.3 million
in cash, of which approximately $37.6 million was used for
the retirement of JetStars outstanding debt. As part of
the purchase price, we issued 1,794,759 shares of common
stock, at a fair value of $22.86 per share for a total fair
value of approximately $41 million. This acquisition
operates in our completion and remedial business segment.
Sledge
Drilling Holding Corp.
On April 2, 2007, we acquired all of the outstanding
capital stock of Sledge Drilling Holding Corp.
(Sledge) for an aggregate purchase price of
approximately $60.8 million, including $50.6 million
in cash, of which approximately $19 million was used for
the repayment of Sledges outstanding debt. As part of the
purchase price, we issued 430,191 shares of common stock at
a fair value of $23.63 per share for a total fair value of
approximately $10.2 million. This acquisition allowed us to
expand our drilling operations in the Permian Basin and operates
in our contract drilling segment.
32
Wildhorse
Services, Inc.
On June 5, 2007, we acquired all of the outstanding capital
stock of Wildhorse Services, Inc. (Wildhorse) for an
aggregate purchase price of approximately $17.3 million,
net of cash acquired. This acquisition allowed us to expand our
rental and fishing tool operations in northwestern Oklahoma and
the Texas panhandle area. This acquisition operates in our
completion and remedial line of business.
Selected
2008 Acquisitions
During 2008, we made several acquisitions that complemented our
existing business segments. These included, among others:
Xterra
Fishing and Rental Tools Co.
On January 28, 2008, we acquired all of the outstanding
capital stock of Xterra Fishing and Rental Tools Co.
(Xterra) for total consideration of
$21.5 million cash. This acquisition operates in our
completion and remedial services line of business.
Azurite
Services Company, Inc, Azurite Leasing Company, LLC and
Freestone Disposal, L.P.
On September 26, 2008, we acquired substantially all of the
operating assets of Azurite for $61.0 million in cash. This
acquisition operates in our fluid services line of business.
Segment
Overview
Well
Servicing
In 2009, our well servicing segment represented 30% 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 natural 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 well servicing rig 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. We measure the
activity level of our well servicing rigs on a weekly basis by
calculating a rig utilization rate which is based on a
55-hour work
week per rig.
Our well servicing rig fleet increased from a weighted average
number of 364 rigs in the first quarter of 2007 to 410 in the
fourth quarter of 2009 through a combination of newbuild
purchases, acquisitions, and other individual equipment
purchases.
33
The following is an analysis of our well servicing segment for
each of the quarters and years in the years ended
December 31, 2007, 2008, and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
Rig
|
|
|
|
Profits
|
|
|
|
|
Number of
|
|
Rig
|
|
Utilization
|
|
Revenue Per
|
|
Per Rig
|
|
Segment
|
|
|
Rigs
|
|
Hours
|
|
Rate
|
|
Rig Hour
|
|
Hour
|
|
Profits %
|
|
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
364
|
|
|
|
210,800
|
|
|
|
81.0
|
%
|
|
$
|
411
|
|
|
$
|
174
|
|
|
|
42.2
|
%
|
Second Quarter
|
|
|
371
|
|
|
|
207,700
|
|
|
|
78.3
|
%
|
|
$
|
415
|
|
|
$
|
163
|
|
|
|
39.5
|
%
|
Third Quarter
|
|
|
383
|
|
|
|
212,100
|
|
|
|
77.7
|
%
|
|
$
|
414
|
|
|
$
|
166
|
|
|
|
40.0
|
%
|
Fourth Quarter
|
|
|
386
|
|
|
|
200,600
|
|
|
|
72.7
|
%
|
|
$
|
409
|
|
|
$
|
159
|
|
|
|
38.8
|
%
|
Full Year
|
|
|
376
|
|
|
|
831,200
|
|
|
|
77.3
|
%
|
|
$
|
412
|
|
|
$
|
166
|
|
|
|
40.1
|
%
|
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
392
|
|
|
|
202,500
|
|
|
|
72.2
|
%
|
|
$
|
398
|
|
|
$
|
158
|
|
|
|
39.8
|
%
|
Second Quarter
|
|
|
403
|
|
|
|
222,300
|
|
|
|
77.1
|
%
|
|
$
|
400
|
|
|
$
|
152
|
|
|
|
37.9
|
%
|
Third Quarter
|
|
|
412
|
|
|
|
233,000
|
|
|
|
79.1
|
%
|
|
$
|
418
|
|
|
$
|
156
|
|
|
|
37.3
|
%
|
Fourth Quarter
|
|
|
414
|
|
|
|
182,400
|
|
|
|
61.6
|
%
|
|
$
|
418
|
|
|
$
|
141
|
|
|
|
33.8
|
%
|
Full Year
|
|
|
405
|
|
|
|
840,200
|
|
|
|
72.5
|
%
|
|
$
|
408
|
|
|
$
|
152
|
|
|
|
37.3
|
%
|
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
414
|
|
|
|
132,300
|
|
|
|
44.7
|
%
|
|
$
|
369
|
|
|
$
|
90
|
|
|
|
24.4
|
%
|
Second Quarter
|
|
|
414
|
|
|
|
110,500
|
|
|
|
37.3
|
%
|
|
$
|
329
|
|
|
$
|
78
|
|
|
|
23.6
|
%
|
Third Quarter
|
|
|
414
|
|
|
|
122,900
|
|
|
|
41.5
|
%
|
|
$
|
313
|
|
|
$
|
76
|
|
|
|
24.4
|
%
|
Fourth Quarter
|
|
|
410
|
|
|
|
119,500
|
|
|
|
40.8
|
%
|
|
$
|
309
|
|
|
$
|
77
|
|
|
|
24.7
|
%
|
Full Year
|
|
|
413
|
|
|
|
485,200
|
|
|
|
41.1
|
%
|
|
$
|
331
|
|
|
$
|
80
|
|
|
|
24.3
|
%
|
We gauge activity levels in our well servicing rig operations
based on rig utilization rate, revenue per rig hour and profits
per rig hour.
Fluid
Services
In 2009, our fluid services segment represented 41% 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 natural gas
wells. Revenues also include well site construction and
maintenance services. 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
natural 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. Revenues from our well site constructions services 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 natural gas
facilities. We typically price fluid services by the job, by the
hour or by the quantities sold, disposed of or hauled.
34
The following is an analysis of our fluid services segment for
each of the quarters and years in the years ended
December 31, 2007, 2008, and 2009 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Profits
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Per
|
|
|
|
|
|
|
Number of
|
|
|
Revenue Per
|
|
|
Fluid
|
|
|
|
|
|
|
Fluid Service
|
|
|
Fluid Service
|
|
|
Service
|
|
|
Segment
|
|
|
|
Trucks
|
|
|
Truck
|
|
|
Truck
|
|
|
Profits %
|
|
|
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
652
|
|
|
$
|
98
|
|
|
$
|
37
|
|
|
|
37.5
|
%
|
Second Quarter
|
|
|
657
|
|
|
$
|
96
|
|
|
$
|
35
|
|
|
|
36.1
|
%
|
Third Quarter
|
|
|
653
|
|
|
$
|
97
|
|
|
$
|
35
|
|
|
|
35.7
|
%
|
Fourth Quarter
|
|
|
656
|
|
|
$
|
104
|
|
|
$
|
37
|
|
|
|
35.7
|
%
|
Full Year
|
|
|
655
|
|
|
$
|
396
|
|
|
$
|
144
|
|
|
|
36.2
|
%
|
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
644
|
|
|
$
|
111
|
|
|
$
|
39
|
|
|
|
35.0
|
%
|
Second Quarter
|
|
|
663
|
|
|
$
|
109
|
|
|
$
|
36
|
|
|
|
33.1
|
%
|
Third Quarter
|
|
|
683
|
|
|
$
|
121
|
|
|
$
|
43
|
|
|
|
35.8
|
%
|
Fourth Quarter
|
|
|
804
|
|
|
$
|
111
|
|
|
$
|
42
|
|
|
|
38.1
|
%
|
Full Year
|
|
|
699
|
|
|
$
|
452
|
|
|
$
|
161
|
|
|
|
35.6
|
%
|
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
814
|
|
|
$
|
80
|
|
|
$
|
25
|
|
|
|
31.4
|
%
|
Second Quarter
|
|
|
808
|
|
|
$
|
61
|
|
|
$
|
17
|
|
|
|
27.9
|
%
|
Third Quarter
|
|
|
805
|
|
|
$
|
62
|
|
|
$
|
14
|
|
|
|
22.7
|
%
|
Fourth Quarter
|
|
|
794
|
|
|
$
|
64
|
|
|
$
|
13
|
|
|
|
20.3
|
%
|
Full Year
|
|
|
805
|
|
|
$
|
267
|
|
|
$
|
69
|
|
|
|
26.0
|
%
|
We gauge activity levels in our fluid services segment based on
revenue and segment profits per fluid service truck.
Completion
and Remedial Services
In 2009, our completion and remedial services segment
represented 26% of our revenues. Revenues from our completion
and remedial services segment are generally derived from a
variety of services designed to stimulate oil and natural gas
production or place cement slurry within the wellbores. Our
completion and remedial services segment includes pressure
pumping, rental and fishing tool operations, cased-hole wireline
services, snubbing and underbalanced drilling.
Our pressure pumping operations concentrate on providing single
truck, lower-horsepower cementing, acidizing and fracturing
services in selected markets. On March 6, 2007, we acquired
all of the outstanding capital stock of JetStar Consolidated
Holdings, Inc. This acquisition allowed us to enter into the
southwest Kansas market and increased our presence in North
Texas. Our total hydraulic horsepower capacity for our pressure
pumping operations was approximately 139,000 horsepower at
December 31, 2009 and December 31, 2008 compared to
120,000 horsepower at December 31, 2007.
We entered the rental and fishing tool business through our
$58.5 million acquisition of G&L Tool, Ltd. in the
first quarter of 2006. This acquisition consisted of
16 rental and fishing tool stores in the North Texas, West
Texas, and Oklahoma markets. We have since further expanded this
business line with several acquisitions and had 20 rental
and fishing tool stores as of December 31, 2009.
We entered the wireline business in 2004 with 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. We entered the snubbing business in 2009 with
the acquisition of Team Snubbing Services, which operated in
Arkansas. For a description of our wireline and underbalanced
drilling services, please read Overview of Our Segments
and
35
Services Completion and Remedial Services
Segment included in Items 1 and 2, Business and
Properties, of this Annual Report on
Form 10-K.
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 natural 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 completion and remedial
services segment for each of the quarters and years in the years
ended December 31, 2007, 2008, and 2009 (dollars in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
|
|
|
|
Revenues
|
|
|
Profits %
|
|
|
2007:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
46,137
|
|
|
|
49.9
|
%
|
Second Quarter
|
|
$
|
63,735
|
|
|
|
47.6
|
%
|
Third Quarter
|
|
$
|
66,304
|
|
|
|
47.6
|
%
|
Fourth Quarter
|
|
$
|
64,515
|
|
|
|
46.2
|
%
|
Full Year
|
|
$
|
240,692
|
|
|
|
47.7
|
%
|
2008:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
68,458
|
|
|
|
47.7
|
%
|
Second Quarter
|
|
$
|
79,579
|
|
|
|
46.4
|
%
|
Third Quarter
|
|
$
|
85,541
|
|
|
|
45.3
|
%
|
Fourth Quarter
|
|
$
|
70,748
|
|
|
|
43.0
|
%
|
Full Year
|
|
$
|
304,326
|
|
|
|
45.6
|
%
|
2009:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
37,259
|
|
|
|
30.5
|
%
|
Second Quarter
|
|
$
|
29,373
|
|
|
|
26.9
|
%
|
Third Quarter
|
|
$
|
32,592
|
|
|
|
29.1
|
%
|
Fourth Quarter
|
|
$
|
35,594
|
|
|
|
30.3
|
%
|
Full Year
|
|
$
|
134,818
|
|
|
|
29.3
|
%
|
We gauge the performance of our completion and remedial services
segment based on the segments operating revenues and
segment profits.
Contract
Drilling
In 2009, our contract drilling segment represented 3% of our
revenues. Revenues from our contract drilling segment are
derived primarily from the drilling of new wells.
Within this segment, we typically charge our drilling rig
customers at a daywork daily rate, or footage at an established
rate per number of feet drilled. Depending on the type of job,
we may also charge by the project. We measure the activity level
of our drilling rigs on a weekly basis by calculating a rig
utilization rate which is based on a seven day work week per rig.
Our contract drilling rig fleet grew from three during the first
quarter of 2007 to nine by the fourth quarter of 2009, due to
the Sledge acquisition in April 2007.
36
The following is an analysis of our contract drilling segment
for each of the quarters and years in the years ended
December 31, 2007, 2008, and 2009 (dollars in thousands):
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Weighted
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Average
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Rig
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Number of
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Operating
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Revenue
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Profits (Loss)
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Segment
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Rigs
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Days
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Per Day
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Per Day
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Profits %
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2007:
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First Quarter
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3
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168
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$
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11,500
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$
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(5,200
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)
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44.9
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%
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Second Quarter
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8
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594
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$
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17,200
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$
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6,900
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39.5
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%
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Third Quarter
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9
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723
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$
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15,700
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$
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6,700
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42.4
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%
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Fourth Quarter
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10
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748
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$
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14,600
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$
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5,300
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36.3
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%
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Full Year
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8
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2,233
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$
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15,400
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$
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5,400
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34.7
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%
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2008:
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First Quarter
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9
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645
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$
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14,700
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$
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3,800
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25.7
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%
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Second Quarter
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9
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699
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$
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14,800
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$
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4,000
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27.2
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%
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Third Quarter
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9
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767
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$
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15,600
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$
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5,600
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35.6
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%
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Fourth Quarter
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9
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666
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$
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14,900
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$
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5,400
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36.2
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%
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Full Year
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9
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2,777
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$
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15,000
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$
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4,700
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31.4
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%
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2009:
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First Quarter
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9
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248
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$
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14,700
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$
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1,500
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10.1
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%
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Second Quarter
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9
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314
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$
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12,700
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$
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2,100
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16.3
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%
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Third Quarter
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9
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391
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$
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10,600
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$
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2,200
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20.4
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%
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Fourth Quarter
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9
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417
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$
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11,000
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$
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2,200
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19.7
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%
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Full Year
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9
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1,370
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$
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12,000
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$
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2,000
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16.9
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%
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We gauge activity levels in our drilling operations based on rig
operating days, revenue per day, and profits per drilling day.
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. 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 our 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
37
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 $500,000 and $250,000 respectively. We have
lower deductibles per occurrence for automobile liability and
general liability. We maintain accruals in our consolidated
balance sheets related to self-insurance retentions by using
third-party actuarial data and historical claims history.
Revenue Recognition. We recognize revenues
when the services are performed, collection of the relevant
receivables is probable, persuasive evidence of the arrangement
exists and the price is fixed and determinable.
Income Taxes. We recognize deferred tax assets
and liabilities for the future tax consequences attributable to
differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases.
Deferred tax assets and liabilities are measured using statutory
tax rates expected to apply to taxable income in the years in
which those temporary differences are expected to be recovered
or settled. The effect on deferred tax assets and liabilities of
a change in tax rate is recognized in the period that includes
the statutory enactment date. A valuation allowance for deferred
tax assets is recognized when it is more likely than not that
the benefit of deferred tax assets will not be realized.
Critical
Accounting Estimates
The preparation of our consolidated financial statements in
conformity with accounting principles generally accepted in the
United States of America (GAAP) requires management to make
certain estimates and assumptions. These estimates and
assumptions affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities
at the balance sheet date and the amounts of revenues and
expenses recognized during the reporting period. We analyze our
estimates based on historical experience and various other
assumptions that we believe to be reasonable under the
circumstances. However, actual results could differ from such
estimates. The following is a discussion of our critical
accounting estimates.
Depreciation and Amortization. In order to
depreciate and amortize our property and equipment and our
intangible assets with finite lives, we estimate the useful
lives and salvage values of these items. Our estimates may be
affected by such factors as changing market conditions,
technological advances in the industry or changes in regulations
governing the industry.
Impairment of Property and Equipment. Our
analysis for potential 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. We analyze the potential impairment of
property and equipment annually as of December 31 or on an
interim basis if events or circumstances indicate that the fair
value of the assets have decreased below the carrying value.
Impairment of Goodwill. Our goodwill is
considered to have an indefinite useful economic life and is not
amortized. We assess impairment of goodwill annually as of
December 31 or on an interim basis if events or circumstances
indicate that the fair value of the asset has decreased below
its carrying value. A two-step process is required 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
38
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.
We performed an assessment of goodwill as of March 31,
2009. A triggering event requiring this assessment
was deemed to have occurred because the oil and natural gas
services industry continued to decline in the first quarter of
2009 and our common stock price declined by 50% from
December 31, 2008 to March 31, 2009. For Step One of
the impairment testing, we tested three reporting units for
goodwill impairment: well servicing, fluid services, and
completion and remedial services. Our contract drilling
reporting unit does not carry any goodwill and was not subject
to the test.
To estimate the fair value of the reporting units, we used a
weighting of the discounted cash flow method and the public
company guideline method of determining fair value of a business
unit. We weighted the discounted cash flow method 85% and public
company guideline method 15%, due to differences between our
reporting units and the peer companies size, profitability
and diversity of operations. In order to validate the
reasonableness of the estimated fair values obtained for the
reporting units, a reconciliation of fair value to market
capitalization was performed for each unit on a stand-alone
basis. A control premium, derived from market transaction data,
was used in this reconciliation to ensure that fair values were
reasonably stated in conjunction with our capitalization. The
measurement date for our common stock price and market
capitalization was the closing price on March 31, 2009.
Based on the results of Step One of the impairment test,
impairment was indicated in all three of the assessed reporting
units. As such, we were required to perform Step Two assessment
on all three of the reporting units. Step Two requires the
allocation of the estimated fair value to the tangible and
intangible assets and liabilities of the respective unit. This
assessment indicated that $204.1 million was considered
impaired as of March 31, 2009. This non-cash charge
eliminated all of our existing goodwill as of March 31,
2009.
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-insured
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 litigation 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 the 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. We test annually for
impairment of 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 have historically
compensated our directors, executives and employees through the
awarding of stock options and restricted stock. We account for
stock option and restricted stock awards in 2007, 2008 and 2009
using a fair-value based method, resulting in compensation
expense for stock-based awards being recorded in our
consolidated statements of income. Stock options issued are
valued on the grant date using Black-Scholes-Merton option
pricing model and restricted stock issued is valued based on the
fair value of our
39
common stock at the grant date. In addition, judgment is
required in estimating the amount of stock-based awards that are
expected to be forfeited. Because the determination of these
various assumptions is subject to significant management
judgment and different assumptions could result in material
differences in amounts recorded in our consolidated financial
statements, management believes that accounting estimates
related to the valuation of stock options are critical.
The fair value of common stock for options granted from
July 1, 2004 through September 30, 2005 was estimated
by management using an internal valuation methodology. We did
not obtain contemporaneous valuations by an unrelated valuation
specialist because we were focused on internal growth and
acquisitions and because we had consistently used our internal
valuation methodology for previous stock awards.
Income Taxes. The amount and availability of
our loss carryforwards (and certain other tax attributes) are
subject to a variety of interpretations and restrictive tests.
The utilization of such carryforwards could be limited or lost
upon certain changes in ownership and the passage of time.
Accordingly, although we believe substantial loss carryforwards
are available to us, no assurance can be given concerning the
realization of such loss carryforwards, or whether or not such
loss carryforwards will be available in the future.
Asset Retirement Obligations. We record the
fair value of an asset retirement obligation as a liability in
the period in which we incur a legal obligation associated with
the retirement of tangible long-lived assets and capitalize an
equal amount as a cost of the asset, depreciating it over the
life of the asset. Subsequent to the initial measurement of the
asset retirement obligation, the obligation is adjusted at the
end of each quarter to reflect the passage of time, changes in
the estimated future cash flows underlying the obligation,
acquisition or construction of assets, and settlement of
obligations.
Results
of Operations
The results of operations between periods will not be
comparable, primarily due to the significant decline in the oil
and natural gas industry throughout 2009.
Year
Ended December 31, 2009 Compared to Year Ended
December 31, 2008
Revenues. Revenues decreased by 48% to
$526.6 million in 2009 from $1.0 billion in 2008. This
decrease was primarily due to lower expenditures by our
customers for our services and increased price competition from
our competitors due to the decline in oil and natural gas prices.
Well servicing revenues decreased by 53% to $160.6 million
in 2009 compared to $343.1 million in 2008. This decrease
was due to the decrease in rig utilization to 41% during 2009
from 73% during 2008, along with a decrease in revenue per rig
hour to $331 during 2009 from $408 during 2008. These declines
were due to decreased expenditures by our customers for our
services along with decreased pricing for our services as a
result of price competition with our competitors. Our average
number of well servicing rigs increased to 413 during 2009
compared to 405 in 2008, due to internal expansion from our
newbuild rig program and the Lackey Construction, LLC and the
Triple N Services, Inc. acquisitions.
Fluid services revenues decreased by 32% to $214.8 million
in 2009 compared to $315.8 million in 2008. This decrease
was primarily due to decreased rates that we charged to our
customers for our services caused by increased price competition
from our competitors. These decreases were partially offset by
the Azurite acquisition in September 2008 which added 98 fluid
service trucks and 632 frac tanks. Our weighted average number
of fluid service trucks increased to 805 in 2009 from 699 in
2008, although our revenue per fluid service truck decreased to
$267,000 in 2009 compared to $452,000 in 2008.
Completion and remedial services revenues decreased by 56% to
$134.8 million in 2009 as compared to $304.3 million
in 2008. The decrease in revenue between these periods was due
to decreased utilization of equipment due to the decline in oil
and natural gas prices. Increased market competition also caused
significant rate declines. Total hydraulic horsepower was
139,000 at both December 31, 2009 and December 31,
2008.
40
Contract drilling revenues decreased by 61% to
$16.4 million in 2009 compared to $41.7 million in
2008. The number of rig operating days decreased to 1,370 in
2009 compared to 2,777 in 2008. This decrease was due to fewer
new well starts in the geographic market in which we operate.
Direct Operating Expenses. Direct operating
expenses, which primarily consist of labor, including
workers compensation and health insurance, and maintenance
and repair costs, decreased by 36% to $389.6 million in
2009 from $612.6 million in 2008. This decrease was due to
the lower activity levels in all of our segments and
cost-cutting measures implemented as a result of the decline in
revenues.
Direct operating expenses for the well servicing segment
decreased by 43% to $121.6 million in 2009 as compared to
$215.2 million in 2008, due primarily to the 42% decrease
in rig hours to 485,200 in 2009 from 840,200 in 2008. Segment
profits decreased to 24.3% of revenues in 2009 compared to 37.3%
in 2008, which reflects the faster decline in activity levels
and rates than in costs during 2009.
Direct operating expenses for the fluid services segment
decreased by 22% to $159.1 million in 2009 as compared to
$203.2 million in 2008, which is due to lower activity
levels. Segment profits were 26.0% of revenues in 2009 compared
to 35.6% in 2008.
Direct operating expenses for the completion and remedial
services segment decreased by 42% to $95.3 million in 2009
as compared to $165.6 million in 2008 due primarily to
decreased activity levels. Segment profits decreased to 29.3% of
revenues in 2009 compared to 45.6% in 2008, due to activity
levels and rates declining faster than costs.
Direct operating expenses for the contract drilling segment
decreased by 52% to $13.6 million in 2009 as compared to
$28.6 million in 2008 due primarily to a 51% decrease in
operating days in 2009. Segment profits for this segment were
16.9% of revenues in 2009 compared to 31.4% in 2008.
General and Administrative Expenses. General
and administrative expenses decreased by 10% to
$104.3 million in 2009 from $115.3 million in 2008,
which included $5.2 million and $4.1 million of
stock-based compensation expense in 2009 and 2008, respectively.
The decrease from 2008 primarily reflects lower salary and
office expenses related to the reduction in the number of
employees along with pay reductions enacted at the end of the
first quarter of 2009.
Depreciation and Amortization
Expenses. Depreciation and amortization expenses
were $132.5 million in 2009, as compared to
$118.6 million in 2008, reflecting the increase in the size
of and investment in our asset base. We invested
$7.8 million for acquisitions, $18.6 million for
capital leases and an additional $43.4 million for cash
capital expenditures in 2009.
Goodwill Impairment. In the first half of
2009, we recorded a non-cash charge totaling $204.0 million
for impairment of all of the goodwill associated with our well
servicing, fluid services, and completion and remedial services
segments as of March 31, 2009. In 2008, we recorded a
$22.5 million non-cash charge for all of the goodwill
associated with our contract drilling division.
Interest Expense. Interest expense increased
by 23% to $32.9 million in 2009 from $26.8 million in
2008. The increase was primarily due to the issuance of the
$225.0 million of 11.625% Senior Secured Notes in July
2009, the proceeds of which were used to retire our
$225.0 million revolving credit facility.
Income Tax Expense. Income tax benefit was
$87.5 million in 2009, as compared to an expense of
$55.1 million in 2008. Our effective benefit rate was
approximately 26% in 2009 and our effective tax rate was
approximately 45% in 2008. The lower effective benefit rate in
2009 relates to the goodwill write-down in the first quarter of
2009 and is due to differences in the taxable nature of the
impaired goodwill. A portion of the goodwill came from stock
acquisitions, which have zero tax basis.
Year
Ended December 31, 2008 Compared to Year Ended
December 31, 2007
Revenues. Revenues increased by 15% to
$1.0 billion in 2008 from $877.2 million in 2007. This
increase was primarily due to acquisitions in the completion and
remedial services and fluid services segments, and to the
internal expansion of our business segments.
41
Well servicing revenues increased by less than 1% to
$343.1 million in 2008 compared to $342.7 million in
2007. Revenue remained relatively flat due to the increase in
rig hours to 840,200 in 2008 as compared to 831,200 in 2007
being offset by a decrease in revenue per rig hour to $408 in
2008 from $412 in 2007. Similarly, an increase in the weighted
average number of rigs was offset by lower utilization rates.
Our weighted average number of rigs increased to 405 in 2008
from 376 in 2007. The increase was due to the addition of 22
newbuild rigs, 13 rigs from acquisitions and the conversion of
one drilling rig to workover mode, offset by the retirement of 9
rigs in 2008. The rig utilization rate for our well servicing
rigs declined to 73% in 2008 compared to 77% in 2007.
Fluid services revenues increased by 22% to $315.8 million
in 2008 compared to $259.3 million in 2007. This increase
was primarily due to the Azurite acquisition and internal
growth. The Azurite acquisition added 98 trucks, 632 frac tanks
and six disposal wells, which increased revenues by
approximately $10.9 million in 2008. Our weighted average
number of fluid service trucks increased to 699 in 2008 compared
to 655 in 2007, an increase of approximately 7%. During 2008,
our average revenue per fluid service truck was approximately
$452,000 as compared to $396,000 in 2007.
Completion and remedial services revenues increased by 26% to
$304.3 million in 2008 as compared to $240.7 million
in 2007. The increase in revenue between these periods was
primarily the result of the acquisition of JetStar in March
2007, Xterra in January 2008 and Triple N Services, Inc.
(Triple N) in May 2008. The yards associated with
the JetStar acquisition added approximately $20.9 million
more in revenue in 2008 compared to 2007, the Xterra yards added
$17.7 million in revenues for 2008 and the Triple N yards
added $4.7 million in revenues for 2008. There was also
improved utilization for our services in 2008 due to higher oil
and natural gas prices for the majority of 2008.
Contract drilling revenues increased by 21% to
$41.7 million in 2008 compared to $34.5 million in
2007. The increase was due mainly to the acquisition of Sledge
in April 2007, which added approximately $3.9 million more
in revenues in 2008 compared to 2007. There was also an increase
in rig operating days to 2,777 in 2008 compared to 2,233 in
2007, an increase of 24%. Revenue per drilling day was $15,000
in 2008 compared to $15,400 in 2007, a decrease of 3%.
Direct Operating Expenses. Direct operating
expenses, which primarily consist of labor, including
workers compensation and health insurance, and maintenance
and repair costs, increased by 18% to $612.6 million in
2008 from $518.9 million in 2007. This increase was
primarily due to the acquisitions we completed in 2008, the
expansion of our well servicing rig and fluid service truck
fleets, and increases in personnel and related benefit costs.
Direct operating expenses increased to 61.0% of revenues in 2008
from 59.2% in 2007.
Direct operating expenses for the well servicing segment
increased by 5% to $215.2 million in 2008 as compared to
$205.1 million in 2007 due primarily to the expansion of
our well servicing rig fleet. Segment profits decreased to 37.3%
of revenues in 2008 compared to 40.1% in 2007, which reflects
higher fuel costs in 2008 and higher labor costs since we
generally retain our rig crews during times of lower utilization.
Direct operating expenses for the fluid services segment
increased by 23% to $203.2 million in 2008 as compared to
$165.3 million in 2007 due primarily to the expansion of
our fluid services fleet. The Azurite acquisition added
approximately $7.2 million in operating expense in 2008.
Segment profits decreased slightly to 35.6% of revenues in 2008
compared to 36.2% in 2007, mainly due to higher fuel costs.
Direct operating expenses for the completion and remedial
services segment increased by 31% to $165.6 million in 2008
as compared to $125.9 million in 2007 due primarily to the
expansion of our services and equipment, including the JetStar,
Xterra and Triple N acquisitions, and higher operating costs.
JetStar operating expenses were approximately $18.3 million
more in 2008 than in 2007, Xterra operating expenses were
$7.6 million in 2008 and Triple N operating expenses were
$2.1 million in 2008. Our segment profits decreased to
45.6% of revenues in 2008 from 47.7% in 2007, as we experienced
higher fuel costs and increases in costs of the materials used
in our pressure pumping operations.
Direct operating expenses for the contract drilling segment
increased by 27% to $28.6 million in 2008 as compared to
$22.5 million in 2007. The Sledge acquisition added
approximately $6.6 million of operating expenses. Our
segment profits decreased to 31.4% of revenues in 2008 from
34.7% in 2007, as we experienced increased fuel and
transportation expense.
42
General and Administrative Expenses. General
and administrative expenses increased by 16% to
$115.3 million in 2008 from $99.0 million in 2007,
which included $4.1 million and $4.0 million of
stock-based compensation expense in 2008 and 2007, 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 $118.6 million in 2008, as compared to
$93.0 million in 2007, reflecting the increase in the size
of and investment in our asset base. We invested
$110.9 million for acquisitions, $50.7 million for
capital leases and an additional $91.9 million for capital
expenditures in 2008.
Goodwill Impairment. In the fourth quarter of
2008, we recorded a non-cash charge totaling $22.5 million
to impair the contract drilling goodwill.
Interest Expense. Interest expense decreased
by 2% to $26.8 million in 2008 from $27.4 million in
2007. The decrease was due primarily to lower interest rates on
our revolving line of credit, which was offset by an increase in
interest expense due to the $30.0 million draw down on our
revolver in September 2008.
Other Income and Expense. Other income and
expense included $18.2 million of merger costs associated
with the terminated merger agreement with Grey Wolf, Inc.,
offset by termination payments received from Grey Wolf, Inc. for
$30.0 million.
Income Tax Expense. Income tax expense was
$55.1 million in 2008, as compared to $52.8 million in
2007. Our effective tax rate was approximately 45% in 2008 and
38% in 2007.
Liquidity
and Capital Resources
Currently, our primary capital resources are net cash flows from
our operations and utilization of capital leases. As of
December 31, 2009, we had cash and cash equivalents of
$125.4 million compared to $111.1 million as of
December 31, 2008. 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 $89.2 million for
the year ended December 31, 2009 as compared to
$212.8 million in 2008 and $198.6 million in 2007. The
decrease in 2009 was due primarily to lower profitability being
partially offset by the collection of accounts receivable
generated in prior periods. The increase in operating cash flows
in 2008 compared to 2007 was primarily due to higher
profitability and working capital changes.
Capital
Expenditures
Capital expenditures are the main component of our investing
activities. Cash capital expenditures (including for
acquisitions) for 2009 were $51.2 million as compared to
$202.8 million in 2008, and $298.2 million in 2007. In
2008 and 2007 the majority of our capital expenditures were for
business acquisitions. We also added assets through our capital
lease program of approximately $18.6 million,
$50.7 million and $26.8 million in 2009, 2008 and
2007, respectively.
In 2010, the minimum capital expenditures planned for sustaining
Basics existing fleet are approximately $35 million.
Capital expenditures for expansion and other replacements will
be made as the operating environment improves. We do not budget
acquisitions in the normal course of business, and we regularly
engage in discussions related to potential acquisitions related
to the well services industry.
Capital
Resources and Financing
Our current primary capital resources are cash flow from our
operations, the ability to enter into capital leases and a cash
balance of $125.4 million at December 31, 2009. In
2009, we financed activities in excess of cash flow from
operations primarily through the use of bank debt and capital
leases.
43
We have significant contractual obligations in the future that
will require capital resources. Our primary contractual
obligations are (1) our long-term debt, (2) interest
on long-term debt, (3) our capital leases, (4) our
operating leases, (5) our asset retirement obligations, and
(6) our other long-term liabilities. The following table
outlines our contractual obligations as of December 31,
2009 (in thousands):
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Obligations Due In Periods Ended
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December 31,
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Contractual Obligations
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Total
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2010
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2011-2012
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2013-2014
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Thereafter
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Long-term debt (excluding capital leases)
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$
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450,000
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$
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$
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$
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225,000
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$
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225,000
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Interest on long-term debt
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234,985
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42,188
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84,375
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84,375
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24,047
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Capital leases
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63,175
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25,967
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32,581
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4,627
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Operating leases
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15,451
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3,862
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5,189
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3,064
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3,336
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Asset retirement obligations
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1,970
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464
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164
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52
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1,290
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Other long-term liabilities
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6,027
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3,270
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1,696
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1,061
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Total
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$
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771,608
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$
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75,751
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$
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124,005
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$
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318,179
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$
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253,673
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Our long-term debt, excluding capital leases, consists of our
$225.0 million 7.125% Senior Notes and our
$225.0 million 11.625% Senior Secured Notes. Interest
on long-term debt relates to our future contractual interest
obligations on our Senior Notes and our Senior Secured Notes.
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, 2009, we had a maximum potential obligation of
$21.0 million related to the contingent earn-out
agreements. See Note 3 of the notes to our historical
consolidated financial statements for additional detail.
Our ability to access additional sources of financing will be
dependent on our operating cash flows and demand for our
services, which could be negatively impacted due to the extreme
volatility of commodity prices.
Senior
Notes
In April 2006, we completed the issuance and sale of
$225 million aggregate principal amount of
7.125% Senior Notes due April 15, 2016 in a private
placement. The Senior Notes are jointly and severally guaranteed
by each of our restricted subsidiaries (currently all of our
subsidiaries other than two immaterial subsidiaries). The net
proceeds from the offering were used to retire the outstanding
balance of our Term B Loan and to pay down the outstanding
balance under our then-existing senior credit facility.
Remaining proceeds were used for general corporate purposes,
including acquisitions.
We issued the Senior Notes pursuant to an indenture, dated as of
April 12, 2006, by and among us, the guarantor parties
thereto and The Bank of New York Trust Company, N.A., as
trustee (the Senior Notes Indenture).
Interest on the Senior Notes accrues at a rate of 7.125% per
year. Interest on the Senior Notes is payable in cash
semi-annually in arrears on April 15 and October 15 of each
year. The Senior Notes mature on April 15, 2016. The Senior
Notes and the guarantees are unsecured and rank equally with all
of our and the guarantors existing and future unsecured
and unsubordinated obligations. The Senior Notes and the
guarantees rank senior in right of payment to any of our and the
guarantors existing and future obligations that are, by
their terms, expressly subordinated in right of payment to the
Senior Notes and the guarantees. The Senior Notes and the
guarantees are effectively subordinated to our and the
guarantors secured obligations to the extent of the value
of the assets securing such obligations.
The Senior Notes Indenture contains covenants that limit the
ability of us and certain of our subsidiaries to:
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incur additional indebtedness;
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pay dividends or repurchase or redeem capital stock;
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make certain investments;
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44
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incur liens;
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enter into certain types of transactions with affiliates;
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limit dividends or other payments by restricted
subsidiaries; and
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sell assets or consolidate or merge with or into other companies.
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These limitations are subject to a number of important
qualifications and exceptions.
Upon an Event of Default (as defined in the Senior Notes
Indenture), the trustee or the holders of at least 25% in
aggregate principal amount of the Senior Notes then outstanding
may declare all of the amounts outstanding under the Senior
Notes to be due and payable immediately.
We may, at our option, redeem all or part of the Senior Notes,
at any time on or after April 15, 2011, at a redemption
price equal to 100% of the principal amount thereof, plus a
premium declining ratably to par and accrued and unpaid
interest, if any, to the date of redemption. Prior to
April 15, 2011, we may redeem the Senior Notes, in whole or
in part, at a redemption price equal to 100% of the principal
amount of the Senior Notes redeemed, plus the Applicable Premium
as defined in the Senior Notes Indenture.
Following a change of control, as defined in the Senior Notes
Indenture, we will be required to make an offer to repurchase
all or any portion of the Senior Notes at a purchase price of
101% of the principal amount, plus accrued and unpaid interest
to the date of repurchase.
Senior
Secured Notes
On July 31, 2009, we completed the issuance and sale of
$225.0 million aggregate principal amount of
11.625% Senior Secured Notes due 2014. The Senior Secured
Notes are jointly and severally, and unconditionally, guaranteed
on a senior secured basis by all of our current subsidiaries
other than two immaterial subsidiaries. As of December 31,
2009, these two subsidiaries held no assets and performed no
operations. The Senior Secured Notes and the related guarantees
were offered and sold in private transactions in accordance with
Rule 144A and Regulation S under the Securities Act of
1933, as amended.
The net proceeds from the issuance of the Senior Secured Notes
were $207.7 million after discounts of $12.1 million
and offering expenses of $5.2 million. We used the net
proceeds from the offering, along with other funds, to repay all
outstanding indebtedness under our revolving credit facility,
which we terminated in connection with the offering.
The Senior Secured Notes and the related guarantees were issued
pursuant to an indenture dated as of July 31, 2009 (the
Senior Secured Notes Indenture), by and among us,
the guarantors party thereto and The Bank of New York Mellon
Trust Company, N.A., as trustee. The obligations under the
Senior Secured Notes Indenture are secured as set forth in the
Senior Secured Notes Indenture and in the Security Agreement (as
defined below), in favor of the trustee, by a first-priority
lien (other than Permitted Collateral Liens, as defined in the
Senior Secured Notes Indenture) in favor of the trustee, on the
Collateral (as defined below) described in the Security
Agreement.
Interest on the Senior Secured Notes accrues at a rate of
11.625% per year. Interest on the Senior Secured Notes is
payable semi-annually in arrears on February 1 and August 1 of
each year, commencing on February 1, 2010. The Senior
Secured Notes mature on August 1, 2014.
The Senior Secured Notes Indenture contains covenants that,
among other things, limit our ability and the ability of certain
of our subsidiaries to:
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incur additional indebtedness;
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pay dividends or repurchase or redeem capital stock;
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make certain investments;
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incur liens;
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enter into certain types of transactions with our affiliates;
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45
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limit dividends or other payments by our restricted subsidiaries
to us; and
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sell assets (including Collateral under the Security Agreement),
or consolidate or merge with or into other companies.
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These limitations are subject to a number of important
exceptions and qualifications.
If we or our restricted subsidiaries sell, transfer or otherwise
dispose of assets or other rights or property that constitute
Collateral (including the same or the issuance of equity
interests in a restricted subsidiary that owns Collateral such
that it thereafter is no longer a restricted subsidiary, a
Collateral Disposition), we are required to deposit
any cash or cash equivalent proceeds constituting net available
proceeds into a segregated account under the sole control of the
trustee that includes only proceeds from the Collateral
Disposition and interest earned thereon (an Asset Sale
Proceeds Account). The Asset Sale Proceeds Account will be
subject to a first-priority lien in favor of the trustee, and
the proceeds are subject to release from the account for
specified uses. These permitted uses include:
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acquiring additional assets of a type constituting Collateral
(Additional Assets), provided the trustee has or is
immediately granted a perfected first-priority security interest
(subject only to Permitted Collateral Liens) in such Additional
Assets; and
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repurchasing or redeeming the Senior Secured Notes.
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Upon an Event of Default (as defined in the Senior Secured Notes
Indenture), the trustee or the holders of at least 25% in
aggregate principal amount of the Senior Secured Notes then
outstanding may declare the entire principal of all the Senior
Secured Notes to be due and payable immediately.
We may, at our option, redeem all or part of the Senior Secured
Notes, at any time on or after February 1, 2012, at a
redemption price equal to 100% of the principal amount thereof,
plus a premium declining ratably to par and accrued and unpaid
interest to the date of redemption. We may redeem some or all of
the Senior Secured Notes before February 1, 2012, at a
redemption price equal to 100% of the principal amount of the
Senior Secured Notes to be redeemed, plus the Applicable Premium
(as defined in the Senior Secured Notes Indenture) and accrued
and unpaid interest to the date of redemption.
In addition, at any time before February 1, 2012, we, at
our option, may redeem up to 35% of the aggregate principal
amount of the Senior Secured Notes issued under the Senior
Secured Notes Indenture with the net cash proceeds of one or
more qualified equity offerings at a redemption price of
111.625% of the principal amount of the Senior Secured Notes to
be redeemed, plus accrued and unpaid interest to the date of
redemption, as long as:
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at least 65% of the aggregate principal amount of the Senior
Secured Notes issued under the Senior Secured Notes Indenture
remains outstanding immediately after the occurrence of such
redemption; and
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such redemption occurs within 90 days of the date of the
closing of any such qualified equity offering.
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Following a change of control as defined in the Senior Secured
Notes Indenture, holders of the Senior Secured Notes will be
entitled to require us to purchase all or a portion of the
Senior Secured Notes at 101% of their principal amount, plus
accrued and unpaid interest to the date of repurchase.
On July 31, 2009, Basic and each of the guarantors party to
the Senior Secured Notes Indenture (the Grantors)
entered into a Security Agreement (the Security
Agreement) in favor of The Bank of New York Mellon
Trust Company, N.A., as trustee under the Senior Secured
Notes Indenture, to secure payment of the Senior Secured Notes
and related guarantees. The Liens (as defined in the Security
Agreement) granted by each of the Grantors under the Security
Agreement consist of a security interest in all of the following
personal property now owned or at any time thereafter acquired
by such Grantor or in which such Grantor now has or at any time
in the future may acquire any right, title or interest and
whether existing as of the date of the Security Agreement or
thereafter coming into existence (together with the Aircraft
Collateral (as defined in the Security Agreement), the
Collateral), as collateral security for the prompt
and complete payment and performance when due (whether at the
stated maturity, by acceleration or otherwise) of the
obligations of the Grantors under the Senior Secured Notes
Indenture, the related Senior Secured Notes and the security
documents:
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all Commercial Tort Claims;
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46
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all Contracts (as defined in the Security Agreement);
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all Documents;
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all Equipment (other than the Aircraft Collateral);
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all General Intangibles (excluding Payment Intangibles except to
the extent included pursuant to the final bullet point below);
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all Goods (as defined in the Security Agreement);
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all Intellectual Property (as defined in the Security Agreement);
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all Investment Property;
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all
Letter-of-Credit
Rights (whether or not the letter of credit is evidenced by a
writing);
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all Supporting Obligations;
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each Asset Sale Proceeds Account (as defined in the Security
Agreement) and all deposits, Securities and Financial Assets (as
defined in the Security Agreement) therein and interest or other
income thereon and investments thereof, and all property of
every type and description in which any proceeds of any
Collateral Disposition (as defined) or other disposition of
Collateral are invested or upon which the trustee is at any time
granted, or required to be granted, a Lien to secure the
Obligations (as defined in the Security Agreement) as set forth
in Section 4.12 of the Senior Secured Notes Indenture and
all proceeds and products of the Collateral described in this
bullet point;
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all other personal property (other than Excluded Property),
whether tangible or intangible, not otherwise described above;
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whatever is received (whether voluntary or involuntary, whether
cash or non cash, including proceeds of insurance and
condemnation awards, rental or lease payments, accounts, chattel
paper, instruments, documents, contract rights, general
intangibles, equipment
and/or
inventory) upon the lease, sale, charter, exchange, transfer, or
other disposition of any of the Collateral described in the
bullet points above;
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all books and records pertaining to the Collateral; and
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to the extent not otherwise included, all Proceeds, Supporting
Obligations and products (including, without limitation, any
Accounts, Chattel Paper, Instruments or Payment Intangibles
constituting Proceeds, Supporting Obligations or products) of
any and all of the foregoing and all collateral security and
guarantees given by any Person with respect to any of the
foregoing; provided, that notwithstanding the foregoing
provisions, Collateral shall not include Excluded Property.
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Excluded Property means the following,
whether now owned or at any time hereafter acquired by any
Grantor or in which such Grantor now has or at any time in the
future may acquire any right, title or interest and whether now
existing or hereafter coming into existence:
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Maritime Assets (as defined in the Security Agreement);
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cash and cash equivalents (as such terms are defined by GAAP)
other than those maintained in an Asset Sales Proceeds Account;
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Securities Accounts containing only cash and cash equivalents
other than any Asset Sale Proceeds Account and Security
Entitlements relating to any such Securities Account;
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equity interests in any subsidiary of any Grantor;
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Inventory;
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trucks, trailers and other motor vehicles covered by a
certificate of title law of any state;
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property
and/or
transactions to which Article 9 of the UCC does not apply
pursuant to
Section 9-109
thereof;
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47
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certain computer software and Equipment acquired prior to the
date thereof and subject to a lien securing purchase money
indebtedness as of the date thereof if (but only to the extent
that) the applicable documentation relating to such lien
prohibits the granting of a lien on such Equipment;
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Equipment leased by any Grantor, other than pursuant to a
capitalized lease, if (but only to the extent that) the lien
securing the Equipment prohibits the granting of a lien on such
Equipment;
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certain General Intangibles, governmental approvals or other
rights arising under any contracts, instruments, permits,
licenses or other documents if the granting of a security
interest therein would cause a breach of a restriction on the
granting of a security interest therein or the assignment
thereof in favor of a third party, subject to exceptions as set
forth in the Security Agreement; and
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Accounts, Chattel Paper, Instruments and Payment Intangibles to
the extent they are not Proceeds, Supporting Obligations or
products of the Collateral.
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The following capitalized terms used above are as defined in the
Uniform Commercial Code (UCC) of the State of New
York, or such other jurisdiction as may be applicable under the
terms of the Security Agreement, on the date of the Security
Agreement: Accounts, Chattel Paper, Commercial Tort Claims,
Deposit Account, Documents, Electronic Chattel Paper, Equipment,
Financial Assets, General Intangibles, Instruments, Inventory,
Investment Property,
Letter-of-Credit
Rights, Payment Intangibles, Proceeds, Securities, Securities
Accounts, Security Entitlements, Supporting Obligations, and
Tangible Chattel Paper.
Under the Security Agreement, each Grantor must maintain a
perfected security interest in favor of the trustee and take all
steps necessary from time to time in order to maintain the
trustees first-priority security interest (other than
Permitted Collateral Liens). If an event of default were to
occur under the Senior Secured Notes Indenture, the Senior
Secured Notes, the guarantees relating to the Senior Secured
Notes, the Security Agreement or any other agreement, instrument
or certificate that is entered into to secure payment or
performance of the Senior Secured Notes, the trustee would be
empowered to exercise all rights and remedies of a secured party
under the UCC, in addition to all other rights and remedies
under the applicable agreements.
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 is material individually. As of
December 31, 2009, we had total capital leases of
approximately $63.2 million.
Losses on
Extinguishment of Debt
In July 2009 and February 2007, we recognized a loss on the
early extinguishment of debt. In July 2009, we wrote off
unamortized debt issuance costs of approximately
$3.5 million in connection with the repayment and
termination of our senior credit facility. In February 2007, we
wrote off unamortized debt issuance costs of approximately
$0.2 million, which related to our previous senior credit
facility.
Credit
Rating Agencies
Our Senior Notes are currently rated B- and Caa1 by Standard and
Poors and Moodys, respectively. Our Senior Secured
Notes are currently rated B+ and Ba3 by Standard and Poors
and Moodys, respectively.
Preferred
Stock
At December 31, 2009 and December 31, 2008, Basic had
5,000,000 shares of $.01 par value preferred stock
authorized, of which none was designated, issued or outstanding.
Other
Matters
Off-Balance
Sheet Arrangements
We have no off-balance sheet arrangements that have or are
reasonably likely to have a current or future effect on our
financial condition, changes in financial condition, revenues or
expenses, results of operations, liquidity, capital expenditures
or capital resources that is material to investors.
48
Net
Operating Losses
As of December 31, 2009, we had approximately
$2.3 million of NOL carryforwards related to the
pre-acquisition period of FESCO Holdings, Inc., which is subject
to an annual limitation of approximately $892,000. The
carryforwards begin to expire in 2017.
Recent
Accounting Pronouncements
On January 1, 2009, the Company adopted authoritative
guidance from the FASB on business combinations. This guidance
requires an acquirer to recognize the assets acquired, the
liabilities assumed, and any noncontrolling interest in the
acquiree at the acquisition date at their fair values as of that
date. An acquirer is required to recognize assets or liabilities
arising from all other contingencies (contractual contingencies)
as of the acquisition date, measured at their acquisition-date
fair values, only if it is more likely than not that they meet
the definition of an asset or liability. Any acquisition related
costs are to be expensed instead of capitalized. This updated
authoritative guidance is included in FASB Accounting Standards
Codification Topic 805 for Business Combinations. The
impact to the Company from the adoption of this authoritative
guidance will vary acquisition by acquisition.
In June 2009, the FASB issued ASU
No. 2009-01,
The FASB Accounting Standards Codification and the
Hierarchy of Generally Accepted Accounting Principles
(ASU
No. 2009-01),
which was adopted on July 1, 2009. ASU
No. 2009-01
establishes the FASB Accounting Standards Codification as the
source of authoritative accounting principles recognized by the
FASB to be applied by nongovernmental entities in the
preparation of financial statements in conformity with GAAP. ASU
No. 2009-01
is not expected to change GAAP and did not have a material
impact on the Companys consolidated financial statements.
In August 2009, the FASB issued ASU
No. 2009-05,
Measuring Liabilities at Fair Value
(ASU
No. 2009-05),
which was adopted on August 27, 2009. ASU
No. 2009-05
issues guidance related to measuring the fair value of a
liability where there is no market for the transfer of the
liability. One or more of the following techniques should be
used in valuing the liability:
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the quoted price of an investment in the identical liability
traded as an asset,
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the quoted prices for similar liabilities, or
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other fair value technique per principles in accountings
standards, such as discounted cash flow.
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This update did not change the techniques the Company uses to
measure the fair value of liabilities and did not have a
material impact on the Companys consolidated financial
statements.
In January 2010, the FASB issued ASU
No. 2010-06,
Improving Disclosures about Fair Value
Measurements (ASU
No. 2010-06).
ASU
No. 2010-06
requires the disclosure of significant transfers in and out of
Level 1 and Level 2 fair value measurements. It also
requires that Level 3 fair value measurements present
information about purchases, sales, issuances and settlements.
Fair value disclosures should also disclose valuation techniques
and inputs used to measure both recurring and nonrecurring fair
value measurements. This update becomes effective for the
Company on January 1, 2010 except for the disclosures about
purchases, sales, issuances, and settlements in the roll forward
in activity in Level 3 fair value measurements, which
become effective January 1, 2011. This update will not
change the techniques the Company uses to measure fair values
and is not expected to have a material impact on the
Companys consolidated financial statements.
Impact
of Inflation on Operations
Management is of the opinion that inflation has not had a
significant impact on our business.
|
|
ITEM 7A.
|
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
As of July 31, 2009, we terminated the revolving portion
along with other tranches of our credit facility, which
revolving portion subjected us to variable interest rate risk.
49
|
|
ITEM 8.
|
FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
|
Basic
Energy Services, Inc.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
Page
|
|
|
|
|
51
|
|
|
|
|
52
|
|
|
|
|
54
|
|
|
|
|
55
|
|
|
|
|
56
|
|
|
|
|
57
|
|
|
|
|
58
|
|
50
MANAGEMENTS
REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Basic Energy Services, Inc. (Basic or
the Company) is responsible for establishing and
maintaining adequate internal control over financial reporting
and for the assessment of the effectiveness of internal control
over financial reporting for the Company. As defined by the
Securities and Exchange Commission
(Rule 13a-15(f)
under the Exchange Act of 1934, as amended), internal control
over financial reporting is a process designed by, or under the
supervision of Basics principal executive and principal
financial officers and effected by its Board of Directors,
management and other personnel, to provide reasonable assurance
regarding the reliability of financial reporting and the
preparation of the consolidated financial statements in
accordance with U.S. generally accepted accounting
principles.
The Companys internal control over financial reporting is
supported by written policies and procedures that
(1) pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect the
Companys transactions and dispositions of the
Companys assets; (2) provide reasonable assurance
that transactions are recorded as necessary to permit
preparation of the consolidated financial statements in
accordance with U.S. generally accepted accounting
principles, and that receipts and expenditures of the Company
are being made only in accordance with authorization of the
Companys management and directors; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of the
Companys assets that could have a material effect on the
consolidated financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In connection with the preparation of the Companys annual
consolidated financial statements, management has undertaken an
assessment of the effectiveness of the Companys internal
control over financial reporting as of December 31, 2009,
based on criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO Framework).
Managements assessment included an evaluation of the
design of the Companys internal control over financial
reporting and testing of the operational effectiveness of those
controls.
Based on this assessment, management has concluded that as of
December 31, 2009, the Companys internal control over
financial reporting was effective to provide reasonable
assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in
accordance with U.S. generally accepted accounting
principles.
KPMG LLP, the independent registered public accounting firm that
audited the Companys consolidated financial statements
included in this report, has issued an attestation report on the
effectiveness of internal control over financial reporting.
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Kenneth
V. Huseman
Kenneth
V. Huseman
Chief Executive Officer
|
|
/s/ Alan
Krenek Alan
Krenek
Chief Financial Officer
|
51
Report of
Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Basic Energy Services, Inc.:
We have audited Basic Energy Services, Incs (the Company)
internal control over financial reporting as of
December 31, 2009, based on criteria established in
Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). The Companys management is responsible
for maintaining effective internal control over financial
reporting and for its assessment of the effectiveness of
internal control over financial reporting, included in the
accompanying Managements Report on Internal Control over
Financial Reporting. Our responsibility is to express an opinion
on the Companys internal control over financial reporting
based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk
that a material weakness exists, and testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk. Our audit also included performing such other
procedures as we considered necessary in the circumstances. We
believe that our audit provides a reasonable basis for our
opinion.
A companys internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of
management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, Basic Energy Services, Inc. maintained, in all
material respects, effective internal control over financial
reporting as of December 31, 2009, based on criteria
established in Internal Control Integrated
Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of Basic Energy Services, Inc. and
subsidiaries as of December 31, 2009 and 2008, 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, 2009, and our report dated February 26,
2010 expressed an unqualified opinion on those consolidated
financial statements.
KPMG LLP
Dallas, Texas
February 26, 2010
52
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 (the Company) as of
December 31, 2009 and 2008, 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, 2009. In
connection with our audits of the consolidated financial
statements, we also have audited the accompanying financial
statement schedule. These consolidated financial statements and
financial statement schedule are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these consolidated financial statements and financial
statement schedule based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of Basic Energy Services, Inc. and subsidiaries as of
December 31, 2009 and 2008, and the results of their
operations and their cash flows for each of the years in the
three-year period ended December 31, 2009, 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.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), Basic
Energy Services, Inc.s internal control over financial
reporting as of December 31, 2009, based on criteria
established in Internal Control Integrated
Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO), and our report
dated February 26, 2010 expressed an unqualified opinion on
the effectiveness of the Companys internal control over
financial reporting.
KPMG LLP
Dallas, Texas
February 26, 2010
53
Basic
Energy Services, Inc.
Consolidated
Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except
|
|
|
|
share data)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
125,357
|
|
|
$
|
111,135
|
|
Restricted Cash
|
|
|
14,123
|
|
|
|
|
|
Trade accounts receivable, net of allowance of $4,757 and
$5,838, respectively
|
|
|
85,945
|
|
|
|
172,930
|
|
Accounts receivable related parties
|
|
|
65
|
|
|
|
148
|
|
Income tax receivable
|
|
|
61,786
|
|
|
|
3,324
|
|
Inventories
|
|
|
10,962
|
|
|
|
11,937
|
|
Prepaid expenses
|
|
|
6,158
|
|
|
|
6,838
|
|
Other current assets
|
|
|
9,831
|
|
|
|
6,508
|
|
Deferred tax assets
|
|
|
8,941
|
|
|
|
11,081
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
323,168
|
|
|
|
323,901
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
|
666,642
|
|
|
|
740,879
|
|
Deferred debt costs, net of amortization
|
|
|
8,041
|
|
|
|
5,132
|
|
Goodwill
|
|
|
2,806
|
|
|
|
202,749
|
|
Other intangible assets, net of amortization
|
|
|
35,807
|
|
|
|
36,004
|
|
Other assets
|
|
|
3,077
|
|
|
|
2,046
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,039,541
|
|
|
$
|
1,310,711
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
22,850
|
|
|
$
|
28,291
|
|
Accrued expenses
|
|
|
42,196
|
|
|
|
47,139
|
|
Current portion of long-term debt
|
|
|
25,967
|
|
|
|
26,063
|
|
Other current liabilities
|
|
|
504
|
|
|
|
658
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
91,517
|
|
|
|
102,151
|
|
|
|
|
|
|
|
|
|
|
Long-term debt, less unamortized discount on senior secured
notes of $11,363 and $0, respectively
|
|
|
475,845
|
|
|
|
454,260
|
|
Deferred tax liabilities
|
|
|
122,221
|
|
|
|
149,591
|
|
Other long-term liabilities
|
|
|
9,809
|
|
|
|
9,705
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Preferred stock; $.01 par value; 5,000,000 shares
authorized; none designated or issued at December 31, 2009
and December 31, 2008, respectively
|
|
|
|
|
|
|
|
|
Common stock; $.01 par value; 80,000,000 shares
authorized; 42,394,809 shares issued and
40,663,979 shares outstanding at December 31, 2009;
and 41,734,485 shares issued and 40,851,862 shares
outstanding at December 31, 2008
|
|
|
424
|
|
|
|
417
|
|
Additional paid-in capital
|
|
|
330,553
|
|
|
|
325,785
|
|
Retained earnings
|
|
|
23,135
|
|
|
|
277,173
|
|
Treasury stock, at cost 1,730,830 and 882,623 shares at
December 31, 2009 and 2008, respectively
|
|
|
(13,963
|
)
|
|
|
(8,371
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
340,149
|
|
|
|
595,004
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
1,039,541
|
|
|
$
|
1,310,711
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial
statements.
54
Basic
Energy Services, Inc.
Consolidated
Statements of Operations and Comprehensive Income
(Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Dollars in thousands, except per share amounts)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
$
|
160,614
|
|
|
$
|
343,113
|
|
|
$
|
342,697
|
|
Fluid services
|
|
|
214,822
|
|
|
|
315,768
|
|
|
|
259,324
|
|
Completion and remedial services
|
|
|
134,818
|
|
|
|
304,326
|
|
|
|
240,692
|
|
Contract drilling
|
|
|
16,373
|
|
|
|
41,735
|
|
|
|
34,460
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
526,627
|
|
|
|
1,004,942
|
|
|
|
877,173
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
|
121,618
|
|
|
|
215,243
|
|
|
|
205,132
|
|
Fluid services
|
|
|
159,079
|
|
|
|
203,205
|
|
|
|
165,327
|
|
Completion and remedial services
|
|
|
95,287
|
|
|
|
165,574
|
|
|
|
125,948
|
|
Contract drilling
|
|
|
13,604
|
|
|
|
28,629
|
|
|
|
22,510
|
|
General and administrative, including stock-based compensation
of $5,152, $4,149 and $3,964 in 2009, 2008 and 2007, respectively
|
|
|
104,253
|
|
|
|
115,319
|
|
|
|
99,042
|
|
Depreciation and amortization
|
|
|
132,520
|
|
|
|
118,607
|
|
|
|
93,048
|
|
Loss on disposal of assets
|
|
|
2,650
|
|
|
|
76
|
|
|
|
477
|
|
Goodwill impairment
|
|
|
204,014
|
|
|
|
22,522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
833,025
|
|
|
|
869,175
|
|
|
|
711,484
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(306,398
|
)
|
|
|
135,767
|
|
|
|
165,689
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(32,949
|
)
|
|
|
(26,766
|
)
|
|
|
(27,416
|
)
|
Interest income
|
|
|
563
|
|
|
|
2,136
|
|
|
|
2,280
|
|
Loss on early extinguishment of debt
|
|
|
(3,481
|
)
|
|
|
|
|
|
|
(230
|
)
|
Other income
|
|
|
1,198
|
|
|
|
12,235
|
|
|
|
176
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes
|
|
|
(341,067
|
)
|
|
|
123,372
|
|
|
|
140,499
|
|
Income tax benefit (expense)
|
|
|
87,529
|
|
|
|
(55,134
|
)
|
|
|
(52,766
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders
|
|
|
(253,538
|
)
|
|
|
68,238
|
|
|
|
87,733
|
|
Basic earnings per share of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders
|
|
$
|
(6.39
|
)
|
|
$
|
1.67
|
|
|
$
|
2.19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders
|
|
$
|
(6.39
|
)
|
|
$
|
1.64
|
|
|
$
|
2.13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial
statements.
55
Basic
Energy Services, Inc.
Consolidated
Statements of Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
Retained
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
Paid-In
|
|
|
Treasury
|
|
|
Earnings
|
|
|
Stockholders
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Stock
|
|
|
(Deficit)
|
|
|
Equity
|
|
|
|
|
|
|
|
|
|
(In thousands, except share data)
|
|
|
Balance December 31, 2006
|
|
|
38,297,605
|
|
|
$
|
383
|
|
|
$
|
256,527
|
|
|
$
|
|
|
|
$
|
122,340
|
|
|
$
|
379,250
|
|
|
|
|
|
|
|
|
|
Issuance of restricted stock
|
|
|
229,100
|
|
|
|
2
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of share based compensation
|
|
|
|
|
|
|
|
|
|
|
3,873
|
|
|
|
|
|
|
|
|
|
|
|
3,873
|
|
|
|
|
|
|
|
|
|
Stock issued as compensation to Chairman of the Board
|
|
|
4,000
|
|
|
|
|
|
|
|
91
|
|
|
|
|
|
|
|
|
|
|
|
91
|
|
|
|
|
|
|
|
|
|
Stock issued in JetStar Consolidated Holdings, Inc. acquisition
|
|
|
1,794,759
|
|
|
|
18
|
|
|
|
41,011
|
|
|
|
|
|
|
|
|
|
|
|
41,029
|
|
|
|
|
|
|
|
|
|
Stock issued in Sledge Drilling Holding Corp acquisition
|
|
|
430,191
|
|
|
|
4
|
|
|
|
10,161
|
|
|
|
|
|
|
|
|
|
|
|
10,165
|
|
|
|
|
|
|
|
|
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(462
|
)
|
|
|
|
|
|
|
(462
|
)
|
|
|
|
|
|
|
|
|
Exercise of stock options
|
|
|
169,875
|
|
|
|
2
|
|
|
|
3,044
|
|
|
|
462
|
|
|
|
(366
|
)
|
|
|
3,142
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
87,733
|
|
|
|
87,733
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2007
|
|
|
40,925,530
|
|
|
|
409
|
|
|
|
314,705
|
|
|
|
|
|
|
|
209,707
|
|
|
|
524,821
|
|
|
|
|
|
|
|
|
|
Issuances of restricted stock
|
|
|
361,700
|
|
|
|
4
|
|
|
|
(25
|
)
|
|
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of share based compensation
|
|
|
|
|
|
|
|
|
|
|
4,064
|
|
|
|
|
|
|
|
|
|
|
|
4,064
|
|
|
|
|
|
|
|
|
|
Treasury stock issued as compensation to Chairman of the Board
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
89
|
|
|
|
-(4
|
)
|
|
|
85
|
|
|
|
|
|
|
|
|
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,994
|
)
|
|
|
|
|
|
|
(9,994
|
)
|
|
|
|
|
|
|
|
|
Exercise of stock options
|
|
|
447,255
|
|
|
|
4
|
|
|
|
7,041
|
|
|
|
1,513
|
|
|
|
(768
|
)
|
|
|
7,790
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
68,238
|
|
|
|
68,238
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2008
|
|
|
41,734,485
|
|
|
|
417
|
|
|
|
325,785
|
|
|
|
(8,371
|
)
|
|
|
277,173
|
|
|
|
595,004
|
|
|
|
|
|
|
|
|
|
Issuances of restricted stock
|
|
|
660,324
|
|
|
|
7
|
|
|
|
(7
|
)
|
|
|
462
|
|
|
|
(462
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of share based compensation
|
|
|
|
|
|
|
|
|
|
|
5,127
|
|
|
|
|
|
|
|
|
|
|
|
5,127
|
|
|
|
|
|
|
|
|
|
Treasury stock issued as compensation to Chairman of the Board
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
43
|
|
|
|
(19
|
)
|
|
|
24
|
|
|
|
|
|
|
|
|
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,151
|
)
|
|
|
|
|
|
|
(6,151
|
)
|
|
|
|
|
|
|
|
|
Exercise of stock options
|
|
|
|
|
|
|
|
|
|
|
(352
|
)
|
|
|
54
|
|
|
|
(19
|
)
|
|
|
(317
|
)
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(253,538
|
)
|
|
|
(253,538
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2009
|
|
|
42,394,809
|
|
|
$
|
424
|
|
|
$
|
330,553
|
|
|
$
|
(13,963
|
)
|
|
$
|
23,135
|
|
|
$
|
340,149
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial
statements.
56
Basic
Energy Services, Inc.
Consolidated
Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(253,538
|
)
|
|
$
|
68,238
|
|
|
$
|
87,733
|
|
Adjustments to reconcile net income to net cash provided by
operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
132,520
|
|
|
|
118,607
|
|
|
|
93,048
|
|
Goodwill impairment
|
|
|
204,014
|
|
|
|
22,522
|
|
|
|
|
|
Accretion on asset retirement obligation
|
|
|
149
|
|
|
|
131
|
|
|
|
115
|
|
Change in allowance for doubtful accounts
|
|
|
(1,081
|
)
|
|
|
(252
|
)
|
|
|
2,127
|
|
Amortization of deferred financing costs
|
|
|
1,414
|
|
|
|
968
|
|
|
|
962
|
|
Amortization of discount on senior secured notes
|
|
|
740
|
|
|
|
|
|
|
|
|
|
Non-cash compensation
|
|
|
5,152
|
|
|
|
4,149
|
|
|
|
3,964
|
|
Loss on early extinguishment of debt
|
|
|
3,481
|
|
|
|
|
|
|
|
230
|
|
Loss on disposal of assets
|
|
|
2,650
|
|
|
|
76
|
|
|
|
477
|
|
Deferred income taxes
|
|
|
(25,230
|
)
|
|
|
30,165
|
|
|
|
15,285
|
|
Changes in operating assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
88,149
|
|
|
|
(32,411
|
)
|
|
|
4,396
|
|
Inventories
|
|
|
975
|
|
|
|
(558
|
)
|
|
|
(328
|
)
|
Prepaid expenses and other current assets
|
|
|
(1,444
|
)
|
|
|
2,348
|
|
|
|
6,325
|
|
Other assets
|
|
|
(1,010
|
)
|
|
|
47
|
|
|
|
(753
|
)
|
Accounts payable
|
|
|
(5,441
|
)
|
|
|
4,759
|
|
|
|
(1,237
|
)
|
Excess tax expense (benefits) from exercise of employee stock
options/vesting of restricted stock
|
|
|
351
|
|
|
|
(5,062
|
)
|
|
|
(2,169
|
)
|
Income tax payable
|
|
|
(58,981
|
)
|
|
|
2,963
|
|
|
|
(11,262
|
)
|
Other liabilities
|
|
|
(343
|
)
|
|
|
1,217
|
|
|
|
(332
|
)
|
Accrued expenses
|
|
|
(3,322
|
)
|
|
|
(5,080
|
)
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
89,205
|
|
|
|
212,827
|
|
|
|
198,591
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of property and equipment
|
|
|
(43,367
|
)
|
|
|
(91,890
|
)
|
|
|
(98,536
|
)
|
Proceeds from sale of assets
|
|
|
4,134
|
|
|
|
8,184
|
|
|
|
6,815
|
|
Change in restricted cash
|
|
|
(14,123
|
)
|
|
|
|
|
|
|
|
|
Payments for other long-term assets
|
|
|
(1,692
|
)
|
|
|
(2,683
|
)
|
|
|
(2,709
|
)
|
Payments for businesses, net of cash acquired
|
|
|
(7,816
|
)
|
|
|
(110,913
|
)
|
|
|
(199,673
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(62,864
|
)
|
|
|
(197,302
|
)
|
|
|
(294,103
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from debt
|
|
|
241,697
|
|
|
|
30,000
|
|
|
|
150,000
|
|
Payments of debt
|
|
|
(239,543
|
)
|
|
|
(24,126
|
)
|
|
|
(15,838
|
)
|
Purchase of treasury stock
|
|
|
(6,151
|
)
|
|
|
(9,994
|
)
|
|
|
(462
|
)
|
Excess tax benefits (expense) from exercise of employee stock
options/vesting of restricted stock
|
|
|
(351
|
)
|
|
|
5,062
|
|
|
|
2,169
|
|
Tax withholding from exercise of stock options
|
|
|
(5
|
)
|
|
|
(4,174
|
)
|
|
|
(1,290
|
)
|
Exercise of employee stock options
|
|
|
38
|
|
|
|
6,901
|
|
|
|
2,265
|
|
Deferred loan costs and other financing activities
|
|
|
(7,804
|
)
|
|
|
|
|
|
|
(756
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by or used in financing activities
|
|
|
(12,119
|
)
|
|
|
3,669
|
|
|
|
136,088
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and equivalents
|
|
|
14,222
|
|
|
|
19,194
|
|
|
|
40,576
|
|
Cash and cash equivalents beginning of year
|
|
|
111,135
|
|
|
|
91,941
|
|
|
|
51,365
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents end of year
|
|
$
|
125,357
|
|
|
$
|
111,135
|
|
|
$
|
91,941
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial
statements.
57
BASIC
ENERGY SERVICES, INC.
December 31,
2008, 2007, and 2006
Basic Energy Services, Inc. (Basic or the
Company) provides a wide range of well site services
to oil and natural gas drilling and producing companies,
including well servicing, fluid services and wellsite
construction services, completion and remedial services and
contract drilling. These services are primarily provided by
Basics fleet of equipment. Basics operations are
concentrated in major United States onshore oil and natural gas
producing regions located in Texas, New Mexico, Oklahoma,
Kansas, Arkansas, Louisiana, Wyoming, North Dakota, Colorado,
Utah and Montana.
Basic revised its reportable business segments beginning in the
first quarter of 2008, and in connection therewith restated the
corresponding items of segment information for earlier periods.
Basics current operating segments are Well Servicing,
Fluid Services, Completion and Remedial Services, and Contract
Drilling. These segments were selected based on changes in
managements resource allocation and performance assessment
in making decisions regarding the Company. Contract Drilling was
previously included in our Well Servicing segment. Well Site
Construction Services is consolidated with our Fluid Services
segment.
|
|
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 variable interest in any other organization, entity,
partnership, or contract. All intercompany transactions and
balances have been eliminated.
Estimates,
Risks 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. Management uses historical and
other pertinent information to determine these estimates. 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, goodwill and intangible
assets
|
|
|
|
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
|
Natural gas prices have continued to decrease during 2009 from
the prices experienced during the second half of 2008, while oil
prices have rebounded from the low prices experienced at the end
of 2008. As a result the Company has experienced lower
utilization and pricing for its services during 2009.
58
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
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 or by the day of service performed.
Fluid Services Fluid services consist
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.
Completion and Remedial 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 completion and remedial 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.
Contract Drilling 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
these jobs by daywork contracts, in which an agreed
upon rate per day is charged to the customer, or
footage contracts, in which an agreed upon rate per
the number of feet drilled is charged to the customer.
Taxes assessed on sales transactions are presented on a net
basis and are not included in revenue.
Cash
and Cash Equivalents and Restricted Cash
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.
Restricted cash is serving as collateral for our workers
compensation insurance coverage.
Fair
Value of Financial Instruments
The following is a summary of the carrying amounts and estimated
fair values of our financial instruments as of December 31,
2009 and 2008. Fair value is defined as the amount that would be
received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants at the
measurement date.
Cash and cash equivalents, restricted cash, trade accounts
receivable, accounts receivable-related parties, accounts
payable and accrued expenses: These carrying amounts approximate
fair value because of the short maturity of these instruments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
December 31, 2008
|
|
|
|
|
|
|
Carrying Amount
|
|
|
Fair Value
|
|
|
Carrying Amount
|
|
|
Fair Value
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
7.125% Senior Notes
|
|
$
|
225,000
|
|
|
$
|
187,313
|
|
|
$
|
225,000
|
|
|
$
|
126,563
|
|
|
|
|
|
11.625% Senior Secured Notes
|
|
|
225,000
|
|
|
|
241,313
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.125% Senior Notes and 11.625% Senior Secured Notes:
The fair value of our long-term notes is based upon the quoted
market prices at December 31, 2009 and December 31,
2008.
Inventories
For rental and fishing tools, inventories consisting mainly of
grapples, controls, and drill bits are stated at the lower of
cost or market, with cost being determined on the average cost
method. Other inventories, consisting
59
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
mainly of rig components, repair parts, drilling and completion
materials and gravel, are held for use in the operations of
Basic and are stated at the lower of cost or market, with cost
being determined on the
first-in,
first-out (FIFO) method.
Property
and Equipment
Property and equipment are stated at cost or at estimated fair
value at acquisition date if acquired in a business combination.
Expenditures for repairs and maintenance are charged to expense
as incurred and additions and improvements that significantly
extend the lives of the assets are capitalized. Upon sale or
other retirement of depreciable property, the cost and
accumulated depreciation and amortization are removed from the
related accounts and any gain or loss is reflected in
operations. All property and equipment are depreciated or
amortized (to the extent of estimated salvage values) on the
straight-line method and the estimated useful lives of the
assets are as follows:
|
|
|
|
|
Building and improvements
|
|
|
20-30 years
|
|
Well servicing units and equipment
|
|
|
3-15 years
|
|
Fluid services equipment
|
|
|
5-10 years
|
|
Brine and fresh water stations
|
|
|
15 years
|
|
Frac/test tanks
|
|
|
10 years
|
|
Pressure pumping equipment
|
|
|
5-10 years
|
|
Construction equipment
|
|
|
3-10 years
|
|
Contract drilling equipment
|
|
|
3-10 years
|
|
Disposal facilities
|
|
|
10-15 years
|
|
Vehicles
|
|
|
3-7 years
|
|
Rental equipment
|
|
|
3-15 years
|
|
Aircraft
|
|
|
20 years
|
|
Software and computers
|
|
|
3 years
|
|
The components of a well servicing rig generally require
replacement or refurbishment during the well servicing
rigs life and are depreciated over their estimated useful
lives, which ranges from 3 to 15 years. The costs of the
original components of a purchased or acquired well servicing
rig are not maintained separately from the base rig.
Impairments
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, which
is at the business segment 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. These assets are normally sold within a short
period of time through a third party auctioneer.
60
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Deferred
Debt Costs
Basic capitalizes certain costs in connection with obtaining its
borrowings, such as lenders fees and related
attorneys fees. These costs are being amortized to
interest expense using the effective interest method.
Deferred debt costs were approximately $10.4 million net of
accumulated amortization of $2.3 million, and
$7.6 million net of accumulated amortization of
$2.4 million at December 31, 2009 and
December 31, 2008, respectively. Amortization of deferred
debt costs totaled approximately $1.4 million, $968,000 and
$962,000 for the years ended December 31, 2009, 2008 and
2007, respectively.
In 2009 and 2007, Basic recognized a loss on early
extinguishment of debt related to deferred debt costs (See
note 5).
Goodwill
and Other Intangible Assets
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. A two-step process is required 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 Company performed an assessment of goodwill as of
March 31, 2009. A triggering event requiring
this assessment was deemed to have occurred because the oil and
gas services industry continued to decline in the first quarter
of 2009 and the Companys common stock price declined by
50% from December 31, 2008 to March 31, 2009. For Step
One of the impairment testing, the Company tested three
reporting units for goodwill impairment: well servicing, fluid
services, and completion and remedial services. The
Companys contract drilling reporting unit does not carry
any goodwill, and was not subject to the test.
To estimate the fair value of the reporting units, the Company
primarily used level 3 inputs from the fair value
hierarchy, which included a weighting of the discounted cash
flow method and the public company guideline method of
determining fair value of a business unit. The Company weighted
the discounted cash flow method 85% and public company guideline
method 15%, due to differences between the Companys
reporting units and the peer companies size, profitability
and diversity of operations. In order to validate the
reasonableness of the estimated fair values obtained for the
reporting units, a reconciliation of fair value to market
capitalization was performed for each unit on a stand-alone
basis. A control premium, derived from market transaction data,
was used in this reconciliation to ensure that fair values were
reasonably stated in conjunction with the Companys
capitalization. The measurement date for the Companys
common stock price and market capitalization was the closing
price on March 31, 2009.
Based on the results of Step One of the impairment test,
impairment was indicated in all three of the assessed reporting
units. As such, the Company was required to perform Step Two
assessment on all three of the reporting units. Step Two
requires the allocation of the estimated fair value to the
tangible and intangible assets and liabilities of the respective
unit. This assessment indicated that $204.1 million was
considered impaired as of March 31, 2009. This non-cash
charge eliminated all of the Companys existing goodwill as
of March 31, 2009.
61
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The changes in the carrying amount of goodwill for the year
ended December 31, 2009, are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Completion and
|
|
|
|
|
|
|
|
|
|
Well
|
|
|
Fluid
|
|
|
Remedial
|
|
|
Contract
|
|
|
|
|
|
|
Servicing
|
|
|
Services
|
|
|
Services
|
|
|
Drilling
|
|
|
Total
|
|
|
Balance as of December 31, 2008
|
|
$
|
29,888
|
|
|
$
|
49,334
|
|
|
$
|
123,527
|
|
|
$
|
|
|
|
$
|
202,749
|
|
Goodwill adjustments
|
|
|
(464
|
)
|
|
|
(259
|
)
|
|
|
3,520
|
|
|
|
|
|
|
|
2,797
|
|
Impairment losses
|
|
|
(29,424
|
)
|
|
|
(48,986
|
)
|
|
|
(124,330
|
)
|
|
|
|
|
|
|
(202,740
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2009
|
|
$
|
|
|
|
$
|
89
|
|
|
$
|
2,717
|
|
|
$
|
|
|
|
$
|
2,806
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible assets subject to amortization consist of customer
relationships and non-compete agreements. The gross carrying
amount of customer relationships subject to amortization was
$37.9 million and $35.4 million as of
December 31, 2009 and 2008, respectively. The gross
carrying amount of non-compete agreements subject to
amortization totaled approximately $4.4 million at
December 31, 2009 and 2008. Accumulated amortization
related to these intangible assets totaled approximately $6.5
and $3.8 million at December 31, 2009 and 2008,
respectively. Amortization expense for the years ended
December 31, 2009, 2008 and 2007 was approximately
$3.1 million, $2.8 million, and $773,000,
respectively. Amortization expense for the next five succeeding
years is estimated to be approximately $3.4 million,
$3.2 million, $2.9 million, $2.6 million, and
$2.6 million in 2010, 2011, 2012, 2013, and 2014,
respectively.
|
|
|
|
|
|
|
|
|
Amortizable Intangible Assets at December 31, 2009 (in
thousands):
|
|
|
|
|
|
|
|
|
Customer Relationships
|
|
|
|
|
|
$
|
37,895
|
|
Accumulated Amortization Customer Relationships
|
|
|
|
|
|
|
(4,233
|
)
|
Non-Compete Agreements
|
|
|
|
|
|
|
4,369
|
|
Accumulated Amortization Non-Compete Agreements
|
|
|
|
|
|
|
(2,224
|
)
|
|
|
|
|
|
|
|
|
|
Total Amortizable Intangible Assets
|
|
|
|
|
|
$
|
35,807
|
|
|
|
|
|
|
|
|
|
|
Customer relationships are amortized over a
15-year
life. Non-Compete Agreements are amortized over a five-year life.
Basic has identified its reporting units to be well servicing,
fluid services, completion and remedial services and contract
drilling.
Stock-Based
Compensation
We have historically compensated our directors, executives and
employees through the awarding of stock options and restricted
stock. We account for stock option and restricted stock awards
in 2007, 2008 and 2009 using a fair-value based method,
resulting in compensation expense for stock-based awards being
recorded in our consolidated statements of income. Stock options
issued are valued on the grant date using Black-Scholes-Merton
option pricing model and restricted stock issued is valued based
on the fair value of our common stock at the grant date. In
addition, judgment is required in estimating the amount of
stock-based awards that are expected to be forfeited. Because
the determination of these various assumptions is subject to
significant management judgment and different assumptions could
result in material differences in amounts recorded in our
consolidated financial statements, management believes that
accounting estimates related to the valuation of stock options
are critical.
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.
62
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Income
Taxes
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 2009, 2008, or 2007.
Asset
Retirement Obligations
Basic is required to record the fair value of an asset
retirement obligation as a liability in the period in which it
incurs a legal obligation associated with the retirement of
tangible long-lived assets and capitalize an equal amount as a
cost of the asset depreciating it over the life of the asset.
Subsequent to the initial measurement of the asset retirement
obligation, the obligation is adjusted at the end of each
quarter to reflect the passage of time, changes in the estimated
future cash flows underlying the obligation, acquisition or
construction of assets, and settlements of obligations.
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. Basic maintains accruals in the
consolidated balance sheets to cover self-insurance retentions
(See note 7).
Comprehensive
Income (Loss)
All items that are required to be recognized under accounting
rules as components of comprehensive income (loss) are to be
reported in a financial statement that is displayed with the
same prominence as other financial statements. Gains and losses
on cash flow hedging derivatives, to the extent effective, are
included in other
63
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
comprehensive income (loss). For the three-year period ended
December 31, 2009, Basic did not have any items of 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
On January 1, 2009, the Company adopted authoritative
guidance from the FASB on business combinations. This guidance
requires an acquirer to recognize the assets acquired, the
liabilities assumed, and any noncontrolling interest in the
acquiree at the acquisition date at their fair values as of that
date. An acquirer is required to recognize assets or liabilities
arising from all other contingencies (contractual contingencies)
as of the acquisition date, measured at their acquisition-date
fair values, only if it is more likely than not that they meet
the definition of an asset or liability. Any acquisition related
costs are to be expensed instead of capitalized. This updated
authoritative guidance is included in FASB Accounting Standards
Codification Topic 805 for Business Combinations. The
impact to the Company from the adoption of this authoritative
guidance will vary acquisition by acquisition.
In June 2009, the FASB issued ASU
No. 2009-01,
The FASB Accounting Standards Codification and the
Hierarchy of Generally Accepted Accounting Principles
(ASU
No. 2009-01),
which was adopted on July 1, 2009. ASU
No. 2009-01
establishes the FASB Accounting Standards Codification as the
source of authoritative accounting principles recognized by the
FASB to be applied by nongovernmental entities in the
preparation of financial statements in conformity with GAAP. ASU
No. 2009-01
is not expected to change GAAP and did not have a material
impact on the Companys consolidated financial statements.
In August 2009, the FASB issued ASU
No. 2009-05,
Measuring Liabilities at Fair Value
(ASU
No. 2009-05),
which was adopted on August 27, 2009. ASU
No. 2009-05
issues guidance related to measuring the fair value of a
liability where there is no market for the transfer of the
liability. One or more of the following techniques should be
used in valuing the liability:
|
|
|
|
|
the quoted price of an investment in the identical liability
traded as an asset,
|
|
|
|
the quoted prices for similar liabilities, or
|
|
|
|
other fair value technique per principles in accountings
standards, such as discounted cash flow.
|
This update did not change the techniques the Company uses to
measure the fair value of liabilities and did not have a
material impact on the Companys consolidated financial
statements.
In January 2010, the FASB issued ASU
No. 2010-06,
Improving Disclosures about Fair Value
Measurements (ASU
No. 2010-06).
ASU
No. 2010-06
requires the disclosure of significant transfers in and out of
Level 1 and Level 2 fair value measurements. It also
requires that Level 3 fair value measurements present
information about purchases, sales, issuances and settlements.
Fair value disclosures should also disclose valuation techniques
and inputs used to measure both recurring and nonrecurring fair
value measurements. This update becomes effective for the
Company on January 1, 2010 except for the disclosures about
purchases, sales, issuances, and settlements in the roll forward
in activity in Level 3 fair value measurements, which
become effective January 1, 2011. This update will not
change the techniques the Company uses to measure fair values
and is not expected to have a material impact on the
Companys consolidated financial statements.
64
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
In 2009, 2008 and 2007, 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)
|
|
|
Parker Drilling Offshore USA, LLC
|
|
|
January 3, 2007
|
|
|
|
20,594
|
|
Davis Tool Company, Inc.
|
|
|
January 17, 2007
|
|
|
|
4,164
|
|
JetStar Consolidated Holdings, Inc.
|
|
|
March 6, 2007
|
|
|
|
86,316
|
|
Sledge Drilling Holding Corp.
|
|
|
April 2, 2007
|
|
|
|
50,632
|
|
Eagle Frac Tank Rentals, LP
|
|
|
May 30, 2007
|
|
|
|
3,813
|
|
Wildhorse Services, Inc.
|
|
|
June 1, 2007
|
|
|
|
17,283
|
|
Bilco Machine, Inc.
|
|
|
June 21, 2007
|
|
|
|
600
|
|
Steve Carter Inc. and Hughes Services Inc.
|
|
|
September 26, 2007
|
|
|
|
19,041
|
|
|
|
|
|
|
|
|
|
|
Total 2007
|
|
|
|
|
|
$
|
202,443
|
|
|
|
|
|
|
|
|
|
|
Xterra Fishing and Rental Tools Co.
|
|
|
January 28, 2008
|
|
|
$
|
21,473
|
|
Lackey Construction, LLC
|
|
|
January 30, 2008
|
|
|
|
4,328
|
|
B&S Disposal, LLC and B&S Equipment, Ltd
|
|
|
April 30, 2008
|
|
|
|
7,071
|
|
Triple N Services, Inc.
|
|
|
May 27, 2008
|
|
|
|
17,315
|
|
Azurite Services Company, Inc., Azurite Leasing Company, LLC and
Freestone Disposal, L.P. (collectively, Azurite)
|
|
|
September 26, 2008
|
|
|
|
60,977
|
|
|
|
|
|
|
|
|
|
|
Total 2008
|
|
|
|
|
|
$
|
111,164
|
|
|
|
|
|
|
|
|
|
|
Team Snubbing Services, Inc.
|
|
|
December 28, 2009
|
|
|
$
|
6,985
|
|
|
|
|
|
|
|
|
|
|
Total 2009
|
|
|
|
|
|
$
|
6,985
|
|
|
|
|
|
|
|
|
|
|
The operations of each of the acquisitions listed above are
included in Basics statement of operations as of each
respective closing date. The acquisition of JetStar Consolidated
Holdings, Inc. and Sledge Drilling Holding Corp. in 2007 and
Azurite in 2008 have been deemed significant and are discussed
below in further detail.
JetStar
Consolidated Holdings, Inc.
On March 6, 2007, Basic acquired all of the capital stock
of JetStar Consolidated Holdings, Inc. (JetStar).
The results of JetStars operations have been included in
the financial statements since that date. The aggregate purchase
price was approximately $127.3 million, including
$86.3 million in cash which included the retirement of
JetStars outstanding debt. Basic issued
1,794,759 shares of common stock, at a fair value of $22.86
per share for a total fair value of approximately
$41 million. The value of the 1,794,759 shares issued
was determined based on the average market price of Basics
common shares over the
two-day
period before and after the date the number of shares were
determined. This acquisition allowed us to enter into the Kansas
market and increased our presence in
65
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
North Texas. JetStar operates in Basics completion and
remedial segment. The following table summarizes the final fair
value of the assets acquired and liabilities assumed at the date
of acquisition for JetStar (in thousands):
|
|
|
|
|
Current Assets
|
|
$
|
12,547
|
|
Property and Equipment
|
|
|
58,785
|
|
Amortizable Intangible Assets(1)
|
|
|
17,857
|
|
Goodwill(2)
|
|
|
61,720
|
|
|
|
|
|
|
Total Assets Acquired
|
|
|
150,909
|
|
|
|
|
|
|
Current Liabilities
|
|
|
(4,581
|
)
|
Deferred Income Taxes
|
|
|
(18,649
|
)
|
Current and Long Term Debt(3)
|
|
|
(37,563
|
)
|
|
|
|
|
|
Total Liabilities Assumed
|
|
|
(60,793
|
)
|
|
|
|
|
|
Net Assets Acquired
|
|
$
|
90,116
|
|
|
|
|
|
|
|
|
|
(1) |
|
Consists of Customer Relationship of $17,543, amortizable over
15 years, and Non-Compete Agreements of $314, amortizable
over five years. |
|
(2) |
|
Approximately $25,955 is expected to be deductible for tax
purposes |
|
(3) |
|
Total balance was paid by Basic on the closing date |
Sledge
Drilling Holding Corp.
On April 2, 2007, Basic acquired all of the capital stock
of Sledge Drilling Holding Corp. (Sledge). The
results of Sledges operations have been included in the
financial statements since that date. The aggregate purchase
price was approximately $60.8 million, including
$50.6 million in cash which included the retirement of
Sledges outstanding debt. Basic issued 430,191 shares
of common stock at a fair value of $23.63 per share for a total
fair value of approximately $10.2 million. The value of the
430,191 shares issued was determined based on the average
market price of Basics common shares over the
two-day
period before and after the date the number shares were
determined. This acquisition allowed Basic to expand its
drilling operations in the Permian Basin. The following table
summarizes the final fair value of the assets acquired and
liabilities assumed at the date of acquisition for Sledge (in
thousands):
|
|
|
|
|
Current Assets
|
|
$
|
6,807
|
|
Property and Equipment
|
|
|
30,638
|
|
Intangible Assets(1)
|
|
|
6,365
|
|
Goodwill(2)
|
|
|
22,522
|
|
|
|
|
|
|
Total Assets Acquired
|
|
|
66,332
|
|
|
|
|
|
|
Current Liabilities
|
|
|
(587
|
)
|
Deferred Income Taxes
|
|
|
(3,804
|
)
|
Current and Long Term Debt(3)
|
|
|
(19,093
|
)
|
|
|
|
|
|
Total Liabilities Assumed
|
|
|
(23,484
|
)
|
|
|
|
|
|
Net Assets Acquired
|
|
$
|
42,848
|
|
|
|
|
|
|
|
|
|
(1) |
|
Consists of Customer Relationship of $6,269, amortizable over
15 years, and Non-Compete Agreements of $96, amortizable
over five years. |
66
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
(2) |
|
None of which is expected to be deducted for tax purposes |
|
(3) |
|
Total balance was paid by Basic on the closing date |
Azurite
On September 26, 2008, Basic acquired substantially all of
the assets of Azurite Services Company, Inc., Azurite Leasing
Company, LLC, and Freestone Disposal, L.P. (collectively,
Azurite) for $61.0 million in cash. This
acquisition operates in our fluid services line of business and
allowed us to expand our operations in the East Texas markets.
The following table summarizes the final estimated fair value of
the assets acquired and liabilities assumed at the date of
acquisition for Azurite (in thousands):
|
|
|
|
|
Property and Equipment
|
|
$
|
54,456
|
|
Intangible Assets(1)
|
|
|
1,862
|
|
Goodwill(2)
|
|
|
4,659
|
|
|
|
|
|
|
Total Assets Acquired
|
|
$
|
60,977
|
|
|
|
|
|
|
|
|
|
(1) |
|
Consists of customer relationship of $1,832, amortizable over
15 years, and non-compete agreements of $30, amortizable
over five years. |
|
(2) |
|
All of which is expected to be deducted for tax purposes. |
The following unaudited pro-forma results of operations have
been prepared as though the Azurite acquisition had been
completed on January 1, 2008. Pro forma amounts are based
on the purchase price allocations of the significant acquisition
and are not necessarily indicative of the results that may be
reported in the future (in thousands, except per share data).
|
|
|
|
|
|
|
Twelve Months Ended
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
Revenues
|
|
$
|
1,040,160
|
|
Net income
|
|
$
|
70,680
|
|
Earnings per common share basic
|
|
$
|
1.73
|
|
Earnings per common share diluted
|
|
$
|
1.70
|
|
Basic does not believe the pro-forma effect of the remainder of
the acquisitions completed in 2007, 2008 or 2009 is material,
either individually or when aggregated, to the reported results
of operations.
Contingent
Earn-out Arrangements and Final Purchase Price
Allocations
Contingent earn-out arrangements are generally arrangements
entered into on certain acquisitions to encourage the
owner/manager to continue operating and building the business
after the purchase transaction. The contingent earn-out
arrangements of the related acquisitions are generally linked to
certain financial measures and performance of the assets
acquired in the various acquisitions. Contingent earn-out
payments that are based on continued employment with the Company
are recorded as compensation expense. All other amounts paid or
reasonably accrued for related to the contingent earn-out
payments are reflected as increases to the goodwill associated
with the acquisition of G&L Tool.
67
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The following presents a summary of the acquisition that has a
contingent earn-out arrangement in effect as of
December 31, 2009 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum
|
|
|
|
|
|
|
|
|
|
exposure of
|
|
|
|
|
|
|
Termination date of
|
|
|
contingent
|
|
|
Amount paid or
|
|
|
|
contingent earn-out
|
|
|
earn-out
|
|
|
accrued through
|
|
Acquisition
|
|
arrangement
|
|
|
arrangement
|
|
|
December 31, 2009
|
|
|
G&L Tool, Ltd.
|
|
|
February 28, 2011
|
|
|
|
21,000
|
|
|
|
5,093
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
21,000
|
|
|
$
|
5,093
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.
|
Property
and Equipment
|
Property and equipment consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Land
|
|
$
|
5,992
|
|
|
$
|
4,689
|
|
Buildings and improvements
|
|
|
34,694
|
|
|
|
29,913
|
|
Well service units and equipment
|
|
|
384,195
|
|
|
|
379,167
|
|
Fluid services equipment
|
|
|
135,246
|
|
|
|
136,814
|
|
Brine and fresh water stations
|
|
|
10,606
|
|
|
|
10,203
|
|
Frac/test tanks
|
|
|
132,057
|
|
|
|
128,845
|
|
Pressure pumping equipment
|
|
|
163,869
|
|
|
|
156,406
|
|
Construction equipment
|
|
|
25,641
|
|
|
|
22,483
|
|
Contract drilling equipment
|
|
|
60,133
|
|
|
|
60,340
|
|
Disposal facilities
|
|
|
57,457
|
|
|
|
49,878
|
|
Vehicles
|
|
|
38,383
|
|
|
|
41,129
|
|
Rental equipment
|
|
|
38,660
|
|
|
|
36,898
|
|
Aircraft
|
|
|
4,251
|
|
|
|
4,119
|
|
Other
|
|
|
29,769
|
|
|
|
21,758
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,120,953
|
|
|
|
1,082,642
|
|
Less accumulated depreciation and amortization
|
|
|
454,311
|
|
|
|
341,763
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
$
|
666,642
|
|
|
$
|
740,879
|
|
|
|
|
|
|
|
|
|
|
68
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
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,
|
|
|
|
2009
|
|
|
2008
|
|
|
Light vehicles
|
|
$
|
25,019
|
|
|
$
|
30,141
|
|
Well service units and equipment
|
|
|
2,100
|
|
|
|
1,194
|
|
Fluid services equipment
|
|
|
64,734
|
|
|
|
56,010
|
|
Pressure pumping equipment
|
|
|
17,440
|
|
|
|
20,492
|
|
Construction equipment
|
|
|
1,034
|
|
|
|
3,679
|
|
Software
|
|
|
10,231
|
|
|
|
9,464
|
|
Other
|
|
|
|
|
|
|
705
|
|
|
|
|
|
|
|
|
|
|
|
|
|
120,558
|
|
|
|
121,685
|
|
Less accumulated amortization
|
|
|
45,603
|
|
|
|
37,370
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
74,955
|
|
|
$
|
84,315
|
|
|
|
|
|
|
|
|
|
|
Amortization of assets held under capital leases of
approximately $20.4 million, $14.7 million and
$8.9 million for the years ended December 31, 2009,
2008 and 2007, respectively, is included in depreciation and
amortization expense in the consolidated statements of
operations.
Long-term debt consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Credit Facilities:
|
|
|
|
|
|
|
|
|
Revolver
|
|
$
|
|
|
|
$
|
180,000
|
|
7.125% Senior Notes
|
|
|
225,000
|
|
|
|
225,000
|
|
11.625% Senior Secured Notes
|
|
|
225,000
|
|
|
|
|
|
Unamortized discount
|
|
|
(11,363
|
)
|
|
|
|
|
Capital leases and other notes
|
|
|
63,175
|
|
|
|
75,323
|
|
|
|
|
|
|
|
|
|
|
|
|
|
501,812
|
|
|
|
480,323
|
|
Less current portion
|
|
|
25,967
|
|
|
|
26,063
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
475,845
|
|
|
$
|
454,260
|
|
|
|
|
|
|
|
|
|
|
Senior
Notes
On April 12, 2006, Basic issued $225.0 million of
7.125% Senior Notes due April 2016 in a private placement.
Proceeds from the sale of the Senior Notes were used to retire
the outstanding balance on Basics $90.0 million Term
B Loan and to pay down approximately $96.0 million under
its then-existing revolving credit facility. The remaining
proceeds were used for general corporate purposes, including
acquisitions. Interest on the Senior Notes is payable in cash
semi-annually, on April 15 and October 15 of each year. The
Senior Notes are unsecured. Under the terms of the sale of the
Senior Notes, Basic was required to take appropriate steps to
offer to exchange other Senior Notes with the same terms that
have been registered with the Securities and Exchange Commission
for the private placement Senior Notes. Basic completed the
exchange offer for all of the Senior Notes on October 16,
2006.
69
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The Senior Notes are redeemable at the option of Basic on or
after April 15, 2011 at the specified redemption price as
described in the indenture governing the Senior Notes (the
Senior Notes Indenture). Prior to April 15,
2011, Basic may redeem the Senior Notes, in whole or in part, at
a redemption price equal to 100% of the principal amount of the
Senior Notes redeemed plus the Applicable Premium as defined in
the Senior Notes Indenture.
Following a change of control, as defined in the Senior Notes
Indenture, Basic will be required to make an offer to repurchase
all or any portion of the Senior Notes at a purchase price of
101% of the principal amount, plus accrued and unpaid interest
to the date of repurchase.
Upon an Event of Default (as defined in the Senior Notes
Indenture), the trustee or the holders of at least 25% in
aggregate principal amount of the Senior Notes then outstanding
may declare all of the amounts outstanding under the Senior
Notes to be due and payable immediately.
Pursuant to the Senior Notes Indenture, Basic is subject to
covenants that limit the ability of Basic and its restricted
subsidiaries to, among other things, incur additional
indebtedness, pay dividends or repurchase or redeem capital
stock, make certain investments, incur liens, enter into certain
types of transactions with affiliates, limit dividends or other
payments by restricted subsidiaries, and sell assets or
consolidate or merge with or into other companies. These
limitations are subject to a number of important qualifications
and exceptions set forth in the Senior Notes Indenture. The
Company was in compliance with the restrictive covenants at
December 31, 2009.
As part of the issuance of the above-mentioned Senior Notes,
Basic incurred debt issuance costs of approximately
$4.6 million, which are being amortized to interest expense
using the effective interest method over the term of the Senior
Notes.
The Senior Notes are jointly and severally guaranteed by each of
Basics restricted subsidiaries (currently all of
Basics subsidiaries other than two immaterial
subsidiaries). Basic Energy Services, Inc., the ultimate parent
company, does not have any independent operating assets or
operations. Subsidiaries other than the restricted subsidiaries
that are guarantors are minor.
Senior
Secured Notes
On July 31, 2009, Basic completed the issuance and sale of
$225.0 million aggregate principal amount of
11.625% Senior Secured Notes due 2014 (the Senior
Secured Notes). The Senior Secured Notes are jointly and
severally, and unconditionally, guaranteed on a senior secured
basis by all of Basics current subsidiaries other than two
immaterial subsidiaries. As of December 31, 2009, these two
subsidiaries held no assets and performed no operations. The
Senior Secured Notes and the related guarantees were offered and
sold in private transactions in accordance with Rule 144A
and Regulation S under the Securities Act of 1933, as
amended. Under the terms of the sale of the Senior Secured
Notes, Basic was required to take appropriate steps to offer to
exchange other Senior Secured Notes with the same terms that
have been registered with the Securities and Exchange Commission
for the private placement Senior Secured Notes. Basic completed
the exchange offer for all of the Senior Secured Notes on
November 25, 2009.
The net proceeds from the issuance of the Senior Secured Notes
were $207.7 million after discounts of $12.1 million
and offering expenses of $5.2 million. Basic used the net
proceeds from the offering, along with other funds, to repay all
outstanding indebtedness under its revolving credit facility,
which Basic terminated in connection with the offering.
The Senior Secured Notes and the related guarantees were issued
pursuant to an indenture dated as of July 31, 2009 (the
Senior Secured Notes Indenture), by and among Basic,
the guarantors party thereto and The Bank of New York Mellon
Trust Company, N.A., as trustee. The obligations under the
Senior Secured Notes Indenture are secured as set forth in the
Senior Secured Notes Indenture and in the Security Agreement (as
defined below), in favor of the trustee, by a first-priority
lien (other than Permitted Collateral Liens, as defined in the
Senior Secured Notes Indenture) in favor of the trustee, on the
Collateral (as defined below) described in the Security
Agreement.
70
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Interest on the Senior Secured Notes accrues at a rate of
11.625% per year. Interest on the Senior Secured Notes is
payable semi-annually in arrears on February 1 and August 1 of
each year, commencing on February 1, 2010. The Senior
Secured Notes mature on August 1, 2014.
The Senior Secured Notes Indenture contains covenants that,
among other things, limit Basics ability, and the ability
of certain of its subsidiaries to, incur additional
indebtedness, pay dividends or repurchase or redeem capital
stock, make certain investments, incur liens, enter into certain
types of transactions with its affiliates, limit dividends or
other payments by its restricted subsidiaries to Basic, sell
assets (including Collateral under the Security Agreement), or
consolidate or merge with or into other companies. These
limitations are subject to a number of important exceptions and
qualifications. Basic was in compliance with the restrictive
covenants at December 31, 2009.
If Basic or its restricted subsidiaries sell, transfer or
otherwise dispose of assets or other rights or property that
constitute Collateral (including the same or the issuance of
equity interests in a restricted subsidiary that owns Collateral
such that it thereafter is no longer a restricted subsidiary, a
Collateral Disposition), Basic is required to
deposit any cash or cash equivalent proceeds constituting net
available proceeds into a segregated account under the sole
control of the trustee that includes only proceeds from the
Collateral Disposition and interest earned thereon (an
Asset Sale Proceeds Account). The Asset Sale
Proceeds Account will be subject to a first-priority lien in
favor of the trustee, and the proceeds are subject to release
from the account for specified uses. These permitted uses
include acquiring additional assets of a type constituting
Collateral (Additional Assets), provided the trustee
has or is immediately granted a perfected first-priority
security interest (subject only to Permitted Collateral Liens)
in such Additional Assets, and repurchasing or redeeming the
Senior Secured Notes.
Upon an Event of Default (as defined in the Senior Secured Notes
Indenture), the trustee or the holders of at least 25% in
aggregate principal amount of the Senior Secured Notes then
outstanding may declare the entire principal of all the Senior
Secured Notes to be due and payable immediately.
Basic may, at its option, redeem all or part of the Senior
Secured Notes, at any time on or after February 1, 2012, at
a redemption price equal to 100% of the principal amount
thereof, plus a premium declining ratably to par and accrued and
unpaid interest to the date of redemption. Basic may redeem some
or all of the Senior Secured Notes before February 1, 2012,
at a redemption price equal to 100% of the principal amount of
the Senior Secured Notes to be redeemed, plus the Applicable
Premium (as defined in the Senior Secured Notes Indenture) and
accrued and unpaid interest to the date of redemption.
In addition, at any time before February 1, 2012, Basic, at
its option, may redeem up to 35% of the aggregate principal
amount of the Senior Secured Notes issued under the Senior
Secured Notes Indenture with the net cash proceeds of one or
more qualified equity offerings at a redemption price of
111.625% of the principal amount of the Senior Secured Notes to
be redeemed, plus accrued and unpaid interest to the date of
redemption, as long as at least 65% of the aggregate principal
amount of the Senior Secured Notes issued under the Senior
Secured Notes Indenture remains outstanding immediately after
the occurrence of such redemption, and such redemption occurs
within 90 days of the date of the closing of any such
qualified equity offering.
Following a change of control as defined in the Senior Secured
Notes Indenture, holders of the Senior Secured Notes will be
entitled to require Basic to purchase all or a portion of the
Senior Secured Notes at 101% of their principal amount, plus
accrued and unpaid interest to the date of repurchase.
On July 31, 2009, Basic and each of the guarantors party to
the Senior Secured Notes Indenture (the Grantors)
entered into a Security Agreement (the Security
Agreement) in favor of The Bank of New York Mellon
Trust Company, N.A., as trustee under the Senior Secured
Notes Indenture, to secure payment of the Senior Secured Notes
and related guarantees. The Liens (as defined in the Security
Agreement) granted by each of the Grantors under the Security
Agreement consist of a security interest in all of the following
personal property now owned or at any time thereafter acquired
by such Grantor or in which such Grantor now has or at any time
in the future may acquire any right, title or interest and
whether existing as of the date of the Security Agreement or
71
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
thereafter coming into existence (together with the Aircraft
Collateral (as defined in the Security Agreement), the
Collateral), as collateral security for the prompt
and complete payment and performance when due (whether at the
stated maturity, by acceleration or otherwise) of the
obligations of the Grantors under the Senior Secured Notes
Indenture, the related Senior Secured Notes and the security
documents:
(i) all Commercial Tort Claims;
(ii) all Contracts (as defined in the Security Agreement);
(iii) all Documents;
(iv) all Equipment (other than the Aircraft Collateral);
(v) all General Intangibles (excluding Payment Intangibles
except to the extent included pursuant to clause (xv)
below);
(vi) all Goods (as defined in the Security Agreement);
(vii) all Intellectual Property (as defined in the Security
Agreement);
(viii) all Investment Property;
(ix) all
Letter-of-Credit
Rights (whether or not the letter of credit is evidenced by a
writing);
(x) all Supporting Obligations;
(xi) each Asset Sale Proceeds Account (as defined in the
Security Agreement) and all deposits, Securities and Financial
Assets (as defined in the Security Agreement) therein and
interest or other income thereon and investments thereof, and
all property of every type and description in which any proceeds
of any Collateral Disposition or other disposition of Collateral
are invested or upon which the trustee is at any time granted,
or required to be granted, a Lien to secure the Obligations (as
defined in the Security Agreement) as set forth in
Section 4.12 of the Senior Secured Notes Indenture and all
proceeds and products of the Collateral described in this clause
(xi);
(xii) all other personal property (other than Excluded
Property), whether tangible or intangible, not otherwise
described above;
(xiii) whatever is received (whether voluntary or
involuntary, whether cash or non cash, including proceeds of
insurance and condemnation awards, rental or lease payments,
accounts, chattel paper, instruments, documents, contract
rights, general intangibles, equipment
and/or
inventory) upon the lease, sale, charter, exchange, transfer, or
other disposition of any of the Collateral described in
clauses (i) through (xii) above;
(xiv) all books and records pertaining to the
Collateral; and
(xv) to the extent not otherwise included, all Proceeds,
Supporting Obligations and products (including, without
limitation, any Accounts, Chattel Paper, Instruments or Payment
Intangibles constituting Proceeds, Supporting Obligations or
products) of any and all of the foregoing and all collateral
security and guarantees given by any Person with respect to any
of the foregoing; provided, that notwithstanding the foregoing
provisions, Collateral shall not include Excluded Property.
Excluded Property means the following,
whether now owned or at any time hereafter acquired by any
Grantor or in which such Grantor now has or at any time in the
future may acquire any right, title or interest and whether now
existing or hereafter coming into existence: Maritime Assets (as
defined in the Security Agreement), cash and cash equivalents
(as such terms are defined by GAAP) other than those maintained
in an Asset Sales Proceeds Account, Securities Accounts
containing only cash and cash equivalents other than any Asset
Sale Proceeds Account and Security Entitlements relating to any
such Securities Account, equity interests in any subsidiary of
any Grantor, Inventory, trucks, trailers and other motor
vehicles covered by a certificate of title law of
72
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
any state, property
and/or
transactions to which Article 9 of the UCC does not apply
pursuant to
Section 9-109
thereof, certain computer software and Equipment acquired prior
to the date thereof and subject to a lien securing purchase
money indebtedness as of the date thereof if (but only to the
extent that) the applicable documentation relating to such lien
prohibits the granting of a lien on such Equipment, Equipment
leased by any Grantor, other than pursuant to a capitalized
lease, if (but only to the extent that) the lien securing the
Equipment prohibits the granting of a lien on such Equipment,
certain General Intangibles, governmental approvals or other
rights arising under any contracts, instruments, permits,
licenses or other documents if the granting of a security
interest therein would cause a breach of a restriction on the
granting of a security interest therein or the assignment
thereof in favor of a third party, subject to exceptions as set
forth in the Security Agreement, and Accounts, Chattel Paper,
Instruments and Payment Intangibles to the extent they are not
Proceeds, Supporting Obligations or products of the Collateral.
The following capitalized terms used above are as defined in the
Uniform Commercial Code (UCC) of the State of New
York, or such other jurisdiction as may be applicable under the
terms of the Security Agreement on the date of the Security
Agreement: Accounts, Chattel Paper, Commercial Tort Claims,
Deposit Account, Documents, Electronic Chattel Paper, Equipment,
Financial Assets, General Intangibles, Instruments, Inventory,
Investment Property,
Letter-of-Credit
Rights, Payment Intangibles, Proceeds, Securities, Securities
Accounts, Security Entitlements, Supporting Obligations, and
Tangible Chattel Paper.
Under the Security Agreement, each Grantor must maintain a
perfected security interest in favor of the trustee and take all
steps necessary from time to time in order to maintain the
trustees first-priority security interest (other than
Permitted Collateral Liens). If an event of default were to
occur under the Senior Secured Notes Indenture, the Senior
Secured Notes, the guarantees relating to the Senior Secured
Notes, the Security Agreement or any other agreement, instrument
or certificate that is entered into to secure payment or
performance of the Senior Secured Notes, the trustee would be
empowered to exercise all rights and remedies of a secured party
under the UCC, in addition to all other rights and remedies
under the applicable agreements.
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.
As of December 31, 2009 the aggregate maturities of debt,
including capital leases, for the next five years and thereafter
are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Debt
|
|
|
Capital Leases
|
|
|
2010
|
|
$
|
|
|
|
$
|
25,967
|
|
2011
|
|
|
|
|
|
|
18,591
|
|
2012
|
|
|
|
|
|
|
13,990
|
|
2013
|
|
|
|
|
|
|
4,578
|
|
2014
|
|
|
225,000
|
|
|
|
49
|
|
Thereafter
|
|
|
225,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
450,000
|
|
|
$
|
63,175
|
|
|
|
|
|
|
|
|
|
|
73
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Basics interest expense consisted of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Cash payments for interest
|
|
$
|
21,357
|
|
|
$
|
24,484
|
|
|
$
|
25,594
|
|
Commitment and other fees paid
|
|
|
159
|
|
|
|
211
|
|
|
|
249
|
|
Amortization of debt issuance costs and discount on senior
secured notes
|
|
|
2,153
|
|
|
|
968
|
|
|
|
962
|
|
Change in accrued interest
|
|
|
9,277
|
|
|
|
1,157
|
|
|
|
540
|
|
Other
|
|
|
3
|
|
|
|
(54
|
)
|
|
|
71
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
32,949
|
|
|
$
|
26,766
|
|
|
$
|
27,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Losses
on Extinguishment of Debt
In July 2009 and February 2007, Basic recognized a loss on the
early extinguishment of debt. In July 2009, Basic wrote off
unamortized debt issuance costs of approximately
$3.5 million, which related to the Companys revolving
credit facility. In February 2007, Basic wrote off unamortized
debt issuance costs of approximately $0.2 million, which
related to the 2005 credit facility.
Income tax expense (benefit) consists of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
(58,972
|
)
|
|
$
|
20,533
|
|
|
$
|
33,157
|
|
State
|
|
|
(3,327
|
)
|
|
|
4,436
|
|
|
|
5,160
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
(62,299
|
)
|
|
|
24,969
|
|
|
|
38,317
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(23,217
|
)
|
|
|
28,792
|
|
|
|
14,207
|
|
State
|
|
|
(2,013
|
)
|
|
|
1,373
|
|
|
|
242
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
(25,230
|
)
|
|
|
30,165
|
|
|
|
14,449
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense
|
|
$
|
(87,529
|
)
|
|
$
|
55,134
|
|
|
$
|
52,766
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic paid Federal income taxes of $243,000 during 2009,
$22.0 million during 2008 and $44.1 million during
2007.
74
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Reconciliation between the amount determined by applying the
Federal statutory rate of 35% to income from continuing
operations with the provision for income taxes is as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Statutory federal income tax
|
|
$
|
(119,374
|
)
|
|
$
|
43,180
|
|
|
$
|
49,174
|
|
Meals and entertainment
|
|
|
374
|
|
|
|
542
|
|
|
|
532
|
|
State taxes, net of federal benefit
|
|
|
(4,227
|
)
|
|
|
4,726
|
|
|
|
4,062
|
|
Impairment of non-dedcutible goodwill
|
|
|
35,586
|
|
|
|
7,883
|
|
|
|
|
|
Changes in estimates and other
|
|
|
112
|
|
|
|
(1,197
|
)
|
|
|
(1,002
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(87,529
|
)
|
|
$
|
55,134
|
|
|
$
|
52,766
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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,
|
|
|
|
2009
|
|
|
2008
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Receivables allowance
|
|
$
|
1,679
|
|
|
$
|
2,151
|
|
Inventory
|
|
|
42
|
|
|
|
42
|
|
Asset retirement obligation
|
|
|
386
|
|
|
|
331
|
|
Accrued liabilities
|
|
|
7,193
|
|
|
|
8,696
|
|
Operating loss carryforward
|
|
|
2,227
|
|
|
|
788
|
|
Goodwill and intangibles
|
|
|
16,797
|
|
|
|
|
|
Deferred compensation
|
|
|
4,786
|
|
|
|
3,497
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
33,110
|
|
|
|
15,505
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Property and equipment
|
|
|
(146,390
|
)
|
|
|
(135,354
|
)
|
Goodwill and intangibles
|
|
|
|
|
|
|
(18,541
|
)
|
Prepaid expenses
|
|
|
|
|
|
|
(120
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
(146,390
|
)
|
|
|
(154,015
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
|
(113,280
|
)
|
|
|
(138,510
|
)
|
|
|
|
|
|
|
|
|
|
Recognized as:
|
|
|
|
|
|
|
|
|
Deferred tax assets current
|
|
|
8,941
|
|
|
|
11,081
|
|
Deferred tax liabilities non-current
|
|
|
(122,221
|
)
|
|
|
(149,591
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
(113,280
|
)
|
|
$
|
(138,510
|
)
|
|
|
|
|
|
|
|
|
|
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, 2009 or 2008.
Effective January 1, 2007, Basic adopted accounting rules
related to uncertainty in income taxes. Our adoption of these
rules in January 2007 did not result in any change to retained
earnings or any additional unrecognized tax benefit. Interest is
recorded in interest expense and penalties are recorded in
income tax expense. We had no interest or penalties related to
an uncertain tax positions during 2009. Basic files federal
income tax returns and state income tax returns in Texas and
other state tax jurisdictions. In general, the Companys
tax returns for fiscal years after 2004
75
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
currently remain subject to examination by appropriate taxing
authorities. None of the Companys income tax returns are
under examination at this time.
As of December 31, 2009, Basic had approximately
$2.3 million of net operating loss carryforwards
(NOL) for U.S. federal income tax purposes
related to the preacquisition period of FESCO (acquired in
2003), which are subject to an annual limitation of
approximately $892,000. 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.
Operating
Leases
Basic leases certain property and equipment under non-cancelable
operating leases. The term of the operating leases generally
range from 12 to 60 months with varying payment dates
throughout each month.
As of December 31, 2009, the future minimum lease payments
under non-cancelable operating leases are as follows (in
thousands):
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
2010
|
|
$
|
3,862
|
|
2011
|
|
|
3,129
|
|
2012
|
|
|
2,060
|
|
2013
|
|
|
1,718
|
|
2014
|
|
|
1,346
|
|
Thereafter
|
|
|
3,336
|
|
Rent expense approximated $13.4 million,
$20.3 million, and $17.4 million for 2009, 2008 and
2007, respectively.
76
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Basic leases rights for the use of various brine and fresh water
wells and disposal wells ranging in terms from
month-to-month
up to 99 years. The above table reflects the future minimum
lease payments if the lease contains a periodic rental. However,
the majority of these leases require payments based on a royalty
percentage or a volume usage.
Employment
Agreements
Under the employment agreement with Mr. Huseman, Chief
Executive Officer and President of Basic, effective
December 31, 2006 through December 31, 2010, amended
February 27, 2008, Mr. Huseman is entitled to an
annual salary of $495,000. Under this employment agreement,
Mr. Huseman is eligible from time to time to receive grants
of stock options and other long-term equity incentive
compensation under our Amended and Restated 2003 Incentive Plan.
In addition, upon a qualified termination of employment,
Mr. Huseman would be entitled to three times his annual
base salary plus his current annual incentive target bonus for
the full year in which the termination of employment occurred.
If employment is terminated for certain reasons within the six
months preceding or the twelve months following the change of
control of our Company, Mr. Huseman would be entitled to a
lump sum severance payment equal to three times the sum of his
annual base salary plus the higher of (i) his current
incentive target bonus for the full year in which the
termination of employment occurred or (ii) the highest
annual incentive bonus received by him for any of the last three
fiscal years.
Basic has entered into employment agreements with various other
executive officers of Basic that range in term up through
December 2010. Under these agreements, if the officers
employment is terminated for certain reasons, he would be
entitled to a lump sum severance payment equal to amounts
ranging from 0.75 times to 1.5 times the sum of his annual base
salary plus his current annual incentive target bonus for the
full year in which the termination occurred . If employment is
terminated for certain reasons within the six months preceding
or the twelve months following the chance of control of our
Company, he would be entitled to a lump sum severance payment
equal to three times the sum of his annual base salary plus the
higher of (i) his current incentive target bonus for the
full year in which the termination of employment occurred or
(ii) the highest annual incentive bonus received by him for
any of the last three fiscal years.
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 $500,000 and $250,000, respectively. Basic
has lower deductibles per occurrence for automobile liability
and general liability. Basic maintains accruals in the
accompanying consolidated balance sheets related to
self-insurance retentions by using third-party data and claims
history. In 2009 and 2008 Basic classified the workers
compensation self-insured risk reserve between short-term and
long-term, with $2.8 million and $4.0 million being
allocated to short-term and $4.1 million and
$5.0 million being allocated to long-term, respectively.
At December 31, 2009 and December 31, 2008,
self-insured risk accruals totaled approximately
$12.9 million, net of $75,000 receivable for medical and
dental coverage, and $15.4 million, net of $992,000
receivable for medical and dental coverage, respectively.
Common
Stock
At December 31, 2009 and 2008, Basic had
80,000,000 shares of Basics common stock, par value
$.01 per share, authorized.
77
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
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. This amount was being charged to expense over the
respective vesting period and totaled approximately $182,000 and
$1.2 million for the years ended December 31, 2008 and
2007.
In March and April 2007, Basic issued 1,794,759 and
430,191 shares of common stock in connection with the
acquisitions of JetStar Consolidated Holding, Inc. and Sledge
Drilling Holding Corp., respectively. (See note 3) In
March 2007, Basic granted various employees 217,100 unvested
shares of common stock which vest over a five year period. Also,
in March 2007, Basic granted the Chairman of the Board
4,000 shares of common stock. In July 2007, Basic granted a
vice president 12,000 shares of restricted common stock
which vest over a four-year period.
In March 2008, Basic granted various employees 361,700 unvested
shares of common stock which vest over a five-year period. Also,
in March 2008, Basic granted the Chairman of the Board
4,000 shares of common stock which vested immediately in
lieu of annual cash director fees. In October 2008, Basic
granted a vice president 5,000 shares of restricted common
stock which vest over a three-year period.
In March 2008, the Compensation Committee of Basics Board
of Directors approved grants of performance-based stock awards
to certain members of management. In March 2009, it was
determined that 93,500 shares, or 100% of the target number
of shares, were earned based on the Companys achievement
of certain earnings per share growth and return on capital
employed performance over the performance period from
January 1, 2006 through December 31, 2008, as compared
to other members of a defined peer group. These shares remain
subject to vesting over a three-year period, with the first
shares vesting on March 15, 2010.
In March 2009, Basic granted various employees 571,824 unvested
shares of common stock which vest over a five-year period. Also,
in March 2009, Basic granted the Chairman of the Board
4,000 shares of common stock which vested immediately in
lieu of annual cash director fees.
In May 2009, consistent with its director compensation
practices, Basic granted a new board member 37,500 shares
of restricted common stock which vest over a three-year period.
During the year ended 2009, Basic issued 5,000 shares of
common stock from treasury stock for the exercise of stock
options.
Treasury
Stock
On October 13, 2008, Basic announced that its Board of
Directors authorized the repurchase of up to $50.0 million
of Basics shares of common stock from time to time in open
market or private transactions, at Basics discretion. The
number of shares purchased and the timing of purchases is based
on several factors, including the price of the common stock,
general market conditions, available cash and alternative
investment opportunities. In 2009, Basic repurchased
809,093 shares at a total price of $6.0 million (an
average of $7.41 per share), inclusive of commissions and fees.
The stock repurchase program was suspended by the Board of
Directors during the first quarter of 2009.
Basic also acquired treasury shares through net share
settlements for payment of payroll taxes upon the vesting of
restricted stock. We repurchased a total of 20,327 and
52,877 shares through net share settlements during 2009 and
2008, respectively.
Preferred
Stock
At December 31, 2009 and 2008, Basic had
5,000,000 shares of preferred stock, par value $.01 per
share, authorized, of which none was designated, issued or
outstanding.
78
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
9.
|
Stockholders
Agreement
|
Basic has a Stockholders Agreement, as amended on
April 2, 2004 (Stockholders Agreement),
which provides for rights relating to the shares of our
stockholders and certain corporate governance matters. The
rights relating to corporate governance matters terminated in
connection with Basics initial public offering.
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 in a transaction or series of
transactions involving 10% or more of the then-outstanding
shares of Basics common stock, 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 affiliates 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 provides for demand and
piggyback registration rights to parties who continue to hold
Registrable Securities as defined in the agreement.
In May 2003, Basics board of directors and stockholders
approved the Basic 2003 Incentive Plan (as amended effective
May, 26 2009) (the Plan), which provides for
granting of incentive awards in the form of stock options,
restricted stock, performance awards, bonus shares, phantom
shares, cash awards and other stock-based awards to officers,
employees, directors and consultants of Basic. The Plan assumed
the awards of the plans of Basics predecessors that were
awarded and remained outstanding prior to adoption of the Plan.
The Plan provides for the issuance of 7,100,000 shares. Of
these shares, approximately 2,143,551 shares are available
for grant as of December 31, 2009. The Plan is administered
by the Plan committee, and in the absence of a Plan committee,
by the Board of Directors, which determines the awards and the
associated terms of the awards and interprets its provisions and
adopts policies for implementing the Plan. The number of shares
authorized under the Plan and the number of shares subject to an
award under the Plan will be adjusted for stock splits, stock
dividends, recapitalizations, mergers and other changes
affecting the capital stock of Basic.
On March 15, 2007, the board of directors granted various
employees options to purchase 92,000 shares of common stock
of Basic at an exercise price of $22.66 per share. All of the
92,000 options granted in 2007 vest over a five-year period and
expire ten years from the date they were granted. These option
awards were granted with an exercise price equal to the market
price of the Companys stock at the date of grant. There
were no options granted during 2009 or 2008.
During the years ended December 31, 2009, 2008 and 2007,
compensation expense related to share-based arrangements
including both restricted stock awards and stock option awards
was approximately $5.2 million, $4.1 million and
$3.9 million, respectively. For compensation expense
recognized during the years ended December 31, 2009, 2008
and 2007, Basic recognized a tax benefit of approximately
$1.9 million, $1.9 million and $1.5 million,
respectively.
As of December 31, 2009, there was $10.4 million of
total unrecognized compensation related to non-vested
share-based compensation arrangements granted under the Plan.
That cost is expected to be recognized over a weighted-average
period of 2.79 years. The total fair value of share-based
awards vested during the years ended December 31, 2009,
2008 and 2007 was approximately $4.1 million,
$10.3 million and $11.3 million, respectively. The
actual tax benefit realized for the tax deduction from vested
share-based awards was $201,000, $1.5 million and
$1.6 million, respectively, for the years ended
December 31, 2009, 2008 and 2007.
79
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Stock
Option Awards
The fair value of each option award is estimated on the date of
grant using the Black-Scholes-Merton option-pricing model that
uses the subjective assumptions noted in the following table.
Since the Company has only been public since December 2005,
expected volatility for options granted during 2007 is a
combination of the Companys historical data and volatility
based upon a peer group. The expected term of options granted
represents the period of time that options granted are expected
to be outstanding. For options granted in 2007, the Company used
the simplified method to calculate the expected term. For
options granted in 2007, the risk-free rate for periods within
the contractual life of the options is based on the
U.S. Treasury yield curve in effect at the time of grant.
The estimates involve inherent uncertainties and the application
of management judgment. In addition, we are required to estimate
the expected forfeiture rate and only recognize expense for
those options expected to vest.
The fair value of each option award is estimated on the date of
grant using the Black-Scholes-Merton option-pricing model that
uses the assumptions noted in the following table:
|
|
|
|
|
|
|
Years Ended
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
Risk-free interest rate
|
|
|
4.5
|
%
|
Expected term
|
|
|
6.65
|
|
Expected volatility
|
|
|
45.3
|
%
|
Expected dividend yield
|
|
|
|
|
Options granted under the Plan expire ten years from the date
they are granted, and generally vest over a
three-to-five
year service period.
The following table reflects the summary of stock options
outstanding at December 31, 2009 and the changes during the
twelve months then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
Average
|
|
|
Aggregate
|
|
|
|
Number of
|
|
|
Average
|
|
|
Remaining
|
|
|
Instrinsic
|
|
|
|
Options
|
|
|
Exercise
|
|
|
Contractual
|
|
|
Value
|
|
|
|
Granted
|
|
|
Price
|
|
|
Term (Years)
|
|
|
(000s)
|
|
|
Non-statutory stock options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, beginning of period
|
|
|
1,608,675
|
|
|
$
|
11.11
|
|
|
|
|
|
|
|
|
|
Options granted
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Options forfeited
|
|
|
(23,000
|
)
|
|
$
|
13.89
|
|
|
|
|
|
|
|
|
|
Options exercised
|
|
|
(5,000
|
)
|
|
$
|
6.98
|
|
|
|
|
|
|
|
|
|
Options expired
|
|
|
(99,750
|
)
|
|
$
|
6.83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period
|
|
|
1,480,925
|
|
|
$
|
11.37
|
|
|
|
4.83
|
|
|
$
|
3,522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, end of period
|
|
|
1,115,550
|
|
|
$
|
9.13
|
|
|
|
4.45
|
|
|
$
|
3,245
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested or expected to vest, end of period
|
|
|
1,471,425
|
|
|
$
|
11.29
|
|
|
|
4.82
|
|
|
$
|
3,522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted-average grant date fair value of share options
granted during the year ended December 31, 2007 was $11.85.
The total intrinsic value of share options exercised during the
years ended December 31, 2009, 2008 and 2007 was
approximately $15,000, $12.2 million and $3.6 million,
respectively.
Cash received from option exercises under the Plan was
approximately $35,000, $2.7 million and $975,000 for the
years ended December 31, 2009, 2008 and 2007, respectively.
The actual tax benefit realized for the tax deductions from
options exercised was $6,000, $5.6 million and
$1.4 million, respectively, for the years ended
December 31, 2009, 2008 and 2007.
80
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The Company has a history of issuing treasury and newly-issued
shares to satisfy share option exercises.
Restricted
Stock Awards
On March 13, 2009, the Compensation Committee of
Basics Board of Directors approved grants of
performance-based stock awards to certain members of management.
The performance-based awards are tied to the Companys
achievement of certain earnings per share growth and return on
capital employed performance over the performance period from
January 1, 2007 through December 31, 2009, as compared
to other members of a defined peer group. The number of shares
to be issued will range from 0% to 150% of the target number of
shares of 265,000 depending on the performance noted above. Any
shares earned at the end of the performance period will then
remain subject to vesting over a three-year period, with the
first shares vesting March 15, 2011. As of
December 31, 2009, it was estimated that 30% of the
performance-based awards will be earned.
A summary of the status of the Companys non-vested share
grants at December 31, 2009 and changes during the year
ended December 31, 2009 is presented in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
Number of
|
|
|
Grant Date Fair
|
|
Nonvested Shares
|
|
Shares
|
|
|
Value Per Share
|
|
|
Nonvested at beginning of period
|
|
|
599,325
|
|
|
$
|
21.41
|
|
Granted during period
|
|
|
698,824
|
|
|
|
6.48
|
|
Vested during period
|
|
|
(92,841
|
)
|
|
|
18.20
|
|
Forfeited during period
|
|
|
(75,200
|
)
|
|
|
14.27
|
|
Performance based earned(1)
|
|
|
14,025
|
|
|
|
21.17
|
|
|
|
|
|
|
|
|
|
|
Nonvested at end of period
|
|
|
1,144,133
|
|
|
$
|
13.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
In March 2008 certain members of management were awarded grants
of performance-based stock awards. The number of shares to be
earned ranged from 0% to 150% of target depending on the
Companys achievement of certain EPS and return on capital
employed performance compared to a peer group. The performance
period for purposes of these grants was January 1, 2006
through December 31, 2008. As of December 31, 2008 it
was estimated that 85% of the target shares would be earned and
in March 2009 it was determined that 100% of the target shares
had been earned. These shares remain subject to vesting over a
three-year period, with the first shares vesting in March 2010. |
|
|
11.
|
Related
Party Transactions
|
Basic had receivables from employees of approximately $65,000
and $148,000 as of December 31, 2009 and December 31,
2008, respectively. During 2006, Basic entered into a lease
agreement with Darle Vuelta Cattle Co., LLC, an affiliate of the
Chief Executive Officer, for approximately $69,000. The term of
the lease is five years and will continue on a
year-to-year
basis unless terminated by either party.
Basic has a 401(k) profit sharing plan that covers substantially
all employees. 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
$671,000, $4.1 million, and $3.0 million in 2009, 2008
and 2007, respectively. In the second quarter of 2009, Basic
suspended the Company match on 401(k) contributions.
81
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
13.
|
Deferred
Compensation Plan
|
In April 2005, Basic established a deferred compensation plan
for certain employees. Participants may defer up to 50% of their
salary and 100% of any cash bonuses. Basic makes matching
contributions of 100% of the first 3% of the participants
deferred pay and 50% of the next 2% of the participants
deferred pay to a maximum match of $9,200 per year. Employer
matching contributions and earnings thereon are subject to a
five-year vesting schedule with full vesting occurring after
five years of service. Employer contributions to the deferred
compensation plan net of earnings approximated a $565,000
expense in 2009, $563,000 gain in 2008 and a $216,000 expense in
2007, respectively.
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
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,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Numerator (both basic and diluted):
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders
|
|
$
|
(253,538
|
)
|
|
$
|
68,238
|
|
|
$
|
87,733
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for basic earnings per share
|
|
|
39,684,231
|
|
|
|
40,754,890
|
|
|
|
40,013,054
|
|
Stock options
|
|
|
|
|
|
|
682,958
|
|
|
|
831,026
|
|
Unvested restricted stock
|
|
|
|
|
|
|
225,842
|
|
|
|
268,324
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted earnings per share
|
|
|
39,684,231
|
|
|
|
41,663,690
|
|
|
|
41,112,404
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders
|
|
$
|
(6.39
|
)
|
|
$
|
1.67
|
|
|
$
|
2.19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders
|
|
$
|
(6.39
|
)
|
|
$
|
1.64
|
|
|
$
|
2.13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The number of antidilutive shares at December 31, 2009,
2008 and 2007 was 1.4 million, 413,000 and 442,000,
respectively.
|
|
15.
|
Business
Segment Information
|
Basic revised its reportable business segments beginning in the
first quarter of 2008 and in connection therewith restated the
corresponding items of segment information for earlier periods.
Basics current operating segments are Well Servicing,
Fluid Services, Completion and Remedial Services, and Contract
Drilling. These segments have been selected based on changes in
managements resource allocation and performance assessment
in making decisions regarding the Company. Contract Drilling was
previously included in our Well Servicing segment. Well Site
Construction Services is now consolidated with our Fluid
Services segment. 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 natural gas. These
services are performed to establish, maintain and improve
production throughout the productive life of an oil and natural
gas well and to plug and abandon a well at
82
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
the end of its productive life. Basics well servicing
equipment and capabilities also 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, completion and remedial projects as
well as part of daily producing well operations. Also included
in this segment is our construction services which provide
services for the construction and maintenance of oil and natural
gas production infrastructures.
Completion and Remedial Services: This segment
utilizes a fleet of pressure pumping units, air compressor
packages specially configured for underbalanced drilling
operations, cased-hole wireline units and an array of
specialized rental equipment and fishing tools. The largest
portion of this business consists of pressure pumping services
focused on cementing, acidizing and fracturing services in niche
markets.
Contract Drilling: This segment utilizes
shallow and medium depth rigs and associated equipment for
drilling wells to a specified depth for customers on a contract
basis.
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.
83
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The following table sets forth certain financial information
with respect to Basics reportable segments (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Completion and
|
|
|
|
|
|
|
|
|
|
|
|
|
Well
|
|
|
Fluid
|
|
|
Remedial
|
|
|
Contract
|
|
|
Corporate
|
|
|
|
|
|
|
Servicing
|
|
|
Services
|
|
|
Services
|
|
|
Drilling
|
|
|
and Other
|
|
|
Total
|
|
|
Year ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
160,614
|
|
|
$
|
214,822
|
|
|
$
|
134,818
|
|
|
$
|
16,373
|
|
|
$
|
|
|
|
$
|
526,627
|
|
Direct operating costs
|
|
|
(121,618
|
)
|
|
|
(159,079
|
)
|
|
|
(95,287
|
)
|
|
|
(13,604
|
)
|
|
|
|
|
|
|
(389,588
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profits
|
|
$
|
38,996
|
|
|
$
|
55,743
|
|
|
$
|
39,531
|
|
|
$
|
2,769
|
|
|
$
|
|
|
|
$
|
137,039
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$
|
49,005
|
|
|
$
|
37,594
|
|
|
$
|
31,313
|
|
|
$
|
7,237
|
|
|
$
|
7,371
|
|
|
$
|
132,520
|
|
Capital expenditures, (excluding acquisitions)
|
|
$
|
16,037
|
|
|
$
|
12,303
|
|
|
$
|
10,247
|
|
|
$
|
2,368
|
|
|
$
|
2,412
|
|
|
$
|
43,367
|
|
Identifiable assets
|
|
$
|
244,556
|
|
|
$
|
195,107
|
|
|
$
|
194,988
|
|
|
$
|
41,320
|
|
|
$
|
363,570
|
|
|
$
|
1,039,541
|
|
Year ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
343,113
|
|
|
$
|
315,768
|
|
|
$
|
304,326
|
|
|
$
|
41,735
|
|
|
$
|
|
|
|
$
|
1,004,942
|
|
Direct operating costs
|
|
|
(215,243
|
)
|
|
|
(203,205
|
)
|
|
|
(165,574
|
)
|
|
|
(28,629
|
)
|
|
|
|
|
|
|
(612,651
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profits
|
|
$
|
127,870
|
|
|
$
|
112,563
|
|
|
$
|
138,752
|
|
|
$
|
13,106
|
|
|
$
|
|
|
|
$
|
392,291
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$
|
45,298
|
|
|
$
|
33,629
|
|
|
$
|
27,473
|
|
|
$
|
6,816
|
|
|
$
|
5,391
|
|
|
$
|
118,607
|
|
Capital expenditures, (excluding acquisitions)
|
|
$
|
35,094
|
|
|
$
|
26,054
|
|
|
$
|
21,285
|
|
|
$
|
5,281
|
|
|
$
|
4,176
|
|
|
$
|
91,890
|
|
Identifiable assets
|
|
$
|
310,964
|
|
|
$
|
262,377
|
|
|
$
|
334,120
|
|
|
$
|
47,027
|
|
|
$
|
356,223
|
|
|
$
|
1,310,711
|
|
Year ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
342,697
|
|
|
$
|
259,324
|
|
|
$
|
240,692
|
|
|
$
|
34,460
|
|
|
$
|
|
|
|
$
|
877,173
|
|
Direct operating costs
|
|
|
(205,132
|
)
|
|
|
(165,327
|
)
|
|
|
(125,948
|
)
|
|
|
(22,510
|
)
|
|
|
|
|
|
|
(518,917
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profits
|
|
$
|
137,565
|
|
|
$
|
93,997
|
|
|
$
|
114,744
|
|
|
$
|
11,950
|
|
|
$
|
|
|
|
$
|
358,256
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$
|
37,586
|
|
|
$
|
23,858
|
|
|
$
|
21,138
|
|
|
$
|
6,433
|
|
|
$
|
4,033
|
|
|
$
|
93,048
|
|
Capital expenditures, (excluding acquisitions)
|
|
$
|
39,803
|
|
|
$
|
25,266
|
|
|
$
|
22,384
|
|
|
$
|
6,813
|
|
|
$
|
4,270
|
|
|
$
|
98,536
|
|
Identifiable assets
|
|
$
|
284,058
|
|
|
$
|
207,380
|
|
|
$
|
284,321
|
|
|
$
|
73,787
|
|
|
$
|
294,063
|
|
|
$
|
1,143,609
|
|
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,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Segment profits
|
|
$
|
137,039
|
|
|
$
|
392,291
|
|
|
$
|
358,256
|
|
General and administrative expenses
|
|
|
(104,253
|
)
|
|
|
(115,319
|
)
|
|
|
(99,042
|
)
|
Depreciation and amortization
|
|
|
(132,520
|
)
|
|
|
(118,607
|
)
|
|
|
(93,048
|
)
|
Gain (loss) on disposal of assets
|
|
|
(2,650
|
)
|
|
|
(76
|
)
|
|
|
(477
|
)
|
Goodwill impairment
|
|
|
(204,014
|
)
|
|
|
(22,522
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
(306,398
|
)
|
|
$
|
135,767
|
|
|
$
|
165,689
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
84
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The accrued expenses are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Compensation related
|
|
$
|
12,709
|
|
|
$
|
19,832
|
|
Workers compensation self-insured risk reserve
|
|
|
3,327
|
|
|
|
4,248
|
|
Health self-insured risk reserve
|
|
|
6,165
|
|
|
|
6,690
|
|
Accrual for receipts
|
|
|
|
|
|
|
4,976
|
|
Authority for expenditure accrual
|
|
|
|
|
|
|
543
|
|
Ad valorem taxes
|
|
|
|
|
|
|
137
|
|
Sales tax
|
|
|
1,226
|
|
|
|
588
|
|
Insurance obligations
|
|
|
2,698
|
|
|
|
2,474
|
|
Purchase order accrual
|
|
|
48
|
|
|
|
38
|
|
Professional fee accrual
|
|
|
343
|
|
|
|
185
|
|
Contingent earnout obligation
|
|
|
346
|
|
|
|
1,438
|
|
Fuel accrual
|
|
|
974
|
|
|
|
897
|
|
Accrued interest
|
|
|
14,360
|
|
|
|
5,083
|
|
Other
|
|
|
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
42,196
|
|
|
$
|
47,139
|
|
|
|
|
|
|
|
|
|
|
|
|
17.
|
Supplemental
Schedule of Cash Flow Information
|
The following table reflects non-cash financing and investing
activity during:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Capital leases issued for equipment
|
|
$
|
18,594
|
|
|
$
|
50,730
|
|
|
$
|
26,814
|
|
Value of shares that may be issued
|
|
$
|
|
|
|
$
|
|
|
|
$
|
2,194
|
|
Contingent earnout accrual
|
|
$
|
|
|
|
$
|
183
|
|
|
$
|
1,032
|
|
Asset retirement obligation additions
|
|
$
|
149
|
|
|
$
|
143
|
|
|
$
|
101
|
|
Value of common stock issued in business combinations
|
|
$
|
|
|
|
$
|
|
|
|
$
|
51,193
|
|
Basic paid income taxes of approximately $2.3 million,
$27.2 million and $44.1 million during the years ended
December 31, 2009, 2008 and 2007, respectively.
85
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
18.
|
Quarterly
Financial Data (Unaudited)
|
The following table summarizes results for each of the four
quarters in the years ended December 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Year
|
|
|
Year ended December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
154,688
|
|
|
$
|
118,848
|
|
|
$
|
124,958
|
|
|
$
|
128,133
|
|
|
$
|
526,627
|
|
Segment profits
|
|
$
|
44,021
|
|
|
$
|
30,820
|
|
|
$
|
31,025
|
|
|
$
|
31,173
|
|
|
$
|
137,039
|
|
Income (loss) from continuing operations
|
|
$
|
(182,825
|
)
|
|
$
|
(21,236
|
)
|
|
$
|
(25,325
|
)
|
|
$
|
(24,152
|
)
|
|
$
|
(253,538
|
)
|
Net income (loss) available to common stockholders
|
|
$
|
(182,825
|
)
|
|
$
|
(21,236
|
)
|
|
$
|
(25,325
|
)
|
|
$
|
(24,152
|
)
|
|
$
|
(253,538
|
)
|
Basic earnings per share of common stock(a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders
|
|
$
|
(4.57
|
)
|
|
$
|
(0.54
|
)
|
|
$
|
(0.64
|
)
|
|
$
|
(0.61
|
)
|
|
$
|
(6.39
|
)
|
Diluted earnings per share of common stock(a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders
|
|
$
|
(4.57
|
)
|
|
$
|
(0.54
|
)
|
|
$
|
(0.64
|
)
|
|
$
|
(0.61
|
)
|
|
$
|
(6.39
|
)
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
39,970
|
|
|
|
39,575
|
|
|
|
39,595
|
|
|
|
39,605
|
|
|
|
39,684
|
|
Diluted
|
|
|
39,970
|
|
|
|
39,575
|
|
|
|
39,595
|
|
|
|
39,605
|
|
|
|
39,684
|
|
Year ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
229,873
|
|
|
$
|
251,522
|
|
|
$
|
277,575
|
|
|
$
|
245,972
|
|
|
$
|
1,004,942
|
|
Segment profits
|
|
$
|
92,126
|
|
|
$
|
97,495
|
|
|
$
|
108,980
|
|
|
$
|
93,690
|
|
|
$
|
392,291
|
|
Income from continuing operations
|
|
$
|
19,656
|
|
|
$
|
18,713
|
|
|
$
|
25,942
|
|
|
$
|
3,927
|
|
|
$
|
68,238
|
|
Net income available to common stockholders
|
|
$
|
19,656
|
|
|
$
|
18,713
|
|
|
$
|
25,942
|
|
|
$
|
3,927
|
|
|
$
|
68,238
|
|
Basic earnings per share of common stock(a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
0.48
|
|
|
$
|
0.46
|
|
|
$
|
0.63
|
|
|
$
|
0.10
|
|
|
$
|
1.67
|
|
Diluted earnings per share of common stock(a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders
|
|
$
|
0.47
|
|
|
$
|
0.45
|
|
|
$
|
0.62
|
|
|
$
|
0.10
|
|
|
$
|
1.64
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
40,577
|
|
|
|
40,721
|
|
|
|
40,988
|
|
|
|
40,731
|
|
|
|
40,755
|
|
Diluted
|
|
|
41,464
|
|
|
|
41,659
|
|
|
|
41,787
|
|
|
|
41,100
|
|
|
|
41,664
|
|
|
|
|
(a) |
|
The sum of individual quarterly net income per share may not
agree to the total for the year due to each periods
computation being based on the weighted average number of common
shares outstanding during each period. |
|
|
19.
|
Fair
Value Measurements
|
Fair value is the price that would be received to sell an asset
or the amount paid to transfer a liability in an orderly
transaction between market participants (an exit price) at the
measurement date. Fair value is a market based measurement
considered from the perspective of a market participant. The
Company uses market data or assumptions that market participants
would use in pricing the asset or liability, including
assumptions about risk and the risks inherent in the inputs to
the valuation. These inputs can be readily observable, market
corroborated, or unobservable. If observable prices or inputs
are not available, unobservable prices or inputs are used to
estimate the current fair value, often using an internal
valuation model. These valuation techniques involve some level
of
86
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
management estimation and judgment, the degree of which is
dependent on the item being valued. The Company primarily
applies a market approach for recurring fair value measurements
using the best available information while utilizing valuation
techniques that maximize the use of observable inputs and
minimize the use of unobservable inputs.
There is a fair value hierarchy that prioritizes the inputs used
to measure fair value. The hierarchy gives the highest priority
to quoted prices in active markets for identical assets or
liabilities (Level 1 measurement) and the lowest priority
to unobservable inputs (Level 3 measurement). The Company
classifies fair value balances based on the observability of
those inputs. The three levels of the fair value hierarchy are
as follows:
Level 1 Quoted prices in active markets
for identical assets or liabilities that the Company has the
ability to access. Active markets are those in which
transactions for the asset or liability occur in sufficient
frequency and volume to provide pricing information on an
ongoing basis.
Level 2 Inputs are other than quoted
prices in active markets included in Level 1, which are
either directly or indirectly observable. These inputs are
either directly observable in the marketplace or indirectly
observable through corroboration with market data for
substantially the full contractual term of the asset or
liability being measured.
Level 3 Inputs reflect managements
best estimate of what market participants would use in pricing
the asset or liability at the measurement date. Consideration is
given to the risk inherent in the valuation technique and the
risk inherent in the inputs to the model.
In valuing certain assets and liabilities, the inputs used to
measure fair value may fall into different levels of the fair
value hierarchy. For disclosure purposes, assets and liabilities
are classified in their entirety in the fair value hierarchy
level based on the lowest level of input that is significant to
the overall fair value measurement. The Companys
assessment of the significance of a particular input to the fair
value measurement requires judgment and may affect the placement
within the fair value hierarchy levels.
The Companys asset retirement obligation related to its
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, is measured
using primarily Level 3 inputs. The significant
unobservable inputs to this fair value measurement include
estimates of plugging, abandonment and remediation costs,
inflation rate and well life. The inputs are calculated based on
historical data as well as current estimated costs.
The fair value is calculated by taking the present value of the
expected cash flow at the time of the closure of the site. The
following table reflects the changes in the liability during
years ended December 31, 2009 and 2008 (in thousands):
|
|
|
|
|
Balance, December 31, 2007
|
|
$
|
1,552
|
|
Additional asset retirement obligations recognized through
acquisitions
|
|
|
143
|
|
Accretion expense
|
|
|
131
|
|
Settlements
|
|
|
(30
|
)
|
Balance, December 31, 2008
|
|
$
|
1,796
|
|
|
|
|
|
|
Additional asset retirement obligations recognized through
acquisitions
|
|
|
24
|
|
Accretion expense
|
|
|
149
|
|
Settlements
|
|
|
|
|
Balance, December 31, 2009
|
|
$
|
1,969
|
|
|
|
|
|
|
Management performed an evaluation of the Companys
activity through February 26, 2010, the date these
financial statements were issued, noting no significant
subsequent events.
87
Schedule II
Valuation and Qualifying Accounts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions
|
|
|
|
|
|
|
|
|
|
Balance at
|
|
|
Charged to
|
|
|
Charged to
|
|
|
|
|
|
Balance at
|
|
|
|
Beginning of
|
|
|
Costs and
|
|
|
Other
|
|
|
|
|
|
End of
|
|
Description
|
|
Period
|
|
|
Expenses(a)
|
|
|
Accounts(b)
|
|
|
Deductions(c)
|
|
|
Period
|
|
|
|
(In thousands)
|
|
|
Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Bad Debt
|
|
$
|
5,838
|
|
|
$
|
1,917
|
|
|
$
|
|
|
|
$
|
(2,998
|
)
|
|
$
|
4,757
|
|
Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Bad Debt
|
|
$
|
6,090
|
|
|
$
|
2,331
|
|
|
$
|
|
|
|
$
|
(2,583
|
)
|
|
$
|
5,838
|
|
Year Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Bad Debt
|
|
$
|
3,963
|
|
|
$
|
3,251
|
|
|
$
|
|
|
|
$
|
(1,124
|
)
|
|
$
|
6,090
|
|
|
|
|
(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 |
88
|
|
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, 2009, 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 and effective to ensure that information
required to be disclosed in such reports is accumulated and
communicated to our management, including our principal
executive officer and principal financial officer, to allow
timely decisions regarding required disclosure.
Changes
in Internal Control Over Financial Reporting
During the most recent fiscal quarter, there have been no
changes in our internal control over financial reporting that
have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.
Design
and Evaluation of Internal Control over Financial
Reporting
Managements Report on Internal Control over Financial
Reporting and the Report of the Independent Registered Public
Accounting Firm are set forth in Part II, Item 8 of
this report and are incorporated herein by reference.
|
|
ITEM 9B.
|
OTHER
INFORMATION
|
None.
PART III
Pursuant to paragraph 3 of General Instruction G to
Form 10-K,
the information required by Item 10, to the extent not set
forth in Executive Officers of the Registrant 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, 2009.
89
PART IV
|
|
ITEM 15.
|
EXHIBITS,
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.
(3) Exhibits
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
2
|
.1*
|
|
Agreement and Plan of Merger, dated as of January 8, 2007,
by and among Basic Energy Services, Inc., JS Acquisition LLC and
JetStar Consolidated Holdings, Inc. (Incorporated by reference
to Exhibit 2.1 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on March 8, 2007)
|
|
2
|
.2*
|
|
Amendment to Merger Agreement, dated as of March 5, 2007,
by and among Basic Energy Services, Inc., JS Acquisition LLC and
JetStar Consolidated Holdings, Inc. (Incorporated by reference
to Exhibit 2.2 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on March 8, 2007)
|
|
3
|
.1*
|
|
Amended and Restated Certificate of Incorporation of the
Company, dated September 22, 2005. (Incorporated by
reference to Exhibit 3.1 of the Companys Registration
Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
3
|
.2*
|
|
Amended and Restated Bylaws of the Company, effective as of
December 17, 2007. (Incorporated by reference to
Exhibit 3.1 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on December 18, 2007)
|
|
4
|
.1*
|
|
Specimen Stock Certificate representing common stock of the
Company. (Incorporated by reference to Exhibit 4.1 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on November 4, 2005)
|
|
4
|
.2*
|
|
Indenture dated April 12, 2006, among Basic Energy
Services, Inc., the guarantors party thereto, and The Bank of
New York Trust Company, N.A., as trustee. (Incorporated by
reference to Exhibit 4.1 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on April 13, 2006)
|
|
4
|
.3*
|
|
Form of 7.125% Senior Note due 2016. (Included in the
Indenture filed as Exhibit 4.1 of the Companys
Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on April 13, 2006)
|
|
4
|
.4*
|
|
First Supplemental Indenture dated as of July 14, 2006 to
Indenture dated as of April 12, 2006 among the Company, as
Issuer, the Subsidiary Guarantors named therein and The Bank of
New York Trust Company, N.A., as trustee. (Incorporated by
reference to Exhibit 4.1 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on July 20, 2006)
|
|
4
|
.5*
|
|
Second Supplemental Indenture dated as of April 26, 2007
and effective as of March 7, 2007 to Indenture dated as of
April 12, 2006 among the Company as Issuer, the Subsidiary
Guarantors named therein and the Bank of New York
Trust Company, N.A., as trustee. (Incorporated by reference
to Exhibit 4.1 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on May 1, 2007)
|
|
4
|
.6*
|
|
Third Supplemental Indenture dated as of April 26, 2007 to
Indenture dated as of April 12, 2006 among the Company as
Issuer, the Subsidiary Guarantors named therein and the Bank of
New York Trust Company, N.A., as trustee. (Incorporated by
reference to Exhibit 4.2 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on May 1, 2007)
|
|
4
|
.7*
|
|
Fourth Supplemental Indenture dated as of February 9, 2009
to Indenture dated as of April 12, 2006 among the Company
as Issuer, the Subsidiary Guarantors named therein and the Bank
of New York Mellon Trust Company, N.A., as Trustee.
(Incorporated by reference to Exhibit 4.7 of the
Companys Annual Report on
Form 10-K
(SEC File
No. 001-32693),
filed on March 9, 2009)
|
90
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
4
|
.8
|
|
Fifth Supplemental Indenture dated as of July 23, 2009 to
Indenture dated as of April 12, 2006 among the Company as
Issuer, the Subsidiary Guarantors named therein and the Bank of
New York Mellon Trust Company, N.A., as Trustee.
|
|
4
|
.9*
|
|
Indenture dated as of July 31, 2009, by and among the
Company as Issuer, the Guarantors named therein and The Bank of
New York Mellon Trust Company, N.A., as Trustee.
(Incorporated by reference to Exhibit 4.1 of the
Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on August 4, 2009)
|
|
4
|
.10*
|
|
Form of 11.625% Senior Secured Note due 2014 (included as
Exhibit A to Exhibit 4.1 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on August 4, 2009)
|
|
4
|
.11*
|
|
Security Agreement dated as of July 31, 2009, by and
between the Company and each of the other Grantors party thereto
in favor of The Bank of New York Mellon Trust Company,
N.A., as Trustee. (Incorporated by reference to Exhibit 4.3
of the Companys Current Report on
Form 8-K
(SEC File No. 001-32693),
filed on August 4, 2009)
|
|
10
|
.1*
|
|
Form of Indemnification Agreement. (Incorporated by reference to
Exhibit 10.1 of the Companys Registration Statement
on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.2*
|
|
Second Amended and Restated Stockholders Agreement dated
as of April 2, 2004 among the Company and the stockholders
listed therein. (Incorporated by reference to Exhibit 10.7
of the Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on August 12, 2005)
|
|
10
|
.3*
|
|
Fourth Amended and Restated Credit Agreement dated as of
October 3, 2003, amended and restated as of
February 6, 2007, among Basic Energy Services, Inc., the
subsidiary guarantors party thereto, Bank of America, N.A., as
syndication agent, Capital One, National Association, as
documentation agent, BNP Paribas, as documentation agent, UBS
AG, Stamford Branch, as issuing bank, administrative agent and
collateral agent, and the lenders party thereto. (Incorporated
by reference to Exhibit 10.1 to the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on February 12, 2007)
|
|
10
|
.4*
|
|
Amendment and Consent No. 1 to Fourth Amended and Restated
Credit Agreement dated May 4, 2009. (Incorporated by
reference to Exhibit 10.1 of the Companys Current
Report on
Form 8-K
(SEC File No. 001-32693),
filed on May 7, 2009)
|
|
10
|
.5*
|
|
Fourth Amended and Restated Basic Energy Services, Inc. 2003
Incentive Plan. (Incorporated by reference to Exhibit 10.1
of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on June 1, 2009)
|
|
10
|
.6*
|
|
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
|
.7*
|
|
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
|
.8*
|
|
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
|
.9*
|
|
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
|
.10*
|
|
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
|
.11*
|
|
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 10.1 to the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2006)
|
|
10
|
.12*
|
|
Form of Nonqualified Stock Option Agreement (Director form
effective March 2006). (Incorporated by reference to
Exhibit 10.13 of the Companys Annual Report on
Form 10-K
(SEC File
No. 001-32693),
filed on March 7, 2008)
|
91
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
10
|
.13*
|
|
Form of Nonqualified Stock Option Agreement (Employee form
effective March 2006). (Incorporated by reference to
Exhibit 10.14 of the Companys Annual Report on
Form 10-K
(SEC File
No. 001-32693),
filed on March 7, 2008)
|
|
10
|
.14*
|
|
Form of Restricted Stock Grant Agreement (Officers and
Employees Post-March 1, 2007). (Incorporated by
reference to Exhibit 10.5 to the Companys Quarterly
Report on
Form 10-Q
(SEC File No. 001-32693),
filed on May 10, 2007)
|
|
10
|
.15*
|
|
Form of Restricted Stock Grant Agreement (Non-Employee
Directors Post-March 1, 2007). (Incorporated by
reference to Exhibit 10.6 to the Companys Quarterly
Report on
Form 10-Q
(SEC File
No. 001-32693),
filed on May 10, 2007)
|
|
10
|
.16*
|
|
Form of Non-Qualified Stock Option Grant Agreement
(Post-March 1, 2007). (Incorporated by reference to
Exhibit 10.7 to the Companys Quarterly Report on
Form 10-Q
(SEC File
No. 001-32693),
filed on May 10, 2007)
|
|
10
|
.17*
|
|
Form of Performance-Based Award Agreement (Officers and
Employees). (Incorporated by reference to Exhibit 10.1 of
the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on March 17, 2008)
|
|
10
|
.18*
|
|
Form of Restricted Stock Grant Agreement (Officers and
Employees). (Incorporated by reference to Exhibit 10.2 of
the Companys Quarterly Report on
Form 10-Q
(SEC File
No. 001-32693),
filed on May 8, 2008)
|
|
10
|
.19*
|
|
Form of Restricted Stock Grant Agreement (Non-Employee
Directors). (Incorporated by reference to Exhibit 10.3 of
the Companys Quarterly Report on
Form 10-Q
(SEC File
No. 001-32693),
filed on May 8. 2008)
|
|
10
|
.20*
|
|
Form of Performance-Based Award Agreement (effective March 2009)
(Incorporated by reference to Exhibit 10.1 of the
Companys Current Report on
Form 8-K
(SEC File
No. 001-32963),
filed on March 19, 2009)
|
|
10
|
.21*
|
|
Contingent Earn Out Agreement dated as of February 28, 2006
among Basic Energy Services, LP and G&L Tool, Ltd.
(Incorporated by reference to Exhibit 10.2 of the
Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on March 2, 2006)
|
|
10
|
.22*
|
|
Employment Agreement of Kenneth V. Huseman, effective as of
December 31, 2006. (Incorporated by reference to
Exhibit 10.1 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2007)
|
|
10
|
.23*
|
|
Employment Agreement of Alan Krenek, effective as of
December 31, 2006. (Incorporated by reference to
Exhibit 10.2 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2007)
|
|
10
|
.24*
|
|
Employment Agreement of James E. Tyner, effective as of
December 31, 2006. (Incorporated by reference to
Exhibit 10.5 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2007)
|
|
10
|
.25*
|
|
Amended and Restated Employment Agreement of Thomas Monroe
Patterson, effective as of November 21, 2008. (Incorporated
by reference to Exhibit 10.2 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on November 24, 2008)
|
|
10
|
.26*
|
|
First Amendment to Employment Agreement of Kenneth V. Huseman,
effective as of January 23, 2007. (Incorporated by
reference to Exhibit 10.1 of the Companys Current
Report on
Form 8-K
(SEC File No. 001-32693),
filed on January 29, 2007)
|
|
10
|
.27
|
|
Amended and Restated Employment Agreement of James F. Newman,
effective as of November 24, 2008.
|
|
10
|
.28
|
|
Employment Agreement of Douglas B. Rogers, effective as of
March 16, 2009.
|
|
12
|
.1
|
|
Ratio of Earnings to Fixed Charges
|
|
21
|
.1*
|
|
Subsidiaries of the Company, (Incorporated by reference to
Exhibit 21.1 of the Companys Registration Statement
on
Form S-4
(SEC File No. 333-161693), filed on September 2, 2009)
|
|
23
|
.1
|
|
Consent of KPMG LLP
|
92
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
31
|
.1
|
|
Certification by Chief Executive Officer required by
Rule 13a-14(a)
and 15d-14(a) under the Exchange Act
|
|
31
|
.2
|
|
Certification by Chief Financial Officer required by
Rule 13a-14(a)
and 15d-14(a) under the Exchange Act
|
|
32
|
.1
|
|
Certification by Chief Executive Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
|
|
32
|
.2
|
|
Certification of Chief Financial Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
|
|
|
|
* |
|
Incorporated by reference |
|
|
|
Management contract or compensatory plan or arrangement |
93
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
BASIC ENERGY SERVICES, INC.
|
|
|
|
By:
|
/s/ Kenneth
V. Huseman
|
Name: Kenneth V. Huseman
|
|
|
|
Title:
|
President, Chief Executive Officer and
|
Director
Date: February 26, 2010
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
|
|
|
|
|
|
|
Signature
|
|
Date
|
|
|
|
|
|
|
|
|
/s/ Kenneth
V. Huseman
Kenneth
V. Huseman
|
|
President, Chief Executive Officer and Director (Principal
Executive Officer)
|
|
February 26, 2010
|
|
|
|
|
|
/s/ Alan
Krenek
Alan
Krenek
|
|
Senior Vice President,
Chief Financial Officer,
Treasurer and Secretary
(Principal Financial Officer
and Principal Accounting Officer)
|
|
February 26, 2010
|
|
|
|
|
|
/s/ Steven
A. Webster
Steven
A. Webster
|
|
Chairman of the Board
|
|
February 26, 2010
|
|
|
|
|
|
/s/ James
S. DAgostino, Jr.
James
S. DAgostino, Jr.
|
|
Director
|
|
February 26, 2010
|
|
|
|
|
|
/s/ William
E. Chiles
William
E. Chiles
|
|
Director
|
|
February 26, 2010
|
|
|
|
|
|
/s/ Robert
F. Fulton
Robert
F. Fulton
|
|
Director
|
|
February 26, 2010
|
|
|
|
|
|
/s/ Sylvester
P. Johnson, IV
Sylvester
P. Johnson, IV
|
|
Director
|
|
February 26, 2010
|
|
|
|
|
|
/s/ Antonio
O. Garza
Antonio
O. Garza
|
|
Director
|
|
February 26, 2010
|
|
|
|
|
|
/s/ Thomas
P. Moore, Jr.
Thomas
P. Moore, Jr.
|
|
Director
|
|
February 26, 2010
|
94
EXHIBIT INDEX
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
2
|
.1*
|
|
Agreement and Plan of Merger, dated as of January 8, 2007,
by and among Basic Energy Services, Inc., JS Acquisition LLC and
JetStar Consolidated Holdings, Inc. (Incorporated by reference
to Exhibit 2.1 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on March 8, 2007)
|
|
2
|
.2*
|
|
Amendment to Merger Agreement, dated as of March 5, 2007,
by and among Basic Energy Services, Inc., JS Acquisition LLC and
JetStar Consolidated Holdings, Inc. (Incorporated by reference
to Exhibit 2.2 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on March 8, 2007)
|
|
3
|
.1*
|
|
Amended and Restated Certificate of Incorporation of the
Company, dated September 22, 2005. (Incorporated by
reference to Exhibit 3.1 of the Companys Registration
Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
3
|
.2*
|
|
Amended and Restated Bylaws of the Company, effective as of
December 17, 2007. (Incorporated by reference to
Exhibit 3.1 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on December 18, 2007)
|
|
4
|
.1*
|
|
Specimen Stock Certificate representing common stock of the
Company. (Incorporated by reference to Exhibit 4.1 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on November 4, 2005)
|
|
4
|
.2*
|
|
Indenture dated April 12, 2006, among Basic Energy
Services, Inc., the guarantors party thereto, and The Bank of
New York Trust Company, N.A., as trustee. (Incorporated by
reference to Exhibit 4.1 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on April 13, 2006)
|
|
4
|
.3*
|
|
Form of 7.125% Senior Note due 2016. (Included in the
Indenture filed as Exhibit 4.1 of the Companys
Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on April 13, 2006)
|
|
4
|
.4*
|
|
First Supplemental Indenture dated as of July 14, 2006 to
Indenture dated as of April 12, 2006 among the Company, as
Issuer, the Subsidiary Guarantors named therein and The Bank of
New York Trust Company, N.A., as trustee. (Incorporated by
reference to Exhibit 4.1 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on July 20, 2006)
|
|
4
|
.5*
|
|
Second Supplemental Indenture dated as of April 26, 2007
and effective as of March 7, 2007 to Indenture dated as of
April 12, 2006 among the Company as Issuer, the Subsidiary
Guarantors named therein and the Bank of New York
Trust Company, N.A., as trustee. (Incorporated by reference
to Exhibit 4.1 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on May 1, 2007)
|
|
4
|
.6*
|
|
Third Supplemental Indenture dated as of April 26, 2007 to
Indenture dated as of April 12, 2006 among the Company as
Issuer, the Subsidiary Guarantors named therein and the Bank of
New York Trust Company, N.A., as trustee. (Incorporated by
reference to Exhibit 4.2 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on May 1, 2007)
|
|
4
|
.7*
|
|
Fourth Supplemental Indenture dated as of February 9, 2009
to Indenture dated as of April 12, 2006 among the Company
as Issuer, the Subsidiary Guarantors named therein and the Bank
of New York Mellon Trust Company, N.A., as Trustee.
(Incorporated by reference to Exhibit 4.7 of the
Companys Annual Report on
Form 10-K
(SEC File
No. 001-32693),
filed on March 9, 2009)
|
|
4
|
.8
|
|
Fifth Supplemental Indenture dated as of July 23, 2009 to
Indenture dated as of April 12, 2006 among the Company as
Issuer, the Subsidiary Guarantors named therein and the Bank of
New York Mellon Trust Company, N.A., as Trustee.
|
|
4
|
.9*
|
|
Indenture dated as of July 31, 2009, by and among the
Company as Issuer, the Guarantors named therein and The Bank of
New York Mellon Trust Company, N.A., as Trustee.
(Incorporated by reference to Exhibit 4.1 of the
Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on August 4, 2009)
|
|
4
|
.10*
|
|
Form of 11.625% Senior Secured Note due 2014 (included as
Exhibit A to Exhibit 4.1 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on August 4, 2009)
|
|
4
|
.11*
|
|
Security Agreement dated as of July 31, 2009, by and
between the Company and each of the other Grantors party thereto
in favor of The Bank of New York Mellon Trust Company,
N.A., as Trustee. (Incorporated by reference to Exhibit 4.3
of the Companys Current Report on
Form 8-K
(SEC File No. 001-32693),
filed on August 4, 2009)
|
|
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)
|
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
10
|
.2*
|
|
Second Amended and Restated Stockholders Agreement dated
as of April 2, 2004 among the Company and the stockholders
listed therein. (Incorporated by reference to Exhibit 10.7
of the Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on August 12, 2005)
|
|
10
|
.3*
|
|
Fourth Amended and Restated Credit Agreement dated as of
October 3, 2003, amended and restated as of
February 6, 2007, among Basic Energy Services, Inc., the
subsidiary guarantors party thereto, Bank of America, N.A., as
syndication agent, Capital One, National Association, as
documentation agent, BNP Paribas, as documentation agent, UBS
AG, Stamford Branch, as issuing bank, administrative agent and
collateral agent, and the lenders party thereto. (Incorporated
by reference to Exhibit 10.1 to the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on February 12, 2007)
|
|
10
|
.4*
|
|
Amendment and Consent No. 1 to Fourth Amended and Restated
Credit Agreement dated May 4, 2009. (Incorporated by
reference to Exhibit 10.1 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on May 7, 2009)
|
|
10
|
.5*
|
|
Fourth Amended and Restated Basic Energy Services, Inc. 2003
Incentive Plan. (Incorporated by reference to Exhibit 10.1
of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on June 1, 2009)
|
|
10
|
.6*
|
|
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
|
.7*
|
|
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
|
.8*
|
|
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
|
.9*
|
|
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
|
.10*
|
|
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
|
.11*
|
|
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 10.1 to the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2006)
|
|
10
|
.12*
|
|
Form of Nonqualified Stock Option Agreement (Director form
effective March 2006). (Incorporated by reference to
Exhibit 10.13 of the Companys Annual Report on
Form 10-K
(SEC File
No. 001-32693),
filed on March 7, 2008)
|
|
10
|
.13*
|
|
Form of Nonqualified Stock Option Agreement (Employee form
effective March 2006). (Incorporated by reference to
Exhibit 10.14 of the Companys Annual Report on
Form 10-K
(SEC File
No. 001-32693),
filed on March 7, 2008)
|
|
10
|
.14*
|
|
Form of Restricted Stock Grant Agreement (Officers and
Employees Post-March 1, 2007). (Incorporated by
reference to Exhibit 10.5 to the Companys Quarterly
Report on
Form 10-Q
(SEC File No. 001-32693),
filed on May 10, 2007)
|
|
10
|
.15*
|
|
Form of Restricted Stock Grant Agreement (Non-Employee
Directors Post-March 1, 2007). (Incorporated by
reference to Exhibit 10.6 to the Companys Quarterly
Report on
Form 10-Q
(SEC File
No. 001-32693),
filed on May 10, 2007)
|
|
10
|
.16*
|
|
Form of Non-Qualified Stock Option Grant Agreement
(Post-March 1, 2007). (Incorporated by reference to
Exhibit 10.7 to the Companys Quarterly Report on
Form 10-Q
(SEC File
No. 001-32693),
filed on May 10, 2007)
|
|
10
|
.17*
|
|
Form of Performance-Based Award Agreement (Officers and
Employees). (Incorporated by reference to Exhibit 10.1 of
the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on March 17, 2008)
|
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
10
|
.18*
|
|
Form of Restricted Stock Grant Agreement (Officers and
Employees). (Incorporated by reference to Exhibit 10.2 of
the Companys Quarterly Report on
Form 10-Q
(SEC File
No. 001-32693),
filed on May 8, 2008)
|
|
10
|
.19*
|
|
Form of Restricted Stock Grant Agreement (Non-Employee
Directors). (Incorporated by reference to Exhibit 10.3 of
the Companys Quarterly Report on
Form 10-Q
(SEC File
No. 001-32693),
filed on May 8. 2008)
|
|
10
|
.20*
|
|
Form of Performance-Based Award Agreement (effective March 2009)
(Incorporated by reference to Exhibit 10.1 of the
Companys Current Report on
Form 8-K
(SEC File
No. 001-32963),
filed on March 19, 2009)
|
|
10
|
.21*
|
|
Contingent Earn Out Agreement dated as of February 28, 2006
among Basic Energy Services, LP and G&L Tool, Ltd.
(Incorporated by reference to Exhibit 10.2 of the
Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on March 2, 2006)
|
|
10
|
.22*
|
|
Employment Agreement of Kenneth V. Huseman, effective as of
December 31, 2006. (Incorporated by reference to
Exhibit 10.1 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2007)
|
|
10
|
.23*
|
|
Employment Agreement of Alan Krenek, effective as of
December 31, 2006. (Incorporated by reference to
Exhibit 10.2 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2007)
|
|
10
|
.24*
|
|
Employment Agreement of James E. Tyner, effective as of
December 31, 2006. (Incorporated by reference to
Exhibit 10.5 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2007)
|
|
10
|
.25*
|
|
Amended and Restated Employment Agreement of Thomas Monroe
Patterson, effective as of November 21, 2008. (Incorporated
by reference to Exhibit 10.2 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on November 24, 2008)
|
|
10
|
.26*
|
|
First Amendment to Employment Agreement of Kenneth V. Huseman,
effective as of January 23, 2007. (Incorporated by
reference to Exhibit 10.1 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 29, 2007)
|
|
10
|
.27
|
|
Amended and Restated Employment Agreement of James F. Newman,
effective as of November 24, 2008.
|
|
10
|
.28
|
|
Employment Agreement of Douglas B. Rogers, effective as of
March 16, 2009.
|
|
12
|
.1
|
|
Ratio of Earnings to Fixed Charges
|
|
21
|
.1*
|
|
Subsidiaries of the Company, (Incorporated by reference to
Exhibit 21.1 of the Companys Registration Statement
on
Form S-4
(SEC File No. 333-161693), filed on September 2, 2009)
|
|
23
|
.1
|
|
Consent of KPMG LLP
|
|
31
|
.1
|
|
Certification by Chief Executive Officer required by
Rule 13a-14(a)
and 15d-14(a) under the Exchange Act
|
|
31
|
.2
|
|
Certification by Chief Financial Officer required by
Rule 13a-14(a)
and 15d-14(a) under the Exchange Act
|
|
32
|
.1
|
|
Certification by Chief Executive Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
|
|
32
|
.2
|
|
Certification of Chief Financial Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
|
|
|
|
* |
|
Incorporated by reference |
|
|
|
Management contract or compensatory plan or arrangement |