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, 2008
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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
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79701
(Zip code
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(Address of principal executive
offices)
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Registrants telephone number, including area code:
(432) 620-5500
Securities registered pursuant to Section 12(b) of the
Act:
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Common Stock, $0.01 par
value per share
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New York Stock
Exchange
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(Title of Class)
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(Name of each exchange on which
registered)
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Securities registered pursuant to Section 12(g) of the
Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes o No þ
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. 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
$545,420,106 as of June 30, 2008, the last business day of
the registrants most recently completed second fiscal
quarter (based on a closing price of $31.50 per share and
24,015,323 shares held by non-affiliates).
There were 40,222,938 shares of the registrants
Common Stock outstanding as of February 27, 2009.
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, may,
estimate, continue,
anticipate, intend, plan,
expect and similar expressions are intended to
identify forward-looking statements. All statements other than
statements of current or historical fact contained in this
annual report are forward looking-statements. Although we
believe that the forward-looking statements contained in this
annual report are based upon reasonable assumptions, the
forward-looking events and circumstances discussed in this
annual report may not occur and actual results could differ
materially from those anticipated or implied in the
forward-looking statements.
Important factors that may affect our expectations, estimates or
projections include:
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a decline in, or substantial volatility of, oil and gas prices,
and any related changes in expenditures by our customers;
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the effects of future acquisitions on our business;
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changes in customer requirements in markets or industries we
serve;
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competition within our industry;
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general economic and market conditions;
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our access to current or future financing arrangements;
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our ability to replace or add workers at economic rates; and
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environmental and other governmental regulations.
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Our forward-looking statements speak only as of the date of this
annual report. Unless otherwise required by law, we undertake no
obligation to publicly update or revise any forward-looking
statements, whether as a result of new information, future
events or otherwise.
This annual report includes market share 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 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
gas throughout the productive life of a well. Our broad range of
services enables us to meet multiple needs of our customers at
the well site. Our operations are managed regionally and are
concentrated in the major United States onshore oil and gas
producing regions in Texas, New Mexico, Oklahoma, Arkansas,
Kansas and Louisiana and the Rocky Mountain states. We provide
our services to a diverse group of over 2,000 oil and gas
companies. We operate the third-largest fleet of well servicing
rigs (also commonly referred to as workover rigs) in the United
States, representing 12% of the overall available
U.S. fleet, with our two larger competitors controlling
approximately 27% and 17%, respectively, according to the AESC
and other publicly available data.
Basic revised its business segments beginning in the first
quarter of 2008, and in connection therewith restated the
corresponding items of segment information for earlier periods.
The new 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. These changes reflect Basics operating focus in
compliance with Statement of Financial Accounting Standards
(SFAS) No. 131, Disclosures about Segments of an
Enterprise and Related Information. The following is a
description of the segments:
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Well Servicing. Our well servicing segment
(34% of our revenues in 2008) currently operates our fleet
of 414 well servicing rigs and related equipment. This
business segment encompasses a full range of services performed
with a mobile well servicing rig, including the installation and
removal of downhole equipment and elimination of obstructions in
the well bore to facilitate the flow of oil and gas. These
services are performed to establish, maintain and improve
production throughout the productive life of an oil and gas well
and to plug and abandon a well at the end of its productive
life. Our well servicing equipment and capabilities are
essential to facilitate most other services performed on a well.
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Fluid Services. Our fluid services segment
(32% of our revenues in 2008) currently utilizes our fleet
of 819 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 (30% of our revenues in
2008) 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 (4% of our revenues in 2008) 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
414 well servicing rigs represents the third-largest fleet
in the United States, and our goal is to be one of the top two
providers of well site services in each of our core operating
areas. Our market position allows us to expand the range of
services performed on a well throughout its life, such as
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, 2008 were either 2000 model year or newer, or
have undergone major refurbishments during the last five years.
As of December 31, 2008, we had taken delivery of 132
newbuild well servicing rigs since October 2004 as part of a
134-rig newbuild commitment, driven by our desire to maintain
one of the most efficient, reliable and safest fleets in the
industry. The remaining two newbuilds are scheduled to be
delivered to us by the end of February 2009. 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 70 of
our rigs since the beginning of 2004. Since 2003, we have
obtained annual independent reviews and evaluations of
substantially all of our assets, which confirmed the location
and condition of these assets.
Extensive Domestic Footprint in the Most Prolific
Basins. Our operations are concentrated in the
major United States onshore oil and gas producing regions in
Texas, New Mexico, Oklahoma, Arkansas, Kansas and Louisiana and
the Rocky Mountain states. We operate in states that accounted
for approximately 58% of the approximately 900,000 existing
onshore oil and gas wells in the 48 contiguous states and
approximately 73% of onshore oil production and 90% of onshore
gas production in 2008. We believe that our operations are
located in the most active U.S. well services markets, as
we currently focus our operations on onshore domestic oil and
gas production areas that include both the highest concentration
of existing oil and gas production activities and the largest
prospective acreage for new drilling activity. This extensive
footprint allows us to offer our suite of services to more than
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 121 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
25 years of industry experience, each regional manager has
extensive knowledge of the customer base, job requirements and
working conditions in each local market. Below our nine regional
or 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 23 acquisitions including:
2006
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LeBus Oil Field Service Co., a fluid service company operating
in our Ark-La-Tex region, and
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G&L Tool, Ltd., a rental and fishing tool company included
in our completion and remedial line of business;
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2007
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JetStar Consolidated Holdings, Inc., a pressure pumping company
operating in our completion and remedial line of
business, and
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Sledge Drilling Holding Corp., a contract drilling company
operating in our contract drilling line of business;
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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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Develop Additional Service Offerings Within the Well
Servicing Market. We intend to continue
broadening the portfolio of services we provide to our clients
by leveraging our well servicing infrastructure. A customer
typically begins a new maintenance or workover project by
securing access to a well servicing rig, which generally stays
on site for the duration of the project. As a result, our rigs
are often the first equipment to arrive at the well site and
typically the last to leave, providing us the opportunity to
offer our customers other complementary services. We believe the
fragmented nature of the well servicing market creates an
opportunity to sell more services to our core customers and to
expand our total service offering within each of our markets. We
have expanded our suite of services available to our customers
and increased our opportunities to cross-sell new services to
our core well servicing customers through recent acquisitions
and internal growth. We expect to continue to develop or
selectively acquire capabilities to provide additional services
to expand and further strengthen our customer relationships.
Pursue Growth Through Selective Capital
Deployment. We intend to continue growing our
business through selective acquisitions, continuing a newbuild
program
and/or
upgrading our existing assets. Our capital investment decisions
are determined by an analysis of the projected return on capital
employed of each of those alternatives. Acquisitions are
evaluated for fit with our area and regional
operations management and are thoroughly reviewed by corporate
level financial, equipment, safety and environmental specialists
to ensure consideration is given to identified risks. We also
evaluate the cost to acquire existing assets from a third party,
the capital required to build new equipment and the point in the
oil and gas commodity price cycle. Based on these factors, we
make capital investment decisions that we believe will support
our long-term growth strategy and these decisions may involve a
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combination of asset acquisitions and the purchase of new
equipment. In 2008, we completed five separate acquisitions for
an aggregate purchase price of $110 million, net of cash
acquired.
General
Industry Overview
Demand for services offered by our industry is a function of our
customers willingness to make operating and capital
expenditures to explore for, develop and produce hydrocarbons in
the U.S., which in turn is affected by current and expected
levels of oil and gas prices. As oil and gas prices increased in
recent years, oil and gas companies increased their drilling and
workover activities. The increased activity resulted in
increased domestic exploration and production spending year over
year for the past four years. In the last part of 2008 there was
a rapid decline in oil and gas prices which we believe has
resulted in a significant decrease in budgeted 2009 domestic
spending compared to 2008 actual spending.
The table below sets forth average daily closing prices for the
Cushing WTI Spot Oil Price and the Energy Information Agency
average wellhead price for natural gas since 2004:
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Cushing WTI Spot
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Average Wellhead Price
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Period
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Oil Price ($/bbl)
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Natural Gas ($/mcf)
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1/1/04 12/31/04
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$
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41.51
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$
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5.49
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1/1/05 12/31/05
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56.64
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7.51
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1/1/06 12/31/06
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66.05
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6.42
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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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Source: U.S. Department of Energy.
Increased expenditures for exploration and production activities
generally drives the increased demand for our services. Rising
oil and gas prices in recent years 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
22% during 2005, 17% during 2006, and 4% during 2007. With the
rapid decline in oil and gas prices in the second half of 2008
there was a decrease in the land-based drilling rig count of
approximately 3% during 2008, according to Baker Hughes. The
decrease in oil and 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 gas companies tend to be
relatively sensitive to volatility in oil or gas prices because
project decisions are tied to a return on investment spanning a
number of years. As such, capital expenditure economics often
require the use of commodity price forecasts which may prove
inaccurate in the amount of time required to plan and execute a
capital expenditure project (such as the drilling of a deep
well). When commodity prices are depressed for even a short
period of time, capital expenditure projects are routinely
deferred until prices return to an acceptable level.
In contrast, both mandatory and discretionary operating
expenditures are substantially more stable than exploration and
drilling expenditures. Mandatory operating expenditure projects
involve activities that cannot be avoided in the short term,
such as regulatory compliance, safety, contractual obligations
and projects to maintain the well and related infrastructure in
operating condition (for example, repairs to a central tank
battery, downhole pump, saltwater disposal system or gathering
system). Discretionary operating expenditure projects may not be
critical to the short-term viability of a lease or field but
these projects are relatively insensitive to commodity price
volatility. Discretionary operating expenditure work is
evaluated according to a simple short-term payout criterion
which is far less dependent on commodity price forecasts.
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Our business is influenced substantially by both operating and
capital expenditures by oil and gas companies. Because existing
oil and gas wells require ongoing spending to maintain
production, expenditures by oil and gas companies for the
maintenance of existing wells are relatively stable and
predictable. In contrast, capital expenditures by oil and gas
companies for exploration and drilling are more directly
influenced by current and expected oil and gas prices and
generally reflect the volatility of commodity prices.
Overview
of Our Segments and Services
Well
Servicing Segment
Our well servicing segment encompasses a full range of services
performed with a mobile well servicing rig, also commonly
referred to as a workover rig, and ancillary equipment. Our rigs
and personnel provide the means for hoisting equipment and tools
into and out of the well bore, and our well servicing equipment
and capabilities are essential to facilitate most other services
performed on a well. Our well servicing segment services, which
are performed to maintain and improve production throughout the
productive life of an oil and gas well, include:
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maintenance work involving removal, repair and replacement of
down-hole equipment and returning the well to production after
these operations are completed;
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hoisting tools and equipment required by the operation into and
out of the well, or removing equipment from the well bore, to
facilitate specialized production enhancement and well repair
operations performed by other oilfield service
companies; and
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plugging and abandonment services when a well has reached the
end of its productive life.
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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 414 well servicing rigs as of
December 31, 2008, including 132 newbuilds since October
2004 and 70 rebuilds since the beginning of 2004. Our well
servicing rigs operate from facilities in Texas, Wyoming,
Oklahoma, North Dakota, New Mexico, Louisiana, Colorado, 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. Prior to December
2004, our well servicing segment consisted entirely of
land-based equipment. During December 2004, we acquired three
inland barges, two of which were equipped with rigs, which were
refurbished and were placed into service in the second quarter
of 2005. In January 2007, we acquired two additional inland
barges equipped with rigs from Parker Drilling Offshore USA,
LLC. Inland barges are used to service wells in shallow water
marine environments, such as coastal marshes and bays.
The following table sets forth the location, characteristics and
number of the well servicing rigs that we operated at
December 31, 2008. 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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South
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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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Texas
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Tex
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Continent
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Mountain
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Total
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Swab
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N/A
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3
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1
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6
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4
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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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5
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2
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0
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17
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1
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25
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Medium Duty
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³90<125
tons
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133
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38
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29
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58
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54
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312
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Heavy Duty
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³125
tons
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29
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4
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6
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4
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8
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51
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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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2
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1
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8
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Inland Barge
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³125
tons
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0
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0
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4
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|
|
|
0
|
|
|
|
0
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
172
|
|
|
|
48
|
|
|
|
45
|
|
|
|
85
|
|
|
|
64
|
|
|
|
414
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
6
We operate a total of 414 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 943 domestic rigs
and Nabors is the second largest with an estimated 592 domestic
rigs at year end. Our only other competitors operating more than
100 rigs is Complete Production Services with an estimated 267
domestic rigs and Forbes Energy Services with an estimated 169
domestic rigs. Excluding the rigs operated by Nabors in
California where we do not compete, we have the second largest
rig fleet in the United States.
The total number of rigs owned by us and the four other largest
companies referenced above is approximately 2,385, or 69% of the
available fleet owned by member companies of the AESC, the major
trade association of well site service providers. The remaining
31% of the well servicing rigs are owned by more than 100 local
and regional companies. The December 2008 monthly activity
survey conducted by the AESC indicated that 68% 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 gas production. We believe regular maintenance
comprises the largest portion of our work in this business
segment. We provide well service rigs, equipment and crews for
these maintenance services. Maintenance services are often
performed on a series of wells in proximity to each other. These
services consist of routine mechanical repairs necessary to
maintain production, such as repairing inoperable pumping
equipment in an oil well or replacing defective tubing in a gas
well, and removing debris such as sand and paraffin from the
well. Other services include pulling the rods, tubing, pumps and
other downhole equipment out of the well bore to identify and
repair a production problem. These downhole equipment failures
are typically caused by the repetitive pumping action of an oil
well. Corrosion, water cut, grade of oil, sand production and
other factors can also result in frequent failures of downhole
equipment.
The need for maintenance activity does not directly depend on
the level of drilling activity, although it is somewhat impacted
by short-term fluctuations in oil and gas prices. Demand for our
maintenance services is affected by changes in the total number
of producing oil and gas wells in our geographic service areas.
Accordingly, maintenance services generally experience
relatively stable demand.
Our regular well maintenance services involve relatively
low-cost, short-duration jobs which are part of normal well
operating costs. Demand for well maintenance is driven primarily
by the production requirements of the local oil or gas fields
and, to a lesser degree, the actual prices received for oil and
gas. Well operators cannot delay all maintenance work without a
significant impact on production. Operators may, however, choose
to shut in producing wells temporarily when oil or gas prices
are too low to justify additional expenditures, including
maintenance.
Workover. In addition to periodic maintenance,
producing oil and gas wells occasionally require major repairs
or modifications called workovers, which are typically more
complex and more time consuming than maintenance operations.
Workover services include extensions of existing wells to drain
new formations either through perforating the well casing to
expose additional productive zones not previously produced,
deepening well bores to new zones or the drilling of lateral
well bores to improve reservoir drainage patterns. Our workover
rigs are also used to convert former producing wells to
injection wells through which water or carbon dioxide is then
pumped into the formation for enhanced oil recovery operations.
Workovers also include major subsurface repairs such as repair
or replacement of well casing, recovery or replacement of tubing
and removal of foreign objects from the well bore. These
extensive workover operations are normally performed by a
workover rig with additional 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 gas producers intermediate and
long-term expectations for oil and gas prices. As oil and gas
prices increase, the level of workover activity tends to
increase as oil and gas producers seek to increase output by
enhancing the efficiency of their wells.
New Well Completion. New well completion
services involve the preparation of newly drilled wells for
production. The completion process may involve selectively
perforating the well casing in the productive zones to allow oil
or gas to flow into the well bore, stimulating and testing these
zones and installing the production string and other downhole
equipment. We provide well service rigs to assist in this
completion process. Newly drilled
7
wells are frequently completed by well servicing rigs to
minimize the use of higher cost drilling rigs in the completion
process. The completion process typically requires a few days to
several weeks, depending on the nature and type of the
completion, and generally requires additional auxiliary
equipment. Accordingly, completion services require less
well-to-well
mobilization of equipment and generally provide higher operating
margins than regular maintenance work. The demand for completion
services is directly related to drilling activity levels, which
are sensitive to expectations relating to and changes in oil and
gas prices.
Plugging and Abandonment. Well servicing rigs
are also used in the process of permanently closing oil and gas
wells no longer capable of producing in economic quantities.
Plugging and abandonment work can be performed with a well
servicing rig along with wireline and cementing equipment;
however, this service is typically provided by companies that
specialize in plugging and abandonment work. Many well operators
bid this work on a turnkey basis, requiring the
service company to perform the entire job, including the sale or
disposal of equipment salvaged from the well as part of the
compensation received, and complying with state regulatory
requirements. Plugging and abandonment work can provide
favorable operating margins and is less sensitive to oil and gas
pricing than drilling and workover activity since well operators
must plug a well in accordance with state regulations when it is
no longer productive. We perform plugging and abandonment work
throughout our core areas of operation in conjunction with
equipment provided by other service companies.
Fluid
Services Segment
Our fluid services segment provides oilfield fluid supply,
transportation, 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
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, 2008:
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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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South
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Mid-
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Mountain
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Basin
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Tex
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Texas
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Continent
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Total
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Fluid Service Trucks
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|
94
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|
|
|
262
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|
|
|
259
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|
|
125
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|
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|
79
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|
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|
819
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|
Salt Water Disposal Wells
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|
0
|
|
|
|
19
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|
|
|
24
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|
|
|
8
|
|
|
|
10
|
|
|
|
61
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|
Fresh/Brine Water Stations
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|
|
0
|
|
|
|
37
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|
|
|
0
|
|
|
|
2
|
|
|
|
0
|
|
|
|
39
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|
Fluid Storage Tanks
|
|
|
268
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|
|
|
499
|
|
|
|
1,119
|
|
|
|
230
|
|
|
|
224
|
|
|
|
2,340
|
|
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.
8
As in our well servicing segment, our fluid services segment has
a base level of business volume related to the regular
maintenance of oil and gas wells. Most oil and gas fields
produce residual salt water in conjunction with oil or gas.
Fluid service trucks pick up this fluid from tank batteries at
the well site and transport it to a salt water disposal well for
injection. This regular maintenance work must be performed if a
well is to remain active. Transportation and disposal of
produced water is considered a low value service by most
operators, and it is difficult for us to command a premium over
rates charged by our competition. Our ability to 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
819 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 gas wastes. Our transport
trucks frequently transport fluids that are disposed of in these
salt water disposal wells. The disposal wells have injection
capacities ranging up to 3,500 barrels per day. Our salt
water disposal wells are strategically located in close
proximity to our customers producing wells. Most oil and
gas wells produce varying amounts of salt water throughout their
productive lives. In the states in which we operate, oil and gas
wastes and salt water produced from oil and gas wells are
required by law to be disposed of in authorized facilities,
including permitted salt water disposal wells. Injection wells
are licensed by state authorities and are completed in permeable
formations below the fresh water table. We maintain separators
at most of our disposal wells permitting us to salvage residual
crude oil, which is later sold for our account.
Fresh and Brine Water Stations. Our network of
fresh and brine water stations, particularly in the Permian
Basin, where surface water is generally not available, is used
to supply water necessary for the drilling and completion of oil
and gas wells. Our strategic locations, in combination with our
other fluid handling services, give us a competitive advantage
over other service providers in those areas in which these other
companies cannot provide these services.
Fluid Storage Tanks. Our fluid storage tanks
can store up to 500 barrels of fluid and are used by
oilfield operators to store various fluids at the well site,
including fresh water, brine and acid for frac jobs, flowback,
temporary production and mud storage. We transport the tanks on
our trucks to well locations that are usually within a
50-mile
radius of our nearest yard. Frac tanks are used during all
phases of the life of a producing well. We
9
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.
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
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;
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|
rental and fishing tools;
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|
cased-hole wireline services; and
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underbalanced drilling in low pressure and fluid sensitive
reservoirs.
|
This segment currently operates 142 pressure pumping units, with
approximately 139,000 of horsepower capacity, to conduct a
variety of services designed to stimulate oil and gas production
or to enable cement slurry to be placed in or circulated within
a well. As of December 31, 2008, we also operated 46 air
compressor packages, including foam circulation units, for
underbalanced drilling and 15 wireline units for cased-hole
measurement and pipe recovery services.
Just as a well servicing rig is required to perform various
operations over the life cycle of a well, there is a similar
need for equipment capable of pumping fluids into the well under
varying degrees of pressure. During the drilling and completion
phase, the well bore is lined with large diameter steel pipe
called casing. Casing is cemented into place by circulating
slurry into the annulus created between the pipe and the rock
wall of the well bore. The cement slurry is forced into the well
by pressure pumping equipment located on the surface. Cementing
services are also utilized over the life of a well to repair
leaks in the casing, to close perforations that are no longer
productive and ultimately to plug the well at the
end of its productive life.
A hydrocarbon reservoir is essentially an interval of rock that
is saturated with oil
and/or gas,
usually in combination with water. Three primary factors
determine the productivity of a well that intersects a
hydrocarbon reservoir: porosity the percentage of
the reservoir volume represented by pore space in which the
hydrocarbons reside, permeability the natural
propensity for the flow of hydrocarbons toward the well bore,
and skin the degree to which the portion
of the reservoir in close proximity to the well bore has
experienced reduced permeability as a result of exposure to
drilling fluids or other contaminants. Well productivity can be
increased by artificially improving either permeability or skin
through stimulation methods.
Permeability can be increased through the use of fracturing
methods. The reservoir is subjected to fluids pumped into it
under high pressure. This pressure creates stress in the
reservoir and causes the rock to fracture thereby creating
additional channels through which hydrocarbons can flow. In most
cases, sand or another form of proppant is pumped with the fluid
as a means of holding open the newly created fractures.
The most common means of reducing near-well bore damage, or
skin, is the injection of a highly reactive solvent (such as
hydrochloric acid) solution into the area where the hydrocarbons
enter the well. This solution has the effect of dissolving
contaminants which have accumulated and are restricting flow.
This process is generically known as acidizing.
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
10
result of abrasion from production tubing, exposure to corrosive
elements or inadequate support from the original attempt to
cement it in place. When a leak develops, it is necessary to
place specialized equipment into the well and to pump cement in
such a way as to seal the leak. Repairing leaks in this manner
is known as squeeze cementing a method
that utilizes pressure pumping equipment.
The following table sets forth the type, number and location of
the completion and remedial services equipment that we operated
at December 31, 2008:
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|
|
|
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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
|
|
|
Permian
|
|
|
|
|
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Ark-La-Tex
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Mid-Continent
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Mountain
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Basin
|
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Total
|
|
|
Pressure Pumping Units
|
|
|
21
|
|
|
|
118
|
|
|
|
3
|
|
|
|
0
|
|
|
|
142
|
|
Coiled Tubing Units
|
|
|
0
|
|
|
|
4
|
|
|
|
0
|
|
|
|
0
|
|
|
|
4
|
|
Air/Foam Packages
|
|
|
0
|
|
|
|
6
|
|
|
|
34
|
|
|
|
6
|
|
|
|
46
|
|
Wireline Units
|
|
|
0
|
|
|
|
15
|
|
|
|
0
|
|
|
|
0
|
|
|
|
15
|
|
Rental and Fishing Tool Stores
|
|
|
0
|
|
|
|
9
|
|
|
|
3
|
|
|
|
8
|
|
|
|
20
|
|
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 gas operations. Underbalanced drilling is a technique that
involves maintaining the pressure in a well at or slightly below
that of the surrounding formation using air, nitrogen, mist,
foam or lightweight drilling
11
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 gas prices.
Our drilling rig services grew significantly in 2007 with the
acquisition of Sledge Drilling in April. We acquired six
drilling rigs in this acquisition.
Properties
Our principal executive offices are located at
500 W. Illinois, Suite 100, Midland, Texas 79701.
We currently conduct our business from 121 area offices, 62 of
which we own and 59 of which we lease. Each office typically
includes a yard, administrative office and maintenance facility.
Of our 121 area offices, 76 are located in Texas, 11 are in
Oklahoma, 10 are in New Mexico, seven are in Wyoming, four are
in Colorado, four are in Louisiana, three are in North Dakota,
two are in Montana, two are in Kansas, one is in Arkansas and
one is in Utah.
Customers
We serve numerous major and independent oil and gas companies
that are active in our core areas of operations. During 2008, no
single customer comprised over 5% of our total revenues. The
majority of our business is with independent oil and gas
companies. While we believe we could redeploy equipment in the
current market environment if we lost 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
gas industry, such as accidents, blowouts, explosions,
craterings, fires and oil spills that can cause:
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personal injury or loss of life;
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damage to or destruction of property, equipment and the
environment; and
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suspension of operations.
|
In addition, claims for loss of oil and gas production and
damage to formations can occur in the well services industry. If
a serious accident were to occur at a location where our
equipment and services are being used, it could result in our
being named as a defendant in lawsuits asserting large claims.
Because our business involves the transportation of heavy
equipment and materials, we may also experience traffic
accidents which may result in spills, property damage and
personal injury.
Despite our efforts to maintain high safety standards, we from
time to time have suffered accidents in the past and anticipate
that we could experience accidents in the future. In addition to
the property and personal losses from
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 44% 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 gas producing regions in the
U.S. These competitors have centralized management teams
that direct their operations and decision-making primarily from
corporate and regional headquarters. In addition, because of
their size, these companies market a large portion of their work
to the major oil and gas companies.
We differentiate ourselves from our major competition by our
operating philosophy. We operate a decentralized organization,
where local management teams are largely responsible for sales
and operations to develop stronger relationships with our
customers at the field level. We target areas that are
attractive to independent oil and gas operators who in our
opinion tend to be more aggressive in spending, less focused on
price and more likely to award work based on performance. With
the major oil and gas companies divesting mature
U.S. properties, we expect our target customers well
population to grow over time through acquisition of properties
formerly operated by major oil and gas companies. We concentrate
on providing services to a diverse group of large and small
independent oil and gas companies. These independents typically
are relationship driven, make decisions at the local level and
are willing to pay higher rates for services. We have been
successful using this business model and believe it will enable
us to continue to grow our business and maintain or expand our
operating margins.
Safety
Program
Our business involves the operation of heavy and powerful
equipment which can result in serious injuries to our employees
and third parties and substantial damage to property. We have
comprehensive safety and training programs designed to minimize
accidents in the 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.
Environmental
Regulation
Our operations are subject to stringent federal, state and local
laws regulating the discharge of materials into the environment
or otherwise relating to health and safety or the protection of
the environment. Numerous governmental agencies, such as the
U.S. Environmental Protection Agency, commonly referred to
as the EPA,
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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 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 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
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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.
Employees
As of December 31, 2008, we employed approximately
5,000 people, with approximately 82% 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
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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 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
gas in the United States. Customers expectations for lower
market prices for oil and 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 gas, domestic and worldwide economic conditions,
political instability in oil and gas producing countries and
merger and divestiture activity among oil and gas producers. The
volatility of the oil and gas industry and the consequent impact
on exploration and production activity could adversely impact
the level of drilling and workover activity by some of our
customers. This reduction may cause a decline in the demand for
our services or adversely affect the price of our services. In
addition, reduced discovery rates of new oil and gas reserves in
our market areas also may have a negative long-term impact on
our business, even in an environment of stronger oil and gas
prices, to the extent existing production is not replaced and
the number of producing wells for us to service declines.
Recent 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. Recent adverse changes in capital
markets and declines in prices for oil and gas have caused many
oil and 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 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 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 gas prices and the related general
production spending and level of drilling activity in the areas
in which we have operations. Volatility or weakness in oil and
gas prices (or the perception that oil and gas prices will
decrease) affects the spending patterns of our customers and may
result in the drilling of fewer new wells or lower production
spending on existing wells. This, in turn, could result in lower
demand for our services and may cause lower rates and lower
utilization of our well service equipment. Continued low oil and
gas prices, a further decline in oil and gas prices or a
reduction in drilling activities could materially and adversely
affect the demand for our services and our results of operations.
Prices for oil and gas historically have been extremely volatile
and are expected to continue to be volatile. Although oil prices
exceeded $140 per barrel and natural gas prices exceeded $13 per
mcf in 2008, prices fell to
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below $40 per barrel and $6 per mcf by the end of 2008. The
Cushing WTI Spot Oil Price averaged $66.05, $72.34 and $99.67
per barrel in 2006, 2007 and 2008, respectively, and the average
wellhead price for natural gas, as recorded by the Energy
Information Agency, was $6.42, $6.38 and $8.07 per mcf for 2006,
2007 and 2008, respectively. The Cushing WTI Spot Oil Price
average for December 2008 was $41.12 and the wellhead price for
natural gas as provided by the Energy Information Agency was
$5.87 for December 2008. The speed and severity of the decline
in oil and gas prices during the fourth quarter of 2008 and the
resulting low prices in the first quarter of 2009 could
materially affect the demand for our services and the rates that
we are able to charge.
We may
not be able to grow successfully through future acquisitions or
successfully manage future growth, and we may not be able to
effectively integrate the businesses we do
acquire.
Our business strategy includes growth through the acquisitions
of other businesses. We may not be able to continue to identify
attractive acquisition opportunities or successfully acquire
identified targets. In addition, we may not be successful in
integrating our current or future acquisitions into our existing
operations, which may result in unforeseen operational
difficulties or diminished financial performance or require a
disproportionate amount of our managements attention. Even
if we are successful in integrating our current or future
acquisitions into our existing operations, we may not derive the
benefits, such as operational or administrative synergies, that
we expected from such acquisitions, which may result in the
commitment of our capital resources without the expected returns
on such capital. Furthermore, competition for acquisition
opportunities may escalate, increasing our cost of making
further acquisitions or causing us to refrain from making
additional acquisitions. We also must meet certain financial
covenants in order to borrow money under our existing credit
agreement to fund future acquisitions.
We may
require additional capital in the future. We cannot assure you
that we will be able to generate sufficient cash internally or
obtain alternative sources of capital on favorable terms, if at
all. If we are unable to fund capital expenditures our business
may be adversely affected.
We anticipate that we will continue to make substantial capital
investments to purchase additional equipment to expand our
services, refurbish our well servicing rigs and replace existing
equipment. For the year ended December 31, 2007, we
invested approximately $98.5 million in cash for capital
expenditures, excluding acquisitions. For the year ended
December 31, 2008, we invested approximately
$91.9 million in cash for capital expenditures, excluding
acquisitions. Historically, we have financed these investments
through internally generated funds, debt and equity offerings,
our capital lease program and our senior 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. The
recent adverse changes in the capital markets could make it
difficult to obtain capital or obtain it at attractive rates.
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 approximately 15% 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 recent changes in the above mentioned factors,
we are recognizing a $22.5 million impairment of goodwill
related to our contract drilling reporting unit in 2008. If the
current economic conditions continue to decline further, we may
be required to recognize a goodwill impairment in future periods
on our well servicing, fluid services, and completion and
remedial reporting units.
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Competition
within the well services industry may adversely affect our
ability to market our services.
The well services industry is highly competitive and fragmented
and includes numerous small companies capable of competing
effectively in our markets on a local basis, as well as several
large companies that possess substantially greater financial and
other resources than we do. Our larger competitors greater
resources could allow those competitors to compete more
effectively than we can. The amount of equipment available may
exceed demand, which could result in active price competition.
Many contracts are awarded on a bid basis, which may further
increase competition based primarily on price. In addition,
recent market conditions have stimulated the reactivation of
well servicing rigs and construction of new equipment, which
could result in excess equipment and lower utilization rates in
future periods.
We
depend on several significant customers, and a loss of one or
more significant customers could adversely affect our results of
operations.
Our customers consist primarily of major and independent oil and
gas companies. During 2007 and 2008, our top five customers
accounted for 16% and 18%, 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.
Our
industry has experienced a high rate of employee turnover. Any
difficulty we experience replacing or adding personnel could
adversely affect our business.
We may not be able to find enough skilled labor to meet our
needs, which could limit our growth. Our business activity
historically decreases or increases with the price of oil and
gas. We may have problems finding enough skilled and unskilled
laborers in the future if the demand for our services increases.
We have raised wage rates to attract workers from other fields
and to retain or expand our current work force during the past
year. If we are not able to increase our service rates
sufficiently to compensate for wage rate increases, our
operating results may be adversely affected.
Other factors may also inhibit our ability to find enough
workers to meet our employment needs. Our services require
skilled workers who can perform physically demanding work. As a
result of our industry volatility and the demanding nature of
the work, workers may choose to pursue employment in fields that
offer a more desirable work environment at wage rates that are
competitive with ours. We believe that our success is dependent
upon our ability to continue to employ and retain skilled
technical personnel. Our inability to employ or retain skilled
technical personnel generally could have a material adverse
effect on our operations.
Our
success depends on key members of our management, the loss of
any of whom could disrupt our business operations.
We depend to a large extent on the services of some of our
executive officers. The loss of the services of Kenneth V.
Huseman, our President and Chief Executive Officer, or other key
personnel could disrupt our operations. Although we have entered
into employment agreements with Mr. Huseman and our other
executive officers that contain, among other provisions,
non-compete agreements, we may not be able to enforce the
non-compete provisions in the employment agreements.
Our
operations are subject to inherent risks, some of which are
beyond our control. These risks may be self-insured, or may not
be fully covered under our insurance policies.
Our operations are subject to hazards inherent in the oil and
gas industry, such as, but not limited to, accidents, blowouts,
explosions, craterings, fires and oil spills. These conditions
can cause:
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personal injury or loss of life;
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damage to or destruction of property, equipment and the
environment; and
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suspension of operations.
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The occurrence of a significant event or adverse claim in excess
of the insurance coverage that we maintain or that is not
covered by insurance could have a material adverse effect on our
financial condition and results of operations. In addition,
claims for loss of oil and gas production and damage to
formations can occur in the well services industry. Litigation
arising from a catastrophic occurrence at a location where our
equipment and services are being used may result in 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.
Laws protecting the environment generally have become more
stringent over time and are expected to continue to do so, which
could lead to material increases in costs for future
environmental compliance and remediation. The modification or
interpretation of existing laws or regulations, or the adoption
of new laws or regulations, could curtail exploratory or
developmental drilling for oil and gas and could limit well
servicing opportunities. Some environmental laws and regulations
may impose strict liability, which means that in some situations
we could be exposed to liability as a result of our conduct that
was lawful at the time it occurred or 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. 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, 2008, our total debt was
$480.3 million, including the aggregate principal amount
due under our Senior Notes of $225 million, an outstanding
revolver balance of $180 million and capital lease
obligations in the aggregate amount of $75.3 million. For
the year ended December 31, 2008, we made cash interest
payments totaling $24.5 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.
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If we are unable to generate sufficient cash flow or are
otherwise unable to obtain the funds required to make principal
and interest payments on our indebtedness, or if we otherwise
fail to comply with the various covenants in our senior credit
facility or other instruments governing any future indebtedness,
we could be in default under the terms of our senior credit
facility or such other instruments. In the event of a default,
the holders of our indebtedness could elect to declare all the
funds borrowed under those instruments to be due and payable
together with accrued and unpaid interest, the lenders under our
credit facility could elect to terminate their commitments there
under and we or one or more of our subsidiaries could be forced
into bankruptcy or liquidation. Any of the foregoing
consequences could restrict our ability to grow our business and
cause the value of our common stock to decline.
Our
senior credit facility and the indenture governing our Senior
Notes impose restrictions on us that may affect our ability to
successfully operate our business.
Our senior credit facility and the indenture governing our
Senior Notes 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 transfer of assets without the
lenders consent; and
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limitation on dividends and distributions.
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In addition, our senior credit facility requires us to maintain
certain financial ratios and to satisfy certain financial
conditions, several of which become more restrictive over time
and may require us to reduce our debt or take some other action
in order to comply with them. The failure to comply with any of
these financial conditions, including the financial ratios or
covenants, would cause a default under our senior credit
facility. A default, if not waived, could result in acceleration
of the outstanding indebtedness under our senior credit
facility, in which case the debt would become immediately due
and payable. In addition, a default or acceleration of
indebtedness under our senior credit facility could result in a
default or acceleration of our Senior Notes or other
indebtedness with cross-default or cross-acceleration
provisions. If this occurs, we may not be able to pay our debt
or borrow sufficient funds to refinance it. Even if new
financing is available, it may not be available on terms that
are acceptable to us. These restrictions could also limit our
ability to obtain future financings, make needed capital
expenditures, withstand a downturn in our business or the
economy in general, or otherwise conduct necessary corporate
activities. We also may be prevented from taking advantage of
business opportunities that arise because of the limitations
imposed on us by the restrictive covenants under our senior
credit facility. Please read Managements Discussion
and Analysis of Financial Condition and Results of
Operations Liquidity and Capital
Resources 2007 Credit Facility for a
discussion of our credit facility.
We are
dependent on particular suppliers for our newbuild rig program
and are vulnerable to delayed deliveries and future price
increases.
We currently purchase our well servicing rigs from a single
supplier as part of a 134-rig commitment, of which the two
remaining rigs are scheduled to be delivered during February
2009. There are a limited number of suppliers that manufacture
this type of equipment. Although pricing is generally fixed for
this newbuild contract and program, future price increases could
affect our ability to continue to increase the number of
newbuild rigs in our
20
fleet at economic levels. In addition, the failure of our
current supplier to timely deliver the remaining newbuild rigs
could adversely affect our budgeted or projected financial and
operational data.
One of
our directors may have a conflict of interest because he is also
currently an affiliate, director or officer of a private equity
firm that makes investments in the energy sector. The resolution
of this conflict of interest may not be in our or our
stockholders best interests.
Steven A. Webster, the Chairman of our Board of Directors, is
the Co-Managing Partner of Avista Capital Holdings, L.P., a
private equity firm that makes investments in the energy sector.
This relationship may create a conflict of interest because of
his responsibilities to Avista and its owners. His duties as a
partner in, or director or officer of, Avista or its affiliates
may conflict with his duties as a director of our company
regarding corporate opportunities and other matters. The
resolution of this conflict may not always be in our or our
stockholders best interest.
Risks
Relating to Our Relationship with DLJ Merchant Banking
Affiliates
of DLJ Merchant Banking will have a substantial influence on the
outcome of stockholder voting and may exercise this voting power
in a manner that may not be in the best interest of our other
stockholders.
As of February 27, 2009, 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 44.9% of our outstanding common stock.
Accordingly, DLJ Merchant Banking is in a position to have a
substantial influence on the outcome of matters requiring a
stockholder vote, including the election of directors, adoption
of amendments to our certificate of incorporation or bylaws or
approval of transactions involving a change of control. The
interests of DLJ Merchant Banking may differ from those of our
other stockholders, and DLJ Merchant Banking may vote its common
stock in a manner that may adversely affect our other
stockholders.
Risks
Relating to Ownership of Our Common Stock
Our
certificate of incorporation and bylaws, as well as Delaware
law, contain provisions that could discourage acquisition bids
or merger proposals, which may adversely affect the market price
of our common stock.
Our certificate of incorporation authorizes our board of
directors to issue preferred stock without stockholder approval.
If our board of directors elects to issue preferred stock, it
could be more difficult for a third party to acquire us. In
addition, some provisions of our certificate of incorporation
and bylaws could make it more difficult for a third party to
acquire control of us, even if the change of control would be
beneficial to our stockholders, including:
|
|
|
|
|
a classified board of directors, so that only approximately
one-third of our directors are elected each year;
|
|
|
|
limitations on the removal of directors;
|
|
|
|
the prohibition of stockholder action by written consent;
|
|
|
|
limitations on the ability of our stockholders to call special
meetings; and
|
|
|
|
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.
21
Because
we have no plans to pay dividends on our common stock, investors
must look solely to stock appreciation for a return on their
investment in us.
We do not anticipate paying any cash dividends on our common
stock in the foreseeable future. We currently intend to retain
all future earnings to fund the development and growth of our
business. Any payment of future dividends will be at the
discretion of our board of directors and will depend on, among
other things, our earnings, financial condition, capital
requirements, level of indebtedness, statutory and contractual
restrictions applying to the payment of dividends and other
considerations that the board of directors deems relevant. The
terms of our existing senior credit facility restrict the
payment of dividends without the prior written consent of the
lenders. Investors must rely on sales of their common stock
after price appreciation, which may never occur, as the only way
to realize a return on their investment. Investors seeking cash
dividends should not purchase our common stock.
|
|
ITEM 1B.
|
UNRESOLVED
STAFF COMMENTS
|
None.
|
|
ITEM 3.
|
LEGAL
PROCEEDINGS
|
From time to time, Basic is a party to litigation or other legal
proceedings that Basic considers to be a part of the ordinary
course of business. Basic is not currently involved in any legal
proceedings that it considers probable or reasonably possible,
individually or in the aggregate, to result in a material
adverse effect on its financial condition, results of operations
or liquidity.
|
|
ITEM 4.
|
SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS
|
None.
Executive
Officers
Our executive officers as of December 31, 2008 and their
respective ages and positions are as follows:
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Position
|
|
Kenneth V. Huseman
|
|
|
56
|
|
|
President, Chief Executive Officer and Director
|
Alan Krenek
|
|
|
53
|
|
|
Senior Vice President, Chief Financial Officer, Treasurer and
Secretary
|
Charles W. Swift
|
|
|
60
|
|
|
Senior Vice President Operations Support
|
T.M. Roe Patterson
|
|
|
34
|
|
|
Senior Vice President Rig and Truck Operations
|
James F. Newman
|
|
|
44
|
|
|
Group Vice President Completion and Remedial Services
|
David W. Sledge(1)
|
|
|
54
|
|
|
Vice President Contract Drilling
|
Mark D. Rankin
|
|
|
55
|
|
|
Vice President Risk Management
|
James E. Tyner
|
|
|
58
|
|
|
Vice President Human Resources
|
|
|
|
(1) |
|
Mr. Sledge resigned effective February 27, 2009. |
Set forth below is the description of the backgrounds of our
executive officers.
Kenneth V. Huseman (President Chief Executive
Officer and Director) has 30 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.
Alan Krenek (Senior Vice President, Chief Financial Officer,
Treasurer and Secretary) has 21 years of related
industry experience. He has been our Vice President, Chief
Financial Officer and Treasurer since January 2005. He
22
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.
Charles W. Swift (Senior Vice President
Operations Support) has 36 years of related industry
experience including 27 years specifically in the domestic
well service business. He was named Senior Vice
President Rig and Truck Operations in July 2006, has
served as a Vice President since 1997 and was involved in
integrating several acquisitions during our expansion phase in
late 1997. He was a co-owner of S&N Well Service from 1986
to 1997 and expanded the business to 17 rigs at the time of sale
of the Company to us. From 1980 to 1986, he worked at Pool
Energy Services Co. where he managed well service and fluid
services businesses. Mr. Swift graduated with a B.B.A.
degree in International Trade from Texas Tech University.
T. M. Roe Patterson (Senior Vice
President Rig and Truck Operations) has
14 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 24 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 thru 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 BSc in Petroleum Engineering from Colorado
School of Mines.
David W. Sledge (Vice President Contract
Drilling) has 29 years of related industry experience.
He has been our Vice President of Contract Drilling since April
2007. Prior to joining us he served as President and COO of
Sledge Drilling Corporation from March 2006 to March 2007. He
served as an Area Manager for Patterson UTI from
2004 to 2006. He was involved in private investments from 1997
to 2004. He served with Gene Sledge Drilling Corp. in various
capacities and was President at the time of its sale to
Patterson UTI in 1996. He presently serves on the
Board of Directors for Comstock Resources Inc. Mr. Sledge
graduated with a B.B.A. degree in Management from Baylor
University. Mr. Sledge resigned effective as of February 27,
2009.
Mark D. Rankin (Vice President Risk Management)
has 31 years of related industry experience. He has
been a Vice President since 2004. From 1997 to 2004, he was a
consultant to oil and gas companies and was involved in
operations research and work process redesign. From 1985 to
1995, he acted as Director of International Marketing and
Marketing for U.S. Operations and a District Manager at
Pool Energy Services Co. He was an International Sales Manager
and Director of Planning and Market Research at Zapata Off-Shore
Company from 1979 to 1985. From 1977 to 1979, he was a Contract
Manager at Western Oceanic, Inc. He graduated with a B.A. in
Political Science from Texas A&M University.
James E. Tyner (Vice President Human Resources)
has been a Vice President since January 2004. From 1999 to
June 2003, he was the General Manager of Human Resources at CMS
Panhandle Companies, where he directed delivery of HR Services.
Mr. Tyner was the Director of Human Resources
Administration and Payroll Services at Duke Energys Gas
Transmission Group from 1998 to 1999. From 1981 to 1998,
Mr. Tyner held various positions at Panhandle Eastern
Corporation. At Panhandle, he managed all Human Resources
functions and developed corporate policies and as a Certified
Safety Professional, he designed and implemented programs to
control workplace hazards. Mr. Tyner received a B.S. in
General Science and M.S. in Microbiology from Mississippi State
University.
23
PART II
|
|
ITEM 5.
|
MARKET
PRICE FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
|
Market
Price for Registrants Common Equity
Our common stock 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, 2007 and 2008,
respectively:
|
|
|
|
|
|
|
|
|
|
|
High
|
|
|
Low
|
|
|
2007:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
24.42
|
|
|
$
|
21.65
|
|
Second Quarter
|
|
$
|
27.77
|
|
|
$
|
23.39
|
|
Third Quarter
|
|
$
|
25.82
|
|
|
$
|
19.25
|
|
Fourth Quarter
|
|
$
|
23.28
|
|
|
$
|
18.92
|
|
2008:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
22.39
|
|
|
$
|
17.95
|
|
Second Quarter
|
|
$
|
32.82
|
|
|
$
|
22.61
|
|
Third Quarter
|
|
$
|
31.25
|
|
|
$
|
20.36
|
|
Fourth Quarter
|
|
$
|
19.87
|
|
|
$
|
8.04
|
|
As of February 27, 2009, we had 40,222,938 shares of
common stock outstanding held by approximately 198 record
holders.
We have not declared or paid any cash dividends on our common
stock, and we do not currently anticipate paying any cash
dividends on our common stock in the foreseeable future. We
currently intend to retain all future earnings to fund the
development and growth of our business. Any future determination
relating to our dividend policy will be at the discretion of our
board of directors and will depend on our results of operations,
financial condition, capital requirements and other factors
deemed relevant by our board. We are also currently restricted
in our ability to pay dividends under our senior credit facility.
Securities
Authorized for Issuance under Equity Compensation
Plans
The following table provides information regarding options or
warrants authorized for issuance under our equity compensation
plans as of December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
Number of
|
|
|
|
|
|
Securities
|
|
|
|
Securities to be
|
|
|
Weighted
|
|
|
Remaining
|
|
|
|
Issued upon
|
|
|
Average Exercise
|
|
|
Available for
|
|
|
|
Exercise of
|
|
|
Price of
|
|
|
Future Issuance
|
|
|
|
Outstanding
|
|
|
Outstanding
|
|
|
Under Equity
|
|
Plan Category
|
|
Options
|
|
|
Options
|
|
|
Compensation Plans
|
|
|
Equity compensation plans approved by security holders(1)
|
|
|
1,608,675
|
|
|
$
|
11.11
|
|
|
|
815,675
|
|
Equity compensation plans not approved by security holders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,608,675
|
|
|
$
|
11.11
|
|
|
|
815,675
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Consists of the Basic Energy Services, Inc. Third Amended and
Restated 2003 Incentive Plan (as amended effective May 12,
2008). |
24
Issuer
Purchases of Equity Securities
The following table provides information relating to our
repurchase of shares of common stock during the three months
ended December 31, 2008 (in thousands, except average price
paid per share):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Approximate Dollar
|
|
|
|
|
|
|
|
|
|
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
|
|
|
per Share
|
|
|
Announced Program
|
|
|
Program (1)
|
|
|
October 1, 2008 to October 31, 2008
|
|
|
228
|
|
|
$
|
10.41
|
|
|
|
228
|
|
|
$
|
47,628
|
|
November 1, 2008 to November 30, 2008
|
|
|
631
|
|
|
$
|
9.61
|
|
|
|
631
|
|
|
$
|
41,558
|
|
December 1, 2008 to December 31, 2008
|
|
|
38
|
|
|
$
|
9.74
|
|
|
|
38
|
|
|
$
|
41,184
|
|
|
|
|
(1) |
|
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 discretion. The stock repurchase program may be
suspended or discontinued at any time. |
25
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, 2008 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, 2008
Value of
$100 Invested December 9, 2005 at December 30, 2005,
December 29, 2006, December 31, 2007 and
December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
26
|
|
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,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Dollars in thousands)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
$
|
343,113
|
|
|
$
|
342,697
|
|
|
$
|
323,755
|
|
|
$
|
221,993
|
|
|
$
|
142,551
|
|
Fluid services
|
|
|
315,768
|
|
|
|
259,324
|
|
|
|
245,011
|
|
|
|
177,927
|
|
|
|
139,610
|
|
Completion and remedial services
|
|
|
304,326
|
|
|
|
240,692
|
|
|
|
154,412
|
|
|
|
59,832
|
|
|
|
29,341
|
|
Contract drilling
|
|
|
41,735
|
|
|
|
34,460
|
|
|
|
6,970
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
1,004,942
|
|
|
|
877,173
|
|
|
|
730,148
|
|
|
|
459,752
|
|
|
|
311,502
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
|
215,243
|
|
|
|
205,132
|
|
|
|
178,028
|
|
|
|
137,392
|
|
|
|
98,058
|
|
Fluid services
|
|
|
203,205
|
|
|
|
165,327
|
|
|
|
153,445
|
|
|
|
114,551
|
|
|
|
96,621
|
|
Completion and remedial services
|
|
|
165,574
|
|
|
|
125,948
|
|
|
|
74,981
|
|
|
|
30,900
|
|
|
|
17,481
|
|
Contract drilling
|
|
|
28,629
|
|
|
|
22,510
|
|
|
|
8,400
|
|
|
|
|
|
|
|
|
|
General and administrative(a)
|
|
|
115,319
|
|
|
|
99,042
|
|
|
|
81,318
|
|
|
|
55,411
|
|
|
|
37,186
|
|
Depreciation and amortization
|
|
|
118,607
|
|
|
|
93,048
|
|
|
|
62,087
|
|
|
|
37,072
|
|
|
|
28,676
|
|
Loss (gain) on disposal of assets
|
|
|
76
|
|
|
|
477
|
|
|
|
277
|
|
|
|
(222
|
)
|
|
|
2,616
|
|
Goodwill impairment
|
|
|
22,522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
869,175
|
|
|
|
711,484
|
|
|
|
558,536
|
|
|
|
375,104
|
|
|
|
280,638
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
135,767
|
|
|
|
165,689
|
|
|
|
171,612
|
|
|
|
84,648
|
|
|
|
30,864
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest expense
|
|
|
(24,630
|
)
|
|
|
(25,136
|
)
|
|
|
(15,504
|
)
|
|
|
(12,660
|
)
|
|
|
(9,550
|
)
|
Gain (loss) on early extinguishment of debt
|
|
|
|
|
|
|
(230
|
)
|
|
|
(2,705
|
)
|
|
|
(627
|
)
|
|
|
|
|
Other income (expense)
|
|
|
12,235
|
|
|
|
176
|
|
|
|
169
|
|
|
|
220
|
|
|
|
(398
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes
|
|
|
123,372
|
|
|
|
140,499
|
|
|
|
153,572
|
|
|
|
71,581
|
|
|
|
20,916
|
|
Income tax expense
|
|
|
(55,134
|
)
|
|
|
(52,766
|
)
|
|
|
(54,742
|
)
|
|
|
(26,800
|
)
|
|
|
(7,984
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
|
68,238
|
|
|
|
87,733
|
|
|
|
98,830
|
|
|
|
44,781
|
|
|
|
12,932
|
|
Discontinued operations, net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(71
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
68,238
|
|
|
|
87,733
|
|
|
|
98,830
|
|
|
|
44,781
|
|
|
|
12,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
68,238
|
|
|
$
|
87,733
|
|
|
$
|
98,830
|
|
|
$
|
44,781
|
|
|
$
|
12,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per share of common stock:
|
|
$
|
1.67
|
|
|
$
|
2.19
|
|
|
$
|
2.87
|
|
|
$
|
1.57
|
|
|
$
|
0.46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per share of common stock:
|
|
$
|
1.64
|
|
|
$
|
2.13
|
|
|
$
|
2.56
|
|
|
$
|
1.35
|
|
|
$
|
0.42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Dollars in thousands)
|
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from operating activities
|
|
$
|
212,827
|
|
|
$
|
198,591
|
|
|
$
|
145,678
|
|
|
$
|
99,189
|
|
|
$
|
46,539
|
|
Cash flows from investing activities
|
|
|
(197,302
|
)
|
|
|
(294,103
|
)
|
|
|
(241,351
|
)
|
|
|
(107,679
|
)
|
|
|
(73,587
|
)
|
Cash flows from financing activities
|
|
|
3,669
|
|
|
|
136,088
|
|
|
|
114,193
|
|
|
|
21,188
|
|
|
|
21,498
|
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions, net of cash acquired
|
|
|
110,913
|
|
|
|
199,673
|
|
|
|
135,568
|
|
|
|
25,378
|
|
|
|
19,284
|
|
Property and equipment
|
|
|
91,890
|
|
|
|
98,536
|
|
|
|
104,574
|
|
|
|
83,095
|
|
|
|
55,674
|
|
|
|
|
(a) |
|
Includes approximately $4,149, $3,964, $3,429, $2,890, and
$1,587 of non-cash stock compensation expense for the years
ended December 31, 2008, 2007, 2006, 2005 and 2004,
respectively. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Dollars in thousands)
|
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
111,135
|
|
|
$
|
91,941
|
|
|
$
|
51,365
|
|
|
$
|
32,845
|
|
|
$
|
20,147
|
|
Property and equipment, net
|
|
|
740,879
|
|
|
|
636,924
|
|
|
|
475,431
|
|
|
|
309,075
|
|
|
|
233,451
|
|
Total assets
|
|
|
1,310,711
|
|
|
|
1,143,609
|
|
|
|
796,260
|
|
|
|
496,957
|
|
|
|
367,601
|
|
Long-term debt
|
|
|
454,260
|
|
|
|
406,306
|
|
|
|
250,742
|
|
|
|
119,241
|
|
|
|
170,915
|
|
Stockholders equity
|
|
|
595,004
|
|
|
|
524,821
|
|
|
|
379,250
|
|
|
|
258,575
|
|
|
|
121,786
|
|
|
|
ITEM 7.
|
MANAGEMENTS
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATION
|
Managements
Overview
We provide a wide range of well site services to oil and gas
drilling and producing companies, including well servicing,
fluid services, 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 40 separate
acquisitions from January 1, 2004 to December 31,
2008. Our weighted average number of well servicing rigs
increased from 126 in 2001 to 414 in the fourth quarter of 2008,
and our weighted average number of fluid service trucks
increased from 156 to 804 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 two in
the first quarter of 2006 to nine in the fourth quarter of 2008,
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.
Basic revised its business segments beginning in the first
quarter of 2008, and in connection therewith, restated the
corresponding items of segment information for earlier periods.
The new 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 segment was consolidated into our Fluid
Services segment. These changes reflect Basics operating
focus in compliance with Statement of Financial Accounting
Standards (SFAS) No. 131, Disclosures about
Segments of an Enterprise and Related Information.
28
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,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
$
|
343.1
|
|
|
|
34
|
%
|
|
$
|
342.7
|
|
|
|
39
|
%
|
|
$
|
323.7
|
|
|
|
44
|
%
|
Fluid services
|
|
|
315.8
|
|
|
|
32
|
%
|
|
|
259.3
|
|
|
|
29
|
%
|
|
|
245.0
|
|
|
|
34
|
%
|
Completion and remedial services
|
|
|
304.3
|
|
|
|
30
|
%
|
|
|
240.7
|
|
|
|
28
|
%
|
|
|
154.4
|
|
|
|
21
|
%
|
Contract drilling
|
|
|
41.7
|
|
|
|
4
|
%
|
|
|
34.5
|
|
|
|
4
|
%
|
|
|
7.0
|
|
|
|
1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
1,004.9
|
|
|
|
100
|
%
|
|
$
|
877.2
|
|
|
|
100
|
%
|
|
$
|
730.1
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our core businesses depend on our customers willingness to
make expenditures to produce, develop and explore for oil and
gas in the United States. Industry conditions are influenced by
numerous factors, such as the supply of and demand for oil and
gas, domestic and worldwide economic conditions, political
instability in oil producing countries and merger and
divestiture activity among oil and gas producers. The volatility
of the oil and gas industry, and the consequent impact on
exploration and production activity, could adversely impact the
level of drilling and workover activity by some of our
customers. This volatility affects the demand for our services
and the price of our services. In addition, the discovery rate
of new oil and gas reserves in our market areas also may have an
impact on our business, even in an environment of stronger oil
and gas prices. For a more comprehensive discussion of our
industry trends, see 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 gas operations. Demand for
these production-related services, including well servicing and
fluid services, tends to remain relatively stable, even in
moderate oil and gas price environments, as ongoing maintenance
spending is required to sustain production. As oil and gas
prices reach higher levels, demand for all of our services
generally increases as our customers engage in more well
servicing activities relating to existing wells to maintain or
increase oil and gas production from those wells. Because our
services are required to support drilling and workover
activities, our revenues will vary based on changes in capital
spending by our customers as oil and gas prices increase or
decrease.
During 2006, our business activity levels increased due to the
impact of higher oil and gas prices and the expansion of our
equipment fleets. 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. For
2009, we expect oil and gas prices to remain substantially below
the levels required to support aggressive capital spending
programs by our customers and that their maintenance related
spending will be deferred for as long as possible. The reduced
spending by our customers will result in significantly lower
demand for our services and increased price competition among
the service providers in each of our segments. We anticipate
that utilization, revenue and margins will be substantially
below 2008 levels. We do not currently believe that the changes
being experienced during the first quarter of 2009 and
anticipated later in 2009 will affect the Companys
compliance with the financial covenants in its debt agreements.
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 gas
commodity price cycle. Based on these factors, we make capital
investment decisions that we believe will support our long-term
growth strategy. While we believe our costs of integration for
prior acquisitions have been reflected in our historical results
of operations, integration of acquisitions may result in
unforeseen operational difficulties or require a
29
disproportionate amount of our managements attention. As
discussed below in Liquidity and Capital
Resources, we also must meet certain financial covenants
in order to borrow money under our existing credit agreement to
fund future acquisitions.
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 2006 through 2008, we grew significantly
through acquisitions and capital expenditures. During 2006, we
completed ten acquisitions, of which G&L Tool, Ltd. was
considered significant for purposes of SFAS No. 141,
Business Combinations. During 2007, we
completed eight acquisitions, of which JetStar Consolidated
Holdings, Inc. and Sledge Drilling Holding Corp. were considered
significant for purposes of SFAS No. 141. During 2008,
we completed five acquisitions, of which Azurite was considered
significant for purposes of SFAS No. 141.
We discuss the aggregate purchase prices and related financing
issues below in Liquidity and Capital Resources and
present the pro forma effects of the acquisition of G&L
Tool, Ltd., JetStar Consolidated Holdings, Inc., Sledge Drilling
Holding Corp., and Azurite in Note 3 of our historical
consolidated financial statements included in this report.
Selected
2006 Acquisitions
During 2006, we made several acquisitions that complemented our
existing business segments and provided an entry into the rental
and fishing tool business. These included, among others:
LeBus Oil
Field Service Co.
On January 31, 2006, we acquired all of the outstanding
capital stock of LeBus Oil Field Service Co. (Lebus)
for an acquisition price of $26 million, subject to
adjustments. This acquisition significantly expanded our fluid
services segment in the Ark-La-Tex region. The cash used to
acquire LeBus was primarily from borrowings under our senior
credit facility.
G&L
Tool, Ltd.
On February 28, 2006, we acquired substantially all of the
operating assets of G&L Tool, Ltd. (G&L)
for total consideration of $58.5 million in cash. This
acquisition provided an entry into the rental and fishing tool
market and operates within our completion and remedial line of
business. The purchase agreement also contained an earn-out
agreement based on annual EBITDA targets. The cash used to
acquire G&L was primarily from borrowings under our senior
credit facility.
Chaparral
Service, Inc.
On August 15, 2006, we acquired all of the outstanding
capital stock and substantially all operating assets of the
subsidiaries of Chaparral Service, Inc. (Chaparral)
for total consideration of $19 million in cash, subject to
30
adjustments. This acquisition expanded our well servicing and
fluid services capabilities in the eastern New Mexico portion of
the Permian Basin. The cash used to acquire Chaparral was
primarily from operating cash.
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.
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
$21.1 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 $60.2 million in cash. This
acquisition operates in our fluid services line of business.
31
Segment
Overview
Well
Servicing
In 2008, our well servicing segment represented 34% of our
revenues. Revenue in our well servicing segment is derived from
maintenance, workover, completion and plugging and abandonment
services. We provide maintenance-related services as part of the
normal, periodic upkeep of producing oil and gas wells.
Maintenance-related services represent a relatively consistent
component of our business. Workover and completion services
generate more revenue per hour than maintenance work due to the
use of auxiliary equipment, but demand for workover and
completion services fluctuates more with the overall activity
level in the industry.
We typically charge our 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 325 rigs in the first quarter of 2006 to 414 in the
fourth quarter of 2008 through a combination of newbuild
purchases, acquisitions, and other individual equipment
purchases.
The following is an analysis of our well servicing segment for
each of the quarters and years in the years ended
December 31, 2006, 2007 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Rig
|
|
|
|
|
|
Profits
|
|
|
|
|
|
|
Number of
|
|
|
Rig
|
|
|
Utilization
|
|
|
Revenue Per
|
|
|
Per Rig
|
|
|
Segment
|
|
|
|
Rigs
|
|
|
Hours
|
|
|
Rate
|
|
|
Rig Hour
|
|
|
Hour
|
|
|
Profits%
|
|
|
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
325
|
|
|
|
208,700
|
|
|
|
89.8
|
%
|
|
$
|
349
|
|
|
$
|
157
|
|
|
|
44.9
|
%
|
Second Quarter
|
|
|
337
|
|
|
|
219,300
|
|
|
|
91.0
|
%
|
|
$
|
365
|
|
|
$
|
165
|
|
|
|
45.2
|
%
|
Third Quarter
|
|
|
351
|
|
|
|
226,300
|
|
|
|
90.2
|
%
|
|
$
|
379
|
|
|
$
|
175
|
|
|
|
46.1
|
%
|
Fourth Quarter
|
|
|
360
|
|
|
|
213,900
|
|
|
|
83.1
|
%
|
|
$
|
398
|
|
|
$
|
174
|
|
|
|
43.8
|
%
|
Full Year
|
|
|
344
|
|
|
|
868,200
|
|
|
|
88.2
|
%
|
|
$
|
373
|
|
|
$
|
168
|
|
|
|
45.0
|
%
|
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
|
%
|
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 2008, our fluid services segment represented 32% of our
revenues. Revenues in our fluid services segment are earned from
the sale, transportation, storage and disposal of fluids used in
the drilling, production and maintenance of oil and gas wells.
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 gas. These
services are necessary for our customers and generally have a
stable
32
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 gas facilities. We typically price fluid services by the
job, by the hour or by the quantities sold, disposed of or
hauled.
The following is an analysis of our fluid services segment for
each of the quarters and years in the years ended
December 31, 2006, 2007 and 2008 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Profits
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Per
|
|
|
|
|
|
|
Number of
|
|
|
Revenue Per
|
|
|
Fluid
|
|
|
|
|
|
|
Fluid Service
|
|
|
Fluid Service
|
|
|
Service
|
|
|
Segment
|
|
|
|
Trucks
|
|
|
Truck
|
|
|
Truck
|
|
|
Profits%
|
|
|
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
529
|
|
|
$
|
101
|
|
|
$
|
37
|
|
|
|
36.4
|
%
|
Second Quarter
|
|
|
568
|
|
|
$
|
109
|
|
|
$
|
42
|
|
|
|
38.2
|
%
|
Third Quarter
|
|
|
614
|
|
|
$
|
105
|
|
|
$
|
38
|
|
|
|
36.7
|
%
|
Fourth Quarter
|
|
|
640
|
|
|
$
|
103
|
|
|
$
|
39
|
|
|
|
38.0
|
%
|
Full Year
|
|
|
588
|
|
|
$
|
417
|
|
|
$
|
156
|
|
|
|
37.4
|
%
|
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
|
%
|
We gauge activity levels in our fluid services segment based on
revenue and segment profits per fluid service truck.
Completion
and Remedial Services
In 2008, our completion and remedial services segment
represented 30% of our revenues. Revenues from our completion
and remedial services segment are generally derived from a
variety of services designed to stimulate oil and gas production
or place cement slurry within the wellbores. Our completion and
remedial services segment includes pressure pumping, rental and
fishing tool operations, cased-hole wireline services and
underbalanced drilling.
Our pressure pumping operations concentrate on providing single
truck, lower-horsepower cementing, acidizing and fracturing
services in selected markets. 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, 2008 compared to 120,000 horsepower at
December 31, 2007 and 58,000 horsepower at
December 31, 2006.
33
We entered the rental and fishing tool business through our
acquisition of G&L 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, 2008.
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. For a description of our wireline and
underbalanced drilling services, please read Overview of
Our Segments and 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 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, 2006, 2007 and 2008 (dollars in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
|
|
|
|
Revenues
|
|
|
Profits%
|
|
|
2006:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
27,455
|
|
|
|
49.5
|
%
|
Second Quarter
|
|
$
|
40,939
|
|
|
|
53.1
|
%
|
Third Quarter
|
|
$
|
42,109
|
|
|
|
51.3
|
%
|
Fourth Quarter
|
|
$
|
43,909
|
|
|
|
51.2
|
%
|
Full Year
|
|
$
|
154,412
|
|
|
|
51.5
|
%
|
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
|
%
|
We gauge the performance of our completion and remedial services
segment based on the segments operating revenues and
segment profits.
Contract
Drilling
In 2008, our contract drilling segment represented 4% 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 two during the first
quarter of 2006 to nine by the fourth quarter of 2008, due to
the Sledge acquisition in April 2007.
34
The following is an analysis of our contract drilling segment
for each of the quarters and years in the years ended
December 31, 2006, 2007, and 2008 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Rig
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Operating
|
|
|
Revenue
|
|
|
Profits (Loss)
|
|
|
Segment
|
|
|
|
Rigs
|
|
|
Days
|
|
|
Per Day
|
|
|
Per Day
|
|
|
Profits%
|
|
|
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
2
|
|
|
|
12
|
|
|
|
N.M.
|
|
|
|
N.M.
|
|
|
|
N.M.
|
|
Second Quarter
|
|
|
2
|
|
|
|
104
|
|
|
$
|
11,700
|
|
|
$
|
(4,900
|
)
|
|
|
−45.2
|
%
|
Third Quarter
|
|
|
2
|
|
|
|
160
|
|
|
$
|
14,700
|
|
|
$
|
1,600
|
|
|
|
10.9
|
%
|
Fourth Quarter
|
|
|
3
|
|
|
|
208
|
|
|
$
|
13,300
|
|
|
$
|
(1,600
|
)
|
|
|
−11.7
|
%
|
Full Year
|
|
|
2
|
|
|
|
484
|
|
|
$
|
14,400
|
|
|
$
|
(3,000
|
)
|
|
|
−20.5
|
%
|
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
3
|
|
|
|
168
|
|
|
$
|
11,500
|
|
|
$
|
(5,200
|
)
|
|
|
−44.9
|
%
|
Second Quarter
|
|
|
8
|
|
|
|
594
|
|
|
$
|
17,200
|
|
|
$
|
6,900
|
|
|
|
39.5
|
%
|
Third Quarter
|
|
|
9
|
|
|
|
723
|
|
|
$
|
15,700
|
|
|
$
|
6,700
|
|
|
|
42.4
|
%
|
Fourth Quarter
|
|
|
10
|
|
|
|
748
|
|
|
$
|
14,600
|
|
|
$
|
5,300
|
|
|
|
36.3
|
%
|
Full Year
|
|
|
8
|
|
|
|
2,233
|
|
|
$
|
15,400
|
|
|
$
|
5,400
|
|
|
|
34.7
|
%
|
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
9
|
|
|
|
645
|
|
|
$
|
14,700
|
|
|
$
|
3,800
|
|
|
|
25.7
|
%
|
Second Quarter
|
|
|
9
|
|
|
|
699
|
|
|
$
|
14,800
|
|
|
$
|
4,000
|
|
|
|
27.2
|
%
|
Third Quarter
|
|
|
9
|
|
|
|
767
|
|
|
$
|
15,600
|
|
|
$
|
5,600
|
|
|
|
35.6
|
%
|
Fourth Quarter
|
|
|
9
|
|
|
|
666
|
|
|
$
|
14,900
|
|
|
$
|
5,400
|
|
|
|
36.2
|
%
|
Full Year
|
|
|
9
|
|
|
|
2,777
|
|
|
$
|
15,000
|
|
|
$
|
4,700
|
|
|
|
31.4
|
%
|
We gauge activity levels in our drilling operations based on rig
operating days, revenue per day, and profits per drilling day.
The results of the first quarter 2006 are not considered
meaningful, due to the
start-up
nature of the drilling operations, and the fact that only twelve
operating days were completed in this quarter.
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
35
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 $375,000 and $180,000 respectively. We have
lower deductibles per occurrence for automobile liability and
general liability. We maintain accruals in our consolidated
balance sheets related to self-insurance retentions by using
third-party actuarial data and historical claims history.
Revenue Recognition. We recognize revenues
when the services are performed, collection of the relevant
receivables is probable, persuasive evidence of the arrangement
exists and the price is fixed and determinable.
Income Taxes. We account for income taxes
based upon SFAS No. 109, Accounting for
Income Taxes (SFAS No. 109).
Under SFAS No. 109, deferred tax assets and
liabilities are recognized for the future tax consequences
attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their
respective tax bases. Deferred tax assets and liabilities are
measured using statutory tax rates expected to apply to taxable
income in the years in which those temporary differences are
expected to be recovered or settled. The effect on deferred tax
assets and liabilities of a change in tax rate is recognized in
the period that includes the statutory enactment date. A
valuation allowance for deferred tax assets is recognized when
it is more likely than not that the benefit of deferred tax
assets will not be realized.
Critical
Accounting Estimates
The preparation of our consolidated financial statements in
conformity with accounting principles generally accepted in the
United States of America (GAAP) requires management to make
certain estimates and assumptions. These estimates and
assumptions affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities
at the balance sheet date and the amounts of revenues and
expenses recognized during the reporting period. We analyze our
estimates based on historical experience and various other
assumptions that we believe to be reasonable under the
circumstances. However, actual results could differ from such
estimates. The following is a discussion of our critical
accounting estimates.
Depreciation and Amortization. In order to
depreciate and amortize our property and equipment and our
intangible assets with finite lives, we estimate the useful
lives and salvage values of these items. Our estimates may be
affected by such factors as changing market conditions,
technological advances in the industry or changes in regulations
governing the industry.
Impairment of Property and Equipment. Our
impairment of property and equipment requires us to estimate
undiscounted future cash flows. Actual impairment charges are
recorded using an estimate of discounted future cash flows. The
determination of future cash flows requires us to estimate rates
and utilization in future periods and such estimates can change
based on market conditions, technological advances in industry
or changes in regulations governing the industry.
Impairment of Goodwill. Our goodwill is
considered to have an indefinite useful economic life and is not
amortized. We assess impairment of our 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. SFAS No. 142, Goodwill
and Other Intangible Assets
(SFAS No. 142), requires a two-step
process for testing impairment. First, the fair value of each
reporting unit is compared to its carrying value to determine
whether an indication of impairment exists. If impairment is
indicated, then the fair value of the reporting units
goodwill is determined by allocating the units fair value
to its assets and liabilities (including any unrecognized
intangible assets) as if the
36
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.
In step one of the annual impairment test and due to the adverse
equity market conditions affecting the Companys common
stock price and the declines in oil and natural gas prices in
the fourth quarter of 2008 and continuing into 2009, the Company
tested its four reporting units, well servicing, fluid services,
completion and remedial services, and contract drilling, for
impairment. To estimate the fair value of the reporting units
the Company used a weighting of the discounted cash flow method,
the guideline transaction method, and the public company
guideline method. The Company weighted the discounted cash flow
method 85% in its analysis and the other two methods combined
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. The control premium used in the reconciliation was
derived from a market transaction data study along with
historical control premiums from other Basic acquisitions. The
measurement date for the stock price for the reconciliation was
the closing price on December 31, 2008.
Based on the results of step one, impairment was indicated in
the contract drilling reporting unit but not in the other three
reporting units. As a result the Company tested the contract
drilling reporting units long-lived assets for impairment
under SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets
(SFAS No. 144), which indicated no
impairment. The Company performed step two for the contract
drilling unit by allocating the estimated fair value to the
tangible and intangible assets and liabilities, which indicated
that the entire value of the goodwill in contract drilling of
$22.5 million was impaired. This non-cash charge eliminates
the goodwill recorded in connection with the Sledge acquisition
in 2007. The goodwill associated with this acquisition has no
tax basis, and accordingly, there is no tax benefit derived from
recording the impairment charge. Further declines in the
Companys stock price and general market conditions may be
considered as a triggering event for the first quarter of 2009.
If this is the case, the Company will analyze its goodwill as of
March 31, 2009 and potentially record further goodwill
impairments in its well servicing, fluid services and/or
completion and remedial services reporting units.
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.
37
Stock-Based Compensation. On January 1,
2006, we adopted the fair value recognition provisions of
SFAS No. 123R, Share-Based Payment
(SFAS No. 123R). Prior to
January 1, 2006, we accounted for
share-based
payments under the recognition and measurement provisions of
Accounting Principles Board Opinion No. 25,
Accounting for stock Issued to Employees
(APB No. 25) which was permitted by
SFAS No. 123, Accounting for Stock-Based
Compensation (SFAS No. 123).
We adopted SFAS No. 123R using both the modified
prospective method and the prospective method as applicable to
the specific awards granted. The modified prospective method was
applied to awards granted subsequent to the Company becoming a
public company. Awards granted prior to the Company becoming
public and which were accounted for under APB No. 25 were
adopted by using the prospective method. The results of prior
periods have not been restated. Compensation expense of the
unvested portion of awards granted as a private company and
outstanding as of January 1, 2006 will continue to be based
upon the intrinsic value method calculated under APB No. 25.
The fair value of common stock for options granted from
July 1, 2004 through September 30, 2005 was estimated
by management using an internal valuation methodology. We did
not obtain contemporaneous valuations by an unrelated valuation
specialist because we were focused on internal growth and
acquisitions and because we had consistently used our internal
valuation methodology for previous stock awards.
Income Taxes. The amount and availability of
our loss carryforwards (and certain other tax attributes) are
subject to a variety of interpretations and restrictive tests.
The utilization of such carryforwards could be limited or lost
upon certain changes in ownership and the passage of time.
Accordingly, although we believe substantial loss carryforwards
are available to us, no assurance can be given concerning the
realization of such loss carryforwards, or whether or not such
loss carryforwards will be available in the future.
Asset Retirement
Obligations. SFAS No. 143,
Accounting for Asset Retirement Obligations
(SFAS No. 143) requires us to record
the fair value of an asset retirement obligation as a liability
in the period in which it incurs a legal obligation associated
with the retirement of tangible long-lived assets and to
capitalize an equal amount as a cost of the asset, depreciating
it over the life of the asset. Subsequent to the initial
measurement of the asset retirement obligation, the obligation
is adjusted at the end of each quarter to reflect the passage of
time, changes in the estimated future cash flows underlying the
obligation, acquisition or construction of assets, and
settlement of obligations.
Results
of Operations
The results of operations between periods will not be
comparable, primarily due to the significant number of
acquisitions made and their relative timing in the year
acquired. See Note 3 of the notes to our historical
consolidated financial statements for more detail.
Year
Ended December 31, 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.
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.
38
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.
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.
39
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.
Year
Ended December 31, 2007 Compared to Year Ended
December 31, 2006
Revenues. Revenues increased by 20% to
$877.2 million in 2007 from $730.1 million in 2006.
This increase was primarily due to acquisitions in the
completion and remedial services and well servicing segments,
and to the internal expansion of our business segments, mainly
well servicing.
Well servicing revenues increased by 6% to $342.7 million
in 2007 compared to $323.8 million in 2006. The increase
was mainly due to internal growth of this segment as we added 45
newbuild rigs to our fleet in 2007. Our weighted average number
of well servicing rigs increased to 376 in 2007 compared to 344
in 2006, an increase of approximately 9%. The rig utilization
rate for our well servicing rigs declined to 77% in 2007
compared to 88% in 2006. This decline was due to stabilization
of industry markets after experiencing significant growth
throughout 2005 and 2006. The effect on revenue from this lower
rig utilization rate was partially offset by an increase of 10%
in our revenue per rig hour from 2006, which increased to $412
per rig hour, and the expansion of our well servicing fleet.
Fluid services revenues increased by 6% to $259.3 million
in 2007 compared to $245.0 million in 2006. This increase
was primarily due to our internal growth and acquisitions. The
Steve Carter Inc. and Hughes Services Inc. acquisition added 22
trucks to our fleet and increased revenues by approximately
$2.2 million for the fourth quarter of 2007. Our weighted
average number of fluid service trucks increased to 655 in 2007
compared to 588 in 2006, an increase of approximately 11%.
During 2007, our average revenue per fluid service truck was
approximately $396,000 as compared to $417,000 in 2006.
Completion and remedial services revenues increased by 56% to
$240.7 million in 2007 as compared to $154.4 million
in 2006. The increase in revenue between these periods was
primarily the result of the acquisition of JetStar in March
2007, which added revenues of $57.1 million, and improved
pricing and utilization of our services.
Contract drilling revenues increased by 394% to
$34.5 million in 2007 compared to $7.0 million in
2006. The increase was due mainly to the acquisition of Sledge,
which added revenues of $23.9 million. Revenue per drilling
day was $15,400 in 2007 compared to $14,400 in 2006, an increase
of 7%.
Direct Operating Expenses. Direct operating
expenses, which primarily consist of labor, including
workers compensation and health insurance, and maintenance
and repair costs, increased by 25% to $518.9 million in
2007 from $414.9 million in 2006. This increase was
primarily due to the acquisitions we completed in 2007, 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 59.2% of revenues in 2007
from 56.8% in 2006.
Direct operating expenses for the well servicing segment
increased by 15% to $205.1 million in 2007 as compared to
$178.0 million in 2006 due primarily to the expansion of
our well servicing rig fleet. Segment profits decreased to 40.1%
of revenues in 2007 compared to 45.0% in 2006, which reflects
higher labor costs as we retained our rig crews during times of
lower utilization.
Direct operating expenses for the fluid services segment
increased by 8% to $165.3 million in 2007 as compared to
$153.4 million in 2006 due primarily to the expansion of
our fluid services fleet and higher labor costs. Segment profits
decreased to 36.2% of revenues in 2007 compared to 37.4% in 2006.
Direct operating expenses for the completion and remedial
services segment increased by 68% to $125.9 million in 2007
as compared to $75.0 million in 2006 due primarily to the
expansion of our services and equipment, including the JetStar
acquisition, and higher operating costs. JetStar operating
expenses were approximately $34.1 million in
40
2007. Our segment profits decreased to 47.7% of revenues in 2007
from 51.4% in 2006, as we experienced higher labor costs and
increases in costs of the materials used in our pressure pumping
operations.
Direct operating expenses for the contract drilling segment
increased by 168% to $22.5 million in 2007 as compared to
$8.4 million in 2006. The increase was primarily due to the
acquisition of Sledge, which added $11.7 million of
operating expenses.
General and Administrative Expenses. General
and administrative expenses increased by 22% to
$99.0 million in 2007 from $81.3 million in 2006,
which included $4.0 million and $3.4 million of
stock-based compensation expense in 2007 and 2006, 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 $93.0 million in 2007 as compared to
$62.1 million in 2006, reflecting the increase in the size
of and investment in our asset base, particularly due to the
Sledge and JetStar acquisitions. We invested $252 million
for acquisitions, $26.8 million for capital leases and an
additional $98.5 million for capital expenditures in 2007.
Interest Expense. Interest expense increased
by 57% to $27.4 million in 2007 from $17.5 million in
2006. The increase was due to an increase in the amount of
long-term debt during the period. In 2007, we used
$150 million of our credit revolver for the acquisitions of
Sledge, JetStar and Wildhorse.
Income Tax Expense. Income tax expense was
$52.8 million in 2007 as compared to $54.7 million in
2006. Our effective tax rate was approximately 38% in 2007 and
36% in 2006.
Loss on Early Extinguishment of Debt. In April
2006, we used the proceeds from our issuance of
$225 million aggregate principal amount of senior notes to
pay in full our Term B Loan under our previous senior credit
facility. In connection with the payment on the Term B Loan, we
recognized a loss on the early extinguishment of debt and
wrote-off unamortized debt issuance costs of approximately
$2.7 million.
Liquidity
and Capital Resources
Currently, our primary capital resources are net cash flows from
our operations, utilization of capital leases as allowed under
our Fourth Amended and Restated Credit Agreement (the 2007
Credit Facility) and availability under our 2007 Credit
Facility, under which approximately $28.8 million of
borrowing capacity was available at December 31, 2008. As
of December 31, 2008, we had cash and cash equivalents of
$111.1 million compared to $91.9 million as of
December 31, 2007. 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 $212.8 million for
the year ended December 31, 2008 as compared to
$198.6 million in 2007 and $145.7 million in 2006. The
increase in 2008 was due primarily to higher revenues being
partially offset by an increase in accounts receivable and other
working capital changes. The increase in operating cash flows in
2007 compared to 2006 was primarily due to higher revenue and
working capital changes.
Capital
Expenditures
Capital expenditures are the main component of our investing
activities. Cash capital expenditures (including for
acquisitions) for 2008 were $202.8 million as compared to
$298.2 million in 2007, and $240.1 million in 2006. In
2008, 2007 and 2006, the majority of our capital expenditures
were for business acquisitions. We also added assets through our
capital lease program of approximately $50.7 million,
$26.8 million and $26.4 million in 2008, 2007 and
2006, respectively.
For 2009, we currently have planned approximately
$40 million in cash capital expenditures and
$22 million in new capital leases, none of which is planned
for acquisitions. We do not budget acquisitions in the normal
course of business. The $40 million of cash capital
expenditures planned for property and equipment is primarily for
(1) purchase of additional equipment to expand our
services, (2) continued refurbishment of our well servicing
rigs
41
and (3) replacement of existing equipment. 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 of up to an
additional $84.7 million at December 31, 2008, the
availability under our 2007 Credit Facility of
$28.8 million at December 31, 2008 and a cash balance
of $111.1 million at December 31, 2008. In 2008, we
financed activities in excess of cash flow from operations
primarily through the use of bank debt and capital leases.
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,
2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Obligations Due in Periods Ended
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
Contractual Obligations
|
|
Total
|
|
|
2009
|
|
|
2010-2011
|
|
|
2012-2013
|
|
|
Thereafter
|
|
|
Long-term debt (excluding capital leases)
|
|
$
|
405,000
|
|
|
$
|
|
|
|
$
|
180,000
|
|
|
$
|
|
|
|
$
|
225,000
|
|
Interest on long-term debt
|
|
|
134,166
|
|
|
|
24,851
|
|
|
|
40,515
|
|
|
|
32,062
|
|
|
|
36,738
|
|
Capital leases
|
|
|
75,323
|
|
|
|
26,063
|
|
|
|
36,292
|
|
|
|
12,968
|
|
|
|
|
|
Operating leases
|
|
|
22,322
|
|
|
|
4,543
|
|
|
|
7,845
|
|
|
|
4,714
|
|
|
|
5,220
|
|
Asset retirement obligations
|
|
|
1,797
|
|
|
|
|
|
|
|
565
|
|
|
|
48
|
|
|
|
1,184
|
|
Other long-term liabilities
|
|
|
4,557
|
|
|
|
1,908
|
|
|
|
1,311
|
|
|
|
985
|
|
|
|
353
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
643,165
|
|
|
$
|
57,365
|
|
|
$
|
266,528
|
|
|
$
|
50,777
|
|
|
$
|
268,495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our long-term debt, excluding capital leases, consists primarily
of revolver indebtedness outstanding under our 2007 Credit
Facility. Interest on long-term debt relates to our future
contractual interest obligation on our $225 million
7.125% Senior Notes due 2016 and $180 million
outstanding under our 2007 Credit Facility. Interest on our 2007
Credit Facility is payable based upon the amount outstanding at
December 31, 2008, at an interest rate of LIBOR plus
125 basis points. 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, 2008, we had a maximum potential obligation of
$22.0 million related to the contingent earn-out agreements.
This amount does not include the balance owed for an acquisition
with no maximum earn-out exposure. In this situation, we will
pay to the sellers an amount for each of the five consecutive
12 month periods equal to 50% of the amount by which annual
EBITDA targets are exceeded. See Note 3 of the notes to our
historical consolidated financial statements for additional
detail.
At December 31, 2008, of the $225 million in financial
commitments under the revolving line of credit under our 2007
Credit Facility, there was only $28.8 million of available
capacity due to the outstanding balance of $180 million and
the $16.2 million of outstanding standby letters of credit.
The 2007 Credit Facility includes provisions allowing us to
request an increase in commitments of up to $100 million
aggregate principal amount at any time. Additionally, the 2007
Credit Facility permits us to make greater expenditures for
acquisitions, capital expenditures and capital leases and to
incur greater purchase money obligations, acquisition
indebtedness and general unsecured indebtedness.
Our ability to access additional sources of financing will be
dependent on our operating cash flows and demand for our
services, which could be negatively impacted due to the extreme
volatility of commodity prices.
Senior
Notes
In April 2006, we completed a private offering for
$225 million aggregate principal amount of
7.125% Senior Notes due April 15, 2016. The Senior
Notes are jointly and severally guaranteed by each of our
subsidiaries. The net proceeds from the offering were used to
retire the outstanding Term B Loan balance and to pay down the
42
outstanding balance under our previous 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.
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 will rank equally
with all of our and the guarantors existing and future
unsecured and unsubordinated obligations. The Senior Notes and
the guarantees will rank senior in right of payment to any of
our and the guarantors existing and future obligations
that are, by their terms, expressly subordinated in right of
payment to the Senior Notes and the guarantees. The Senior Notes
and the guarantees are effectively subordinated to our and the
guarantors secured obligations, including our senior
credit facility, to the extent of the value of the assets
securing such obligations.
The indenture contains covenants that limit the ability of us
and certain of our subsidiaries to:
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incur additional indebtedness;
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pay dividends or repurchase or redeem capital stock;
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make certain investments;
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incur liens;
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enter into certain types of transactions with affiliates;
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limit dividends or other payments by restricted
subsidiaries; and
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sell assets or consolidate or merge with or into other companies.
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These limitations are subject to a number of important
qualifications and exceptions.
Upon an Event of Default (as defined in the indenture), the
trustee or the holders of at least 25% in aggregate principal
amount of the Senior Notes then outstanding may declare all of
the amounts outstanding under the Senior Notes to be due and
payable immediately.
We may, at our option, redeem all or part of the Senior Notes,
at any time on or after April 15, 2011 at a redemption
price equal to 100% of the principal amount thereof, plus a
premium declining ratably to par and accrued and unpaid
interest, if any, to the date of redemption.
At any time or from time to time prior to April 15, 2009,
we, at our option, may redeem up to 35% of the outstanding
Senior Notes with money that we raise in one or more equity
offerings at a redemption price of 107.125% of the principal
amount of the Senior Notes redeemed, plus accrued and unpaid
interest, as long as:
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at least 65% of the aggregate principal amount of Senior Notes
issued under the indenture remains outstanding immediately after
giving effect to any such redemption; and
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we redeem the Senior Notes not more than 90 days after the
closing date of any such equity offering.
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If we experience certain kinds of changes of control, holders of
the Senior Notes will be entitled to require us to purchase all
or a portion of the Senior Notes at 101% of their principal
amount, plus accrued and unpaid interest.
2007
Credit Facility
On February 6, 2007, we amended and restated our existing
credit agreement by entering into the 2007 Credit Facility. At
December 31, 2008, we had $180 million outstanding
under this facility. The amendments contained in the 2007 Credit
Facility included:
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eliminating the $90 million class of Term B Loans;
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creating a new class of Revolving Loans, which increased the
lenders total revolving commitments from $150 million
to $225 million;
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43
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increasing the Incremental Revolving Commitments
from $75.0 million to an aggregate principal amount of
$100 million;
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changing the applicable margins for Alternative Base Rate or
Eurodollar revolving loans;
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amending the negative covenants relating to our ability to incur
indebtedness and liens, to add tests based on a percentage of
our consolidated tangible assets in addition to fixed dollar
amounts, or to increase applicable dollar limits on baskets or
other tests for permitted indebtedness or liens;
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amending the negative covenants relating to our ability to pay
dividends, or repurchase or redeem our capital stock, in order
to conform more closely with permitted payments under our Senior
Notes; and
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eliminating certain restrictions on our ability to create or
incur certain lease obligations.
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Under the 2007 Credit Facility, Basic Energy Services, Inc. is
the sole borrower and each of our subsidiaries is a subsidiary
guarantor. The 2007 Credit Facility provides for a
$225 million revolving line of credit
(Revolver). The 2007 Credit Facility includes
provisions allowing us to request an increase in commitments of
up to $100 million aggregate principal amount subject to
meeting certain tangible value requirements and subject to
lender participation at the time of the request. Additionally,
the 2007 Credit Facility permits us to make greater expenditures
for acquisitions, capital expenditures and capital leases and to
incur greater purchase money obligations, acquisition
indebtedness and general unsecured indebtedness. The commitment
under the Revolver provides for (1) the borrowing of funds,
(2) the issuance of up to $30 million of letters of
credit and (3) $2.5 million of swing-line loans. All
of the outstanding amounts under the Revolver are due and
payable on December 15, 2010. The 2007 Credit Facility is
secured by substantially all of our tangible and intangible
assets. We incurred approximately $0.7 million in debt
issuance costs in connection with the 2007 Credit Facility.
At our option, borrowings under the Revolver bear interest at
either (1) the Alternative Base Rate (i.e., the
higher of the banks prime rate or the federal funds rate
plus .50% per year) plus a margin ranging from 0.25% to 0.5% or
(2) an Adjusted LIBOR Rate (equal to
(a) the London Interbank Offered Rate (the LIBOR
rate) as determined by the Administrative Agent in effect
for such interest period divided by (b) one minus the
Statutory Reserves, if any, for such borrowing for such interest
period) plus a margin ranging from 1.25% to 1.5%. The margins
vary depending on our leverage ratio. Fees on the letters of
credit are due quarterly on the outstanding amount of the
letters of credit at a rate ranging from 1.25% to 1.5% for
participation fees and 0.125% for fronting fees. A commitment
fee is due quarterly on the available borrowings under the
Revolver at a rate of 0.375%.
Pursuant to the 2007 Credit Facility, we must apply proceeds
from certain specified events to reduce principal outstanding
borrowings under the Revolver, including:
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assets sales greater than $2.0 million individually or
$7.5 million in the aggregate on an annual basis;
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100% of the net cash proceeds from any debt issuance, including
certain permitted unsecured senior or senior subordinated debt,
but excluding certain other permitted debt issuances; and
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50% of the net cash proceeds from any equity issuance (including
equity issued upon the exercise of any warrant or option).
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The 2007 Credit Facility contains various restrictive covenants
and compliance requirements, including the following:
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limitations on the incurrence of additional indebtedness;
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restrictions on mergers, sales or transfer of assets without the
lenders consent;
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limitations on dividends and distributions; and
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various financial covenants, including:
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a maximum leverage ratio of 3.25 to 1.00, and
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a minimum interest coverage ratio of 3.00 to 1.00.
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44
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, 2008, we had total capital leases of
approximately $75.3 million.
Losses on
Extinguishment of Debt
In February 2007 and April 2006, we recognized a loss on the
early extinguishment of debt. In February 2007, we wrote off
unamortized debt issuance costs of approximately
$0.2 million, which related to our previous senior credit
facility. In April 2006, we wrote off unamortized debt issuance
costs of approximately $2.7 million, which related to the
prepayment of the Term B Loan under our previous senior credit
facility.
Credit
Rating Agencies
Our Senior Notes are currently rated BB- and B1 by Standard and
Poors and Moodys, respectively. Our 2007 Credit
Facility maintains ratings of BB+ and Ba1 from Standard and
Poors and Moodys, respectively.
Preferred
Stock
At December 31, 2008 and December 31, 2007, 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 or results of operations.
Net
Operating Losses
As of December 31, 2008, 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
In September 2006, the Financial Accounting Standards Board
(FASB) issued SFAS No. 157, Fair
Value Measurements (SFAS 157), which became effective
for financial assets and liabilities of the Company on
January 1, 2008 and non-financial assets and liabilities of
the Company on January 1, 2009. This standard defines fair
value, establishes a framework for measuring fair value and
expands disclosures about fair value measurements. SFAS 157
does not require any new fair value measurements but would apply
to assets and liabilities that are required to be recorded at
fair value under other accounting standards. The impact, if any,
to the Company from the adoption of SFAS 157 in 2009 will
depend on the Companys assets and liabilities at that time
that are required to be measured at fair value.
In February 2007, the FASB issued SFAS 159, The Fair
Value Option for Financial Assets and Financial Liabilities
(SFAS 159), which became effective for the Company on
January 1, 2008. This standard permits companies to choose
to measure many financial instruments and certain other items at
fair value and report unrealized gains and losses in earnings.
Such accounting is optional and is generally to be applied
instrument by instrument.
In December 2007, the FASB issued SFAS No. 141R,
Business Combinations (SFAS 141R), which became
effective for the Company on January 1, 2009. This
Statement requires an acquirer to recognize the assets acquired,
the liabilities assumed, and any noncontrolling interest in the
acquiree at the acquisition date be measured 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 a
liability in FASB Concepts Statement
45
No. 6, Elements of Financial Statements.
Any acquisition related costs are to be expensed instead of
capitalized. The impact to the Company from the adoption of
SFAS 141R in 2009 will depend on acquisitions at the time.
In December 2007, the FASB issued SFAS No. 160,
Noncontrolling Interests in Consolidated Financial Statements
(SFAS 160), which became effective for the Company on
January 1, 2009. This standard establishes accounting and
reporting standards for ownership interests in subsidiaries held
by parties other than the parent, the amount of consolidated net
income attributable to the parent and to the noncontrolling
interest, changes in a parents ownership interest and the
valuation of retained non-controlling equity investments when a
subsidiary is deconsolidated. The Statement also establishes
reporting requirements that provide sufficient disclosures that
clearly identify and distinguish between the interests of the
parent and the interests of the non-controlling owners. The
Company does not anticipate that this pronouncement will have a
material impact on its results of operations or consolidated
financial position.
In March 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging
Activities (SFAS 161), which became effective for the
Company on January 1, 2009. This standard improves
financial reporting for derivative instruments and hedging
activities by requiring enhanced disclosures to expand on these
instruments effects on a companys financial
position, financial performance and cash flows. The Company does
not anticipate that this pronouncement will have a material
impact on its results of operations or consolidated financial
position.
In April 2008, the FASB issued FSP
SFAS No. 142-3,
Determination of Useful Life of Intangible Assets
(FSP 142-3).
FSP 142-3
amends the factors that should be considered in developing the
renewal or extension assumptions used to determine the useful
life of a recognized intangible asset under SFAS 142.
FSP 142-3
is effective for fiscal years beginning after December 15, 2008.
Earlier adoption is not permitted. We are currently evaluating
the potential impact the adoption of
FSP 142-3
will have on our consolidated financial statements.
In May 2008, the FASB issued SFAS No. 162,
The Hierarchy of Generally Accepted Accounting Principles
(SFAS 162), which becomes effective for the Company
60 days following the SECs approval of the Public
Company Accounting Oversight Board amendments to AU
Section 411, The Meaning of Present Fairly in
Conformity With Generally Accepted Accounting
Principles. This standard identifies the sources of
accounting principles and the framework for selecting the
principles used in preparation of financial statements that are
presented in conformity with generally accepted accounting
principles (GAAP). The Company does not anticipate that this
pronouncement will have a material impact on its results of
operations or consolidated financial position.
In June 2008, the FASB issued Staff Position
EITF 03-6-1
Determining Whether Instruments Granted in Share-Based
Payment Transactions are Participating Securities
(FSP
EITF 03-6-1).
FSP
EITF 03-6-1
addresses whether instruments granted in share based payment
transactions are participating securities prior to vesting and,
therefore, need to be included in earnings allocation in
computing earnings per share (EPS) under the
two-class method described in paragraphs 60 and 61 of
SFAS No. 128, Earnings Per Share.
FSP
EITF 03-6-1
is effective for financial statements issued for fiscal years
and interim periods beginning after December 15, 2008 and
requires retrospective adjustment for all comparable prior
periods presented. The Company does not anticipate that the
adoption of FSP
EITF 03-6-1
will have a material impact on its EPS disclosures.
Impact
of Inflation on Operations
Management is of the opinion that inflation has not had a
significant impact on our business.
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ITEM 7A.
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QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
As of December 31, 2008, we had $180 million
outstanding under the revolving portion of our 2007 Credit
Facility subject to variable interest rate risk. The impact of a
1% increase in interest rates on this amount of debt would
result in increased interest expense of approximately
$1.8 million annually and a decrease in net income of
approximately $996,000.
46
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ITEM 8.
|
FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
|
Basic
Energy Services, Inc.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
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Page
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48
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49
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51
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52
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53
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54
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55
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47
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, 2008,
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, 2008, the Companys internal control over
financial reporting was effective to provide reasonable
assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in
accordance with U.S. generally accepted accounting
principles.
The Company acquired substantially all of the assets of Azurite
Services Company, Inc., Azurite Leasing Company, LLC and
Freestone Disposal, L.P. (collectively Azurite)
during 2008, and management excluded from its assessment of the
effectiveness of the Companys internal control over
financial reporting as of December 31, 2008 any internal
control evaluation over financial reporting the associated total
assets of approximately $60.2 million and total revenues of
approximately $10.9 million included in the consolidated
financial statements of Basic Energy Services Inc. and
subsidiaries as of and for the year ended December 31, 2008.
KPMG LLP, the independent registered public accounting firm that
audited the Companys consolidated financial statements
included in this report, has issued an audit report on the
effectiveness of internal control over financial reporting.
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/s/ Kenneth
V. Huseman
Kenneth
V. Huseman
Chief Executive Officer
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/s/ Alan
Krenek Alan
Krenek
Chief Financial Officer
|
48
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, 2008, 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, 2008, based on criteria
established in Internal Control Integrated
Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
The Company acquired substantially all of the assets of Azurite
Services Company, Inc., Azurite Leasing Company, LLC, and
Freestone Disposal, L.P. (collectively, Azurite)
during 2008, and management excluded from its assessment of the
effectiveness of the Companys internal control over
financial reporting as of December 31, 2008, Azurites
internal control over financial reporting associated with total
assets of $60.2 million and total revenues of
$10.9 million included in the consolidated financial
statements of Basic Energy Services, Inc. and subsidiaries as of
and for the year ended December 31, 2008. Our audit of
internal control over financial reporting of the Company also
excluded an evaluation of the internal control over financial
reporting of Azurite.
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, 2008 and 2007, 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, 2008, and our report dated March 6, 2009
expressed an unqualified opinion on those consolidated financial
statements.
KPMG LLP
Dallas, Texas
March 6, 2009
49
Report of
Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Basic Energy Services, Inc.:
We have audited the accompanying consolidated balance sheets of
Basic Energy Services, Inc. and subsidiaries (the Company) as of
December 31, 2008 and 2007, 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, 2008. 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, 2008 and 2007, and the results of their
operations and their cash flows for each of the years in the
three-year period ended December 31, 2008, 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, 2008, based on criteria
established in Internal Control Integrated
Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO), and our report
dated March 6, 2009 expressed an unqualified opinion on the
effectiveness of the Companys internal control over
financial reporting.
KPMG LLP
Dallas, Texas
March 6, 2009
50
Basic
Energy Services, Inc.
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except
|
|
|
|
share data)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
111,135
|
|
|
$
|
91,941
|
|
Trade accounts receivable, net of allowance of $5,838 and
$6,090, respectively
|
|
|
172,930
|
|
|
|
138,384
|
|
Accounts receivable related parties
|
|
|
148
|
|
|
|
91
|
|
Federal income tax receivable
|
|
|
3,324
|
|
|
|
1,130
|
|
Inventories
|
|
|
11,937
|
|
|
|
11,034
|
|
Prepaid expenses
|
|
|
6,838
|
|
|
|
6,999
|
|
Other current assets
|
|
|
6,508
|
|
|
|
6,353
|
|
Deferred tax assets
|
|
|
11,081
|
|
|
|
10,593
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
323,901
|
|
|
|
266,525
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
|
740,879
|
|
|
|
636,924
|
|
Deferred debt costs, net of amortization
|
|
|
5,132
|
|
|
|
6,100
|
|
Goodwill
|
|
|
202,749
|
|
|
|
204,963
|
|
Other intangible assets
|
|
|
36,004
|
|
|
|
26,975
|
|
Other assets
|
|
|
2,046
|
|
|
|
2,122
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,310,711
|
|
|
$
|
1,143,609
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
28,291
|
|
|
$
|
22,146
|
|
Accrued expenses
|
|
|
47,139
|
|
|
|
51,003
|
|
Current portion of long-term debt
|
|
|
26,063
|
|
|
|
17,413
|
|
Other current liabilities
|
|
|
658
|
|
|
|
1,474
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
102,151
|
|
|
|
92,036
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
454,260
|
|
|
|
406,306
|
|
Deferred tax liabilities
|
|
|
149,591
|
|
|
|
114,604
|
|
Other long-term liabilities
|
|
|
9,705
|
|
|
|
5,842
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Preferred stock; $.01 par value; 5,000,000 shares
authorized; none designated or issued at December 31, 2008
and December 31, 2007, respectively
|
|
|
|
|
|
|
|
|
Common stock; $.01 par value; 80,000,000 shares
authorized; 41,734,485 shares issued and
40,851,862 shares outstanding at December 31, 2008;
and 40,925,530 shares issued and 40,896,217 shares
outstanding at December 31, 2007
|
|
|
417
|
|
|
|
409
|
|
Additional paid-in capital
|
|
|
325,785
|
|
|
|
314,705
|
|
Retained earnings
|
|
|
277,173
|
|
|
|
209,707
|
|
Treasury stock, 882,623 and 29,313 shares at
December 31, 2008 and 2007, respectively
|
|
|
(8,371
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
595,004
|
|
|
|
524,821
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
1,310,711
|
|
|
$
|
1,143,609
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial
statements.
51
Basic
Energy Services, Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars in thousands, except per share amounts)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
$
|
343,113
|
|
|
$
|
342,697
|
|
|
$
|
323,755
|
|
Fluid services
|
|
|
315,768
|
|
|
|
259,324
|
|
|
|
245,011
|
|
Completion and remedial services
|
|
|
304,326
|
|
|
|
240,692
|
|
|
|
154,412
|
|
Contract drilling
|
|
|
41,735
|
|
|
|
34,460
|
|
|
|
6,970
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
1,004,942
|
|
|
|
877,173
|
|
|
|
730,148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
|
215,243
|
|
|
|
205,132
|
|
|
|
178,028
|
|
Fluid services
|
|
|
203,205
|
|
|
|
165,327
|
|
|
|
153,445
|
|
Completion and remedial services
|
|
|
165,574
|
|
|
|
125,948
|
|
|
|
74,981
|
|
Contract drilling
|
|
|
28,629
|
|
|
|
22,510
|
|
|
|
8,400
|
|
General and administrative, including stock-based compensation
of $4,149, $3,964 and $3,429 in 2008, 2007 and 2006, respectively
|
|
|
115,319
|
|
|
|
99,042
|
|
|
|
81,318
|
|
Depreciation and amortization
|
|
|
118,607
|
|
|
|
93,048
|
|
|
|
62,087
|
|
Loss on disposal of assets
|
|
|
76
|
|
|
|
477
|
|
|
|
277
|
|
Goodwill impairment
|
|
|
22,522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
869,175
|
|
|
|
711,484
|
|
|
|
558,536
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
135,767
|
|
|
|
165,689
|
|
|
|
171,612
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(26,766
|
)
|
|
|
(27,416
|
)
|
|
|
(17,466
|
)
|
Interest income
|
|
|
2,136
|
|
|
|
2,280
|
|
|
|
1,962
|
|
Loss on early extinguishment of debt
|
|
|
|
|
|
|
(230
|
)
|
|
|
(2,705
|
)
|
Other income
|
|
|
12,235
|
|
|
|
176
|
|
|
|
169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes
|
|
|
123,372
|
|
|
|
140,499
|
|
|
|
153,572
|
|
Income tax expense
|
|
|
(55,134
|
)
|
|
|
(52,766
|
)
|
|
|
(54,742
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
68,238
|
|
|
|
87,733
|
|
|
|
98,830
|
|
Basic earnings per share of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
1.67
|
|
|
$
|
2.19
|
|
|
$
|
2.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
1.64
|
|
|
$
|
2.13
|
|
|
$
|
2.56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
68,238
|
|
|
$
|
87,733
|
|
|
$
|
98,830
|
|
Unrealized gains on hedging activities
|
|
|
|
|
|
|
|
|
|
|
51
|
|
Less: reclassification adjustment for gain included in net income
|
|
|
|
|
|
|
|
|
|
|
(287
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income:
|
|
$
|
68,238
|
|
|
$
|
87,733
|
|
|
$
|
98,594
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial
statements.
52
Basic
Energy Services, Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
|
Retained
|
|
|
Other
|
|
|
Total
|
|
|
|
Common Stock
|
|
|
Paid-In
|
|
|
Deferred
|
|
|
Treasury
|
|
|
Earnings
|
|
|
Comprehensive
|
|
|
Stockholders
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Compensation
|
|
|
Stock
|
|
|
(Deficit)
|
|
|
Income
|
|
|
Equity
|
|
|
|
(In thousands, except share data)
|
|
|
Balance December 31, 2005
|
|
|
33,931,935
|
|
|
$
|
339
|
|
|
$
|
239,218
|
|
|
$
|
(7,341
|
)
|
|
$
|
(2,531
|
)
|
|
$
|
28,654
|
|
|
$
|
236
|
|
|
$
|
258,575
|
|
Adoption of Statement of Financial Accounting Standard
No. 123R
|
|
|
|
|
|
|
|
|
|
|
(7,341
|
)
|
|
|
7,341
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of deferred compensation
|
|
|
|
|
|
|
|
|
|
|
3,429
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,429
|
|
Unrealized gain on interest rate swap agreement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
51
|
|
|
|
51
|
|
Settlement of interest rate swap agreement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(287
|
)
|
|
|
(287
|
)
|
Offering costs
|
|
|
|
|
|
|
|
|
|
|
(227
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(227
|
)
|
Exercise of stock warrants
|
|
|
4,350,000
|
|
|
|
44
|
|
|
|
17,357
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,401
|
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,218
|
)
|
|
|
|
|
|
|
|
|
|
|
(3,218
|
)
|
Exercise of stock options
|
|
|
15,670
|
|
|
|
|
|
|
|
4,091
|
|
|
|
|
|
|
|
5,749
|
|
|
|
(5,144
|
)
|
|
|
|
|
|
|
4,696
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
98,830
|
|
|
|
|
|
|
|
98,830
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2006
|
|
|
38,297,605
|
|
|
|
383
|
|
|
|
256,527
|
|
|
|
|
|
|
|
|
|
|
|
122,340
|
|
|
|
|
|
|
|
379,250
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial
statements.
53
Basic
Energy Services, Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
68,238
|
|
|
$
|
87,733
|
|
|
$
|
98,830
|
|
Adjustments to reconcile net income to net cash provided by
operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
118,607
|
|
|
|
93,048
|
|
|
|
62,087
|
|
Goodwill impairment
|
|
|
22,522
|
|
|
|
|
|
|
|
|
|
Accretion on asset retirement obligation
|
|
|
131
|
|
|
|
115
|
|
|
|
78
|
|
Change in allowance for doubtful accounts
|
|
|
(252
|
)
|
|
|
2,127
|
|
|
|
1,188
|
|
Amortization of deferred financing costs
|
|
|
968
|
|
|
|
962
|
|
|
|
804
|
|
Non-cash compensation
|
|
|
4,149
|
|
|
|
3,964
|
|
|
|
3,429
|
|
Loss on early extinguishment of debt
|
|
|
|
|
|
|
230
|
|
|
|
2,705
|
|
Loss on disposal of assets
|
|
|
76
|
|
|
|
477
|
|
|
|
277
|
|
Deferred income taxes
|
|
|
30,165
|
|
|
|
15,285
|
|
|
|
2,611
|
|
Changes in operating assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(32,411
|
)
|
|
|
4,396
|
|
|
|
(32,933
|
)
|
Inventories
|
|
|
(558
|
)
|
|
|
(328
|
)
|
|
|
(714
|
)
|
Prepaid expenses and other current assets
|
|
|
2,348
|
|
|
|
6,325
|
|
|
|
(6,771
|
)
|
Other assets
|
|
|
47
|
|
|
|
(753
|
)
|
|
|
(450
|
)
|
Accounts payable
|
|
|
4,759
|
|
|
|
(1,237
|
)
|
|
|
5,128
|
|
Excess tax benefits from exercise of employee stock options
|
|
|
(5,062
|
)
|
|
|
(2,169
|
)
|
|
|
(4,022
|
)
|
Income tax payable
|
|
|
2,963
|
|
|
|
(11,262
|
)
|
|
|
6,344
|
|
Other liabilities
|
|
|
1,217
|
|
|
|
(332
|
)
|
|
|
(171
|
)
|
Accrued expenses
|
|
|
(5,080
|
)
|
|
|
10
|
|
|
|
7,258
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
212,827
|
|
|
|
198,591
|
|
|
|
145,678
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of property and equipment
|
|
|
(91,890
|
)
|
|
|
(98,536
|
)
|
|
|
(104,574
|
)
|
Proceeds from sale of assets
|
|
|
8,184
|
|
|
|
6,815
|
|
|
|
5,560
|
|
Payments for other long-term assets
|
|
|
(2,683
|
)
|
|
|
(2,709
|
)
|
|
|
(6,769
|
)
|
Payments for businesses, net of cash acquired
|
|
|
(110,913
|
)
|
|
|
(199,673
|
)
|
|
|
(135,568
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(197,302
|
)
|
|
|
(294,103
|
)
|
|
|
(241,351
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from debt
|
|
|
30,000
|
|
|
|
150,000
|
|
|
|
305,546
|
|
Payments of debt
|
|
|
(24,126
|
)
|
|
|
(15,838
|
)
|
|
|
(204,793
|
)
|
Purchase of treasury stock
|
|
|
(9,994
|
)
|
|
|
(462
|
)
|
|
|
(3,218
|
)
|
Offering costs related to initial public offering
|
|
|
|
|
|
|
|
|
|
|
(227
|
)
|
Excess tax benefits from exercise of employee stock options
|
|
|
5,062
|
|
|
|
2,169
|
|
|
|
4,022
|
|
Tax withholding from exercise of stock options
|
|
|
(4,174
|
)
|
|
|
(1,290
|
)
|
|
|
(1,310
|
)
|
Exercise of employee stock options
|
|
|
6,901
|
|
|
|
2,265
|
|
|
|
1,984
|
|
Proceeds from exercise stock warrants
|
|
|
|
|
|
|
|
|
|
|
17,401
|
|
Deferred loan costs and other financing activities
|
|
|
|
|
|
|
(756
|
)
|
|
|
(5,212
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
3,669
|
|
|
|
136,088
|
|
|
|
114,193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and equivalents
|
|
|
19,194
|
|
|
|
40,576
|
|
|
|
18,520
|
|
Cash and cash equivalents beginning of year
|
|
|
91,941
|
|
|
|
51,365
|
|
|
|
32,845
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents end of year
|
|
$
|
111,135
|
|
|
$
|
91,941
|
|
|
$
|
51,365
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial
statements.
54
BASIC
ENERGY SERVICES, INC.
December 31,
2008, 2007, and 2006
Basic Energy Services, Inc. provides a range of well site
services to oil and gas drilling and producing companies,
including well servicing, fluid services, completion and
remedial services and contract drilling. These services are
primarily provided by Basics fleet of equipment.
Basics operations are concentrated in the major United
States onshore oil and gas producing regions in Texas, New
Mexico, Oklahoma, Kansas, Arkansas and Louisiana, and the Rocky
Mountain states.
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.
The new 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. These changes reflect Basics operating focus in
compliance with SFAS No. 131, Disclosures
about Segments of an Enterprise and Related
Information.
|
|
2.
|
Summary
of Significant Accounting Policies
|
Principles
of Consolidation
The accompanying consolidated financial statements include the
accounts of Basic and its wholly-owned subsidiaries. Basic has
no interest in any other organization, entity, partnership, or
contract that could require any evaluation under FASB
Interpretation No. 46R or Accounting Research
Bulletin No. 51. All intercompany transactions and
balances have been eliminated.
Estimates,
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. 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
|
Oil and gas prices decreased significantly in the second half of
2008 which resulted in lower utilization of the Companys
services in the fourth quarter of 2008. For 2009, the Company
expects oil and gas prices to remain substantially below the
levels required to support aggressive capital spending programs
by its customers and that maintenance related spending by
customers will be deferred as long as possible. The Company
expects the reduced spending level by its customers will result
in lower demand for its services and increased price competition
among
55
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
service providers in all segments of its business which will
negatively affect the Companys revenue and gross margins.
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 (formerly Drilling
and Completion Services) Basic recognizes
revenue when services are performed, collection of the relevant
receivables is probable, persuasive evidence of an arrangement
exists and the price is fixed or determinable. Basic prices
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
Basic considers all highly liquid instruments purchased with a
maturity of three months or less to be cash equivalents. Basic
maintains its excess cash in various financial institutions,
where deposits may exceed federally insured amounts at times.
Fair
Value of Financial Instruments
The carrying value amount of cash, accounts receivable, accounts
payable and accrued liabilities approximate fair value due to
the short maturity of these instruments. The carrying amount of
long-term debt approximates fair value because Basics
current borrowing rate is based on a variable market rate of
interest.
Inventories
For rental and fishing tools, inventories consisting mainly of
grapples, controls, and drill bits are stated at the lower of
cost or market, with cost being determined on the average cost
method. Other inventories, consisting mainly of rig components,
repair parts, drilling and completion materials and gravel, are
held for use in the operations of Basic and are stated at the
lower of cost or market, with cost being determined on the
first-in,
first-out (FIFO) method.
Property
and Equipment
Property and equipment are stated at cost or at estimated fair
value at acquisition date if acquired in a business combination.
Expenditures for repairs and maintenance are charged to expense
as incurred and additions and improvements that significantly
extend the lives of the assets are capitalized. Upon sale or
other retirement of
56
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
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
In accordance with Statement of Financial Accounting Standards
No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets (SFAS No. 144),
long-lived assets, such as property, plant, and equipment, and
purchased intangibles subject to amortization, are reviewed for
impairment at a minimum annually, or whenever, in
managements judgment events or changes in circumstances
indicate that the carrying amount of such assets may not be
recoverable. Recoverability of assets to be held and used is
measured by a comparison of the carrying amount of such assets
to estimated undiscounted future cash flows expected to be
generated by the assets. Expected future cash flows and carrying
values are aggregated at their lowest identifiable level. If the
carrying amount of such assets exceeds its estimated future cash
flows, an impairment charge is recognized by the amount by which
the carrying amount of such assets exceeds the fair value of the
assets. Assets to be disposed of would be separately presented
in the consolidated balance sheet and reported at the lower of
the carrying amount or fair value less costs to sell, and are no
longer depreciated. The assets and liabilities, if material, of
a disposed group classified as held for sale would be presented
separately in the appropriate asset and liability sections of
the consolidated balance sheet. These assets are normally sold
within a short period of time through a third party auctioneer.
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 $7.6 million net of
accumulated amortization of $2.4 million, and
$7.6 million net of accumulated amortization of
$1.5 million at December 31, 2008 and
December 31, 2007, respectively. Amortization of deferred
debt costs totaled approximately $968,000, $962,000 and $804,000
for the years ended December 31, 2008, 2007 and 2006,
respectively.
In 2006, Basic recognized a loss on early extinguishment of debt
related to deferred debt costs. (See note 5)
57
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Goodwill
and Other Intangible Assets
Statement of Financial Accounting Standards No. 142,
Goodwill and Other Intangible Assets
(SFAS No. 142) eliminates the
amortization of goodwill and other intangible assets with
indefinite lives. Intangible assets with lives restricted by
contractual, legal, or other means will continue to be amortized
over their useful lives. Goodwill and other intangible assets
not subject to amortization are tested for impairment annually
or more frequently if events or changes in circumstances
indicate that the asset might be impaired.
SFAS No. 142 requires a two-step process for testing
impairment. First, the fair value of each reporting unit is
compared to its carrying value to determine whether an
indication of impairment exists. If impairment is indicated,
then the fair value of the reporting units goodwill is
determined by allocating the units fair value to its
assets and liabilities (including any unrecognized intangible
assets) as if the reporting unit had been acquired in a business
combination. The amount of impairment for goodwill is measured
as the excess of its carrying value over its fair value. Basic
completed its assessment of goodwill impairment as of the date
of adoption and completed a subsequent annual impairment
assessment as of December 31 each year thereafter.
In step one of the annual impairment test and due to the adverse
equity market conditions affecting the Companys common
stock price and the declines in oil and natural gas prices in
the fourth quarter of 2008 and continuing into 2009, the Company
tested its four reporting units, well servicing, fluid services,
completion and remedial services, and contract drilling, for
impairment. To estimate the fair value of the reporting units,
the Company used a weighting of the discounted cash flow method,
the guideline transaction method, and the public company
guideline company method. The Company weighted the discounted
cash flow method 85% in its analysis and the other two methods
combined 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 cap was performed. The
control premium used in the reconciliation was derived from a
market transaction data study along with historical control
premiums from the Companys other acquisitions. The
measurement date for the stock price for the reconciliation was
the closing price on December 31, 2008.
Based on the results of step one, impairment was indicated in
the contract drilling reporting unit but not in the other three
reporting units. As a result, the Company tested the contract
drilling reporting units long-lived assets for impairment
under SFAS No. 144, which indicated no impairment. The
Company performed step two for the contract drilling unit by
allocating the estimated fair value to the tangible and
intangible assets and liabilities, which indicated that the
entire value of the goodwill in contract drilling of
$22.5 million was impaired. This non-cash charge eliminates
the goodwill recorded in connection with the Sledge acquisition
in 2007. The goodwill associated with this acquisition has no
tax basis, and accordingly, there is no tax benefit derived from
recording the impairment charge. Further declines in the
Companys stock price and general market conditions may be
considered as a triggering event for the first quarter of 2009.
If this is the case, the Company will analyze its goodwill as of
March 31, 2009 and potentially record further goodwill
impairments in its well servicing, fluid services and/or
completion and remedial services reporting units.
Intangible assets subject to amortization under
SFAS No. 142 consist of customer relationships and
non-compete agreements. The gross carrying amount of customer
relationships subject to amortization was $35.4 million and
$23.8 million as of December 31, 2008 and 2007,
respectively. The gross carrying amount of non-compete
agreements subject to amortization totaled approximately
$4.4 million and $5.2 million at December 31,
2008 and 2007, respectively. Accumulated amortization related to
these intangible assets totaled approximately $3.8 and
$2.1 million at December 31, 2008 and 2007,
respectively. Amortization expense for the years ended
December 31, 2008, 2007 and 2006 was approximately
$2.8 million, $773,000, and $650,000, respectively.
Amortization expense
58
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
for the next five succeeding years is estimated to be
approximately $3.2 million, $3.1 million,
$3.0 million, $2.6 million, and $2.4 million in
2009, 2010, 2011, 2012, and 2013, respectively.
|
|
|
|
|
Amortizable Intangible Assets at December 31, 2008 (in
thousands):
|
|
|
|
|
Customer Relationships
|
|
$
|
35,441
|
|
Accumulated Amortization Customer Relationships
|
|
|
(1,879
|
)
|
Non-Compete Agreements
|
|
|
4,392
|
|
Accumulated Amortization Non-Compete Agreements
|
|
|
(1,950
|
)
|
|
|
|
|
|
Total Amortizable Intangible Assets
|
|
$
|
36,004
|
|
|
|
|
|
|
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. The goodwill allocated to such reporting units as of
December 31, 2008 was $29.9 million,
$49.3 million, $123.5 million, and $0, respectively.
The change in the carrying amount of goodwill for the year ended
December 31, 2008 of $2.2 million relates to goodwill
from acquisitions and payments pursuant to contingent earn-out
agreements and impairments, with approximately
$3.1 million, $6.1 million and $12.0 million of
goodwill additions relating to the well servicing, fluid
services, and completion and remedial units, respectively. There
was a decrease in the carrying amount of goodwill for the year
ended December 31, 2008 of $23.4 million related to
contract drilling. The decrease in the carrying amount of
goodwill for contract drilling is due primarily to the
impairment of $22.5 million. Other intangibles net of
accumulated amortization allocated to reporting units as of
December 31, 2008 was $454,000, $3.3 million,
$26.3 million and $5.9 million for well servicing,
fluid services, completion and remedial services, and contract
drilling, respectively.
Stock-Based
Compensation
On January 1, 2006, Basic adopted Statement of Financial
Accounting Standards No. 123 (revised
2004) Share-Based Payment
(SFAS No. 123R). Prior to
January 1, 2006, the Company accounted for share-based
payments under the recognition and measurement provisions of
Accounting Principles Board Opinion No. 25,
Accounting for Stock issued to Employees
(APB No. 25) which was permitted by
Statement of Financial Accounting Standards No. 123,
Accounting for Stock-Based Compensation
(SFAS No. 123).
Basic adopted SFAS No. 123R using both the modified
prospective method and the prospective method as applicable to
the specific awards granted. The modified prospective method was
applied to awards granted subsequent to the Company becoming a
public company. Awards granted prior to the Company becoming
public and which were accounted for under APB No. 25 were
adopted by using the prospective method. The results of prior
periods have not been restated. Compensation expense cost of the
unvested portion of awards granted as a private company and
outstanding as of January 1, 2006 will continue to be based
upon the intrinsic value method calculated under APB No. 25.
Under SFAS No. 123R, entities using the minimum value
method and the prospective application are not permitted to
provide the pro forma disclosures (as was required under
SFAS No. 123) subsequent to adoption of
SFAS No. 123R since they do not have the fair value
information required by SFAS No. 123R. Therefore, in
accordance with SFAS No. 123R, Basic no longer
includes pro forma disclosures that were required by
SFAS No. 123.
Income
Taxes
Basic accounts for income taxes based upon Statement of
Financial Accounting Standards No. 109, Accounting
for Income Taxes (SFAS 109). Under
SFAS No. 109, deferred tax assets and liabilities are
recognized for the future tax consequences attributable to
differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases.
Deferred tax assets and liabilities are measured using statutory
tax rates expected to apply to taxable income in the years in
which those temporary
59
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
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 2008, 2007, or 2006.
Derivative
Instruments and Hedging Activities
In June 1998, the Financial Accounting Standards Board
(FASB) issued Statement of Financial Accounting
Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities
(SFAS No. 133), which establishes
standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for
hedging activities. It requires that an entity recognize all
derivative as either assets or liabilities on the balance sheet
and measure those instruments at fair value. It establishes
conditions under which a derivative may be designated as a
hedge, and establishes standards for reporting changes in the
fair value of a derivative. Basic adopted
SFAS No. 133, as amended by SFAS No. 138, on
January 1, 2001. Basic adopted the additional amendments
pursuant to SFAS No. 149 for contracts entered or
modified after June 30, 2003, if any. At inception, Basic
formally documents the relationship between the hedging
instrument and the underlying hedged item as well as risk
management objective and strategy. Basic assesses, both at
inception and on an ongoing basis, whether the derivative used
in hedging transition is highly effective in offsetting changes
in the fair value of cash flows of the respective hedged item.
In May 2004, Basic implemented a cash flow hedge to protect
itself from fluctuation in cash flows associated with its credit
facility. Changes in fair value of the hedging derivative were
initially recorded in other comprehensive income, then
recognized in income in the same period(s) in which the hedged
transaction affected income. Ineffective portions of a cash flow
hedging derivatives change in fair value were recognized
currently in earnings. Basic had no ineffectiveness related to
its cash flow hedge in 2005. The March 28, 2006 amendment
to the 2005 credit facility deleted the requirement to maintain
the cash flow hedge upon payoff of the Term B Loans. In April
2006, Basic paid off all outstanding borrowings under the Term B
Loan (See note 5). Accordingly in April 2006, the interest
rate swap was terminated and the balance remaining in
accumulated comprehensive income was recognized in earnings.
Asset
Retirement Obligations
As of January 1, 2003, Basic adopted Statement of Financial
Accounting Standards No. 143, Accounting for Asset
Retirement Obligation
(SFAS No. 143). SFAS No. 143
requires Basic to record the fair value of an asset retirement
obligation as a liability in the period in which it incurs a
legal obligation associated with the retirement of tangible
long-lived assets and capitalize an equal amount as a cost of
the asset depreciating it over the life of the asset. Subsequent
to the initial measurement of the asset retirement obligation,
the obligation is adjusted at the end of each quarter to reflect
the passage of time, changes in the estimated future cash flows
underlying the obligation, acquisition or construction of
assets, and settlements of obligations.
60
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Basic owns and operates salt water disposal sites, brine water
wells, gravel pits and land farm sites, each of which is subject
to rules and regulations regarding usage and eventual closure.
The following table reflects the changes in the liability during
years ended December 31, 2008 and 2007 (in thousands):
|
|
|
|
|
Balance, December 31, 2006
|
|
$
|
1,336
|
|
Additional asset retirement obligations recognized through
acquisitions
|
|
|
101
|
|
Accretion expense
|
|
|
115
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
Environmental
Basic is subject to extensive federal, state and local
environmental laws and regulations. These laws, which are
constantly changing, regulate the discharge of materials into
the environment and may require Basic to remove or mitigate the
adverse environmental effects of disposal or release of
petroleum, chemical and other substances at various sites.
Environmental expenditures are expensed or capitalized depending
on the future economic benefit. Expenditures that relate to an
existing condition caused by past operations and that have no
future economic benefits are expensed. Liabilities for
expenditures of a non-capital nature are recorded when
environmental assessment
and/or
remediation is probable and the costs can be reasonably
estimated.
Litigation
and Self-Insured Risk Reserves
Basic estimates its reserves related to litigation and
self-insured risks based on the facts and circumstances specific
to the litigation and self-insured claims and its past
experience with similar claims in accordance with Statement of
Financial Accounting Standard No. 5 Accounting for
Contingencies. Basic maintains accruals in the
consolidated balance sheets to cover self-insurance retentions
(See note 7).
Comprehensive
Income
Basic follows the provisions of Statement of Financial
Accounting Standards No. 130, Reporting of
Comprehensive Income
(SFAS No. 130). SFAS No. 130
establishes standards for reporting and presentation of
comprehensive income and its components. SFAS No. 130
requires all items that are required to be recognized under
accounting standards as components of comprehensive income to be
reported in a financial statement that is displayed with the
same prominence as other financial statements. In accordance
with the provisions of SFAS No. 130, gains and losses
on cash flow hedging derivatives, to the extent effective, are
included in other comprehensive income (loss).
Reclassifications
Certain reclassifications of prior year financial statement
amounts have been made to conform to current year presentations.
Recent
Accounting Pronouncements
In September 2006, the FASB issued SFAS No. 157,
Fair Value Measurements (SFAS 157), which became
effective for financial assets and liabilities of the Company on
January 1, 2008 and non-financial assets and liabilities of
the Company on January 1, 2009. This standard defines fair
value, establishes a framework for
61
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
measuring fair value and expands disclosures about fair value
measurements. SFAS 157 does not require any new fair value
measurements but would apply to assets and liabilities that are
required to be recorded at fair value under other accounting
standards. The impact, if any, to the Company from the adoption
of SFAS 157 in 2009 will depend on the Companys
assets and liabilities at that time that are required to be
measured at fair value.
In February 2007, the FASB issued SFAS No. 159, The
Fair Value Option for Financial Assets and Financial Liabilities
(SFAS 159), which became effective for the Company on
January 1, 2008. This standard permits companies to choose
to measure many financial instruments and certain other items at
fair value and report unrealized gains and losses in earnings.
Such accounting is optional and is generally to be applied
instrument by instrument.
In December 2007, the FASB issued SFAS No. 141R,
Business Combinations (SFAS 141R), which becomes
effective for the Company on January 1, 2009. This
Statement requires an acquirer to recognize the assets acquired,
the liabilities assumed, and any noncontrolling interest in the
acquiree at the acquisition date be measured 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 a
liability in FASB Concepts Statement No. 6, Elements of
Financial Statements. Any acquisition related costs are to be
expensed instead of capitalized. The impact to the Company from
the adoption of SFAS 141R in 2009 will depend on
acquisitions at the time.
In December 2007, the FASB issued SFAS No. 160,
Noncontrolling Interests in Consolidated Financial Statements
(SFAS 160), which becomes effective for the Company on
January 1, 2009. This standard establishes accounting and
reporting standards for ownership interests in subsidiaries held
by parties other than the parent, the amount of consolidated net
income attributable to the parent and to the noncontrolling
interest, changes in a parents ownership interest and the
valuation of retained non-controlling equity investments when a
subsidiary is deconsolidated. The Statement also establishes
reporting requirements that provide sufficient disclosures that
clearly identify and distinguish between the interests of the
parent and the interests of the non-controlling owners. The
Company does not anticipate that this pronouncement will have a
material impact on its results of operations or consolidated
financial position.
In March 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging
Activities (SFAS 161), which became effective for the
Company on January 1, 2009. This standard improves
financial reporting for derivative instruments and hedging
activities requiring enhanced disclosures to expand on these
instruments effects on the Companys financial
position, financial performance and cash flows. The Company does
not anticipate that this pronouncement will have a material
impact on its results of operations or consolidated financial
position.
In April 2008, the FASB issued FSP SFAS No. 142-3,
Determination of Useful Life of Intangible Assets
(FSP 142-3). FSP 142-3 amends the factors that
should be considered in developing the renewal or extension
assumptions used to determine the useful life of a recognized
intangible asset under SFAS 142. FSP 142-3 is effective for
fiscal years beginning after December 15, 2008. Earlier
adoption is not permitted. We are currently evaluating the
potential impact the adoption of FSP 142-3 will have on our
consolidated financial statements.
In May 2008, the FASB issued SFAS No. 162,
The Hierarchy of Generally Accepted Accounting Principles
(SFAS 162), which becomes effective for the Company
60 days following the SECs approval of the Public
Company Accounting Oversight Board amendments to AU
Section 411, The Meaning of Present Fairly in Conformity
With Generally Accepted Accounting Principles. This standard
identifies the sources of accounting principles and the
framework for selecting the principles used in preparation of
financial statements that are presented in conformity with
generally accepted accounting principles (GAAP). The Company
does not anticipate that this pronouncement will have a material
impact on its results of operations or consolidated financial
position.
In June 2008, the FASB issued Staff Position
EITF 03-6-1
Determining Whether Instruments Granted in Share-Based
Payment Transactions are Participating Securities
(FSP
EITF 03-6-1).
FSP
EITF 03-6-1
addresses
62
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
whether instruments granted in share based payment transactions
are participating securities prior to vesting and, therefore,
need to be included in earnings allocation in computing earnings
per share (EPS) under the two-class method described
in paragraphs 60 and 61 of SFAS No. 128,
Earnings Per Share. FSP
EITF 03-6-1
is effective for financial statements issued for fiscal years
and interim periods beginning after December 15, 2008 and
requires retrospective adjustment for all comparable prior
periods presented. The Company does not anticipate that the
adoption of FSP
EITF 03-6-1
will have a material impact on its EPS disclosures.
In 2008, 2007 and 2006, 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)
|
|
|
LeBus Oil Field Services Co.
|
|
|
January 31, 2006
|
|
|
$
|
24,618
|
|
G&L Tool, Ltd.
|
|
|
February 28, 2006
|
|
|
|
58,514
|
|
Arkla Cementing, Inc.
|
|
|
March 27, 2006
|
|
|
|
5,012
|
|
Globe Well Service, Inc.
|
|
|
May 30, 2006
|
|
|
|
11,674
|
|
Hydro-Static Tubing Testers, Inc.
|
|
|
July 6, 2006
|
|
|
|
1,143
|
|
Hennessey Rental Tools, Inc.
|
|
|
August 1, 2006
|
|
|
|
8,205
|
|
Stimulation Services, LLC
|
|
|
August 1, 2006
|
|
|
|
4,500
|
|
Chaparral Service, Inc.
|
|
|
August 15, 2006
|
|
|
|
17,605
|
|
Reddline Services, LLC
|
|
|
August 24, 2006
|
|
|
|
1,900
|
|
Rebel Testers, Ltd.
|
|
|
September 14, 2006
|
|
|
|
2,397
|
|
|
|
|
|
|
|
|
|
|
Total 2006
|
|
|
|
|
|
$
|
135,568
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
$
|
21,110
|
|
Lackey Construction, LLC
|
|
|
January 30, 2008
|
|
|
|
4,328
|
|
B&S Disposal, LLC and B&S Equipment, Ltd
|
|
|
April 30, 2008
|
|
|
|
7,067
|
|
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
|
|
|
|
60,155
|
|
|
|
|
|
|
|
|
|
|
Total 2008
|
|
|
|
|
|
$
|
109,975
|
|
|
|
|
|
|
|
|
|
|
63
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The operations of each of the acquisitions listed above are
included in Basics statement of operations as of each
respective closing date. The acquisition of G&L Tool, Ltd.
in 2006, 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.
G&L
Tool, Ltd.
On February 28, 2006, Basic acquired substantially all of
the assets of G&L Tool, Ltd. (G&L) for
$58.5 million plus a contingent earn-out payment not to
exceed $21.0 million. The contingent earn-out payment will
be equal to fifty percent of the amount by which the annual
EBITDA (as defined in the purchase agreement) earned by the
G&L assets exceeds an annual targeted EBITDA. There is no
guarantee or assurance that the targeted EBITDA will be reached.
This acquisition provided a platform to expand into the rental
and fishing tool market. The cost of the G&L acquisition
was allocated $40.8 million to property and equipment,
$5.2 million to inventory, $12.5 million to goodwill,
all of which is expected to be deductible for tax purposes, and
$51,000 to non-compete agreements.
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
2-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 North Texas. JetStar will operate 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 5 years. |
|
(2) |
|
Approximately $25,955 is expected to be deductible for tax
purposes |
|
(3) |
|
Total balance was paid by Basic on the closing date |
64
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
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
2-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 5 years. |
|
(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 $60.2 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 preliminary estimated fair
value of the assets acquired and liabilities assumed at the date
of acquisition for Azurite (in thousands):
|
|
|
|
|
Property and Equipment
|
|
$
|
53,127
|
|
Intangible Assets(1)
|
|
|
1,862
|
|
Goodwill(2)
|
|
|
5,166
|
|
|
|
|
|
|
Total Assets Acquired
|
|
$
|
60,155
|
|
|
|
|
|
|
|
|
|
(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 deductible for tax purposes. |
Revisions to the fair values, which may be significant, will be
recorded by the Company as further adjustments to the purchase
price allocations.
65
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The following unaudited pro-forma results of operations have
been prepared as though the JetStar, Sledge, and Azurite
acquisitions had been completed on January 1, 2007. Pro
forma amounts are based on the purchase price allocations of the
significant acquisitions and are not necessarily indicative of
the results that may be reported in the future (in thousands,
except per share data).
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Revenues
|
|
$
|
1,040,160
|
|
|
$
|
933,697
|
|
Net income
|
|
$
|
70,680
|
|
|
$
|
92,064
|
|
Earnings per common share basic
|
|
$
|
1.73
|
|
|
$
|
2.28
|
|
Earnings per common share diluted
|
|
$
|
1.70
|
|
|
$
|
2.22
|
|
Basic does not believe the pro-forma effect of the remainder of
the acquisitions completed in 2007 or 2008 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, in accordance with EITF
No. 95-8,
Accounting for Contingent Consideration Paid to the
Shareholders of an Acquired Enterprise in Purchase Business
Combinations. 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
acquisitions of New Force Energy Services, Rolling Plains,
Premier Vacuum Services and G&L Tool. Payments related to
contingent earn-out agreements on Chaparral Services will be
reflected as compensation expense when paid or accrued.
The following presents a summary of acquisitions that have a
contingent earn-out arrangement in effect as of
December 31, 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum
|
|
|
|
|
|
|
|
|
|
exposure of
|
|
|
|
|
|
|
Termination date of
|
|
|
contingent
|
|
|
Amount paid or
|
|
|
|
contingent earn-out
|
|
|
earn-out
|
|
|
accrued through
|
|
Acquisition
|
|
arrangement
|
|
|
arrangement
|
|
|
December 31, 2008
|
|
|
Rolling Plains
|
|
|
April 30, 2009
|
|
|
|
|
*
|
|
$
|
6,732
|
|
Chaparral Services, Inc.
|
|
|
August 31, 2011
|
|
|
$
|
1,000
|
|
|
|
|
|
G&L Tool, Ltd.
|
|
|
February 28, 2011
|
|
|
|
21,000
|
|
|
|
5,093
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
22,000
|
|
|
$
|
11,825
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Basic will pay to the sellers an amount for each of the five
consecutive
12-month
periods beginning on May 1, 2004 equal to 50% of the amount
by which annual EBITDA exceeds an annual targeted EBITDA. There
is no guarantee or assurance that the targeted EBITDA will be
reached. |
66
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
4.
|
Property
and Equipment
|
Property and equipment consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Land
|
|
$
|
4,689
|
|
|
$
|
3,475
|
|
Buildings and improvements
|
|
|
29,913
|
|
|
|
21,655
|
|
Well service units and equipment
|
|
|
379,167
|
|
|
|
328,468
|
|
Fluid services equipment
|
|
|
136,814
|
|
|
|
91,830
|
|
Brine and fresh water stations
|
|
|
10,203
|
|
|
|
8,964
|
|
Frac/test tanks
|
|
|
128,845
|
|
|
|
85,649
|
|
Pressure pumping equipment
|
|
|
156,406
|
|
|
|
132,746
|
|
Construction equipment
|
|
|
22,483
|
|
|
|
28,798
|
|
Contract drilling equipment
|
|
|
60,340
|
|
|
|
59,231
|
|
Disposal facilities
|
|
|
49,878
|
|
|
|
27,790
|
|
Vehicles
|
|
|
41,129
|
|
|
|
36,440
|
|
Rental equipment
|
|
|
36,898
|
|
|
|
33,381
|
|
Aircraft
|
|
|
4,119
|
|
|
|
4,119
|
|
Other
|
|
|
21,758
|
|
|
|
15,858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,082,642
|
|
|
|
878,404
|
|
Less accumulated depreciation and amortization
|
|
|
341,763
|
|
|
|
241,480
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
$
|
740,879
|
|
|
$
|
636,924
|
|
|
|
|
|
|
|
|
|
|
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,
|
|
|
|
2008
|
|
|
2007
|
|
|
Light vehicles
|
|
$
|
30,141
|
|
|
$
|
25,768
|
|
Well service units and equipment
|
|
|
1,194
|
|
|
|
1,016
|
|
Fluid services equipment
|
|
|
56,010
|
|
|
|
34,668
|
|
Pressure pumping equipment
|
|
|
20,492
|
|
|
|
4,540
|
|
Construction equipment
|
|
|
3,679
|
|
|
|
4,440
|
|
Software
|
|
|
9,464
|
|
|
|
6,308
|
|
Other
|
|
|
705
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
121,685
|
|
|
|
76,740
|
|
Less accumulated amortization
|
|
|
37,370
|
|
|
|
22,660
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
84,315
|
|
|
$
|
54,080
|
|
|
|
|
|
|
|
|
|
|
Amortization of assets held under capital leases of
approximately $14.7 million, $8.9 million and
$5.3 million for the years ended December 31, 2008,
2007 and 2006, respectively, is included in depreciation and
amortization expense in the consolidated statements of
operations.
67
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Long-term debt consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2007 Credit Facility
|
|
$
|
180,000
|
|
|
$
|
150,000
|
|
7.125% Senior Notes
|
|
|
225,000
|
|
|
|
225,000
|
|
Capital leases and other notes
|
|
|
75,323
|
|
|
|
48,719
|
|
|
|
|
|
|
|
|
|
|
|
|
|
480,323
|
|
|
|
423,719
|
|
Less current portion
|
|
|
26,063
|
|
|
|
17,413
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
454,260
|
|
|
$
|
406,306
|
|
|
|
|
|
|
|
|
|
|
Senior
Notes
On April 12, 2006, the Company issued $225.0 million
of 7.125% Senior Notes due April 2016 in a private
placement. Proceeds from the sale of the Senior Notes were used
to retire the outstanding balance on the Companys
$90.0 million Term B Loan and to pay down approximately
$96.0 million under the revolving credit facility, which
amounts may be reborrowed to fund future acquisitions or for
general corporate purposes. Interest payments on the Senior
Notes are due semi-annually, on April 15 and October 15.
The Senior Notes are unsecured. Under the terms of the sale of
the Senior Notes, the Company was required to take appropriate
steps to offer to exchange other Senior Notes with the same
terms that have been registered with the Securities and Exchange
Commission for the private placement Senior Notes. The Company
completed the exchange offer for all of the Senior Notes on
October 16, 2006.
The Senior Notes are redeemable at the option of the Company on
or after April 15, 2011 at the specified redemption price
as described in the Indenture. Prior to April 15, 2011, the
Company may redeem 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 Indenture. Prior to April 15, 2009, the Company may
redeem up to 35% of the Senior Notes with the proceeds of
certain equity offerings at a redemption price equal to 107.125%
of the principal amount of the Senior Notes redeemed, plus
accrued and unpaid interest to the date of redemption. This
redemption must occur less than 90 days after the date of
the closing of any such equity offering.
Following a change of control, as defined in the Indenture, the
Company will be required to make an offer to repurchase all or
any portion of the Senior Notes at a purchase price of 101% of
the principal amount, plus accrued and unpaid interest to the
date of repurchase.
Pursuant to the Indenture, the Company is subject to covenants
that limit the ability of the Company and its restricted
subsidiaries to, among other things: incur additional
indebtedness, pay dividends, make certain other payments
repurchase or redeem capital stock, make certain investments,
incur liens, enter into certain types of transactions with
affiliates, limit dividends or other payments by restricted
subsidiaries, and sell assets or consolidate or merge with or
into other companies. These limitations are subject to a number
of important qualifications and exceptions set forth in the
Indenture. The Company was in compliance with the restrictive
covenants at December 31, 2008.
As part of the issuance of the above-mentioned Senior Notes, the
Company incurred debt issuance costs of approximately
$4.6 million, which are being amortized to interest expense
using the effective interest method over the term of the Senior
Notes.
The Senior Notes are jointly and severally guaranteed by the
Company and all of its restricted subsidiaries. Basic Energy
Services, Inc., the ultimate parent company, does not have any
independent operating assets or operations. Subsidiaries other
than the restricted subsidiaries that are guarantors are minor.
68
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
2007
Credit Facility
On February 6, 2007, Basic entered into a $225 million
Fourth Amended and Restated Credit Agreement with a syndicate of
lenders (the 2007 Credit Facility), which refinanced
all of the existing credit facilities. Under the 2007 Credit
Facility, Basic Energy Services, Inc. is the sole borrower and
each of its subsidiaries is a subsidiary guarantor. The 2007
Credit Facility provides for a $225 million revolving line
of credit (Revolver). The 2007 Credit Facility
includes provisions allowing us to request an increase in
commitments of up to $100 million aggregate principal
amount subject to meeting certain tangible value requirements
and subject to lender participation at the time of the request.
Additionally, the 2007 Credit Facility permits us to make
greater expenditures for acquisitions, capital expenditures and
capital leases and to incur greater purchase money obligations,
acquisition indebtedness and general unsecured indebtedness. The
commitment under the Revolver provides for (1) the
borrowing of funds, (2) the issuance of up to
$30 million of letters of credit and
(3) $2.5 million of swing-line loans. All of the
outstanding amounts under the Revolver are due and payable on
December 15, 2010. The 2007 Credit Facility is secured by
substantially all of our tangible and intangible assets. Basic
incurred approximately $0.7 million in debt issuance costs
in connection with the 2007 Credit Facility.
At Basics option, borrowings under the Revolver bears
interest at either (1) the Alternative Base
Rate (i.e., the higher of the banks prime rate or
the federal funds rate plus .50% per year) plus a margin ranging
from 0.25% to 0.5% or (2) an Adjusted LIBOR
Rate (equal to (a) the London Interbank Offered Rate
(the LIBOR rate) as determined by the Administrative
Agent in effect for such interest period divided by (b) one
minus the Statutory Reserves, if any, for such borrowing for
such interest period) plus a margin ranging from 1.25% to 1.5%.
The margins vary depending on our leverage ratio. Fees on the
letters of credit are due quarterly on the outstanding amount of
the letters of credit at a rate ranging from 1.25% to 1.5% for
participation fees and 0.125% for fronting fees. A commitment
fee is due quarterly on the available borrowings under the
Revolver at a rate of 0.375%.
At December 31, 2008, Basic, under its Revolver, had
outstanding $180 million of borrowings and
$16.2 million of letters of credit and no amounts
outstanding in swing-line loans. At December 31, 2008,
Basic had availability under its Revolver of $28.8 million.
Pursuant to the 2007 Credit Facility, Basic must apply proceeds
from certain specified events to reduce principal outstanding
borrowings under the Revolver, from (a) assets sales
greater than $2.0 million individually or $7.5 million
in the aggregate on an annual basis, (b) 100% of the net
cash proceeds from any debt issuance, including certain
permitted unsecured senior or senior subordinated debt, but
excluding certain other permitted debt issuances and
(c) 50% of the net cash proceeds from any equity issuance
(including equity issued upon the exercise of any warrant or
option).
The 2007 Credit Facility contains various restrictive covenants
and compliance requirements, which include (a) limitations
on the incurrence of additional indebtedness,
(b) restrictions on mergers, sales or transfer of assets
without the lenders consent (c) limitations on
dividends and distributions and (d) various financial
covenants, including (1) a maximum leverage ratio of 3.25
to 1.00, and (2) a minimum interest coverage ratio of 3.00
to 1.00. At December 31, 2008, Basic was in compliance with
its covenants.
Other
Debt
Basic has a variety of other capital leases and notes payable
outstanding that are generally customary in its business. None
of these debt instruments are material individually or in the
aggregate.
69
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
As of December 31, 2008 the aggregate maturities of debt,
including capital leases, for the next five years and thereafter
are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Debt
|
|
|
Capital Leases
|
|
|
2009
|
|
$
|
|
|
|
$
|
26,063
|
|
2010
|
|
|
180,000
|
|
|
|
21,985
|
|
2011
|
|
|
|
|
|
|
14,307
|
|
2012
|
|
|
|
|
|
|
10,450
|
|
2013
|
|
|
|
|
|
|
2,518
|
|
Thereafter
|
|
|
225,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
405,000
|
|
|
$
|
75,323
|
|
|
|
|
|
|
|
|
|
|
Basics interest expense consisted of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Cash payments for interest
|
|
$
|
24,484
|
|
|
$
|
25,594
|
|
|
$
|
12,587
|
|
Commitment and other fees paid
|
|
|
211
|
|
|
|
249
|
|
|
|
566
|
|
Amortization of debt issuance costs
|
|
|
968
|
|
|
|
962
|
|
|
|
804
|
|
Accrued interest
|
|
|
1,157
|
|
|
|
540
|
|
|
|
3,384
|
|
Other
|
|
|
(54
|
)
|
|
|
71
|
|
|
|
125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
26,766
|
|
|
$
|
27,416
|
|
|
$
|
17,466
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Losses
on Extinguishment of Debt
In February 2007 and April 2006, Basic recognized a loss on the
early extinguishment of debt. In February 2007, Basic wrote off
unamortized debt issuance costs of approximately
$0.2 million, which related to the 2005 credit facility. In
April 2006, Basic wrote off unamortized debt issuance costs of
approximately $2.7 million, which related to the prepayment
of the Term B Loan.
Income tax expense consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
20,533
|
|
|
$
|
33,157
|
|
|
$
|
50,499
|
|
State
|
|
|
4,436
|
|
|
|
5,160
|
|
|
|
1,632
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
24,969
|
|
|
$
|
38,317
|
|
|
$
|
52,131
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
28,792
|
|
|
$
|
14,207
|
|
|
$
|
3,594
|
|
State
|
|
|
1,373
|
|
|
|
242
|
|
|
|
(983
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
30,165
|
|
|
$
|
14,449
|
|
|
$
|
2,611
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense
|
|
$
|
55,134
|
|
|
$
|
52,766
|
|
|
$
|
54,742
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
70
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Basic paid Federal income taxes of $22.0 million during
2008, $44.1 million during 2007 and $40.2 million
during 2006.
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,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Statutory federal income tax
|
|
$
|
43,180
|
|
|
$
|
49,174
|
|
|
$
|
53,750
|
|
Meals and entertainment
|
|
|
542
|
|
|
|
532
|
|
|
|
430
|
|
State taxes, net of federal benefit
|
|
|
4,726
|
|
|
|
4,062
|
|
|
|
778
|
|
Impairment of non-deductible goodwill
|
|
|
7,883
|
|
|
|
|
|
|
|
|
|
Changes in estimates and other
|
|
|
(1,197
|
)
|
|
|
(1,002
|
)
|
|
|
(216
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
55,134
|
|
|
$
|
52,766
|
|
|
$
|
54,742
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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,
|
|
|
|
2008
|
|
|
2007
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Receivables allowance
|
|
$
|
2,151
|
|
|
$
|
2,314
|
|
Inventory
|
|
|
42
|
|
|
|
41
|
|
Asset retirement obligation
|
|
|
331
|
|
|
|
283
|
|
Accrued liabilities
|
|
|
8,696
|
|
|
|
8,044
|
|
Operating loss carryforward
|
|
|
788
|
|
|
|
1,100
|
|
Deferred compensation
|
|
|
3,497
|
|
|
|
2,648
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
15,505
|
|
|
|
14,430
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Property and equipment
|
|
|
(135,354
|
)
|
|
|
(104,476
|
)
|
Goodwill and intangibles
|
|
|
(18,541
|
)
|
|
|
(13,846
|
)
|
Prepaid expenses
|
|
|
(120
|
)
|
|
|
(119
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
(154,015
|
)
|
|
|
(118,441
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
(138,510
|
)
|
|
$
|
(104,011
|
)
|
|
|
|
|
|
|
|
|
|
Recognized as:
|
|
|
|
|
|
|
|
|
Deferred tax assets current
|
|
|
11,081
|
|
|
|
10,593
|
|
Deferred tax liabilities non-current
|
|
|
(149,591
|
)
|
|
|
(114,604
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
(138,510
|
)
|
|
$
|
(104,011
|
)
|
|
|
|
|
|
|
|
|
|
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, 2008 or 2007.
Effective January 1, 2007, Basic adopted the provisions of
the FASB issued Interpretation No. 48
(FIN 48), Accounting for Uncertainty in
Income Taxes. Our adoption of FIN 48 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 2008. Basic files federal income tax
returns and state income tax returns in Texas and other state
tax jurisdictions. In
71
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
general, the Companys tax returns for fiscal years after
2003 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, 2008, 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, 2008, the future minimum lease payments
under non-cancelable operating leases are as follows (in
thousands):
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
2009
|
|
$
|
4,543
|
|
2010
|
|
|
4,257
|
|
2011
|
|
|
3,588
|
|
2012
|
|
|
2,550
|
|
2013
|
|
|
2,164
|
|
Thereafter
|
|
|
5,220
|
|
Rent expense approximated $20.3 million,
$17.4 million, and $13.9 million for 2008, 2007 and
2006, respectively.
72
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, 2009, amended
February 27, 2008, Mr. Huseman will be entitled to an
annual salary of $550,000. Under this employment agreement,
Mr. Huseman is eligible from time to time to receive grants
of stock options and other long-term equity incentive
compensation under our Amended and Restated 2003 Incentive Plan.
In addition, upon a qualified termination of employment,
Mr. Huseman would be entitled to three times his base
salary plus his current annual incentive target bonus for the
full year in which the termination of employment occurred. If
employment is terminated for certain reasons within the six
months preceding or the twelve months following the change of
control of our Company, Mr. Huseman would be entitled to a
lump sum severance payment equal to three times the sum of his
base salary plus the higher of (i) his current incentive
target bonus for the full year in which the termination of
employment occurred or (ii) the highest annual incentive
bonus received by him for any of the last three fiscal years.
Basic has entered into employment agreements with various other
executive officers of Basic that range in term up through
December 2009. Under these agreements, if the officers
employment is terminated for certain reasons, he would be
entitled to a lump sum severance payment equal to amounts
ranging from 1.5 times to 0.75 times the sum of his base salary
plus his current annual incentive target bonus for the full year
in which the termination occurred . If employment is terminated
for certain reasons within the six months preceding or the
twelve months following the chance of control of our Company, he
would be entitled to a lump sum severance payment equal to three
times the sum of his base salary plus the higher of (i) his
current incentive target bonus for the full year in 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 $375,000 and $180,000, 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 2008 Basic classified the workers compensation
self-insured risk reserve between short-term and long-term, with
$4.0 million being allocated to short-term and
$5.0 million being allocated to long-term.
At December 31, 2008 and December 31, 2007,
self-insured risk accruals totaled approximately
$15.4 million, net of $992,000 receivable for medical and
dental coverage, and $15.1 million, net of $0 receivable
for medical and dental coverage, respectively.
Common
Stock
At December 31, 2008 and 2007, Basic had
80,000,000 shares of Basics common stock, par value
$.01 per share, authorized.
In February 2002, a group of related investors purchased a total
of 3,000,000 shares of Basics common stock at a
purchase price of $4 per share, for a total purchase price of
$12 million. As part of the purchase, 600,000 common
73
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
stock warrants were issued in connection with this transaction,
the fair value of which was approximately $1.2 million
(calculated using an option valuation model). The warrants
allowed the holder to purchase 600,000 shares of
Basics common stock at $4 per share. The warrants were
exercisable in whole or in part after June 30, 2002 and
prior to February 13, 2007.
In June of 2002 Basic granted 3,750,000 common stock warrants to
acquire a total of 3,750,000 shares of common stock at a
price of $4 per share, exercisable in whole or in part from
June 30, 2002 through June 30, 2007.
In February 2004, Basic granted certain officers and directors
837,500 restricted shares of common stock. The shares vest 25%
per year for four years from the award date and are subject to
other vesting and forfeiture provisions. The estimated fair
value of the restricted shares was $5.8 million at the date
of the grant. This amount is being charged to expense over the
respective vesting period and totaled approximately $182,000,
$1.2 million and $1.3 million for the years ended
December 31, 2008, 2007 and 2006.
In December 2005, Basic issued 5,000,000 shares of common
stock during the Companys Initial Public Offering to a
group of investors for $100 million or $20 per share. After
deducting fees, this resulted in net proceeds to Basic totaling
approximately $91.5 million.
On October 5, 2006, all outstanding warrants were exercised
to purchase an aggregate of 4,350,000 shares of
Basics common stock. In connection with the exercise of
the warrants, Basic received an aggregate of $17.4 million
from the Holders in satisfaction of the exercise price of the
warrants (representing an exercise price of $4.00 per share of
Basics common stock acquired).
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.
During the year ended 2008, Basic issued 138,675 shares of
common stock from treasury stock for the exercise of stock
options. Also, Basic issued 447,255 shares of newly-issued
common 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. As of December 31, 2008, Basic
repurchased 897,558 shares at a total price of
$8.8 million (an average of $9.82 per share), inclusive of
commissions and fees.
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 52,877 and
20,388 shares through net share settlements during 2008 and
2007, respectively.
74
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Preferred
Stock
At December 31, 2008 and 2007, Basic had
5,000,000 shares of preferred stock, par value $.01 per
share, authorized, of which none was designated, issued or
outstanding.
|
|
9.
|
Stockholders
Agreement
|
Basic has a Stockholders Agreement, as amended on
April 2, 2004 (Stockholders Agreement),
which provides for rights relating to the shares of our
stockholders and certain corporate governance matters.
The Stockholders Agreement provides for participation
rights of the other stockholders to require affiliates of DLJ
Merchant Banking to offer to include a specified percentage of
their shares whenever affiliates of DLJ Merchant Banking sell
their shares for value 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 affiliated of DLJ Merchant Banking to require the
other stockholders who are a party to this agreement to sell a
portion of their shares of common stock and common stock
equivalents in the sale in any proposed to sale of shares of
common stock and common stock equivalents representing more than
50% of such equity interest held by the affiliates of DLJ
Merchant Banking to a person or persons who are not an affiliate
of them.
The Stockholders Agreement also 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
April 22, 2005) (the Plan), which provides for
granting of incentive awards in the form of stock options,
restricted stock, performance awards, bonus shares, phantom
shares, cash awards and other stock-based awards to officers,
employees, directors and consultants of Basic. The Plan assumed
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 5,000,000 shares. Of
these shares, approximately 816,000 shares are available
for grant as of December 31, 2008. The Plan is administered
by the Plan committee, and in the absence of a Plan committee,
by the Board of Directors, which determines the awards and the
associated terms of the awards and interprets its provisions and
adopts policies for implementing the Plan. The number of shares
authorized under the Plan and the number of shares subject to an
award under the Plan will be adjusted for stock splits, stock
dividends, recapitalizations, mergers and other changes
affecting the capital stock of Basic.
On March 15, 2006, the Board of Directors granted various
employees and directors options to purchase 418,000 shares
of common stock of Basic at an exercise price of $26.84 per
share. All of the 418,000 options granted in 2006 vest over a
five-year period and expire 10 years from the date they
were granted. These option awards were granted with an exercise
price equal to the market price of the Companys stock at
the date of grant. 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 10 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
2008.
The fair value of each option award is estimated on the date of
grant using the Black-Scholes-Merton option-pricing model that
uses the subjective assumptions noted in the following table.
Since the Company has only been public since December 2005,
expected volatility for options granted during 2006 is a
volatility based upon a peer group. 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 and 2006, the Company
used the simplified method to calculate the expected term. For
options granted in 2007 and 2006, the risk-free rate for periods
within the
75
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
contractual life of the options is based on the
U.S. Treasury yield curve in effect at the time of grant.
The estimates involve inherent uncertainties and the application
of management judgment. In addition, we are required to estimate
the expected forfeiture rate and only recognize expense for
those options expected to vest. During the years ended
December 31, 2008, 2007 and 2006, compensation expense
related to share-based arrangements was approximately
$4.1 million, $3.9 million and $3.4 million,
respectively. For compensation expense recognized during the
years ended December 31, 2008, 2007 and 2006 Basic
recognized a tax benefit of approximately $1.9 million,
$1.5 million and $1.2 million, respectively.
The fair value of each option award accounted for under
SFAS No. 123R is estimated on the date of grant using
the Black-Scholes-Merton option-pricing model that uses the
assumptions noted in the following table:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Risk-free interest rate
|
|
|
4.5
|
%
|
|
|
4.7
|
%
|
Expected term
|
|
|
6.65
|
|
|
|
6.65
|
|
Expected volatility
|
|
|
45.3
|
%
|
|
|
47.0
|
%
|
Expected dividend yield
|
|
|
|
|
|
|
|
|
Options granted under the Plan expire 10 years from the
date they are granted, and generally vest over a
three-to-five
year service period.
The following table reflects the summary of stock options
outstanding at December 31, 2008 and the changes during the
twelve months then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
Average
|
|
|
Aggregate
|
|
|
|
Number of
|
|
|
Average
|
|
|
Remaining
|
|
|
Instrinsic
|
|
|
|
Options
|
|
|
Exercise
|
|
|
Contractual
|
|
|
Value
|
|
|
|
Granted
|
|
|
Price
|
|
|
Term (Years)
|
|
|
(000s)
|
|
|
Non-statutory stock options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, beginning of period
|
|
|
2,257,355
|
|
|
$
|
9.58
|
|
|
|
|
|
|
|
|
|
Options granted
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Options forfeited
|
|
|
(53,750
|
)
|
|
$
|
15.29
|
|
|
|
|
|
|
|
|
|
Options exercised
|
|
|
(585,930
|
)
|
|
$
|
4.65
|
|
|
|
|
|
|
|
|
|
Options expired
|
|
|
(9,000
|
)
|
|
$
|
21.32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period
|
|
|
1,608,675
|
|
|
$
|
11.11
|
|
|
|
5.76
|
|
|
$
|
8,714
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, end of period
|
|
|
957,925
|
|
|
$
|
7.44
|
|
|
|
5.03
|
|
|
$
|
6,782
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested or expected to vest, end of period
|
|
|
1,584,425
|
|
|
$
|
10.88
|
|
|
|
5.73
|
|
|
$
|
8,714
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted-average grant date fair value of share options
granted during the years ended December 31, 2007 and 2006
was $11.85 and $14.47, respectively. The total intrinsic value
of share options exercised during the years ended
December 31, 2008, 2007 and 2006 was approximately
$12.2 million, $3.6 million and $7.1 million,
respectively.
On March 11, 2008, the Compensation Committee of our Board
of Directors approved grants of performance-based stock awards
to certain members of management. The performance-based awards
consist of the Company achieving certain earnings per share
growth targets and certain 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. The number of shares to be issued will
range from 0% to 150% of the target number of shares of 101,500
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, 2010.
76
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
A summary of the status of the Companys non-vested share
grants at December 31, 2008 and changes during the year
ended December 31, 2008 is presented in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
Number of
|
|
|
Grant Date Fair
|
|
Nonvested Shares
|
|
Shares
|
|
|
Value Per Share
|
|
|
Nonvested at beginning of period
|
|
|
378,000
|
|
|
$
|
15.74
|
|
Granted during period
|
|
|
456,975
|
|
|
|
20.85
|
|
Vested during period
|
|
|
(178,300
|
)
|
|
|
7.90
|
|
Forfeited during period
|
|
|
(57,350
|
)
|
|
|
21.55
|
|
|
|
|
|
|
|
|
|
|
Nonvested at end of period
|
|
|
599,325
|
|
|
$
|
21.41
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2008, there was $11.9 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 2.65 years. The total fair value of share-based
awards vested during the years ended December 31, 2008,
2007 and 2006 was approximately $10.3 million,
$11.3 million and $12.3 million, respectively. The
actual tax benefit realized for the tax deduction from vested
share-based awards was $1.5 million, $1.6 million and
$2.1 million, respectively for the years ended
December 31, 2008, 2007 and 2006.
Cash received from share option exercises under the incentive
plan was approximately $2.7 million, $975,000 and $674,000
for the years ended December 31, 2008, 2007 and 2006,
respectively. The actual tax benefit realized for the tax
deductions from options exercised was $5.6 million,
$1.4 million and $4.0 million, respectively, for the
years ended December 31, 2008, 2007 and 2006.
The Company has a history of issuing Treasury and newly-issued
shares to satisfy share option exercises.
|
|
11.
|
Related
Party Transactions
|
Basic had receivables from employees of approximately $148,000
and $91,000 as of December 31, 2008 and December 31,
2007, 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
$4.1 million, $3.0 million, and $2.5 million in
2008, 2007 and 2006, respectively.
|
|
13.
|
Deferred
Compensation Plan
|
In April 2005, Basic established a deferred compensation plan
for certain employees. Participants may defer up to 50% of their
salary and 100% of any cash bonuses. Basic makes matching
contributions of 100% of the first 3% of the participants
deferred pay and 50% of the next 2% of the participants
deferred pay to a maximum match of $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 $563,000 gain
in 2008 and a $216,000, and $199,000 expense in 2007 and 2006,
respectively.
77
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Basic presents earnings per share information in accordance with
the provisions of Statement of Financial Accounting Standards
No. 128, Earnings per Share
(SFAS No. 128). Under
SFAS No. 128, basic earnings per common share are
determined by dividing net earnings applicable to common stock
by the weighted average number of common shares actually
outstanding during the year. Diluted earnings per common share
is based on the increased number of shares that would be
outstanding assuming conversion 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,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Numerator (both basic and diluted):
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
68,238
|
|
|
$
|
87,733
|
|
|
$
|
98,830
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for basic earnings per share
|
|
|
40,754,890
|
|
|
|
40,013,054
|
|
|
|
34,471,771
|
|
Stock options
|
|
|
682,958
|
|
|
|
831,026
|
|
|
|
1,054,040
|
|
Unvested restricted stock
|
|
|
225,842
|
|
|
|
268,324
|
|
|
|
244,153
|
|
Common stock warrants
|
|
|
|
|
|
|
|
|
|
|
2,823,029
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted earnings per share
|
|
|
41,663,690
|
|
|
|
41,112,404
|
|
|
|
38,592,993
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
1.67
|
|
|
$
|
2.19
|
|
|
$
|
2.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
1.64
|
|
|
$
|
2.13
|
|
|
$
|
2.56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The number of antidilutive shares at December 31, 2008,
2007 and 2006 was 413,000, 442,000 and 401,000, 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.
The new 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. These changes reflect Basics operating
focus in compliance with SFAS No. 131,
Disclosures about Segments of an Enterprise and Related
Information. The following is a description of the
segments:
Well Servicing: This business segment
encompasses a full range of services performed with a mobile
well servicing rig, including the installation and removal of
downhole equipment and elimination of obstructions in the well
bore to facilitate the flow of oil and gas. These services are
performed to establish, maintain and improve production
throughout the productive life of an oil and gas well and to
plug and abandon a well at the end of its productive life. Basic
well servicing equipment and capabilities are essential to
facilitate most other services performed on a well.
Fluid Services: This segment utilizes a fleet
of trucks and related assets, including specialized tank trucks,
storage tanks, water wells, disposal facilities and related
equipment. Basic employs these assets to provide, transport,
store and dispose of a variety of fluids. These services are
required in most workover, completion and
78
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
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 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.
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, 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
|
|
Year ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
323,755
|
|
|
$
|
245,011
|
|
|
$
|
154,412
|
|
|
$
|
6,970
|
|
|
$
|
|
|
|
$
|
730,148
|
|
Direct operating costs
|
|
|
(178,028
|
)
|
|
|
(153,445
|
)
|
|
|
(74,981
|
)
|
|
|
(8,400
|
)
|
|
|
|
|
|
|
(414,854
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profits
|
|
$
|
145,727
|
|
|
$
|
91,566
|
|
|
$
|
79,431
|
|
|
$
|
(1,430
|
)
|
|
$
|
|
|
|
$
|
315,294
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$
|
26,992
|
|
|
$
|
19,692
|
|
|
$
|
11,070
|
|
|
$
|
1,938
|
|
|
$
|
2,395
|
|
|
$
|
62,087
|
|
Capital expenditures, (excluding acquisitions)
|
|
$
|
29,677
|
|
|
$
|
33,167
|
|
|
$
|
18,646
|
|
|
$
|
19,050
|
|
|
$
|
4,034
|
|
|
$
|
104,574
|
|
Identifiable assets
|
|
$
|
226,566
|
|
|
$
|
193,927
|
|
|
$
|
129,471
|
|
|
$
|
17,112
|
|
|
$
|
229,184
|
|
|
$
|
796,260
|
|
79
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
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,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Segment profits
|
|
$
|
392,291
|
|
|
$
|
358,256
|
|
|
$
|
315,294
|
|
General and administrative expenses
|
|
|
(115,319
|
)
|
|
|
(99,042
|
)
|
|
|
(81,318
|
)
|
Depreciation and amortization
|
|
|
(118,607
|
)
|
|
|
(93,048
|
)
|
|
|
(62,087
|
)
|
Gain (loss) on disposal of assets
|
|
|
(76
|
)
|
|
|
(477
|
)
|
|
|
(277
|
)
|
Goodwill Impairment (Contract drilling segment)
|
|
|
(22,522
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
135,767
|
|
|
$
|
165,689
|
|
|
$
|
171,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accrued expenses are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Compensation related
|
|
$
|
19,832
|
|
|
$
|
16,790
|
|
Workers compensation self-insured risk reserve
|
|
|
4,248
|
|
|
|
9,326
|
|
Health self-insured risk reserve
|
|
|
6,690
|
|
|
|
6,054
|
|
Accrual for receipts
|
|
|
4,976
|
|
|
|
3,955
|
|
Authority for expenditure accrual
|
|
|
543
|
|
|
|
211
|
|
Ad valorem taxes
|
|
|
137
|
|
|
|
73
|
|
Sales tax
|
|
|
588
|
|
|
|
1,140
|
|
Insurance obligations
|
|
|
2,474
|
|
|
|
995
|
|
Purchase order accrual
|
|
|
38
|
|
|
|
45
|
|
Professional fee accrual
|
|
|
185
|
|
|
|
424
|
|
Contingent earnout obligation
|
|
|
1,438
|
|
|
|
1,158
|
|
Retainers
|
|
|
|
|
|
|
172
|
|
Fuel accrual
|
|
|
897
|
|
|
|
1,692
|
|
Accrued interest
|
|
|
5,083
|
|
|
|
3,926
|
|
Contingent liability
|
|
|
|
|
|
|
1,296
|
|
Franchise Tax Payable
|
|
|
|
|
|
|
3,704
|
|
Other
|
|
|
10
|
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
47,139
|
|
|
$
|
51,003
|
|
|
|
|
|
|
|
|
|
|
80
BASIC
ENERGY SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
17.
|
Supplemental
Schedule of Cash Flow Information
|
The following table reflects non-cash financing and investing
activity during:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Capital leases issued for equipment
|
|
$
|
50,730
|
|
|
$
|
26,814
|
|
|
$
|
26,420
|
|
Value of shares that may be issued
|
|
$
|
|
|
|
$
|
2,194
|
|
|
$
|
|
|
Contingent earnout accrual
|
|
$
|
183
|
|
|
$
|
1,032
|
|
|
$
|
2,256
|
|
Asset retirement obligation additions
|
|
$
|
143
|
|
|
$
|
101
|
|
|
$
|
767
|
|
Value of common stock issued in business combinations
|
|
$
|
|
|
|
$
|
51,193
|
|
|
$
|
|
|
Basic paid income taxes of approximately $27.2 million,
$44.1 million and $43.2 million during the years ended
December 31, 2008, 2007 and 2006, respectively.
81
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, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Year
|
|
|
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
|
|
Year ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
198,930
|
|
|
$
|
223,256
|
|
|
$
|
229,232
|
|
|
$
|
225,755
|
|
|
$
|
877,173
|
|
Segment profits
|
|
$
|
82,785
|
|
|
$
|
91,235
|
|
|
$
|
94,280
|
|
|
$
|
89,956
|
|
|
$
|
358,256
|
|
Income from continuing operations
|
|
$
|
22,073
|
|
|
$
|
21,692
|
|
|
$
|
24,426
|
|
|
$
|
19,541
|
|
|
$
|
87,733
|
|
Net income available to common stockholders
|
|
$
|
22,073
|
|
|
$
|
21,692
|
|
|
$
|
24,426
|
|
|
$
|
19,541
|
|
|
$
|
87,733
|
|
Basic earnings per share of common stock(a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
0.57
|
|
|
$
|
0.54
|
|
|
$
|
0.60
|
|
|
$
|
0.48
|
|
|
$
|
2.19
|
|
Diluted earnings per share of common stock(a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
0.56
|
|
|
$
|
0.52
|
|
|
$
|
0.59
|
|
|
$
|
0.47
|
|
|
$
|
2.13
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
38,521
|
|
|
|
40,493
|
|
|
|
40,516
|
|
|
|
40,517
|
|
|
|
40,013
|
|
Diluted
|
|
|
39,661
|
|
|
|
41,621
|
|
|
|
41,591
|
|
|
|
41,551
|
|
|
|
41,112
|
|
|
|
|
(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. |
On October 13, 2008, Basic announced that its Board of
Directors had authorized the repurchase of up to
$50.0 million of Basics common shares from time to
time in open market or private transactions, at Basics
discretion. From January 1, 2009 through February 27,
2009, Basic has repurchased 622,700 common shares at a total
price of $4.9 million (an average of $7.92 per share).
82
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, 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
|
|
Year Ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Bad Debt
|
|
$
|
2,775
|
|
|
$
|
1,909
|
|
|
$
|
|
|
|
$
|
(721
|
)
|
|
$
|
3,963
|
|
|
|
|
(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 |
83
|
|
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, 2008, 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 and Other Key Employees
in Item 4, and Items 11 through 14 of Part III of
this Report is incorporated by reference from our definitive
proxy statement involving the election of directors and the
approval of independent auditors, which is to be filed pursuant
to Regulation 14A within 120 days after the end of our
fiscal year ended December 31, 2008.
84
PART IV
|
|
ITEM 15.
|
EXHIBITS AND
FINANCIAL STATEMENT SCHEDULES
|
(a) Financial Statements, Schedules and Exhibits
(1) Financial Statements Basic Energy Services,
Inc. and Subsidiaries:
The Financial Statements listed in the Index to Consolidated
Financial Statements are filed as part of this report on
Form 10-K
(see Part II, Item 8, Financial Statements and
Supplementary Data).
(2) Financial Statement Schedules
With the exception of Schedule II Valuation and
Qualifying Accounts, all other consolidated financial statement
schedules have been omitted because they are not required, are
not applicable, or the required information has been included
elsewhere within this
Form 10-K.
(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. (the
Company), 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 3.1 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on November 4, 2005)
|
|
4
|
.2*
|
|
Indenture dated April 12, 2006, among Basic Energy
Services, Inc., the guarantors party thereto, and The Bank of
New York Trust Company, N.A., as trustee. (Incorporated by
reference to Exhibit 4.1 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on April 13, 2006)
|
|
4
|
.3*
|
|
Form of 7.125% Senior Note due 2016. (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 Supplement 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
|
85
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
10
|
.1*
|
|
Form of Indemnification Agreement. (Incorporated by reference to
Exhibit 10.1 of the Companys Registration Statement
on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.2*
|
|
Second Amended and Restated Stockholders Agreement dated
as of April 2, 2004 among the Company and the stockholders
listed therein. (Incorporated by reference to Exhibit 10.7
of the Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on August 12, 2005)
|
|
10
|
.3*
|
|
Stock Purchase Agreement dated as of September 18, 2003, as
amended on October 1, 2003, among the Company, FESCO
Holdings, Inc. and the sellers named therein. (Incorporated by
reference to Exhibit 10.8 of the Companys
Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on August 12, 2005)
|
|
10
|
.4*
|
|
Asset Purchase Agreement dated as of August 14, 2003 among
the Company and PWI, Inc. (Incorporated by reference to
Exhibit 10.9 of the Companys Registration Statement
on
Form S-1
(SEC File
No. 333-127517),
filed on August 12, 2005)
|
|
10
|
.5*
|
|
Fourth Amended and Restated Credit Agreement dated as of
October 3, 2003, amended and restated as of
February 6, 2007, among Basic Energy Services, Inc., the
subsidiary guarantors party thereto, Bank of America, N.A., as
syndication agent, Capital One, National Association, as
documentation agent, BNP Paribas, as documentation agent, UBS
AG, Stamford Branch, as issuing bank, administrative agent and
collateral agent, and the lenders party thereto. (Incorporated
by reference to Exhibit 10.1 to the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on February 12, 2007)
|
|
10
|
.6*
|
|
Third Amended and Restated 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 May 29, 2008)
|
|
10
|
.7*
|
|
Form of Non-Qualified Option Grant Agreement (Executive
Officer Pre-March 1, 2005). (Incorporated by
reference to Exhibit 10.12 of the Companys
Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.8*
|
|
Form of Non-Qualified Option Grant Agreement (Executive
Officer Post-March 1, 2005). (Incorporated by
reference to Exhibit 10.13 of the Companys
Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.9*
|
|
Form of Non-Qualified Option Grant Agreement (Non-Employee
Director Pre-March 1, 2005). (Incorporated by
reference to Exhibit 10.14 of the Companys
Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.10*
|
|
Form of Non-Qualified Option Grant Agreement (Non-Employee
Director Post-March 1, 2005). (Incorporated by
reference to Exhibit 10.15 of the Companys
Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.11*
|
|
Form of Restricted Stock Grant Agreement. (Incorporated by
reference to Exhibit 10.16 of the Companys
Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.12*
|
|
Form of Amendment to Nonqualified Stock Option Agreement, dated
as of December 31, 2005, by and between the Company and the
optionees party thereto. (Incorporated by reference to
Exhibit 10.1 to the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2006)
|
|
10
|
.13*
|
|
Form of Nonqualified Stock Option Agreement (Director form
effective March 2006). (Incorporated by reference to
Exhibit 10.13 of the Companys Annual Report on
Form 10-K
(SEC File
No. 001-32693),
filed on March 7, 2008)
|
|
10
|
.14*
|
|
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
|
.15*
|
|
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
|
.16*
|
|
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)
|
86
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
10
|
.17*
|
|
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
|
.18*
|
|
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
|
.19*
|
|
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
|
.20*
|
|
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
|
.21*
|
|
Workover Unit Package Contract and Acceptance Agreement, dated
as of May 17, 2005, between Basic Energy Services, L.P. and
Taylor Rigs, LLC. (Incorporated by reference to
Exhibit 10.17 of the Companys Registration Statement
on
Form S-1
(SEC File
No. 333-127517),
filed on November 4, 2005)
|
|
10
|
.22*
|
|
Share Exchange Agreement, dated as of September 22, 2003,
among BES Holding Co. and the Stockholders named therein.
(Incorporated by reference to Exhibit 10.18 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.23*
|
|
Form of Share Tender and Repurchase Agreement. (Incorporated by
reference to Exhibit 10.19 of the Companys
Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on November 4, 2005)
|
|
10
|
.24*
|
|
Workover Unit Package Contract and Acceptance Agreement, dated
as of November 10, 2005, between Basic Energy Services,
L.P. and Taylor Rigs, LLC. (Incorporated by reference to
Exhibit 10.20 of the Companys Registration Statement
on
Form S-1
(SEC File
No. 333-127517),
filed on November 16, 2005)
|
|
10
|
.25*
|
|
Asset Purchase Agreement dated as of February 21, 2006
among Basic Energy Services, LP, Basic Energy Services GP, LLC,
G&L Tool, Ltd., DLH Management, LLC and LJH, Ltd.
(Incorporated by reference to Exhibit 10.1 of the
Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on March 2, 2006)
|
|
10
|
.26*
|
|
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
|
.27*
|
|
Fee Reimbursement Agreement, dated as of July 24, 2006, by
and among the Company, Southwest Partners II, L.P., Southwest
Partners, III, L.P. and Fortress Holdings, LLC.
(Incorporated by reference to Exhibit 10.23 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-136019),
filed on July 25, 2006)
|
|
10
|
.28*
|
|
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
|
.29*
|
|
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
|
.30*
|
|
Amended and Restated Employment Agreement of Charles W. Swift,
effective as of November 21, 2008. (Incorporated by
reference to Exhibit 10.1 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on November 24, 2008)
|
|
10
|
.31*
|
|
Employment Agreement of Dub William Harrison, effective as of
December 31, 2006. (Incorporated by reference to
Exhibit 10.4 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2007)
|
|
10
|
.32*
|
|
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)
|
87
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
10
|
.33*
|
|
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
|
.34*
|
|
Employment Agreement of Mark David Rankin, effective as of
December 31, 2006. (Incorporated by reference to
Exhibit 10.7 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2007)
|
|
10
|
.35*
|
|
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
|
.36*
|
|
Registration Rights Agreement, dated as of March 6, 2007,
by and among Basic Energy Services, Inc. and the JetStar
Stockholders Representative. (Incorporated by reference to
Exhibit 10.1 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on March 8, 2007)
|
|
10
|
.37*
|
|
Registration Rights Agreement, dated as of April 2, 2007,
by and among the Company and the Holders named therein.
(Incorporated by reference to Exhibit 10.1 of the
Companys current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on April 5, 2007)
|
|
21
|
.1
|
|
Subsidiaries of the Company
|
|
23
|
.1
|
|
Consent of KPMG LLP
|
|
31
|
.1
|
|
Certification by Chief Executive Officer required by
Rule 13a-14(a)
and 15d-14(a) under the Exchange Act
|
|
31
|
.2
|
|
Certification by Chief Financial Officer required by
Rule 13a-14(a)
and 15d-14(a) under the Exchange Act
|
|
32
|
.1
|
|
Certification by Chief Executive Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
|
|
32
|
.2
|
|
Certification of Chief Financial Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
|
|
|
|
* |
|
Incorporated by reference |
|
|
|
Management contract or compensatory plan or arrangement |
88
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
BASIC ENERGY SERVICES, INC.
|
|
|
|
By:
|
/s/ Kenneth
V. Huseman
|
Name: Kenneth V. Huseman
|
|
|
|
Title:
|
President, Chief Executive Officer and Director
|
Date: March 6, 2009
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
|
|
|
|
|
|
|
Signature
|
|
Date
|
|
|
|
|
|
|
|
|
/s/ Kenneth
V. Huseman
Kenneth
V. Huseman
|
|
President, Chief Executive Officer and Director (Principal
Executive Officer)
|
|
March 6, 2009
|
|
|
|
|
|
/s/ Alan
Krenek
Alan
Krenek
|
|
Senior Vice President,
Chief Financial Officer,
Treasurer and Secretary
(Principal Financial Officer
and Principal Accounting Officer)
|
|
March 6, 2009
|
|
|
|
|
|
/s/ Steven
A. Webster
Steven
A. Webster
|
|
Chairman of the Board
|
|
March 6, 2009
|
|
|
|
|
|
/s/ James
S. DAgostino, Jr.
James
S. DAgostino, Jr.
|
|
Director
|
|
March 6, 2009
|
|
|
|
|
|
/s/ William
E. Chiles
William
E. Chiles
|
|
Director
|
|
March 6, 2009
|
|
|
|
|
|
/s/ Robert
F. Fulton
Robert
F. Fulton
|
|
Director
|
|
March 6, 2009
|
|
|
|
|
|
/s/ Sylvester
P. Johnson, IV
Sylvester
P. Johnson, IV
|
|
Director
|
|
March 6, 2009
|
|
|
|
|
|
/s/ H.H.
Wommack, III
H.H.
Wommack, III
|
|
Director
|
|
March 6, 2009
|
|
|
|
|
|
/s/ Thomas
P. Moore, Jr.
Thomas
P. Moore, Jr.
|
|
Director
|
|
March 6, 2009
|
89
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. (the
Company), 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 3.1 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on November 4, 2005)
|
|
4
|
.2*
|
|
Indenture dated April 12, 2006, among Basic Energy
Services, Inc., the guarantors party thereto, and The Bank of
New York Trust Company, N.A., as trustee. (Incorporated by
reference to Exhibit 4.1 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on April 13, 2006)
|
|
4
|
.3*
|
|
Form of 7.125% Senior Note due 2016. (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 Supplement 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
|
|
10
|
.1*
|
|
Form of Indemnification Agreement. (Incorporated by reference to
Exhibit 10.1 of the Companys Registration Statement
on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.2*
|
|
Second Amended and Restated Stockholders Agreement dated
as of April 2, 2004 among the Company and the stockholders
listed therein. (Incorporated by reference to Exhibit 10.7
of the Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on August 12, 2005)
|
|
10
|
.3*
|
|
Stock Purchase Agreement dated as of September 18, 2003, as
amended on October 1, 2003, among the Company, FESCO
Holdings, Inc. and the sellers named therein. (Incorporated by
reference to Exhibit 10.8 of the Companys
Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on August 12, 2005)
|
|
10
|
.4*
|
|
Asset Purchase Agreement dated as of August 14, 2003 among
the Company and PWI, Inc. (Incorporated by reference to
Exhibit 10.9 of the Companys Registration Statement
on
Form S-1
(SEC File
No. 333-127517),
filed on August 12, 2005)
|
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
10
|
.5*
|
|
Fourth Amended and Restated Credit Agreement dated as of
October 3, 2003, amended and restated as of
February 6, 2007, among Basic Energy Services, Inc., the
subsidiary guarantors party thereto, Bank of America, N.A., as
syndication agent, Capital One, National Association, as
documentation agent, BNP Paribas, as documentation agent,
UBS AG, Stamford Branch, as issuing bank, administrative agent
and collateral agent, and the lenders party thereto.
(Incorporated by reference to Exhibit 10.1 to the
Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on February 12, 2007)
|
|
10
|
.6*
|
|
Third Amended and Restated 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 May 29, 2008)
|
|
10
|
.7*
|
|
Form of Non-Qualified Option Grant Agreement (Executive
Officer Pre-March 1, 2005). (Incorporated by
reference to Exhibit 10.12 of the Companys
Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.8*
|
|
Form of Non-Qualified Option Grant Agreement (Executive
Officer Post-March 1, 2005). (Incorporated by
reference to Exhibit 10.13 of the Companys
Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.9*
|
|
Form of Non-Qualified Option Grant Agreement (Non-Employee
Director Pre-March 1, 2005). (Incorporated by
reference to Exhibit 10.14 of the Companys
Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.10*
|
|
Form of Non-Qualified Option Grant Agreement (Non-Employee
Director Post-March 1, 2005). (Incorporated by
reference to Exhibit 10.15 of the Companys
Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.11*
|
|
Form of Restricted Stock Grant Agreement. (Incorporated by
reference to Exhibit 10.16 of the Companys
Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.12*
|
|
Form of Amendment to Nonqualified Stock Option Agreement, dated
as of December 31, 2005, by and between the Company and the
optionees party thereto. (Incorporated by reference to
Exhibit 10.1 to the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2006)
|
|
10
|
.13*
|
|
Form of Nonqualified Stock Option Agreement (Director form
effective March 2006). (Incorporated by reference to
Exhibit 10.13 of the Companys Annual Report on
Form 10-K
(SEC File
No. 001-32693),
filed on March 7, 2008)
|
|
10
|
.14*
|
|
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
|
.15*
|
|
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
|
.16*
|
|
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
|
.17*
|
|
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
|
.18*
|
|
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
|
.19*
|
|
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
|
.20*
|
|
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
|
.21*
|
|
Workover Unit Package Contract and Acceptance Agreement, dated
as of May 17, 2005, between Basic Energy Services, L.P. and
Taylor Rigs, LLC. (Incorporated by reference to
Exhibit 10.17 of the Companys Registration Statement
on
Form S-1
(SEC File
No. 333-127517),
filed on November 4, 2005)
|
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
10
|
.22*
|
|
Share Exchange Agreement, dated as of September 22, 2003,
among BES Holding Co. and the Stockholders named therein.
(Incorporated by reference to Exhibit 10.18 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on September 28, 2005)
|
|
10
|
.23*
|
|
Form of Share Tender and Repurchase Agreement. (Incorporated by
reference to Exhibit 10.19 of the Companys
Registration Statement on
Form S-1
(SEC File
No. 333-127517),
filed on November 4, 2005)
|
|
10
|
.24*
|
|
Workover Unit Package Contract and Acceptance Agreement, dated
as of November 10, 2005, between Basic Energy Services,
L.P. and Taylor Rigs, LLC. (Incorporated by reference to
Exhibit 10.20 of the Companys Registration Statement
on
Form S-1
(SEC File
No. 333-127517),
filed on November 16, 2005)
|
|
10
|
.25*
|
|
Asset Purchase Agreement dated as of February 21, 2006
among Basic Energy Services, LP, Basic Energy Services GP, LLC,
G&L Tool, Ltd., DLH Management, LLC and LJH, Ltd.
(Incorporated by reference to Exhibit 10.1 of the
Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on March 2, 2006)
|
|
10
|
.26*
|
|
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
|
.27*
|
|
Fee Reimbursement Agreement, dated as of July 24, 2006, by
and among the Company, Southwest Partners II, L.P., Southwest
Partners, III, L.P. and Fortress Holdings, LLC.
(Incorporated by reference to Exhibit 10.23 of the
Companys Registration Statement on
Form S-1
(SEC File
No. 333-136019),
filed on July 25, 2006)
|
|
10
|
.28*
|
|
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
|
.29*
|
|
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
|
.30*
|
|
Amended and Restated Employment Agreement of Charles W. Swift,
effective as of November 21, 2008. (Incorporated by
reference to Exhibit 10.1 of the Companys Current
Report on
Form 8-K
(SEC File
No. 001-32693),
filed on November 24, 2008)
|
|
10
|
.31*
|
|
Employment Agreement of Dub William Harrison, effective as of
December 31, 2006. (Incorporated by reference to
Exhibit 10.4 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2007)
|
|
10
|
.32*
|
|
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
|
.33*
|
|
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
|
.34*
|
|
Employment Agreement of Mark David Rankin, effective as of
December 31, 2006. (Incorporated by reference to
Exhibit 10.7 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on January 4, 2007)
|
|
10
|
.35*
|
|
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
|
.36*
|
|
Registration Rights Agreement, dated as of March 6, 2007,
by and among Basic Energy Services, Inc. and the JetStar
Stockholders Representative (Incorporated by reference to
Exhibit 10.1 of the Companys Current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on March 8, 2007)
|
|
10
|
.37*
|
|
Registration Rights Agreement, dated as of April 2, 2007,
by and among the Company and the Holders named therein.
(Incorporated by reference to Exhibit 10.1 of the
Companys current Report on
Form 8-K
(SEC File
No. 001-32693),
filed on April 5, 2007)
|
|
21
|
.1
|
|
Subsidiaries of the Company
|
|
23
|
.1
|
|
Consent of KPMG LLP
|
|
|
|
|
|
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 |