e424b3
Filed Pursuant to Rule 424(b)(3)
Registration No. 333-136019
2,101,641 Shares
Basic Energy Services, Inc.
Common Stock
Basic Energy Services, Inc. is registering 2,101,641 shares
of common stock which will be distributed by Fortress Holdings,
LLC to its members and by Southwest Partners II, L.P. and
Southwest Partners III, L.P. to their partners. We will not
receive any of the proceeds from the shares of common stock
distributed by the distributing stockholders.
Our common stock is listed on The New York Stock Exchange under
the symbol BAS. The last reported sales price of our
common stock on August 4, 2006 was $27.07 per share.
See Risk Factors beginning on page 11 to
read about factors you should consider before buying our common
stock.
Neither the Securities and Exchange Commission nor any state
securities commission has approved or disapproved of these
securities or passed on the adequacy or accuracy of this
prospectus. Any representation to the contrary is a criminal
offense.
Prospectus dated August 7, 2006
1. Well Servicing Rig Preparing to Begin Work
2. Fluid Services Transport Truck
3. 24 Hour Workover Rig
4. Well Site Construction Equipment
5. Saltwater Disposal Facility
6. Frac Tank Utilized for Storage of Fluids
7. Trailer-Mounted Pressure Pumping Equipment
8. Coiled Tubing Unit Used in Pressure Pumping
9. Inland Barge Workover Rig
10. Trailer-Mounted Foam Circulating Unit Used in
Underbalanced Workover Operations
TABLE OF CONTENTS
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You should rely only on the information contained in this
prospectus or to which we have referred you. We have not
authorized anyone to provide you with information that is
different from what we have provided to you. This document may
only be used where it is legal to sell these securities. The
information in this document may only be accurate on the date of
this document.
In this prospectus, we use the terms Basic Energy
Services, we, us and
our to refer to Basic Energy Services, Inc. together
with its subsidiaries unless the context otherwise requires. The
term distributing stockholders refers collectively
to Fortress Holdings, LLC, Southwest Partners II, L.P. and
Southwest Partners III, L.P.
-i-
PROSPECTUS SUMMARY
This summary highlights information contained elsewhere in
this prospectus. You should read the entire prospectus
carefully, including the risks discussed in the Risk
Factors section, the historical consolidated financial
statements and notes to those financial statements. This summary
may not contain all of the information that investors should
consider before investing in our common stock. If you are not
familiar with some of the oil and gas industry terms used in
this prospectus, please read our Glossary of Terms included as
Appendix A to this prospectus.
Our Company
We provide a wide range of well site services to oil and gas
drilling and producing companies, including well servicing,
fluid services, drilling and completion services and well site
construction services. These services are fundamental to
establishing and maintaining the flow of oil and gas throughout
the productive life of a well. Our broad range of services
enables us to meet multiple needs of our customers at the well
site. Our operations are managed regionally and are concentrated
in the major United States onshore oil and gas producing regions
in Texas, New Mexico, Oklahoma and Louisiana and the Rocky
Mountain states. We provide our services to a diverse group of
over 1,000 oil and gas companies. We operate the third-largest
fleet of well servicing rigs (also commonly referred to as
workover rigs) in the United States, representing approximately
13% of the overall available U.S. fleet. Our two larger
competitors control approximately 31% and 18%, respectively, as
of May 2006, according to the Association of Energy Services
Companies and other publicly available data. We have expanded
our asset base from $53.0 million of total assets as of
December 31, 2000 to $497.0 million of total assets as
of December 31, 2005 and increased our revenues from
$56.5 million in 2000 to $459.8 million in 2005.
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 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 increase spending for drilling new
wells and well servicing activities related to maintaining or
increasing production from existing wells. The utilization rate
for our fleet of well servicing rigs increased from
approximately 71% in 2003 to 78% in 2004, 87% in 2005, and 89%
in the first quarter of 2006. Because our services are required
to support drilling and workover activities, we are also subject
to changes in capital spending by our customers as oil and gas
prices increase or decrease.
We currently conduct our operations through the following four
business segments:
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Well Servicing. Our well servicing segment
(48% of our revenues in 2005 and 47% of our revenues in the
first quarter of 2006) currently operates our fleet of over
330 well servicing rigs and related equipment. This
business segment encompasses a full range of services performed
with a mobile well servicing rig, including the installation and
removal of downhole equipment and elimination of obstructions in
the well bore to facilitate the flow of oil and gas. These
services are performed to establish, maintain and improve
production throughout the productive life of an oil and gas well
and to plug and abandon a well at the end of its productive
life. Our well servicing equipment and capabilities are
essential to facilitate most other services performed on a well. |
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Fluid Services. Our fluid services segment
(29% of our revenues in 2005 and 28% of our revenues in the
first quarter of 2006) currently utilizes our fleet of over 550
fluid services trucks and related assets, including specialized
tank trucks, storage tanks, water wells, disposal facilities and
related equipment. These assets provide, transport, store and |
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dispose of a variety of fluids. These services are required in
most workover, drilling and completion projects and are
routinely used in daily producing well operations. |
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Drilling and Completion Services. Our drilling and
completion services segment (13% of our revenues in 2005
and 18% of our revenues in the first quarter of 2006)
currently operates our fleet of 70 pressure pumping units,
29 air compressor packages specially configured for
underbalanced drilling operations and 10 cased-hole
wireline units. These services are designed to initiate or
stimulate oil and gas production. The largest portion of this
business consists of pressure pumping services focused on
cementing, acidizing and fracturing services in niche markets.
We also entered the fishing and rental tool business through an
acquisition in the first quarter of 2006. |
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Well Site Construction Services. Our well site
construction services segment (10% of our revenues in 2005
and 7% of our revenues in the first quarter of 2006)
currently utilizes our fleet of over 200 operated power
units, which include dozers, trenchers, motor graders, backhoes
and other heavy equipment. We utilize these assets primarily to
provide services for the construction and maintenance of oil and
gas production infrastructure, such as preparing and maintaining
access roads and well locations, installation of small diameter
gathering lines and pipelines and construction of temporary
foundations to support drilling rigs. |
Our industry historically has consisted of a large number of
small companies, several regional contractors and a few large
national companies. Over the last decade, our industry has
consolidated, including the consolidation of the well servicing
segment of our industry, from nine large competitors (with 50 or
more well servicing rigs) to four. However, the industry still
remains fragmented with an estimated 120 companies owning
approximately 900 remaining well servicing rigs, or
approximately 26% of the industrys total fleet. We have
led recent consolidation of this industry by acquiring regional
businesses and assets in 40 separate acquisitions from the
beginning of 2001 through March 31, 2006. We plan to
continue participating in the consolidation of our industry by
selectively acquiring additional businesses and assets that
complement and expand our existing service offerings and
geographic footprint and offer attractive projected rates of
return on capital employed. However, we cannot assure you that
we can complete such acquisitions.
General Industry Overview
Demand for services offered by our industry is a function of our
customers willingness to make operating and capital
expenditures to explore for, develop and produce hydrocarbons in
the U.S., which in turn is affected by current and expected
levels of oil and gas prices. The following industry statistics
illustrate the growing spending dynamic in the U.S. oil and
gas sector (including the offshore sector that we do not serve):
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With the rebound in oil and gas prices in early 1999, oil and
gas companies have increased their drilling and workover
activities. The increased activity resulted in increased
exploration and production spending compared to the prior year
of 16% and 30% in 2004 and 2005, respectively, and is expected
to increase 16% in 2006, according to www.WorldOil.com. |
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A survey of 18 U.S. major integrated and 130 independent
oil and gas companies by World Oil Magazine projected the
U.S. drilling activity in 2006 to be skewed more towards
independent players. Specifically, independent oil and gas
companies, which represent over 90% of our revenues, are
expected to drill 27% more wells in 2006 than in 2005, while the
major integrated producers are expected to drill only 16% more
wells over the same period. This trend is primarily driven by
the increased acquisitions of proved oil and gas properties by
independent producers. When these types of properties are
acquired, |
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purchasers typically intensify drilling, workover and well
maintenance activities to accelerate production from the newly
acquired reserves. |
Increased expenditures for exploration and production activities
generally involve the deployment of more drilling and well
servicing rigs, which often serves as an indicator of demand for
our services. Rising oil and gas prices since early 1999 and the
corresponding increase in onshore oil exploration and production
spending have led to expanded drilling and well service
activity, as the U.S. land-based drilling rig count
increased approximately 36% from
year-end 2002 to
year-end 2003,
11% from year-end
2003 to year-end 2004,
22% from year-end
2004 to year-end 2005
and 7% during the first quarter of 2006, according to Baker
Hughes. In addition, the U.S. land-based workover rig count
increased approximately 13% from
year-end 2002 to
year-end 2003,
10% from year-end
2003 to year-end 2004,
17% from year-end
2004 to year-end 2005
and 3% during the first quarter of 2006, according to Baker
Hughes.
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.
Competitive Strengths
We believe that the following competitive strengths currently
position us well within our industry:
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Significant Market Position. We maintain a
significant market share for our well servicing operations in
our core operating areas throughout Texas and a growing market
share in the other markets that we serve. Our fleet of over
330 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
completion, maintenance, workover and plugging and abandonment
services. |
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Modern and Active Fleet. We operate a modern and
active fleet of well servicing rigs. We believe over 95% of the
active US well servicing rig fleet was built prior to 1985.
Approximately 98, or 30%, of our rigs at March 31, 2006
were either 2000 model year or newer, or have undergone major
refurbishments during the last four years. Since October 2004,
we have taken delivery of 45 newbuild well servicing rigs
through March 31, 2006 as part of a
102-rig newbuild
commitment, driven by our desire to maintain one of the most
efficient, reliable and safest fleets in the industry. The
remainder of these newbuilds is scheduled to be delivered to us
prior to the end of December 2007. Approximately 98% of our
fleet was active or available for work and the remainder was
awaiting refurbishment at March 31, 2006. Since 2003, we
have obtained annual independent reviews and evaluations of
substantially all of our assets, which confirmed the location
and condition of these assets. |
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Extensive Domestic Footprint in the Most Prolific
Basins. Our operations are concentrated in the major
United States onshore oil and gas producing regions in Texas,
New Mexico, Oklahoma and Louisiana and the Rocky Mountain
states. We operate in states that accounted for approximately
57% of the approximately 900,000 existing onshore oil and gas
wells in the 48 contiguous states and approximately 77% of
onshore oil production and 72% of onshore gas production in
2005. We believe that our operations are located in the most
active U.S. well services markets, as we currently focus
our operations on onshore domestic oil and gas production areas
that include both the highest concentration of existing oil and
gas production activities and the largest |
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prospective acreage for new drilling activity. This extensive
footprint allows us to offer our suite of services to more than
1,000 customers who are active in those areas and allows us
to redeploy equipment between markets as activity shifts. |
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Diversified Service Offering for Further Revenue
Growth. Our experience, equipment and network of over 90
service locations position us to market our full range of well
site services to our existing customers. We believe our range of
well site services provides us a competitive advantage over
smaller companies that typically offer fewer services. 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. |
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Decentralized Management with Strong Corporate
Infrastructure. Our corporate group is responsible for
maintaining a unified infrastructure to support our diversified
operations through standardized financial and accounting,
safety, environmental and maintenance processes and controls.
Below our corporate level, we operate a decentralized
operational organization in which our seven regional managers
are responsible for their regional operations, including asset
management, cost control, policy compliance and training and
other aspects of quality control. With an average of over
28 years of industry experience, each regional manager has
extensive knowledge of the customer base, job requirements and
working conditions in each local market. This management
structure allows us to monitor operating performance on a daily
basis, maintain financial, accounting and asset management
controls, integrate acquisitions, prepare timely financial
reports and manage contractual risk. |
Our Business Strategy
We intend to increase our shareholder value by pursuing the
following strategies:
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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. |
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Expand Within Our Regional Markets. We intend to
continue strengthening our presence within our existing
geographic footprint through internal growth and acquisitions of
businesses with strong customer relationships, well-maintained
equipment and experienced and skilled personnel. Our larger
competitors have not actively pursued acquisitions of small to
mid-size regional businesses or assets in recent years due to
the small relative scale and financial impact of these potential
acquisitions. In contrast, we have successfully pursued these
types of acquisitions, which remain attractive to us and make a
meaningful impact on our overall operations. |
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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. 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 |
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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. |
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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, 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. |
Our strategies could be affected by any of the risk factors
described in Risk Factors beginning on page 11.
How You Can Contact Us
Our principal executive offices are located at
400 W. Illinois, Suite 800, Midland, Texas 79701,
and our telephone number is
(432) 620-5500.
Recent Developments
On January 31, 2006, we acquired all of the outstanding
capital stock of LeBus Oil Field Service Co. for a total
acquisition price of approximately $26 million in cash,
subject to adjustment. LeBus, which generated approximately
$21 million in revenues in 2005, has 57 fluid services
trucks, 225 frac tanks, and six disposal facilities. LeBus
provides transportation, storage and disposal of oilfield fluids
in the East Texas and North Louisiana regions from its New
London and Tenaha, Texas operating locations. This acquisition
is indicative of our acquisition strategy to expand within our
regional markets.
On February 28, 2006, we purchased substantially all of the
operating assets of G&L Tool, Ltd., an oilfield services
fishing and rental tool business headquartered in Abilene,
Texas, for total consideration of $58 million in cash. The
assets acquired from G&L generated approximately
$39 million in revenues during 2005. This acquisition
provides us entry into the fishing and rental tool business and
allows us to pursue complementary and cross-selling
opportunities throughout our West and North Texas locations.
This acquisition is indicative of our strategy to develop
additional service offerings within the well servicing market.
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 revolving balance
under our 2005 Credit Facility. Remaining proceeds will be used
for general corporate purposes, including acquisitions. For a
description of our 2005 Credit Facility, please read
Managements Discussion and Analysis of Financial
Condition and Results of Operations Liquidity and
Capital Resources Credit Facilities.
5
The Distribution
The 2,101,641 shares of our common stock are being
registered to permit a one-time distribution of controlled
securities to the partners of Southwest Partners II, L.P. and
Southwest Partners III, L.P. and to the members of Fortress
Holdings, LLC. Neither we, nor the distributing stockholders
will receive any proceeds from this transaction.
The partners and members of the distributing stockholders who
will receive shares of our common stock in this registered
offering may sell the shares of common stock directly to
purchasers or through underwriters, broker-dealers or agents
under Section 4(1) of the Securities Act, except to the
extent any such partner or member is deemed to be our
affiliate under Rule 144 of the Securities Act.
After receiving shares of our common stock in this offering, the
partners and members of the distributing stockholders, to the
extent not deemed to be our affiliate under
Rule 144 of the Securities Act, will act independently of
us, and the distributing stockholders, in making decisions
regarding the timing, manner and size of each sale of our common
stock.
We are not aware of any plans, arrangements or understandings
between the partners or members of the distributing stockholders
and any underwriter, broker-dealer or agent regarding the sale
of the shares of common stock and we do not assure you that the
partners or members of the distributing stockholders will sell
any or all of the registered shares of common stock following
distribution. In addition, we do not assure you that the
partners or members will not transfer, devise or gift the shares
of common stock by other means not described in this prospectus.
Moreover, any securities covered by this prospectus that qualify
for sale pursuant to Rule 144 of the Securities Act may be
sold under Rule 144 rather than pursuant to this prospectus.
H.H. Wommack, III, one of our directors and an affiliate of the
distributing stockholders, will receive shares of common stock
in connection with the distributions.
We will not receive any of the net proceeds from the
distribution of shares of our common stock by the distributing
stockholders. See Use of Proceeds and Plan of
Distribution.
See Risk Factors beginning on page 11 of this
prospectus for a discussion of factors that you should carefully
consider before deciding to invest in shares of our common stock.
6
Summary Historical Financial Information
The following table sets forth our summary historical financial
and operating data for the periods shown. The following
information should be read in conjunction with
Capitalization, Managements Discussion
and Analysis of Financial Condition and Results of
Operations and our financial statements included elsewhere
in this prospectus. The amounts for each historical annual
period presented below were derived from our audited financial
statements.
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Three Months | |
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Ended | |
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Year Ended December 31, | |
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March 31, | |
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2003 | |
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2004 | |
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2005 | |
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2005 | |
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2006 | |
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(unaudited) | |
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(dollars in thousands, except per share data) | |
Statement of Operations
Data:
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Revenues:
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Well servicing
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$ |
104,097 |
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$ |
142,551 |
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$ |
221,993 |
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$ |
44,798 |
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$ |
73,465 |
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Fluid services
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52,810 |
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98,683 |
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132,280 |
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29,303 |
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43,121 |
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Drilling and completion services
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14,808 |
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29,341 |
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59,832 |
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10,764 |
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27,455 |
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Well site construction services
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9,184 |
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40,927 |
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45,647 |
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8,948 |
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10,265 |
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Total revenues
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180,899 |
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311,502 |
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459,752 |
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93,813 |
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154,306 |
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Expenses:
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Well servicing
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73,244 |
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98,058 |
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137,392 |
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28,191 |
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41,610 |
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Fluid services
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34,420 |
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65,167 |
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82,551 |
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19,238 |
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26,305 |
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Drilling and completion services
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9,363 |
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17,481 |
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30,900 |
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5,860 |
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13,854 |
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Well site construction services
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6,586 |
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31,454 |
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32,000 |
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7,108 |
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7,643 |
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General and administrative(1)
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22,722 |
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37,186 |
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55,411 |
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13,091 |
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18,005 |
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Depreciation and amortization
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18,213 |
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28,676 |
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37,072 |
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8,047 |
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12,837 |
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Loss (gain) on disposal of
assets
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391 |
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2,616 |
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(222 |
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102 |
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(200 |
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Total expenses
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164,939 |
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280,638 |
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375,104 |
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81,637 |
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120,054 |
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Operating income
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15,960 |
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30,864 |
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84,648 |
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12,176 |
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34,252 |
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest expense
|
|
|
(5,174 |
) |
|
|
(9,550 |
) |
|
|
(12,660 |
) |
|
|
(2,960 |
) |
|
|
(2,779 |
) |
|
Loss on early extinguishment of debt
|
|
|
(5,197 |
) |
|
|
|
|
|
|
(627 |
) |
|
|
|
|
|
|
|
|
|
Other income (expense)
|
|
|
146 |
|
|
|
(398 |
) |
|
|
220 |
|
|
|
75 |
|
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
before income taxes
|
|
|
5,735 |
|
|
|
20,916 |
|
|
|
71,581 |
|
|
|
9,291 |
|
|
|
31,500 |
|
|
Income tax expense
|
|
|
(2,772 |
) |
|
|
(7,984 |
) |
|
|
(26,800 |
) |
|
|
(3,490 |
) |
|
|
(11,819 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
|
2,963 |
|
|
|
12,932 |
|
|
|
44,781 |
|
|
|
5,801 |
|
|
|
19,681 |
|
|
Discontinued operations, net of tax
|
|
|
22 |
|
|
|
(71 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of accounting
change, net of tax
|
|
|
(151 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
2,834 |
|
|
|
12,861 |
|
|
|
44,781 |
|
|
|
5,801 |
|
|
|
19,681 |
|
|
Preferred stock dividend
|
|
|
(1,525 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of preferred stock
discount
|
|
|
(3,424 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to
common stockholders
|
|
$ |
(2,115 |
) |
|
$ |
12,861 |
|
|
$ |
44,781 |
|
|
$ |
5,801 |
|
|
$ |
19,681 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share of
common stock:(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
(0.09 |
) |
|
$ |
0.46 |
|
|
$ |
1.57 |
|
|
$ |
0.21 |
|
|
$ |
0.59 |
|
|
|
Diluted
|
|
$ |
(0.09 |
) |
|
$ |
0.42 |
|
|
$ |
1.35 |
|
|
$ |
0.18 |
|
|
$ |
0.53 |
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months | |
|
|
|
|
Ended | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
|
|
|
|
|
|
(unaudited) | |
|
|
(dollars in thousands, except per share data) | |
Statement of Cash Flow
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from operating activities
|
|
$ |
29,815 |
|
|
$ |
46,539 |
|
|
$ |
99,189 |
|
|
$ |
16,734 |
|
|
$ |
25,915 |
|
Cash flows from investing activities
|
|
|
(84,903 |
) |
|
|
(73,587 |
) |
|
|
(107,679 |
) |
|
|
(19,946 |
) |
|
|
(111,584 |
) |
Cash flows from financing activities
|
|
|
79,859 |
|
|
|
21,498 |
|
|
|
21,188 |
|
|
|
(2,817 |
) |
|
|
72,777 |
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions, net of cash acquired
|
|
|
61,885 |
|
|
|
19,284 |
|
|
|
25,378 |
|
|
|
3,909 |
|
|
|
87,520 |
|
|
Property and equipment
|
|
|
23,501 |
|
|
|
55,674 |
|
|
|
83,095 |
|
|
|
16,083 |
|
|
|
24,812 |
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(3)
|
|
$ |
28,993 |
|
|
$ |
59,071 |
|
|
$ |
121,313 |
|
|
$ |
20,298 |
|
|
$ |
47,116 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, | |
|
As of | |
|
|
| |
|
March 31, | |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
|
|
|
|
|
|
|
(unaudited) | |
|
|
(dollars in thousands) | |
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
25,697 |
|
|
$ |
20,147 |
|
|
$ |
32,845 |
|
|
$ |
19,953 |
|
Property and equipment, net
|
|
|
188,243 |
|
|
|
233,451 |
|
|
|
309,075 |
|
|
|
399,865 |
|
Total assets
|
|
|
302,653 |
|
|
|
367,601 |
|
|
|
496,957 |
|
|
|
616,787 |
|
Total long-term debt, including
current portion
|
|
|
148,509 |
|
|
|
182,476 |
|
|
|
126,887 |
|
|
|
210,047 |
|
Total stockholders equity
|
|
|
107,295 |
|
|
|
121,786 |
|
|
|
258,575 |
|
|
|
278,241 |
|
|
|
(1) |
Includes approximately $994,000, $1,587,000 and $2,890,000 of
non-cash stock-based compensation expense for the years ended
December 31, 2003, 2004 and 2005, respectively, and
$591,000 and $758,000 for the three months ended March 31,
2005 and 2006, respectively. |
|
(2) |
Reflects a 5-for-1 stock split effected as a stock dividend in
September 2005. |
|
(3) |
EBITDA means earnings before interest, taxes, depreciation and
amortization. EBITDA is used as a supplemental financial measure
by our management and directors and by external users of our
financial statements, such as investors, to assess: |
|
|
|
|
|
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis; |
|
|
|
the ability of our assets to generate cash sufficient to pay
interest on our indebtedness; and |
|
|
|
our operating performance and return on invested capital as
compared to those of other companies in the well services
industry, without regard to financing methods and capital
structure. |
8
EBITDA has limitations as an analytical tool and should not be
considered an alternative to net income, operating income, cash
flow from operating activities or any other measure of financial
performance or liquidity presented in accordance with generally
accepted accounting principles (GAAP). EBITDA excludes some, but
not all, items that affect net income and operating income, and
these measures may vary among other companies. Limitations to
using EBITDA as an analytical tool include:
|
|
|
|
|
EBITDA does not reflect our current or future requirements for
capital expenditures or capital commitments; |
|
|
|
EBITDA does not reflect changes in, or cash requirements
necessary to service interest or principal payments on, our debt; |
|
|
|
EBITDA does not reflect income taxes; |
|
|
|
although depreciation and amortization are non-cash charges, the
assets being depreciated and amortized will often have to be
replaced in the future, and EBITDA does not reflect any cash
requirements for such replacements; and |
|
|
|
other companies in our industry may calculate EBITDA differently
than we do, limiting its usefulness as a comparative measure. |
The following table presents a reconciliation of EBITDA to net
income, which is the most directly comparable GAAP financial
performance measure, for each of the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months | |
|
|
|
|
Ended | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
|
|
|
|
|
|
(unaudited) | |
|
|
(dollars in thousands) | |
Reconciliation of EBITDA to Net
Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
2,834 |
|
|
$ |
12,861 |
|
|
$ |
44,781 |
|
|
$ |
5,801 |
|
|
$ |
19,681 |
|
|
Income taxes
|
|
|
2,772 |
|
|
|
7,984 |
|
|
|
26,800 |
|
|
|
3,490 |
|
|
|
11,819 |
|
|
Net interest expense
|
|
|
5,174 |
|
|
|
9,550 |
|
|
|
12,660 |
|
|
|
2,960 |
|
|
|
2,779 |
|
|
Depreciation and amortization
|
|
|
18,213 |
|
|
|
28,676 |
|
|
|
37,072 |
|
|
|
8,047 |
|
|
|
12,837 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$ |
28,993 |
|
|
$ |
59,071 |
|
|
$ |
121,313 |
|
|
$ |
20,298 |
|
|
$ |
47,116 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
Operating Data
The following table sets forth operating data for our well
servicing, fluid services, drilling and completion services and
well site construction services segments for the periods shown.
The data presented below reflects the following:
|
|
|
|
|
we charge our well servicing customers on an hourly
basis rig hours reflect actual billed hours; |
|
|
|
our rig utilization rate is calculated using a
55-hour work week per
rig; |
|
|
|
our fluid services segment includes an array of services billed
on an hourly, daily and per barrel basis; accordingly, we
believe revenue per truck is the more meaningful information for
this measure; and |
|
|
|
in our drilling and completion services segment, we charge
different rates for our pressure pumping trucks based on the
type of services performed and varying horsepower requirements,
and in our well site construction services segment, we similarly
charge different rates for different equipment, in each case
making segment profits the most meaningful measure of
performance. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months | |
|
|
Year Ended | |
|
Ended | |
|
|
December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
Well Servicing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of rigs
|
|
|
257 |
|
|
|
279 |
|
|
|
305 |
|
|
|
291 |
|
|
|
327 |
|
Rig hours (000s)
|
|
|
523.9 |
|
|
|
618.8 |
|
|
|
760.7 |
|
|
|
175.3 |
|
|
|
209.0 |
|
Rig utilization rate
|
|
|
71.4 |
% |
|
|
77.8 |
% |
|
|
87.1 |
% |
|
|
84.3 |
% |
|
|
89.4 |
% |
Revenue per rig hour
|
|
$ |
199 |
|
|
$ |
230 |
|
|
$ |
292 |
|
|
$ |
255 |
|
|
$ |
352 |
|
Segment profits per rig hour
|
|
$ |
59 |
|
|
$ |
72 |
|
|
$ |
111 |
|
|
$ |
94 |
|
|
$ |
152 |
|
Segment profits as a percent of
revenue
|
|
|
29.6 |
% |
|
|
31.2 |
% |
|
|
38.1 |
% |
|
|
37.1 |
% |
|
|
43.4 |
% |
Fluid Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of fluid
service trucks
|
|
|
249 |
|
|
|
386 |
|
|
|
455 |
|
|
|
435 |
|
|
|
529 |
|
Revenue per fluid service truck
(000s)
|
|
$ |
212 |
|
|
$ |
256 |
|
|
$ |
291 |
|
|
$ |
67 |
|
|
$ |
82 |
|
Segment profits per fluid service
truck (000s)
|
|
$ |
74 |
|
|
$ |
87 |
|
|
$ |
109 |
|
|
$ |
24 |
|
|
$ |
32 |
|
Segment profits as a percent of
revenue
|
|
|
34.8 |
% |
|
|
34.0 |
% |
|
|
37.6 |
% |
|
|
34.3 |
% |
|
|
39.0 |
% |
Drilling and Completion
Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profits as a percent of
revenue
|
|
|
36.8 |
% |
|
|
40.4 |
% |
|
|
48.4 |
% |
|
|
45.6 |
% |
|
|
49.5 |
% |
Well Site Construction
Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profits as a percent of
revenue
|
|
|
28.3 |
% |
|
|
23.1 |
% |
|
|
29.9 |
% |
|
|
20.6 |
% |
|
|
25.5 |
% |
Please read Managements Discussion and Analysis of
Financial Condition and Results of Operations Well
Servicing, Fluid Services,
Drilling and Completion Services and
Well Site Construction Services for an
analysis of our well servicing, fluid services, drilling and
completion and well site construction services.
10
RISK FACTORS
You should carefully consider the risks described below, as
well as the other information included in this prospectus,
before making an investment decision to invest in our common
stock. If any of these risks were to occur, our business,
results of operations or financial condition could be materially
and adversely affected. In that case, the trading price of our
common stock could decline, and you could lose all or part of
your investment.
Risks Related to Our Business
A decline in or substantial volatility of oil and gas
prices could adversely affect the demand for our
services.
The demand for our services is primarily determined by current
and anticipated oil and gas prices and the related general
production spending and level of drilling activity in the areas
in which we have operations. Volatility or weakness in oil and
gas prices (or the perception that oil and gas prices will
decrease) affects the spending patterns of our customers and may
result in the drilling of fewer new wells or lower production
spending on existing wells. This, in turn, could result in lower
demand for our services and may cause lower rates and lower
utilization of our well service equipment. A decline in oil and
gas prices or a reduction in drilling activities could
materially and adversely affect the demand for our services and
our results of operations.
Prices for oil and gas historically have been extremely volatile
and are expected to continue to be volatile. For example,
although oil and natural gas prices have recently hit record
prices exceeding $70 per barrel and $14.00 per mcf,
respectively, oil and natural gas prices fell below $11 per
barrel and $2 per mcf, respectively, in early 1999. The
Cushing WTI Spot Oil Price averaged $31.08, $41.51, $56.64 and
$63.27 per barrel in 2003, 2004, 2005, and the first three
months of 2006, respectively, and the average wellhead price for
natural gas, as recorded by the Energy Information Agency, was
$4.98, $5.49, $7.51 and $7.49 per mcf for 2003, 2004, 2005,
and the first three months of 2006, respectively. Commodity
prices have increased significantly in recent years, and these
prices may not remain at current levels.
Our business depends on domestic spending by the oil and
gas industry, and this spending and our business may be
adversely affected by industry conditions that are beyond our
control.
We depend on our customers willingness to make operating
and capital expenditures to explore, develop and produce oil and
gas in the United States. Customers expectations for lower
market prices for oil and gas may curtail spending thereby
reducing demand for our services and equipment.
Industry conditions are influenced by numerous factors over
which we have no control, such as the supply of and demand for
oil and gas, domestic and worldwide economic conditions,
political instability in oil and gas producing countries and
merger and divestiture activity among oil and gas producers. The
volatility of the oil and gas industry and the consequent impact
on exploration and production activity could adversely impact
the level of drilling and workover activity by some of our
customers. This reduction may cause a decline in the demand for
our services or adversely affect the price of our services. In
addition, reduced discovery rates of new oil and gas reserves in
our market areas also may have a negative long-term impact on
our business, even in an environment of stronger oil and gas
prices, to the extent existing production is not replaced and
the number of producing wells for us to service declines.
We may not be able to grow successfully through future
acquisitions or successfully manage future growth, and we may
not be able to effectively integrate the businesses we do
acquire.
Our business strategy includes growth through the acquisitions
of other businesses. We may not be able to continue to identify
attractive acquisition opportunities or successfully acquire
11
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.
Our auditors have previously identified material
weaknesses in our internal controls, and if we fail to develop
or maintain an effective system of internal controls, we may not
be able to accurately report our financial results or prevent
fraud. As a result, investors could lose confidence in our
financial reporting, which would harm our business and the
trading price of our common stock.
Effective internal controls, including internal control over
financial reporting and disclosure controls and procedures, are
necessary for us to provide reliable financial reports and
effectively prevent fraud and to operate successfully as a
public company. If we cannot provide reliable financial reports
or prevent fraud, our reputation and operating results could be
materially harmed. We have in the past discovered, and may in
the future discover, areas of our internal controls that need
improvement.
In July 2004, our independent auditors advised our board of
directors that they had identified material weaknesses in our
internal controls in connection with the audit of our 2003
consolidated financial statements. The material weaknesses noted
consisted of an inadequacy of our procedures or errors regarding
account reconciliations not being performed timely or properly;
formal procedures for establishing certain accounting
assumptions, estimates and/or conclusions; and recording of
certain expenses in the incorrect period. Our auditors also
noted certain other items specific to our operations that they
did not consider to be material weaknesses.
To improve our financial accounting organization and processes,
we have established an internal audit department and have added
new personnel and positions in our accounting and finance
organization. We also implemented a new accounting software
system throughout our operations during the third quarter of
2004 and adopted additional policies and procedures to address
the items noted by our auditors and generally to strengthen our
financial reporting system. We believe that as of
December 31, 2005, we have remediated the material
weaknesses previously identified. However, the process of
designing and implementing an effective financial reporting
system is a continuous effort that requires us to anticipate and
react to changes in our business and the economic and regulatory
environments and to expend significant resources to maintain a
financial reporting system that is adequate to satisfy our
reporting obligations.
We have had only limited operating experience with the
improvements we have made to date. We may not be able to
implement and maintain adequate controls over our financial
processes and reporting in the future, which may require us to
restate our financial statements in the future. In addition, we
may discover additional past, ongoing or future weaknesses or
significant deficiencies in our financial reporting system in
the future. Any failure to implement required new or improved
controls, or difficulties encountered in their implementation,
could cause us to fail to meet our reporting obligations or
result in material misstatements in our financial statements.
Any such failure also could adversely affect the results of the
periodic management evaluations and annual auditor attestation
reports regarding the effectiveness of our internal
control over financial reporting that will be required
when the SECs rules under
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Section 404 of the Sarbanes-Oxley Act of 2002 become
applicable to us beginning with our Annual Report on
Form 10-K for the
year ending December 31, 2006 to be filed in the first
quarter of 2007. Inferior internal controls could also cause
investors to lose confidence in our reported financial
information, which could result in a lower trading price of our
common stock.
We may require additional capital in the future. We cannot
assure you that we will be able to generate sufficient cash
internally or obtain alternative sources of capital on favorable
terms, if at all. If we are unable to fund capital expenditures
our business may be adversely affected.
We anticipate that we will continue to make substantial capital
investments to purchase additional equipment to expand our
services, refurbish our well servicing rigs and replace existing
equipment. For the year ended December 31, 2005, we
invested approximately $83.1 million in cash for capital
investments, excluding acquisitions. During the first quarter of
2006, we made capital expenditures of approximately
$30.0 million, and we expect to spend a total of
approximately $93 million in cash capital expenditures
during fiscal year 2006, excluding acquisitions. Historically,
we have financed these investments through internally generated
funds, debt and equity offerings, our capital lease program and
our secured credit facilities. These significant capital
investments require cash that we could otherwise apply to other
business needs. However, if we do not incur these expenditures
while our competitors make substantial fleet investments, our
market share may decline and our business may be adversely
affected. In addition, if we are unable to generate sufficient
cash internally or obtain alternative sources of capital to fund
our proposed capital expenditures, acquisitions, take advantage
of business opportunities or respond to competitive pressures,
it could materially adversely affect our results of operations,
financial condition and growth. If we raise additional funds by
issuing equity securities, dilution to existing stockholders may
result.
Competition within the well services industry may
adversely affect our ability to market our services.
The well services industry is highly competitive and fragmented
and includes numerous small companies capable of competing
effectively in our markets on a local basis as well as several
large companies that possess substantially greater financial and
other resources than we do. Our larger competitors greater
resources could allow those competitors to compete more
effectively than we can. The amount of equipment available may
exceed demand, which could result in active price competition.
Many contracts are awarded on a bid basis, which may further
increase competition based primarily on price. In addition,
recent market conditions have stimulated the reactivation of
well servicing rigs and construction of new equipment, which
could result in excess equipment and lower utilization rates in
future periods.
We depend on several significant customers, and a loss of
one or more significant customers could adversely affect our
results of operations.
Our customers consist primarily of major and independent oil and
gas companies. During 2005 and the first three months of 2006,
our top five customers accounted for 16% and 14%, respectively,
of our revenues. The loss of any one of our largest customers or
a sustained decrease in demand by any of such customers could
result in a substantial loss of revenues and could have a
material adverse effect on our results of operations.
We are dependent on particular suppliers for our newbuild
rig program and are vulnerable to delayed deliveries and future
price increases.
We currently purchase our well servicing rigs from a single
supplier as part of a 102-rig commitment for rigs to be
delivered through the end of December 2007, of which 45 rigs
have been delivered as of March 31, 2006. There is also a
limited number of suppliers that manufacture this type of
equipment. Although pricing is generally fixed for this newbuild
contract
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and program, future price increases could affect our ability to
continue to increase the number of newbuild rigs in our fleet at
economic levels. In addition, the failure of our current
supplier to timely deliver the newbuild rigs could adversely
affect our budgeted or projected financial and operational data.
Our industry has experienced a high rate of employee
turnover. Any difficulty we experience replacing or adding
personnel could adversely affect our business.
We may not be able to find enough skilled labor to meet our
needs, which could limit our growth. Our business activity
historically decreases or increases with the price of oil and
gas. We may have problems finding enough skilled and unskilled
laborers in the future if the demand for our services increases.
We have raised wage rates to attract workers from other fields
and to retain or expand our current work force during the past
year. If we are not able to increase our service rates
sufficiently to compensate for wage rate increases, our
operating results may be adversely affected.
Other factors may also inhibit our ability to find enough
workers to meet our employment needs. Our services require
skilled workers who can perform physically demanding work. As a
result of our industry volatility and the demanding nature of
the work, workers may choose to pursue employment in fields that
offer a more desirable work environment at wage rates that are
competitive with ours. We believe that our success is dependent
upon our ability to continue to employ and retain skilled
technical personnel. Our inability to employ or retain skilled
technical personnel generally could have a material adverse
effect on our operations.
Our success depends on key members of our management, the
loss of any of whom could disrupt our business
operations.
We depend to a large extent on the services of some of our
executive officers. The loss of the services of Kenneth V.
Huseman, our President and Chief Executive Officer, or other key
personnel could disrupt our operations. Although we have entered
into employment agreements with Mr. Huseman and our other
executive officers that contain, among other provisions,
non-compete agreements, we may not be able to enforce the
non-compete provisions in the employment agreements.
Our operations are subject to inherent risks, some of
which are beyond our control. These risks may not be fully
covered under our insurance policies.
Our operations are subject to hazards inherent in the oil and
gas industry, such as, but not limited to, accidents, blowouts,
explosions, craterings, fires and oil spills. These conditions
can cause:
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personal injury or loss of life; |
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damage to or destruction of property, equipment and the
environment; and |
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suspension of operations. |
The occurrence of a significant event or adverse claim in excess
of the insurance coverage that we maintain or that is not
covered by insurance could have a material adverse effect on our
financial condition and results of operations. In addition,
claims for loss of oil and gas production and damage to
formations can occur in the well services industry. Litigation
arising from a catastrophic occurrence at a location where our
equipment and services are being used may result in us being
named as a defendant in lawsuits asserting large claims.
We maintain insurance coverage that we believe to be customary
in the industry against these hazards. However, we do not have
insurance against all foreseeable risks, either because
insurance is not available or because of the high premium costs.
We are also self-insured up to
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retention limits with regard to workers compensation and
medical and dental coverage of our employees and, with certain
exceptions, we generally maintain no physical property damage
coverage on our workover rig fleet. We maintain accruals in our
consolidated balance sheets related to self-insurance retentions
by using third-party data and historical claims history. The
occurrence of an event not fully insured against, or the failure
of an insurer to meet its insurance obligations, could result in
substantial losses. In addition, we may not be able to maintain
adequate insurance in the future at rates we consider
reasonable. Insurance may not be available to cover any or all
of these risks, or, even if available, it may be inadequate, or
insurance premiums or other costs could rise significantly in
the future so as to make such insurance prohibitive. It is
likely that, in our insurance renewals, our premiums and
deductibles will be higher, and certain insurance coverage
either will be unavailable or considerably more expensive than
it has been in the recent past. In addition, our insurance is
subject to coverage limits and some policies exclude coverage
for damages resulting from environmental contamination.
We are subject to federal, state and local regulation
regarding issues of health, safety and protection of the
environment. Under these regulations, we may become liable for
penalties, damages or costs of remediation. Any changes in laws
and government regulations could increase our costs of doing
business.
Our operations are subject to federal, state and local laws and
regulations relating to protection of natural resources and the
environment, health and safety, waste management, and
transportation of waste and other materials. Our fluid services
segment includes disposal operations into injection wells that
pose some risks of environmental liability, including leakage
from the wells to surface or subsurface soils, surface water or
groundwater. Liability under these laws and regulations could
result in cancellation of well operations, fines and penalties,
expenditures for remediation, and liability for property damage
and personal injuries. Sanctions for noncompliance with
applicable environmental laws and regulations also may include
assessment of administrative, civil and criminal penalties,
revocation of permits and issuance of corrective action orders.
Laws protecting the environment generally have become more
stringent over time and are expected to continue to do so, which
could lead to material increases in costs for future
environmental compliance and remediation. The modification or
interpretation of existing laws or regulations, or the adoption
of new laws or regulations, could curtail exploratory or
developmental drilling for oil and gas and could limit well
servicing opportunities. Some environmental laws and regulations
may impose strict liability, which means that in some situations
we could be exposed to liability as a result of our conduct that
was lawful at the time it occurred or conduct of, or conditions
caused by, prior operators or other third parties.
Clean-up costs and
other damages arising as a result of environmental laws, and
costs associated with changes in environmental laws and
regulations could be substantial and could have a material
adverse effect on our financial condition. Please read
Business Environmental Regulation for
more information on the environmental laws and government
regulations that are applicable to us.
Our indebtedness could restrict our operations and make us
more vulnerable to adverse economic conditions.
As of May 31, 2006, our total debt was $249.6 million,
including $225.0 million of Senior Notes due 2016 and
capital lease obligations in the aggregate amount of
$24.6 million. Our Senior Notes due 2016 bear interest at
7.125%, payable semi-annually in arrears on April 15 and
October 15 of each year, starting October 15, 2006. In
addition, as of May 31, 2006, we had $9.6 million of
letters of credit outstanding and availability for up to
$140.4 million of additional borrowings under our 2005
Credit Facility and the potential to expand term or revolving
borrowings under our 2005 Credit Facility by up to an additional
$75 million.
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Our current and future indebtedness could have important
consequences to you. For example, it could:
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impair our ability to make investments and obtain additional
financing for working capital, capital expenditures,
acquisitions or other general corporate purposes; |
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limit our ability to use operating cash flow in other areas of
our business because we must dedicate a substantial portion of
these funds to make principal and interest payments on our
indebtedness; |
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make us more vulnerable to a downturn in our business, our
industry or the economy in general as a substantial portion of
our operating cash flow will be required to make principal and
interest payments on our indebtedness, making it more difficult
to react to changes in our business and in industry and market
conditions; |
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limit our ability to obtain additional financing that may be
necessary to operate or expand our business; |
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put us at a competitive disadvantage to competitors that have
less debt; and |
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increase our vulnerability to interest rate increases to the
extent that we incur variable rate indebtedness. |
If we are unable to generate sufficient cash flow or are
otherwise unable to obtain the funds required to make principal
and interest payments on our indebtedness, or if we otherwise
fail to comply with the various covenants in our 2005 Credit
Facility, the indenture governing our Senior Notes or other
instruments governing any future indebtedness, we could be in
default under the terms of our 2005 Credit Facility, the
indenture governing our Senior Notes or such instruments. In the
event of a default, the holders of our indebtedness could elect
to declare all the funds borrowed under those instruments to be
due and payable together with accrued and unpaid interest, the
lenders under our 2005 Credit Facility could elect to terminate
their commitments thereunder and we or one or more of our
subsidiaries could be forced into bankruptcy or liquidation. Any
of the foregoing consequences could restrict our ability to grow
our business and cause the value of our common stock to decline.
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Our 2005 Credit Facility and the indenture governing our
Senior Notes impose restrictions on us that may affect our
ability to successfully operate our business. |
Our 2005 Credit Facility and the indenture governing our Senior
Notes limit our ability to take various actions, such as:
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limitations on the incurrence of additional indebtedness; |
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restrictions on mergers, sales or transfer of assets without the
lenders consent; and |
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limitation on dividends and distributions. |
In addition, our 2005 Credit Facility requires us to maintain
certain financial ratios and to satisfy certain financial
conditions and covenants, 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, financial
ratios or covenants would cause a default under our 2005 Credit
Facility. A default, if not waived, could result in acceleration
of the outstanding indebtedness under our 2005 Credit Facility,
in which case the debt would become immediately due and payable.
In addition, a default or acceleration of indebtedness under our
2005 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
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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 2005 Credit
Facility. Please read Managements Discussion and
Analysis of Financial Condition and Results of
Operations Liquidity and Capital
Resources Credit Facilities 2005 Credit
Facility for a discussion of our 2005 Credit Facility.
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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 Related to our Relationship with DLJ Merchant
Banking
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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 May 18, 2006, DLJ Merchant Banking Partners III, L.P.
and affiliated funds (DLJ Merchant Banking), which
are managed by affiliates of Credit Suisse, a Swiss Bank, and
Credit Suisse Securities (USA) LLC, beneficially owned
approximately 47.4% of our outstanding common stock. After
giving effect to the shares to be sold in this offering, DLJ
Merchant Banking will beneficially own approximately 26.9% of
our outstanding common stock (or approximately 23.8% if the
underwriters over-allotment option is exercised in full),
although DLJ Merchant Banking will own only approximately 17.5%
of our outstanding shares of common stock (or approximately
14.0% if the underwriters over-allotment option is
exercised in full) due to their ownership of warrants that would
not entitle DLJ Merchant Banking to vote unless the warrants
were exercised for shares. Nonetheless, 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 not be in
the best interest of the other stockholders.
Risks Related to this Distribution
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Certain stockholders shares are restricted from
immediate resale but may be sold into the market in the near
future. This could cause the market price of our common stock to
drop significantly. |
As of July 24, 2006, we had outstanding
33,827,105 shares of common stock. In addition to shares
issuable upon the exercise of options issued under our 2003
Incentive Plan, there are 4,350,000 shares that may be
issued upon the exercise of warrants held by DLJ Merchant
Banking. Of these outstanding shares, after this distribution,
17,708,335 shares will be freely tradable without
restriction under the Securities Act except for any shares
purchased by one of our affiliates as defined in
Rule 144 under the Securities Act.
After this distribution, the holders of 13,709,424 shares
(not including shares issuable upon the exercise of warrants
held by DLJ Merchant Banking) will have rights, subject to some
limited conditions, to demand that we include their shares in
registration statements that we file on their
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behalf, on our behalf or on behalf of other stockholders. By
exercising their registration rights and selling a large number
of shares, these holders could cause the price of our common
stock to decline. Furthermore, if we file a registration
statement to offer additional shares of our common stock and
have to include shares held by those holders, it could impair
our ability to raise needed capital by depressing the price at
which we could sell our common stock.
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Our certificate of incorporation and bylaws, as well as
Delaware law, contain provisions that could discourage
acquisition bids or merger proposals, which may adversely affect
the market price of our common stock. |
Our certificate of incorporation authorizes our board of
directors to issue preferred stock without stockholder approval.
If our board of directors elects to issue preferred stock, it
could be more difficult for a third party to acquire us. In
addition, some provisions of our certificate of incorporation
and bylaws could make it more difficult for a third party to
acquire control of us, even if the change of control would be
beneficial to our stockholders, including:
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a classified board of directors, so that only approximately
one-third of our directors are elected each year; |
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limitations on the removal of directors; |
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the prohibition of stockholder action by written
consent; and |
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limitations on the ability of our stockholders to call special
meetings and establish advance notice provisions for stockholder
proposals and nominations for elections to the board of
directors to be acted upon at meetings of stockholders. |
Delaware law prohibits us from engaging in any business
combination with any interested stockholder, meaning
generally that a stockholder who beneficially owns more than 15%
of our stock cannot acquire us for a period of three years from
the date this person became an interested stockholder, unless
various conditions are met, such as approval of the transaction
by our board of directors.
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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 2005 Credit Facility and the indenture governing
our Senior Notes may 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.
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If our stock price declines after this distribution, you
could lose a significant part of your investment. |
The market price of our common stock could be subject to wide
fluctuations in response to a number of factors, most of which
we cannot control, including:
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changes in securities analysts recommendations and their
estimates of our financial performance; |
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the publics reaction to our press releases, announcements
and our filings with the Securities and Exchange Commission; |
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fluctuations in broader stock market prices and volumes,
particularly among securities of oil and gas service companies; |
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changes in market valuations of similar companies; |
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additions or departures of key personnel; |
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commencement of or involvement in litigation; |
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announcements by us or our competitors of strategic alliances,
significant contracts, new technologies, acquisitions,
commercial relationships, joint ventures or capital commitments; |
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variations in our quarterly results of operations or cash flows
or those of other oil and gas service companies; |
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changes in our pricing policies or pricing policies of our
competitors; |
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future issuances and sales of our common stock; and |
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changes in general conditions in the U.S. economy,
financial markets or the oil and gas industry. |
In recent years, the stock market has experienced extreme price
and volume fluctuations. This volatility has had a significant
effect on the market price of securities issued by many
companies for reasons unrelated to the operating performance of
these companies. These market fluctuations may also result in a
lower price of our common stock.
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FORWARD-LOOKING STATEMENTS AND INDUSTRY DATA
This prospectus 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. We have based these forward-looking statements largely
on our current expectations and projections about future events
and financial trends affecting the financial condition of our
business. These forward-looking statements are subject to a
number of risks, uncertainties and assumptions, including, among
other things, the risk factors discussed in this prospectus 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
prospectus are forward-looking statements.
Although we believe that the forward-looking statements
contained in this prospectus are based upon reasonable
assumptions, the forward-looking events and circumstances
discussed in this prospectus may not occur and actual results
could differ materially from those anticipated or implied in the
forward-looking statements.
Important factors that may affect our expectations, estimates or
projections include:
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a decline in or substantial volatility of oil and gas prices,
and any related changes in expenditures by our customers; |
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the effects of future acquisitions on our business; |
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changes in customer requirements in markets or industries we
serve; |
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competition within our industry; |
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general economic and market conditions; |
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our access to current or future financing arrangements; |
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our ability to replace or add workers at economic rates; and |
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environmental and other governmental regulations. |
Our forward-looking statements speak only as of the date of this
prospectus. 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 prospectus includes market share, industry data and
forecasts that we obtained from internal company surveys
(including estimates based on our knowledge and experience in
the industry in which we operate), market research, consultant
surveys, publicly available information, industry publications
and surveys. These sources include Oil & Gas Journal
magazine, World Oil magazine, Baker Hughes Incorporated, the
Association of Energy Service Companies, and the Energy
Information Administration of the U.S. Department of
Energy. Industry surveys, publications, consultant surveys and
forecasts generally state that the information contained therein
has been obtained from sources believed to be reliable. Although
we believe such information is accurate and reliable, we have
not independently verified any of the data from third-party
sources cited or used for our managements industry
estimates, nor have we ascertained the underlying economic
assumptions relied upon therein. For example, the number of
onshore well servicing rigs in the U.S. could be lower than
our estimate to the extent our two larger competitors have
continued to report as stacked rigs equipment that is not
actually complete or subject to refurbishment. Statements as to
our position relative to our competitors or as to market share
refer to the most recent available data.
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PLAN OF DISTRIBUTION
The shares of our common stock are being registered to permit a
one time distribution of controlled securities to the partners
of Southwest Partners II, L.P. and Southwest
Partners III, L.P. and to the members of Fortress
Holdings, LLC. Neither we, nor the distributing
stockholders will receive any proceeds from this transaction.
The partners and members of the distributing stockholders who
will receive shares of our common stock in this registered
offering may sell the shares of common stock directly to
purchasers or through underwriters, broker-dealers or agents
under Section 4(1) of the Securities Act, except to the
extent any such partner or member is deemed to be our
affiliate under Rule 144 of the Securities Act.
After receiving shares of our common stock in this offering, the
partners and members of the distributing stockholders, to the
extent not deemed to be our affiliate under
Rule 144 of the Securities Act, will act independently of
us, and the distributing stockholders, in making decisions
regarding the timing, manner and size of each sale of our common
stock.
We are not aware of any plans, arrangements or understandings
between the partners or members of the distributing stockholders
and any underwriter, broker-dealer or agent regarding the sale
of the shares of common stock and we do not assure you that the
partners or members of the distributing stockholders will sell
any or all of the registered shares of common stock following
distribution. In addition, we do not assure you that the
partners or members will not transfer, devise or gift the shares
of common stock by other means not described in this prospectus.
Moreover, any securities covered by this prospectus that qualify
for sale pursuant to Rule 144 of the Securities Act may be
sold under Rule 144 rather than pursuant to this prospectus.
The distributing stockholders have agreed, among other things,
to bear all expenses payable in connection with the registration
and distribution of the shares of common stock covered by this
prospectus. We estimate that the expenses for which we will be
responsible in connection with filing this registration
statement and distribution of prospectuses will be approximately
$275,000.
The shares of common stock to be distributed pursuant to this
prospectus are listed on the New York Stock Exchange under the
trading symbol BAS.
If dealers are utilized in the sale of shares of common stock,
the partners or members will sell such shares of common stock to
the dealers as principals. The dealers may then resell such
shares of common stock to the public at varying prices to be
determined by such dealers at the time of resale. The names of
the dealers and the terms of the transaction will be set forth
in a prospectus supplement, if required.
The partners or members may also sell shares of common stock
through agents designated by them from time to time.
The partners or members may sell any of the shares of common
stock directly to purchasers. In this case, the partners or
members may not engage underwriters or agents in the offer and
sale of these shares of common stock.
The partners or members may indemnify underwriters, dealers or
agents who participate in the distribution of securities against
certain liabilities, including liabilities under the Securities
Act and agree to contribute to payments which these
underwriters, dealers or agents may be required to make.
The shares of common stock may be sold in one or more
transactions at fixed prices, at prevailing market prices at the
time of sale, at varying prices determined at the time of sale,
or at negotiated prices. Sales may be effected in transactions,
which may involve block transactions or crosses:
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on any national securities exchange or quotation service on
which the shares of common stock may be listed or quoted at the
time of sale; |
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in the over-the-counter market; |
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in transactions otherwise than on exchanges or quotation
services or in the over-the-counter market; |
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through the exercise of purchased or written options; or |
|
|
|
through any other method permitted under applicable law. |
In connection with sales of the shares of common stock or
otherwise, the partners or members may enter into hedging
transactions with broker-dealers, which may in turn engage in
short sales of the shares of common stock in the course of
hedging the positions they assume. The partners or members may
also sell short the shares of common stock and deliver the
shares of common stock to close out short positions, or loan or
pledge the shares of common stock to broker-dealers that in turn
may sell the shares of common stock.
In order to comply with the securities laws of some states, if
applicable, the shares of common stock may be sold in these
jurisdictions only through registered or licensed brokers or
dealers. In addition, in some states the shares of common stock
may not be sold unless they have been registered or qualified
for sale or an exemption from registration or qualification
requirements is available and is complied with.
The partners or members and any underwriters, broker-dealers or
agents that participate in the sale of the shares of common
stock may be underwriters within the meaning of
Section 2(11) of the Securities Act. Any discounts,
commissions, concessions or profit they earn on any resale of
the shares of common stock may be underwriting discounts and
commissions under the Securities Act. Any partner or member who
is an underwriter within the meaning of
Section 2(11) of the Securities Act will be subject to the
prospectus delivery requirements of the Securities Act. The
partners or members have acknowledged that they understand their
obligations to comply with the provisions of the Exchange Act
and the rules thereunder relating to stock manipulation,
particularly Regulation M.
22
USE OF PROCEEDS
We will not receive any net proceeds in connection with the
distribution of shares of common stock by the distributing
stockholders. However, the distributing stockholders have agreed
to pay our expenses incurred in connection with the registration
of the distribution. See Plan of Distribution.
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
Our common stock has traded on the New York Stock Exchange under
the symbol BAS since December 9, 2005. As of
August 4, 2006, there were 39 stockholders of record. The
following table sets forth, for the periods indicated, the range
of high and low sales prices for our common stock as reported by
the New York Stock Exchange:
|
|
|
|
|
|
|
|
|
|
|
Price | |
|
|
| |
|
|
High | |
|
Low | |
|
|
| |
|
| |
2005
|
|
|
|
|
|
|
|
|
Fourth Quarter(1)
|
|
$ |
22.60 |
|
|
$ |
19.10 |
|
2006
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$ |
31.15 |
|
|
$ |
19.91 |
|
Second Quarter
|
|
$ |
38.30 |
|
|
$ |
24.32 |
|
Third Quarter(2)
|
|
$ |
31.37 |
|
|
$ |
23.60 |
|
|
|
(1) |
Reflects trading activity from December 9, 2005 through
December 31, 2005. |
|
(2) |
Reflects trading activity through August 4, 2006. |
On August 4, 2006, the last reported sale price of our
common stock was $27.07 per share.
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 2005 Credit Facility
and may be limited in our ability to pay dividends under the
indenture governing our Senior Notes.
23
CAPITALIZATION
The following table sets forth our capitalization at
March 31, 2006. The information was derived from and is
qualified by reference to our financial statements included
elsewhere in this prospectus. You should read this information
in conjunction with Selected Historical Financial
Data, Managements Discussion and Analysis of
Financial Condition and Results of Operations and our
combined financial statements and the related notes thereto
included elsewhere in this prospectus.
|
|
|
|
|
|
|
|
|
|
March 31, | |
|
|
2006 | |
|
|
| |
|
|
(in thousands) | |
Cash and cash equivalents
|
|
$ |
19,953 |
|
|
|
|
|
Total long-term debt, including
current portion:
|
|
|
|
|
|
Notes payable:
|
|
|
|
|
|
|
Revolving credit facility
|
|
$ |
96,000 |
|
|
|
Term B Loan
|
|
|
89,750 |
|
|
|
Other debt and obligations under
capital leases
|
|
|
24,297 |
|
|
|
|
|
|
|
|
Total
|
|
|
210,047 |
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
Common stock, $.01 par value,
80,000,000 shares authorized; 33,931,935 shares issued
and 33,787,305 shares outstanding
|
|
|
339 |
|
|
Additional paid-in capital
|
|
|
235,264 |
|
|
Deferred compensation
|
|
|
|
|
|
Retained earnings
|
|
|
46,174 |
|
|
Treasury stock, 144,630 shares
at cost
|
|
|
(3,618 |
) |
|
Accumulated other comprehensive
income
|
|
|
82 |
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
278,241 |
|
|
|
|
|
|
|
Total capitalization
|
|
$ |
488,288 |
|
|
|
|
|
The foregoing capitalization does not reflect our issuance in
April 2006 of $225 million of Senior Notes due 2016, the
proceeds of which were used to retire the outstanding
Term B Loan balance and to pay down the outstanding balance
under our revolving credit facility. As of May 31, 2006, we
had no amounts outstanding under our revolving credit facility.
24
SELECTED HISTORICAL 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 Capitalization,
Managements Discussion and Analysis of Financial
Condition and Results of Operations and our financial
statements included elsewhere in this prospectus. The amounts
for each historical annual period presented below were derived
from our audited financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2001 | |
|
2002 | |
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited) | |
|
|
(dollars in thousands, except per share data) | |
Statement of Operations
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
$ |
62,943 |
|
|
$ |
73,848 |
|
|
$ |
104,097 |
|
|
$ |
142,551 |
|
|
$ |
221,993 |
|
|
$ |
44,798 |
|
|
$ |
73,465 |
|
|
Fluid services
|
|
|
36,766 |
|
|
|
34,170 |
|
|
|
52,810 |
|
|
|
98,683 |
|
|
|
132,280 |
|
|
|
29,303 |
|
|
|
43,121 |
|
|
Drilling and completion services
|
|
|
|
|
|
|
733 |
|
|
|
14,808 |
|
|
|
29,341 |
|
|
|
59,832 |
|
|
|
10,764 |
|
|
|
27,455 |
|
|
Well site construction services
|
|
|
|
|
|
|
|
|
|
|
9,184 |
|
|
|
40,927 |
|
|
|
45,647 |
|
|
|
8,948 |
|
|
|
10,265 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
99,709 |
|
|
|
108,751 |
|
|
|
180,899 |
|
|
|
311,502 |
|
|
|
459,752 |
|
|
|
93,813 |
|
|
|
154,306 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
|
40,906 |
|
|
|
55,643 |
|
|
|
73,244 |
|
|
|
98,058 |
|
|
|
137,392 |
|
|
|
28,191 |
|
|
|
41,610 |
|
|
Fluid services
|
|
|
21,363 |
|
|
|
22,705 |
|
|
|
34,420 |
|
|
|
65,167 |
|
|
|
82,551 |
|
|
|
19,238 |
|
|
|
26,305 |
|
|
Drilling and completion services
|
|
|
|
|
|
|
512 |
|
|
|
9,363 |
|
|
|
17,481 |
|
|
|
30,900 |
|
|
|
5,860 |
|
|
|
13,854 |
|
|
Well site construction services
|
|
|
|
|
|
|
|
|
|
|
6,586 |
|
|
|
31,454 |
|
|
|
32,000 |
|
|
|
7,108 |
|
|
|
7,643 |
|
|
General and administrative(1)
|
|
|
10,813 |
|
|
|
13,019 |
|
|
|
22,722 |
|
|
|
37,186 |
|
|
|
55,411 |
|
|
|
13,091 |
|
|
|
18,005 |
|
|
Depreciation and amortization
|
|
|
9,599 |
|
|
|
13,414 |
|
|
|
18,213 |
|
|
|
28,676 |
|
|
|
37,072 |
|
|
|
8,047 |
|
|
|
12,837 |
|
|
Loss (gain) on disposal of
assets
|
|
|
(10 |
) |
|
|
351 |
|
|
|
391 |
|
|
|
2,616 |
|
|
|
(222 |
) |
|
|
102 |
|
|
|
(200 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
82,671 |
|
|
|
105,644 |
|
|
|
164,939 |
|
|
|
280,638 |
|
|
|
375,104 |
|
|
|
81,637 |
|
|
|
120,054 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
17,038 |
|
|
|
3,107 |
|
|
|
15,960 |
|
|
|
30,864 |
|
|
|
84,648 |
|
|
|
12,176 |
|
|
|
34,252 |
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest expense
|
|
|
(3,303 |
) |
|
|
(4,750 |
) |
|
|
(5,174 |
) |
|
|
(9,550 |
) |
|
|
(12,660 |
) |
|
|
(2,960 |
) |
|
|
(2,779 |
) |
Gain (loss) on early extinguishment
of debt
|
|
|
(1,462 |
) |
|
|
|
|
|
|
(5,197 |
) |
|
|
|
|
|
|
(627 |
) |
|
|
|
|
|
|
|
|
Other income (expense)
|
|
|
16 |
|
|
|
31 |
|
|
|
146 |
|
|
|
(398 |
) |
|
|
220 |
|
|
|
75 |
|
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing
operations before income taxes
|
|
|
12,289 |
|
|
|
(1,612 |
) |
|
|
5,735 |
|
|
|
20,916 |
|
|
|
71,581 |
|
|
|
9,291 |
|
|
|
31,500 |
|
Income tax (expense) benefit
|
|
|
(4,688 |
) |
|
|
382 |
|
|
|
(2,772 |
) |
|
|
(7,984 |
) |
|
|
(26,800 |
) |
|
|
(3,490 |
) |
|
|
(11,819 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing
operations
|
|
|
7,601 |
|
|
|
(1,230 |
) |
|
|
2,963 |
|
|
|
12,932 |
|
|
|
44,781 |
|
|
|
5,801 |
|
|
|
19,681 |
|
Income (loss) from discontinued
operations, net of tax
|
|
|
|
|
|
|
|
|
|
|
22 |
|
|
|
(71 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of accounting
change, net of tax
|
|
|
|
|
|
|
|
|
|
|
(151 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
7,601 |
|
|
|
(1,230 |
) |
|
|
2,834 |
|
|
|
12,861 |
|
|
|
44,781 |
|
|
|
5,801 |
|
|
|
19,681 |
|
Preferred stock dividend
|
|
|
|
|
|
|
(1,075 |
) |
|
|
(1,525 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of preferred stock
discount
|
|
|
|
|
|
|
(374 |
) |
|
|
(3,424 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to
common stockholders
|
|
$ |
7,601 |
|
|
$ |
(2,679 |
) |
|
$ |
(2,115 |
) |
|
$ |
12,861 |
|
|
$ |
44,781 |
|
|
$ |
5,801 |
|
|
$ |
19,681 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2001 | |
|
2002 | |
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited) | |
|
|
(dollars in thousands, except per share data) | |
Basic earnings (loss) per share of
common stock(2):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations less
preferred stock dividend and accretion
|
|
$ |
0.50 |
|
|
$ |
(0.13 |
) |
|
$ |
(0.09 |
) |
|
$ |
0.46 |
|
|
$ |
1.57 |
|
|
$ |
0.21 |
|
|
$ |
0.59 |
|
|
Discontinued operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of accounting
change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to
common stockholders
|
|
$ |
0.50 |
|
|
$ |
(0.13 |
) |
|
$ |
(0.09 |
) |
|
$ |
0.46 |
|
|
$ |
1.57 |
|
|
$ |
0.21 |
|
|
$ |
0.59 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per share
of common stock(2):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations less
preferred stock dividend and accretion
|
|
$ |
0.50 |
|
|
$ |
(0.13 |
) |
|
$ |
(0.09 |
) |
|
$ |
0.42 |
|
|
$ |
1.35 |
|
|
$ |
0.18 |
|
|
$ |
0.53 |
|
|
Discontinued operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of accounting
change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to
common stockholders
|
|
$ |
0.50 |
|
|
$ |
(0.13 |
) |
|
$ |
(0.09 |
) |
|
$ |
0.42 |
|
|
$ |
1.35 |
|
|
$ |
0.18 |
|
|
$ |
0.53 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Cash
Flow:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from operating activities
|
|
$ |
14,060 |
|
|
$ |
17,012 |
|
|
$ |
29,815 |
|
|
$ |
46,539 |
|
|
$ |
99,189 |
|
|
$ |
16,734 |
|
|
$ |
25,915 |
|
Cash flows from investing activities
|
|
|
(60,305 |
) |
|
|
(45,303 |
) |
|
|
(84,903 |
) |
|
|
(73,587 |
) |
|
|
(107,679 |
) |
|
|
(19,946 |
) |
|
|
(111,584 |
) |
Cash flows from financing activities
|
|
|
50,770 |
|
|
|
21,572 |
|
|
|
79,859 |
|
|
|
21,498 |
|
|
|
21,188 |
|
|
|
(2,817 |
) |
|
|
72,777 |
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions, net of cash acquired
|
|
|
44,928 |
|
|
|
31,075 |
|
|
|
61,885 |
|
|
|
19,284 |
|
|
|
25,378 |
|
|
|
3,909 |
|
|
|
87,520 |
|
|
Property and equipment
|
|
|
15,208 |
|
|
|
14,674 |
|
|
|
23,501 |
|
|
|
55,674 |
|
|
|
83,095 |
|
|
|
16,083 |
|
|
|
24,812 |
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(3)
|
|
$ |
25,191 |
|
|
$ |
16,552 |
|
|
$ |
28,993 |
|
|
$ |
59,071 |
|
|
$ |
121,313 |
|
|
$ |
20,298 |
|
|
$ |
47,116 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, | |
|
As of | |
|
|
| |
|
March 31, | |
|
|
2001 | |
|
2002 | |
|
2003 | |
|
2004 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited) | |
|
|
(dollars in thousands) | |
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
7,645 |
|
|
$ |
926 |
|
|
$ |
25,697 |
|
|
$ |
20,147 |
|
|
$ |
32,845 |
|
|
$ |
19,953 |
|
Property and equipment, net
|
|
|
78,602 |
|
|
|
108,487 |
|
|
|
188,243 |
|
|
|
233,451 |
|
|
|
309,075 |
|
|
|
399,865 |
|
Total assets
|
|
|
126,207 |
|
|
|
156,502 |
|
|
|
302,653 |
|
|
|
367,601 |
|
|
|
496,957 |
|
|
|
616,787 |
|
Long-term debt, including current
portion
|
|
|
45,258 |
|
|
|
39,706 |
|
|
|
148,509 |
|
|
|
182,476 |
|
|
|
126,887 |
|
|
|
210,047 |
|
Mandatorily redeemable cumulative
preferred stock
|
|
|
|
|
|
|
12,093 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity
|
|
|
58,938 |
|
|
|
72,558 |
|
|
|
107,295 |
|
|
|
121,786 |
|
|
|
258,575 |
|
|
|
278,241 |
|
|
|
(1) |
Includes approximately $994,000, $1,587,000 and $2,890,000 of
non-cash stock compensation expense for the years ended
December 31, 2003, 2004 and 2005, respectively, and
$591,000 and $758,000 for the three months ended March 31,
2005 and 2006, respectively. |
|
(2) |
Reflects a 5-for-1 stock split effected as a stock dividend in
September 2005. |
|
(3) |
EBITDA means earnings before interest, taxes, depreciation and
amortization. EBITDA is used as a supplemental financial measure
by our management and directors and by external users of our
financial statements, such as investors, to assess: |
|
|
|
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis; |
|
|
the ability of our assets to generate cash sufficient to pay
interest on our indebtedness; and |
26
|
|
|
our operating performance and return on invested capital as
compared to those of other companies in the well services
industry, without regard to financing methods and capital
structure. |
|
|
|
EBITDA has limitations as an analytical tool and should not be
considered an alternative to net income, operating income, cash
flow from operating activities or any other measure of financial
performance or liquidity presented in accordance with generally
accepted accounting principles (GAAP). EBITDA excludes some, but
not all, items that affect net income and operating income, and
these measures may vary among other companies. Limitations to
using EBITDA as an analytical tool include: |
|
|
|
EBITDA does not reflect our current or future requirements for
capital expenditures or capital commitments; |
|
|
EBITDA does not reflect changes in, or cash requirements
necessary to service interest or principal payments on, our debt; |
|
|
EBITDA does not reflect income taxes; |
|
|
although depreciation and amortization are non-cash charges, the
assets being depreciated and amortized will often have to be
replaced in the future, and EBITDA does not reflect any cash
requirements for such replacements; and |
|
|
other companies in our industry may calculate EBITDA differently
than we do, limiting its usefulness as a comparative measure. |
|
|
|
The following table presents a
reconciliation of EBITDA to net income (loss), which is the most
directly comparable GAAP financial performance measure, for each
of the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months | |
|
|
|
|
Ended | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2001 | |
|
2002 | |
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited) | |
|
|
(dollars in thousands) | |
Reconciliation of EBITDA to Net
Income (Loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$ |
7,601 |
|
|
$ |
(1,230 |
) |
|
$ |
2,834 |
|
|
$ |
12,861 |
|
|
$ |
44,781 |
|
|
$ |
5,801 |
|
|
$ |
19,681 |
|
|
Income tax expense (benefit)
|
|
|
4,688 |
|
|
|
(382 |
) |
|
|
2,772 |
|
|
|
7,984 |
|
|
|
26,800 |
|
|
|
3,490 |
|
|
|
11,819 |
|
|
Net interest expense
|
|
|
3,303 |
|
|
|
4,750 |
|
|
|
5,174 |
|
|
|
9,550 |
|
|
|
12,660 |
|
|
|
2,960 |
|
|
|
2,779 |
|
|
Depreciation and amortization
|
|
|
9,599 |
|
|
|
13,414 |
|
|
|
18,213 |
|
|
|
28,676 |
|
|
|
37,072 |
|
|
|
8,047 |
|
|
|
12,837 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$ |
25,191 |
|
|
$ |
16,552 |
|
|
$ |
28,993 |
|
|
$ |
59,071 |
|
|
$ |
121,313 |
|
|
$ |
20,298 |
|
|
$ |
47,116 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27
MANAGEMENTS DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Managements Overview
We provide a wide range of well site services to oil and gas
drilling and producing companies, including well servicing,
fluid services, drilling and completion services and well site
construction services. Our results of operations since the
beginning of 2002 reflect the impact of our acquisition strategy
as a leading consolidator in the domestic land-based well
services industry during this period. Our acquisitions have
increased our breadth of service offerings at the well site and
expanded our market presence. In implementing this strategy, we
have purchased businesses and assets in 40 separate
acquisitions from January 1, 2001 to March 31, 2006.
Our weighted average number of well servicing rigs has increased
from 126 in 2001 to 327 in the first quarter of 2006, and our
weighted average number of fluid service trucks has increased
from 156 to 529 in the same period. In 2003, primarily through
acquisitions, we significantly increased our drilling and
completion (principally pressure pumping) services and entered
the well site construction services segment. These acquisitions
make changes in revenues, expenses and income not directly
comparable.
Our operating revenues from each of our segments, and their
relative percentages of our total revenues, consisted of the
following (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
$ |
104.1 |
|
|
|
58 |
% |
|
$ |
142.6 |
|
|
|
46 |
% |
|
$ |
222.0 |
|
|
|
48 |
% |
|
$ |
44.8 |
|
|
|
48 |
% |
|
$ |
73.5 |
|
|
|
47 |
% |
Fluid services
|
|
|
52.8 |
|
|
|
29 |
% |
|
|
98.7 |
|
|
|
32 |
% |
|
|
132.3 |
|
|
|
29 |
% |
|
|
29.3 |
|
|
|
31 |
% |
|
|
43.1 |
|
|
|
28 |
% |
Drilling and completion services
|
|
|
14.8 |
|
|
|
8 |
% |
|
|
29.3 |
|
|
|
9 |
% |
|
|
59.8 |
|
|
|
13 |
% |
|
|
10.8 |
|
|
|
11 |
% |
|
|
27.4 |
|
|
|
18 |
% |
Well site construction services
|
|
|
9.2 |
|
|
|
5 |
% |
|
|
40.9 |
|
|
|
13 |
% |
|
|
45.7 |
|
|
|
10 |
% |
|
|
8.9 |
|
|
|
10 |
% |
|
|
10.3 |
|
|
|
7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$ |
180.9 |
|
|
|
100 |
% |
|
$ |
311.5 |
|
|
|
100 |
% |
|
$ |
459.8 |
|
|
|
100 |
% |
|
$ |
93.8 |
|
|
|
100 |
% |
|
$ |
154.3 |
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our core businesses depend on our customers willingness to
make expenditures to produce, develop and explore for oil and
gas in the United States. Industry conditions are influenced by
numerous factors, such as the supply of and demand for oil and
gas, domestic and worldwide economic conditions, political
instability in oil producing countries and merger and
divestiture activity among oil and gas producers. The volatility
of the oil and gas industry, and the consequent impact on
exploration and production activity, could adversely impact the
level of drilling and workover activity by some of our
customers. This volatility affects the demand for our services
and the price of our services. In addition, the discovery rate
of new oil and gas reserves in our market areas also may have an
impact on our business, even in an environment of stronger oil
and gas prices. For a more comprehensive discussion of our
industry trends, see Business General Industry
Overview.
We derive a majority of our revenues from services supporting
production from existing oil and gas operations. Demand for
these production related services, including well servicing and
fluid services, tends to remain relatively stable 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 our production related services
generally increases as our customers increase spending for
drilling new wells and well servicing activities related to
maintaining or increasing production from existing wells.
Because our services are required to support drilling and
workover activities, we are also subject to changes in capital
spending by our customers as oil and gas prices increase or
decrease.
28
We believe that the most important performance measures for our
lines of business are as follows:
|
|
|
|
|
Well Servicing rig hours, rig utilization rate,
revenue per rig hour and segment profits as a percent of
revenues; |
|
|
|
Fluid Services revenue per truck and segment profits
as a percent of revenues; |
|
|
|
Drilling and Completion Services segment profits as
a percent of revenues; and |
|
|
|
Well Site Construction Services segment profits as a
percent of revenues. |
Segment profits are computed as segment operating revenues less
direct operating costs. These measurements provide important
information to us about the activity and profitability of our
lines of business. For a detailed analysis of these indicators
for our company, see below in Segment
Overview.
We intend to continue growing our business through selective
acquisitions, continuing a newbuild program and/or upgrading our
existing assets. Our capital investment decisions are determined
by an analysis of the projected return on capital employed of
each of those alternatives, which is substantially driven by the
cost to acquire existing assets from a third party, the capital
required to build new equipment and the point in the oil and gas
commodity price cycle. Based on these factors, we make capital
investment decisions that we believe will support our long-term
growth strategy. While we believe our costs of integration for
prior acquisitions have been reflected in our historical results
of operations, integration of acquisitions may result in
unforeseen operational difficulties or require a
disproportionate amount of our managements attention. As
discussed below in Liquidity and Capital
Resources, we also must meet certain financial covenants
in order to borrow money under our existing credit agreement to
fund future acquisitions.
Recent Strategic Acquisitions and Expansions
During the period from 2003 through 2005, we grew significantly
through acquisitions and capital expenditures. During 2003, this
growth was focused more on acquisitions of new lines of related
business and of regional platforms for our existing businesses.
During 2004 and 2005, we directed our focus for growth more on
the integration and expansion of our existing businesses,
through capital expenditures and to a lesser extent,
acquisitions. During the first quarter of 2006, we completed
three additional acquisitions, one of which was significant for
purposes of Statement of Financial Accounting Standards
No. 141 Business Combinations.
We discuss the aggregate purchase prices and related financing
issues below in Liquidity and Capital
Resources and present the pro forma effects of the
acquisition of G&L in note 3 of the unaudited
historical financial statements included in this prospectus.
Selected 2003 Acquisitions
The following is a summary of our four largest acquisitions
during 2003. These acquisitions are indicative of our strategic
expansion into new lines of business.
New Force Energy Services, Inc.
|
|
|
On January 27, 2003, we completed the acquisition of the
business and assets of New Force Energy Services, Inc., a
pressure pumping services company in north central Texas. This
acquisition added 31 pressure pumping units and associated
support equipment and three new locations in north central Texas
and increased the services offered in our Permian Basin,
North Texas and
Ark-La-Tex divisions.
This transaction was structured as an asset purchase for a total
purchase price of approximately $7.7 million in cash and up
to an additional $2.7 million in future contingent earnest
payments, of which $1.6 million had been earned as of
December 31, 2005. |
29
FESCO Holdings, Inc./ First Energy Services Company
|
|
|
On October 3, 2003, we completed the acquisition of
FESCO Holdings, Inc., which we refer to as FESCO, a fluid
and well site construction services provider that operates
through its subsidiary First Energy Services Company.
FESCOs operations are concentrated in Wyoming, Montana,
North Dakota and Colorado and historically have been
largely dependent on drilling activity in the Rocky Mountain
states. This transaction extended our operating presence in the
Rocky Mountain states, a region that we expect will experience
increased levels of demand for well site and fluid services due
to increased drilling activity. We have supplemented
FESCOs fluid services capabilities with our well servicing
capabilities and equipment to provide additional service
offerings in the Rocky Mountain states. The transaction was
structured as a stock-for-stock merger for a total purchase
price of approximately $37.9 million, including
$19.1 million of assumed FESCO debt. |
PWI Inc.
|
|
|
On October 3, 2003, we completed the acquisition of
substantially all the operating assets of PWI Inc. and
certain other affiliated entities, which we refer to as PWI, a
provider of onshore oilfield fluid, equipment rental, and well
site construction services. These services include fluid
transportation and sales, disposal services, oilfield equipment
rental, well site construction and lease maintenance work.
Through eight locations, PWI operated primarily in southeast
Texas and southwest Louisiana. The PWI acquisition substantially
enhanced our existing onshore Gulf Coast well servicing
operations by adding fluid services and well site construction
services to this market. This acquisition provided us
established operations in an active region and enables us to
cross-sell additional services in the area. We acquired the
assets of PWI for $25.1 million in cash and up to an
additional $2.5 million in future contingent earn-out
payments. The contingent earn-out agreement was terminated by
the parties entering into an agreement to pay $75,000 per
year for four years beginning in October 2005. |
Pennant Services Company
|
|
|
On October 3, 2003, we completed the acquisition of
substantially all of the operating assets of Pennant Services
Company, a well servicing company with operations in Wyoming and
Utah. This acquisition added 13 well servicing rigs and
associated workover equipment to our fleet, which have been
integrated with FESCOs operations to expand the range of
services and equipment that we offer to customers in the Rocky
Mountain states. We acquired these assets for $7.4 million
in cash. |
Selected 2004 Acquisitions
During 2004, we made a number of smaller acquisitions and
capital expenditures that we anticipate will serve as a platform
for future growth. These include:
Energy Air Drilling
|
|
|
On August 30, 2004, we completed the acquisition of Energy
Air Drilling Service Company, an underbalanced drilling services
company, with operations in Farmington, New Mexico, and
Grand Junction, Colorado. This acquisition added 18 air
drilling packages, four trailer mounted foam units, and
additional compressors and boosters. This acquisition provided a
platform to expand into the Southern Rockies market area, while
expanding our service offerings. The transaction was structured
as a securities purchase for a total purchase price of
approximately $6.5 million in cash. |
30
AWS Wireline Services
|
|
|
On November 1, 2004, we completed the acquisition of
substantially all of the operating assets of AWS Wireline
Services, a cased-hole wireline company based in Albany, Texas.
This acquisition of six wireline units was our initial entry
into the wireline business. This service is complementary to our
existing pressure pumping service organization infrastructure in
this same market area. This transaction was structured as an
asset purchase for a total purchase price of approximately
$4.3 million in cash. |
Selected 2005 Acquisitions
During 2005, we made several acquisitions that complement our
existing lines of business. These included, among others:
MD Well Service, Inc.
|
|
|
On May 17, 2005, we completed the acquisition of MD Well
Service, Inc., a well servicing company operating in the Rocky
Mountain region. This transaction was structured as an asset
purchase for a total purchase price of $6.0 million. |
Oilwell Fracturing Services, Inc.
|
|
|
On October 10, 2005, we completed the acquisition of
Oilwell Fracturing Services, Inc., a pressure pumping services
company that provides acidizing and fracturing services with
operations in central Oklahoma. This acquisition will strengthen
the presence of our drilling and completion services segment in
our Mid Continent division. This transaction was structured as a
stock purchase for a total purchase price of approximately
$16.1 million. The assets acquired in the acquisition
included approximately $2.3 million in cash. The cash used
to acquire Oilwell Fracturing Services was primarily from
borrowings under our 2005 Credit Facility. |
Selected 2006 Acquisitions
During the first quarter of 2006, we made three acquisitions
that complement our existing lines of business and increased our
presence in the rental tool business. These included:
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. The
acquisition will operate in our fluid services line of business
in the Ark-La-Tex division. The cash used to acquire LeBus was
primarily from borrowings under our 2005 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 million cash. This acquisition
will operate in our drilling and completion line of business.
The purchase agreement also contained an earn-out agreement
based on annual EBITDA targets. The cash used to acquire G&L
was primarily from borrowings under our 2005 Credit Facility.
Certain pro forma effects of this acquisition are set forth in
note 3 of the unaudited historical financial statements
included in this prospectus. |
Segment Overview
Well Servicing
|
|
|
In 2005, our well servicing segment represented 48% of our
revenues and, during the first three months of 2006, 47% of our
revenues. Revenue in our well servicing segment is derived |
31
|
|
|
from maintenance, workover, completion and plugging and
abandonment services. We provide maintenance related services as
part of the normal, periodic upkeep of producing oil and gas
wells. Maintenance-related services represent a relatively
consistent component of our business. Workover and completion
services generate more revenue per hour than maintenance work
due to the use of auxiliary equipment, but demand for workover
and completion services fluctuates more with the overall
activity level in the industry. |
We typically charge our customers for services on an hourly
basis at rates that are determined by the type of service and
equipment required, market conditions in the region in which the
rig operates, the ancillary equipment provided on the rig and
the necessary personnel. Depending on the type of job, we may
also charge by the project or by the day. We measure our
activity levels by the total number of hours worked by all of
the rigs in our fleet. We monitor our fleet utilization levels,
with full utilization deemed to be 55 hours per week per
rig. Through acquisitions and individual equipment purchases,
our fleet has more than tripled since the beginning of 2001.
The following is an analysis of our well servicing operations
for each of the quarters and years in the years ended
December 31, 2003, 2004 and 2005 and the quarter ended
March 31, 2006 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted | |
|
|
|
|
|
|
|
Segment | |
|
|
|
|
Average | |
|
|
|
Rig | |
|
Revenue | |
|
Profits | |
|
|
|
|
Number | |
|
Rig | |
|
Utilization | |
|
per | |
|
per | |
|
Segment | |
|
|
of Rigs | |
|
Hours | |
|
Rate | |
|
Rig Hour | |
|
Rig Hour | |
|
Profits % | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
2003:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
252 |
|
|
|
128,200 |
|
|
|
71.2% |
|
|
$ |
188 |
|
|
$ |
52 |
|
|
|
27.2% |
|
Second Quarter
|
|
|
252 |
|
|
|
131,000 |
|
|
|
72.7% |
|
|
$ |
195 |
|
|
$ |
62 |
|
|
|
31.8% |
|
Third Quarter
|
|
|
252 |
|
|
|
133,200 |
|
|
|
73.9% |
|
|
$ |
200 |
|
|
$ |
62 |
|
|
|
30.8% |
|
Fourth Quarter
|
|
|
270 |
|
|
|
131,500 |
|
|
|
68.1% |
|
|
$ |
211 |
|
|
$ |
59 |
|
|
|
28.6% |
|
Full Year
|
|
|
257 |
|
|
|
523,900 |
|
|
|
71.4% |
|
|
$ |
199 |
|
|
$ |
59 |
|
|
|
29.6% |
|
2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
272 |
|
|
|
145,900 |
|
|
|
75.0% |
|
|
$ |
218 |
|
|
$ |
69 |
|
|
|
31.5% |
|
Second Quarter
|
|
|
276 |
|
|
|
154,600 |
|
|
|
78.4% |
|
|
$ |
222 |
|
|
$ |
69 |
|
|
|
31.1% |
|
Third Quarter
|
|
|
282 |
|
|
|
162,400 |
|
|
|
80.5% |
|
|
$ |
234 |
|
|
$ |
72 |
|
|
|
30.6% |
|
Fourth Quarter
|
|
|
284 |
|
|
|
155,900 |
|
|
|
76.8% |
|
|
$ |
246 |
|
|
$ |
78 |
|
|
|
31.7% |
|
Full Year
|
|
|
279 |
|
|
|
618,800 |
|
|
|
77.8% |
|
|
$ |
230 |
|
|
$ |
72 |
|
|
|
31.2% |
|
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
291 |
|
|
|
175,300 |
|
|
|
84.3% |
|
|
$ |
255 |
|
|
$ |
94 |
|
|
|
37.1% |
|
Second Quarter
|
|
|
303 |
|
|
|
192,400 |
|
|
|
88.8% |
|
|
$ |
280 |
|
|
$ |
107 |
|
|
|
38.2% |
|
Third Quarter
|
|
|
311 |
|
|
|
198,000 |
|
|
|
89.0% |
|
|
$ |
299 |
|
|
$ |
108 |
|
|
|
36.0% |
|
Fourth Quarter
|
|
|
316 |
|
|
|
195,000 |
|
|
|
86.3% |
|
|
$ |
329 |
|
|
$ |
134 |
|
|
|
40.7% |
|
Full Year
|
|
|
305 |
|
|
|
760,700 |
|
|
|
87.1% |
|
|
$ |
292 |
|
|
$ |
111 |
|
|
|
38.1% |
|
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
327 |
|
|
|
209,000 |
|
|
|
89.4% |
|
|
$ |
352 |
|
|
$ |
152 |
|
|
|
43.4% |
|
We gauge activity levels in our well servicing segment based on
rig utilization rate, revenue per rig hour and segment profits
per rig hour.
Improving market conditions since 2003 have created increased
demand for our services. Rig hours have increased due to a
combination of the improved utilization of our well servicing
rigs and the expansion of our well servicing fleet as a result
of our newbuild rig program.
We have been able to increase our revenue per rig hour from $188
in the first quarter of 2003 to $352 in the first quarter of
2006 mainly as a result of this higher utilization, which has
contributed to our improved segment profits.
32
Fluid Services
|
|
|
In 2005, our fluid services segment represented 29% of our
revenues and, during the first three months of 2006, 28% of our
revenues. Revenues in our fluid services segment are earned from
the sale, transportation, storage and disposal of fluids used in
the drilling, production and maintenance of oil and gas wells.
The fluid services segment has a base level of business
consisting of transporting and disposing of salt water produced
as a by-product of the production of oil and gas. These services
are necessary for our customers and generally have a stable
demand but typically produce lower relative segment profits than
other parts of our fluid services segment. Fluid services for
completion and workover projects typically require fresh or
brine water for making drilling mud, circulating fluids or frac
fluids used during a job, and all of these fluids require
storage tanks and hauling and disposal. Because we can provide a
full complement of fluid sales, trucking, storage and disposal
required on most drilling and workover projects, the add-on
services associated with drilling and workover activity enable
us to generate higher segment profits contributions. The higher
segment profits are due to the relatively small incremental
labor costs associated with providing these services in addition
to our base fluid services segment. We typically price fluid
services by the job, by the hour or by the quantities sold,
disposed of or hauled. |
The following is an analysis of our fluid services operations
for each of the quarters and years in the years ended
December 31, 2003, 2004 and 2005 and the quarter ended
March 31, 2006 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted | |
|
|
|
|
|
|
|
|
Average | |
|
|
|
Segment | |
|
|
|
|
Number of | |
|
Revenue per | |
|
Profits per | |
|
|
|
|
Fluid Service | |
|
Fluid Service | |
|
Fluid Service | |
|
Segment | |
|
|
Trucks | |
|
Truck | |
|
Truck | |
|
Profits % | |
|
|
| |
|
| |
|
| |
|
| |
2003:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
202 |
|
|
$ |
51 |
|
|
$ |
16 |
|
|
|
32.4% |
|
Second Quarter
|
|
|
209 |
|
|
$ |
53 |
|
|
$ |
18 |
|
|
|
34.7% |
|
Third Quarter
|
|
|
223 |
|
|
$ |
50 |
|
|
$ |
18 |
|
|
|
35.3% |
|
Fourth Quarter
|
|
|
363 |
|
|
$ |
56 |
|
|
$ |
21 |
|
|
|
35.8% |
|
Full Year
|
|
|
249 |
|
|
$ |
212 |
|
|
$ |
74 |
|
|
|
34.8% |
|
2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
371 |
|
|
$ |
60 |
|
|
$ |
21 |
|
|
|
34.5% |
|
Second Quarter
|
|
|
376 |
|
|
$ |
61 |
|
|
$ |
20 |
|
|
|
33.4% |
|
Third Quarter
|
|
|
386 |
|
|
$ |
67 |
|
|
$ |
23 |
|
|
|
33.7% |
|
Fourth Quarter
|
|
|
411 |
|
|
$ |
68 |
|
|
$ |
23 |
|
|
|
34.3% |
|
Full Year
|
|
|
386 |
|
|
$ |
256 |
|
|
$ |
87 |
|
|
|
34.0% |
|
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
435 |
|
|
$ |
67 |
|
|
$ |
24 |
|
|
|
34.3% |
|
Second Quarter
|
|
|
447 |
|
|
$ |
71 |
|
|
$ |
26 |
|
|
|
37.0% |
|
Third Quarter
|
|
|
465 |
|
|
$ |
74 |
|
|
$ |
28 |
|
|
|
38.6% |
|
Fourth Quarter
|
|
|
472 |
|
|
$ |
79 |
|
|
$ |
31 |
|
|
|
39.8% |
|
Full Year
|
|
|
455 |
|
|
$ |
291 |
|
|
$ |
109 |
|
|
|
37.6% |
|
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
529 |
|
|
$ |
82 |
|
|
$ |
32 |
|
|
|
39.0% |
|
We gauge activity levels in our fluid services segment based on
revenues and segment profits per fluid service truck.
We substantially increased our fluid services truck fleet as the
result of the PWI and FESCO acquisitions in the fourth quarter
of 2003. Improved market conditions since 2003 have enabled
33
us to further increase our fluid services truck fleet through
internal expansion. We also expanded this segment with the
acquisition of LeBus during the first quarter of 2006.
The majority of the increase in revenue per fluid services truck
from $51,000 in the first quarter of 2003 to $82,000 in the
first quarter of 2006 is due to the revenues derived from the
expansion of our frac tank fleet and disposal facilities as well
as increases in prices charged for our services. Our segment
profits per fluid services truck have increased because of these
factors and increased utilization of our equipment.
Drilling and Completion Services
In 2005, our drilling and completion services segment
represented 13% of our revenues and, during the first three
months of 2006, 18% of our revenue. Revenues from our drilling
and completion services segment are generally derived from a
variety of services designed to stimulate oil and gas production
or place cement slurry within the wellbores. Our drilling and
completion services segment includes pressure pumping,
cased-hole wireline services, underbalanced drilling and fishing
and rental tool operations.
Our pressure pumping operations concentrate on providing single
truck, lower horsepower cementing, acidizing and fracturing
services in selected markets. We entered the market for pressure
pumping in East Texas during late 2002, and we expanded our
presence with the acquisition of New Force in January 2003. We
entered this market in the Rocky Mountain states with the
acquisition of FESCO, which had a small cementing business based
in Gillette, Wyoming. In December 2003, we acquired the assets
of Graham Acidizing and integrated these assets into our North
Texas and East Texas operations.
We entered the wireline business in 2004 as part of our
acquisition of AWS Wireline, a regional firm based in North
Texas. We entered the underbalanced drilling services business
in 2004 through our acquisition of Energy Air Drilling Services,
a business operating in northwest New Mexico and the western
slope of Colorado markets. For a description of our wireline and
underbalanced drilling services, please read
Business Overview of Our Segments and
Services Drilling and Completion Services
Segment.
We entered the fishing and rental tool business through our
acquisition of G&L in the first quarter of 2006.
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.
34
The following is an analysis of our drilling and completion
services for each of the quarters and years in the years ended
December 31, 2003, 2004 and 2005 and the quarter ended
March 31, 2006 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment | |
|
|
Revenues | |
|
Profits % | |
|
|
| |
|
| |
2003:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$ |
2,642 |
|
|
|
45.3% |
|
Second Quarter
|
|
$ |
3,454 |
|
|
|
32.7% |
|
Third Quarter
|
|
$ |
4,183 |
|
|
|
38.2% |
|
Fourth Quarter
|
|
$ |
4,529 |
|
|
|
33.6% |
|
Full Year
|
|
$ |
14,808 |
|
|
|
36.8% |
|
2004:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$ |
4,865 |
|
|
|
35.5% |
|
Second Quarter
|
|
$ |
7,251 |
|
|
|
46.0% |
|
Third Quarter
|
|
$ |
8,463 |
|
|
|
41.0% |
|
Fourth Quarter
|
|
$ |
8,762 |
|
|
|
38.0% |
|
Full Year
|
|
$ |
29,341 |
|
|
|
40.4% |
|
2005:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$ |
10,764 |
|
|
|
45.6% |
|
Second Quarter
|
|
$ |
13,512 |
|
|
|
49.1% |
|
Third Quarter
|
|
$ |
15,883 |
|
|
|
48.2% |
|
Fourth Quarter
|
|
$ |
19,673 |
|
|
|
49.5% |
|
Full Year
|
|
$ |
59,832 |
|
|
|
48.4% |
|
2006:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$ |
27,455 |
|
|
|
49.5% |
|
We gauge the performance of our drilling and completion services
segment based on the segments operating revenues and
segment profits. Improved market conditions since 2003 have
enabled us to increase our pricing for these services,
contributing to the improved segment profits as a percentage of
segment revenues.
Well Site Construction Services
In 2005, our well site construction services segment represented
10% of our revenues and, during the first three months of 2006,
7% of our revenues. Revenues from our well site construction
services segment are derived primarily from preparing and
maintaining access roads and well locations, installing small
diameter gathering lines and pipelines, constructing foundations
to support drilling rigs and providing maintenance services for
oil and gas facilities. We entered the well site construction
services segment during the fourth quarter of 2003 in the Gulf
Coast through the acquisition of PWI and in the Rocky Mountain
states through our acquisition of FESCO.
Within this segment, we generally charge established hourly
rates or competitive bid for projects depending on customer
specifications and equipment and personnel requirements. This
segment allows us to perform services to customers outside the
oil and gas industry, since substantially all of our power units
are general purpose construction equipment. However, the
majority of our current business in this segment is with
customers in the oil and gas industry. If our customer base has
the demand for certain types of power units that we do not
currently own, we generally purchase or lease them without
significant delay.
35
The following is an analysis of our well site construction
services for the quarter ended December 31, 2003 (when we
first entered this segment), each of the quarters and years in
the years ended December 31, 2004 and 2005 and the quarter
ended March 31, 2006 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment | |
|
|
Revenues | |
|
Profits % | |
|
|
| |
|
| |
2003:
|
|
|
|
|
|
|
|
|
Fourth Quarter
|
|
$ |
9,184 |
|
|
|
28.3% |
|
2004:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$ |
8,776 |
|
|
|
24.6% |
|
Second Quarter
|
|
$ |
9,869 |
|
|
|
21.3% |
|
Third Quarter
|
|
$ |
11,297 |
|
|
|
24.3% |
|
Fourth Quarter
|
|
$ |
10,985 |
|
|
|
22.4% |
|
Full Year
|
|
$ |
40,927 |
|
|
|
23.1% |
|
2005:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$ |
8,948 |
|
|
|
20.6% |
|
Second Quarter
|
|
$ |
10,918 |
|
|
|
30.8% |
|
Third Quarter
|
|
$ |
11,367 |
|
|
|
31.6% |
|
Fourth Quarter
|
|
$ |
14,414 |
|
|
|
33.6% |
|
Full Year
|
|
$ |
45,647 |
|
|
|
29.9% |
|
2006:
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$ |
10,265 |
|
|
|
25.5% |
|
We gauge the performance of our well site construction services
segment based on the segments operating revenues and
segment profits. While we monitor our levels of idle equipment,
we do not focus on revenues per piece of equipment. To the
extent we believe we have excess idle power units, we may be
able to divest ourselves of certain types of power units.
Operating Cost Overview
Our operating costs are comprised primarily of labor, including
workers compensation and health insurance, repair and
maintenance, fuel and insurance. A majority of our employees are
paid on an hourly basis. With a reduced pool of workers in the
industry, it is possible that we will have to raise wage rates
to attract workers from other fields and retain or expand our
current work force. We believe we will be able to increase
service rates to our customers to compensate for wage rate
increases. We also incur costs to employ personnel to sell and
supervise our services and perform maintenance on our fleet.
These costs are not directly tied to our level of business
activity. Compensation for our administrative personnel in local
operating yards and in our corporate office is accounted for as
general and administrative expenses. Repair and maintenance is
performed by our crews, company maintenance personnel and
outside service providers. Insurance is generally a fixed cost
regardless of utilization and relates to the number of rigs,
trucks and other equipment in our fleet, employee payroll and
safety record.
Critical Accounting Policies and Estimates
Our consolidated financial statements are impacted by the
accounting policies used and the estimates and assumptions made
by management during their preparation. A complete summary of
these policies is included in note 2 of the notes to our
audited historical consolidated financial statements. The
following is a discussion of our critical accounting policies
and estimates.
36
Critical Accounting Policies
We have identified below accounting policies that are of
particular importance in the presentation of our financial
position, results of operations and cash flows and which require
the application of significant judgment by management.
Property and Equipment. Property and equipment are stated
at cost, or at estimated fair value at acquisition date if
acquired in a business combination. Expenditures for repairs and
maintenance are charged to expense as incurred. We also review
the capitalization of refurbishment of workover rigs as
described in note 2 of the notes to our audited historical
consolidated financial statements.
Impairments. We review our assets for impairment at a
minimum annually, or whenever, in managements judgment,
events or changes in circumstances indicate that the carrying
amount of a long-lived asset may not be recovered over its
remaining service life. Provisions for asset impairment are
charged to income when the sum of the estimated future cash
flows, on an undiscounted basis, is less than the assets
carrying amount. When impairment is indicated, an impairment
charge is recorded based on an estimate of future cash flows on
a discounted basis.
Self-Insured Risk Accruals. We are self-insured up to
retention limits with regard to workers compensation and
medical and dental coverage of our employees. We generally
maintain no physical property damage coverage on our workover
rig fleet, with the exception of certain of our
24-hour workover rigs
and newly manufactured rigs. We have deductibles per occurrence
for workers compensation and medical and dental coverage
of $150,000 and $125,000, respectively. We have lower
deductibles per occurrence for automobile liability and general
liability. We maintain accruals in our consolidated balance
sheets related to self-insurance retentions by using third party
data and historical claims history.
Revenue Recognition. We recognize revenues when the
services are performed, collection of the relevant receivables
is probable, persuasive evidence of the arrangement exists and
the price is fixed and determinable.
Income Taxes. We account for income taxes based upon
Statement of Financial Accounting Standards No. 109,
Accounting for Income Taxes
(SFAS No. 109). Under
SFAS No. 109, deferred tax assets and liabilities are
recognized for the future tax consequences attributable to
differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases.
Deferred tax assets and liabilities are measured using statutory
tax rates expected to apply to taxable income in the years in
which those temporary differences are expected to be recovered
or settled. The effect on deferred tax assets and liabilities of
a change in tax 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
37
values of these items. Our estimates may be affected by such
factors as changing market conditions, technological advances in
industry or changes in regulations governing the industry.
Impairment of Property and Equipment. Our impairment of
property and equipment requires us to estimate undiscounted
future cash flows. Actual impairment charges are recorded using
an estimate of discounted future cash flows. The determination
of future cash flows requires us to estimate rates and
utilization in future periods and such estimates can change
based on market conditions, technological advances in industry
or changes in regulations governing the industry.
Allowance for Doubtful Accounts. We estimate our
allowance for doubtful accounts based on an analysis of
historical collection activity and specific identification of
overdue accounts. Factors that may affect this estimate include
(1) changes in the financial position of significant
customers and (2) a decline in commodity prices that could
affect the entire customer base.
Litigation and Self-Insured Risk Reserves. We estimate
our reserves related to litigation and self-insure risk based on
the facts and circumstances specific to the litigation and
self-insured risk claims and our past experience with similar
claims. The actual outcome of litigated and insured claims could
differ significantly from estimated amounts. As discussed in
Self-Insured Risk Accruals above with
respect to our critical accounting policies, we maintain
accruals on our balance sheet to cover self-insured retentions.
These accruals are based on certain assumptions developed using
third party data and historical data to project future losses.
Loss estimates in the calculation of these accruals are adjusted
based upon actual claim settlements and reported claims.
Fair Value of Assets Acquired and Liabilities Assumed. We
estimate the fair value of assets acquired and liabilities
assumed in business combinations, which involves the use of
various assumptions. These estimates may be affected by such
factors as changing market conditions, technological advances in
industry or changes in regulations governing the industry. The
most significant assumptions, and the ones requiring the most
judgment, involve the estimated fair value of property and
equipment, intangible assets and the resulting amount of
goodwill, if any. Our adoption of SFAS No. 142 on
January 1, 2002 requires us to test annually for impairment
the goodwill and intangible assets with indefinite useful lives
recorded in business combinations. This requires us to estimate
the fair values of our own assets and liabilities at the
reporting unit level. Therefore, considerable judgment, similar
to that described above in connection with our estimation of the
fair value of acquired companies, is required to assess goodwill
and certain intangible assets for impairment.
Cash Flow Estimates. Our estimates of future cash flows
are based on the most recent available market and operating data
for the applicable asset or reporting unit at the time the
estimate is made. Our cash flow estimates are used for asset
impairment analyses.
Stock Based Compensation. On January 1, 2006, we
adopted the fair value recognition provisions of Statement of
Financial Accounting Standards No. 123R,
Share-Based Payment
(SFAS No. 123R). Prior to January 1,
2006, we accounted for share-based payments under the
recognition and measurement provisions of Accounting Principles
Board Opinion No. 25, Accounting for Stock issued
to Employees (APB No. 25) which was
permitted by Statement of Financial Accounting Standards
No. 123, Accounting for Stock-Based
Compensation (SFAS No. 123).
We adopted FAS 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 our becoming a public
company. Awards granted prior to our 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
38
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.
We used a market approach to estimate our enterprise value at
the dates on which options were granted. Our market approach
uses estimates of EBITDA and cash flows multiplied by relevant
market multiples. We used market multiples of publicly traded
energy service companies that were supplied by investment
bankers in order to estimate our enterprise value. The
assumptions underlying the estimates are consistent with our
business plan. The risks associated with achieving our forecasts
were assessed in the multiples we utilized. Had different
multiples been utilized, the valuations would have been
different.
As disclosed in note 10 to our audited historical
consolidated financial statements for the year ended
December 31, 2005, we granted stock options as follows for
the year ended December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted | |
|
Weighted | |
|
Weighted | |
|
|
Number | |
|
Average | |
|
Average | |
|
Average | |
|
|
of Options | |
|
Exercise | |
|
Fair Value | |
|
Intrinsic Value | |
Grants Made |
|
Granted | |
|
Price | |
|
Per Share | |
|
Per Share | |
|
|
| |
|
| |
|
| |
|
| |
January 2005
|
|
|
100,000 |
|
|
$ |
5.16 |
|
|
$ |
9.63 |
|
|
$ |
4.47 |
|
March 2005
|
|
|
865,000 |
|
|
$ |
6.98 |
|
|
$ |
12.78 |
|
|
$ |
5.80 |
|
May 2005
|
|
|
5,000 |
|
|
$ |
6.98 |
|
|
$ |
15.48 |
|
|
$ |
8.50 |
|
December 2005
|
|
|
37,500 |
|
|
$ |
21.01 |
|
|
$ |
21.01 |
|
|
$ |
0.00 |
|
The reasons for the differences between the fair value per share
at the option grant date and our December 2005 initial public
offering price of $20.00 are as follows:
|
|
|
|
|
During the three months ended March 31, 2005, we closed
four acquisitions which added two well servicing rigs, 12 fluid
hauling trucks/trailers, two salt water disposal wells and other
equipment. Industry conditions also improved in the first
quarter. As a result of this, our revenues exceeded the first
quarter projected revenues by 12%. In addition, we placed an
order for six new well servicing rigs which were delivered
throughout the remainder of 2005. |
|
|
|
During the three months ended June 30, 2005, we closed two
acquisitions which added six well servicing rigs and additional
pressure pumping equipment. Demand for our equipment and
services continued to strengthen during this quarter. Our well
servicing rig revenue per hour increased by 10% from the first
quarter of 2005. Based on the market outlook, we placed an order
for an additional 24 new well servicing rigs, five of which
were put into service later in 2005. |
|
|
|
We increased our projected EBITDA and cash flows for 2005 and
2006 due to the acquisitions and improved operating results. |
|
|
|
Market prices of publicly traded energy service companies have
increased significantly from January 1, 2005 due to
increases in demand caused by increasing commodity prices. |
Based on the IPO price of $20.00, the intrinsic value of the
options granted in the last twelve months was
$12.8 million, all of which related to unvested options. We
have recorded
39
deferred compensation related to these options of
$5.2 million, which is being recorded to compensation
expense over the service period.
Income Taxes. The amount and availability of our loss
carryforwards (and certain other tax attributes) are subject to
a variety of interpretations and restrictive tests. The
utilization of such carryforwards could be limited or lost upon
certain changes in ownership and the passage of time.
Accordingly, although we believe substantial loss carryforwards
are available to us, no assurance can be given concerning the
realization of such loss carryforwards, or whether or not such
loss carryforwards will be available in the future.
Asset Retirement Obligations. SFAS No. 143
requires us to record the fair value of an asset retirement
obligation as a liability in the period in which it becomes 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.
Three Months Ended March 31, 2006 Compared to Three
Months Ended March 31, 2005
Revenues. Revenues increased 64% to $154.3 million
in the first three months in 2006 from $93.8 million during
the same period in 2005. This increase was primarily due to the
internal expansion of our business segments, particularly well
servicing and fluid services, as well as in part due to
acquisitions. The pricing and utilization of our services, and
thus related revenues, improved due to the increase in well
maintenance and drilling activity caused by higher oil and gas
prices.
Well servicing revenues increased 64% to $73.5 million in
the first quarter in 2006 compared to $44.8 million in the
first quarter in 2005. This increase was due primarily to the
internal growth of this segment as well as an increase in our
revenue per rig hour of approximately 38%, from $255 per
hour to $352 per hour. Our weighted average number of rigs
increased to 327 in the first quarter in 2006 compared to 291 in
the same period in 2005, an increase of approximately 12%. In
addition, the utilization rate of our rig fleet increased to
89.4% in the first quarter in 2006 compared to 84.3% in the same
period in 2005.
Fluid services revenues increased 47% to $43.1 million
during the first quarter in 2006 as compared to
$29.3 million in the same period in 2005. The increase in
revenue was due primarily to our internal growth of this
segment. Our weighted average number of fluid service trucks
increased to 529 in the first quarter in 2006 compared to 435 in
the same period in 2005, an increase of approximately 22%. The
increase in weighted average number of fluid service trucks is
due to internal expansion as well as the trucks added from the
LeBus acquisition. In the first quarter in 2006, our average
revenue per fluid service truck was approximately $82,000 as
compared to approximately $67,000 in the same period in 2005.
The increase in average revenue per fluid service truck reflects
the expansion of our frac tank fleet and saltwater disposal
operations, and increases in prices charged for our services.
Drilling and completion services revenue increased 155% to
$27.5 million during the first quarter in 2006 as compared
to $10.8 million in the same period in 2005. The increase
in revenue between these periods was primarily the result of
internal expansion, the acquisition of Oil Well
40
Fracturing Services in October 2005, the acquisition of G&L
during February 2006 and improved pricing and utilization of our
services.
Well site construction services revenue increased 15% to
$10.3 million during the first quarter in 2006 as compared
to $8.9 million during the same period in 2005.
Direct Operating Expenses. Direct operating expenses,
which primarily consist of labor, including workers compensation
and health insurance, and maintenance and repair costs,
increased 48% to $89.4 million in the first quarter in 2006
from $60.4 million in the same period in 2005 primarily as
a result of additional rigs and trucks, as well as higher
utilization of our equipment. Operating expenses decreased to
58% of revenue for the first quarter in 2006 from 64% in the
same period in 2005, as fixed operating costs such as field
supervision, insurance and vehicle expenses were spread over a
higher revenue base. We also benefited from higher utilization
and increased pricing of our services.
Direct operating expenses for the well servicing segment
increased 48% to $41.6 million in the first quarter in 2005
compared to $28.2 million in the same period in 2005
primarily due to the internal growth of this segment. Segment
profits for this segment increased to 43.4% of revenues in the
first quarter in 2006 compared to 37.1% in the same period in
2005 primarily due to the improved pricing and higher
utilization of our equipment.
Direct operating expenses for the fluid services segment
increased 37% to $26.3 million in the first quarter in 2006
compared to $19.2 million in the same period in 2005
primarily due to increased activity and expansion of our fluid
services fleet. Segment profits for this segment increased to
39.0% of revenues in the first quarter in 2006 compared to 34.3%
in the same period in 2005 primarily due to the expansion of our
frac tank fleet and saltwater disposal operations, and increases
in prices charged for our services.
Direct operating expenses for the drilling and completion
services segment increased 136% to $13.9 million in the
first quarter in 2006 compared to $5.9 million in the same
period in 2005 primarily due to the increased activity and
expansion of our services and equipment, including the G&L
acquisition. Segment profits for this segment increased to 49.5%
of revenues in the first quarter in 2006 compared to 45.6% in
the same period in 2005.
Direct operating expenses for the well-site construction
services segment increased 8% to $7.6 million in the first
quarter in 2006 compared to $7.1 million in the same period
in 2005. Segment profits for this segment increased to 25.5% of
revenues in the first quarter of 2006 compared to 20.6% in the
same period in 2005.
General and Administrative Expenses. General and
administrative expenses increased 38% to $18.0 million in
the first quarter in 2006 from $13.1 million in the same
period in 2005. The increase primarily reflects higher salary
and office expenses related to the expansion of our business as
well as additional staffing to enhance internal controls as a
public company.
Depreciation and Amortization Expenses. Depreciation and
amortization expenses were $12.8 million for the first
quarter in 2006 and $8.0 million in the same period in
2005, reflecting the increase in the size and investment in our
asset base. We invested $87.5 million for acquisitions and
an additional $30.0 million for capital expenditures,
including capital leases, in the first quarter in 2006.
Interest Expense. Interest expense was $3.1 million
in the first quarter in 2006, unchanged from the same period in
2005.
Income Tax Expense (Benefit). Income tax expense was
$11.8 million in the first quarter in 2006 compared to
$3.5 million in the same period in 2005, reflecting the
improvement in our profitability. Our effective tax rate in both
periods was approximately 38%.
41
Net Income. Our net income increased to
$19.7 million in the first quarter in 2006 from
$5.8 million in the same period in 2005. This improvement
was due primarily to the factors described above, including our
increased asset base and related revenues, higher utilization
rates and increased revenues per rig and fluid service truck,
and higher operating margins on our drilling and completion
services equipment.
Year Ended December 31, 2005 Compared to Year Ended
December 31, 2004
Revenues. Revenues increased by 48% to
$459.8 million in 2005 from $311.5 million in 2004.
This increase was primarily due to the internal expansion of our
business segments, particularly well servicing and fluid
services. The pricing and utilization of our services improved
due to the increase in well maintenance and drilling activity
caused by higher oil and gas prices.
Well servicing revenues increased by 56% to $222.0 million
in 2005 compared to $142.6 million in 2004. The increase
was due mainly to our internal growth of this segment as well as
an increase in our revenue per rig hour of approximately 27%,
from $230 per hour to $292 per hour. Our weighted
average number of rigs increased to 305 in 2005 compared to 279
in 2004, an increase of approximately 9%. In addition, the
utilization rate of our rig fleet increased to 87.1% in 2005
compared to 77.8% in 2004.
Fluid services revenues increased by 34% to $132.3 million
in 2005 compared to $98.7 million in 2004. This increase
was primarily due to our internal growth of this segment. Our
weighted average number of fluid service trucks increased to 455
in 2005 compared to 386 in 2004, an increase of approximately
18%. During 2005, our average revenue per fluid service truck
was approximately $291,000 as compared to $256,000 in 2004. The
increase in average revenue per fluid service truck reflects the
expansion of our frac tank fleet and saltwater disposal
operations, and minor increases in prices charged for our
services.
Drilling and completion services revenues increased by 104% to
$59.8 million in 2005 as compared to $29.3 million in
2004. The increase in revenues between these periods was
primarily the result of acquisitions, including our acquisition
of wireline and underbalanced drilling businesses in 2004,
increased rates for our services and internal growth.
Well site construction services revenues increased 12% to
$45.6 million in 2005 as compared to $40.9 million in
2004.
Direct Operating Expenses. Direct operating expenses,
which primarily consist of labor, including workers compensation
and health insurance, and maintenance and repair costs,
increased by 33% to $282.8 million in 2005 from
$212.2 million in 2004 as a result of additional rigs and
trucks, as well as higher utilization of our equipment. Direct
operating expenses decreased to 62% of revenues for the period
from 68% in 2004, as fixed operating costs such as field
supervision, insurance and vehicle expenses were spread over a
higher revenue base. We also benefited from higher utilization
and increased pricing of our services.
Direct operating expenses for the well servicing segment
increased by 40% to $137.4 million in 2005 as compared to
$98.1 million in 2004 due primarily to increased activity
and increased labor costs for our crews. Segment profits
increased to 38.1% of revenues in 2005 compared to 31.2% in
2004, due to improved pricing for our services and higher
utilization of our equipment.
Direct operating expenses for the fluid services segment
increased by 27% to $82.6 million in 2005 as compared to
$65.2 million in 2004 due primarily to increased activity
and expansion of our fluid services fleet. Segment profits
increased to 37.6% of revenues in 2005 compared to 34.0% in 2004.
Direct operating expenses for the drilling and completion
services segment increased by 77% to $30.9 million in 2005
as compared to $17.5 million in 2004 due primarily to
increased
42
activity and expansion of our services and equipment. Our
segment profits increased to 48.4% of revenues in 2005 from
40.4% in 2004.
Direct operating expenses for the well-site construction
services segment increased by 2% to $32.0 million in 2005
as compared to $31.5 million in 2004. Segment profits for
this segment increased to 29.9% of revenues in 2005 as compared
to 23.1% for the same period in 2004.
General and Administrative Expenses. General and
administrative expenses increased by 49% to $55.4 million
in 2005 from $37.2 million in 2004 which included
$2.9 million and $1.6 million of stock-based
compensation expense in 2005 and 2004, respectively. The
increase primarily reflects higher salary and office expenses
related to the expansion of our business.
Depreciation and Amortization Expenses. Depreciation and
amortization expenses were $37.1 million in 2005 and
$28.7 million in 2004, reflecting the increase in the size
of and investment in our asset base. We invested
$25.4 million for acquisitions in 2005 and an additional
$83.1 million for capital expenditures in 2005 (excluding
capital leases).
Interest Expense. Interest expense increased by 35% to
$13.1 million in 2005 from $9.7 million in 2004. The
increase was due to an increase in the amount of long-term debt
during the period and higher interest rates. Both prime and
LIBOR interest rates increased substantially in 2005, and both
our revolver and Term B Loan interest rates are tied
directly to these rates.
Income Tax Expense. Income tax expense was
$26.8 million in 2005 as compared to $8.0 million in
2004. Our effective tax rate in 2005 and 2004 was approximately
38%.
Loss on Early Extinguishment of Debt. In December 2005,
we entered into a Third Amended and Restated Credit Agreement.
In connection with this, we recognized a loss on the early
extinguishment of debt and wrote-off unamortized debt issuance
costs of approximately $627,000.
Net Income. Our net income increased to
$44.8 million in 2005 from $12.9 million in 2004. This
improvement was due primarily to the factors described above,
including our increased asset base and related revenues, higher
utilization rates and increased revenues per rig and fluid
service truck, and higher operating margins on our drilling and
completion services equipment.
Year Ended December 31, 2004 Compared to Year Ended
December 31, 2003
Revenues. Revenues increased 72% to $311.5 million
in 2004 from $180.9 million in 2003. This increase was
primarily due to major acquisitions that we made in the fourth
quarter of 2003, increased oilfield service activity resulting
from continued strong oil and gas prices, the purchase of
additional revenue generating equipment and the higher
utilization derived from the redeployment of equipment to take
advantage of increasing activity in some of our markets. We
operated a weighted average of 279 rigs in 2004 compared to
257 in 2003, and 386 fluid service trucks in 2004 compared to
249 in 2003, which also contributed to the increase.
Well servicing revenues increased 37% to $142.6 million in
2004 compared to $104.1 million in 2003. Our full-fleet
utilization rate was 77.8% and revenue per rig hour was $230 in
2004 compared to 71.4% and $199, respectively, for 2003. The
higher rig utilization was due to the general increase in
activity caused by continued higher oil and gas prices and more
aggressive deployment of our fleet in areas of increasing
activity. The increasing rate per hour reflects price increases
implemented by us combined with a changing geographic mix of
activity.
Fluid services revenues increased 87% to $98.7 million in
2004 from $52.8 million in 2003. During 2004, our average
revenues per fluid service truck totaled $256,000, versus
average revenues of $212,000 per truck during the same
period in 2003.
Drilling and completion service revenues were $29.3 million
during 2004 as compared to $14.8 million during 2003. Our
significant entry into this segment occurred in late January 2003
43
with the acquisition of New Force and other acquisitions
occurring during the fourth quarter of 2003. The increase in
revenues between periods is primarily the result of the addition
of equipment and an increase in rates due to higher utilization.
Well site construction service revenues were $40.9 million
in 2004, as compared to $9.2 million in 2003. We entered
this segment in the fourth quarter of 2003 with our acquisition
of FESCO and PWI. This service line has benefited from the
increase in drilling activity, primarily in the Rocky Mountains.
Direct Operating Expenses. Direct operating expenses,
which primarily consist of labor and repair and maintenance,
increased 72% to $212.2 million in 2004 from
$123.6 million in 2003 as a result of operating additional
rigs and trucks, as well as higher utilization of our equipment.
Direct operating expenses as a percentage of revenues for 2004
remained virtually unchanged from the 68.0% in 2003, as fixed
operating costs such as field supervision, insurance and vehicle
expenses were spread over a higher revenue base, and this was
offset by unit increases in fuel and steel. The addition of our
construction services line also contributed to the static margin
as this service line generates a lower margin than our other
service lines.
Direct operating expenses for the well servicing segment
increased 34% to $98.1 million in 2004 as compared to
$73.2 million in 2003 due to increased activity. Segment
profits increased to 31.2% of revenues in 2004 compared to 29.6%
during 2003, as higher activity levels and rate increases were
able to offset cost increases for fuel and supplies.
Direct operating expenses for the fluid services segment
increased 89% to $65.2 million in 2004 from
$34.4 million in 2003. Segment profits for the fluid
services segment decreased to 34.0% in 2004 from 34.8% in 2003.
This was the result of higher fuel and disposal costs, which
were partially offset by an increase in drilling related
activity.
Direct operating expenses for the drilling and completion
services segment were $17.5 million in 2004 as compared to
$9.4 million in 2003, and the segment profits for this
segment were 40.4% for 2004. Our significant entry into this
segment occurred in late January 2003 with the acquisition of
New Force and other acquisitions occurring throughout the
remainder of 2003.
Direct operating expenses for our well site construction
services segment in 2004 were $31.5 million, and the
segment profits for this segment were 23.1% for this period as
compared to $6.6 million in direct operating expenses and
segment profits of 28.3% for the same period in 2003. We entered
this segment in October 2003, as previously discussed.
General and Administrative Expenses. General and
administrative expenses increased 63.7% to $37.2 million in
2004 from $22.7 million in 2003, which included
$1.6 million and $1.0 million of stock based
compensation expense in 2004 and 2003, respectively. The
increase primarily reflects higher salary and office expenses
related to the expansion of our business into the Rocky
Mountains and the Gulf Coast region in the fourth quarter of
2003, the addition of our North Texas pressure pumping business
(in our drilling and completion segment), and additional
administrative personnel to support new service locations and
growth of the company.
Depreciation and Amortization Expenses. Depreciation and
amortization expenses were $28.7 million for 2004 and
$18.2 million for 2003, reflecting the increase in the size
and investment in our asset base. We invested $19.3 million
for acquisitions in 2004 and an additional $55.7 million
for capital expenditures in 2004 (excluding capital leases).
Interest Expense. Interest expense increased 85.6% to
$9.7 million in 2004 from $5.2 million in 2003. The
increase was due to an increase in long-term debt which was
primarily used in connection with our acquisitions, most of
which was added in the fourth quarter of 2003, and capital
expenditures for property and equipment. In addition, both prime
and LIBOR interest rates increased in 2004, and our Term B
Loan interest rate is tied directly to these rates. Our 2003
interest expense was favorably impacted by the reduced interest
rate we received in our January
44
2003 refinancing, as well as an additional reduction in interest
rates in our October 2003 refinancing. As part of the
refinancings in January 2003 and October 2003, we recognized a
loss of $5.2 million from the early extinguishment of debt.
As part of our 2004 refinancing, we further reduced our base
interest rate by 50 basis points. See
Liquidity and Capital Resources.
Income Tax Expense. Income taxes increased to an
$8.0 million expense in 2004 from a $2.8 million
expense in 2003. The change was due to improved profitability
offset in part by a decrease in the effective tax rate in 2004.
The effective tax rate in 2004 was approximately 38.2% as
compared to 48.3% in 2003. The decrease in the effective tax
rate in 2004 was due primarily to an adjustment of the federal
tax rate from 34% in previous years to 35% in 2003, and the
associated effects on our deferred tax liability.
Discontinued Operations. As part of the FESCO acquisition
in October 2003, we acquired certain fluid services assets in
Alaska that, prior to completing the acquisition, we decided to
sell. Accordingly, these assets were treated as held for sale
and therefore the financial results for the assets are reflected
as discontinued operations. These assets were sold in the third
quarter of 2004 at their carrying value. At the time of sale, we
charged the remaining liability for a property lease to
discontinued operations.
Cumulative Effect of Accounting Change. As of
January 1, 2003, we adopted Statement of Financial
Accounting Standards No. 143, Accounting for Asset
Retirement Obligation
(SFAS No. 143). SFAS No. 143
requires us to record the fair value of an asset retirement
obligation as a liability in the period in which it incurs a
legal obligation associated with the retirement of tangible
long-lived assets and capitalize an equal amount as a cost of
the asset depreciating it over the life of the asset. As a
result of this adoption we recorded an expense, net of tax of
approximately $151,000 in 2003.
Net Income. Our net income increased to
$12.9 million in 2004 from a net income of
$2.8 million in 2003. This improvement was due primarily to
the increase in revenues and margins in 2004 compared to 2003
detailed above.
Liquidity and Capital Resources
Currently, our primary capital resources are net cash flows from
our operations, utilization of capital leases as allowed under
our 2005 Credit Facility and availability under our 2005 Credit
Facility, of which approximately $44.4 million was
available at March 31, 2006. As of April 30, 2006, we
had paid down all amounts under the revolving portion of our
2005 Credit Facility with the proceeds from our offering of
Senior Notes and had availability of $140.4 million and
$9.6 million of letters of credit outstanding under this
facility. As of March 31, 2006, we had cash and cash
equivalents of $20.0 million compared to $14.1 million
as of March 31, 2005. We have utilized, and expect to
utilize in the future, bank and capital lease financing and
sales of equity to obtain capital resources. When appropriate,
we will consider public or private debt and equity offerings and
non-recourse transactions to meet our liquidity needs.
Net Cash Provided By Operating Activities
Cash flow from operating activities was $99.2 million for
the year ended December 31, 2005 as compared to
$46.5 million in 2004, and was $29.8 million in 2003.
The increase in operating cash flows in 2005 compared to 2004
was primarily due to expansion of our fleet and improvements in
the segment profits and utilization of our equipment. The
increase in operating cash flows in 2004 over 2003 was primarily
due to improvements in the segment profits and utilization of
our equipment and our acquisitions in late 2003. For 2004 and
2005, these favorable trends were negatively impacted by an
increase in cash required to satisfy our working capital
requirements, particularly the increase in accounts receivable.
45
Cash flow from operating activities was $25.9 million
during the first quarter of 2006 as compared to
$16.7 million during the same period in 2005. The increase
in operating cash flows in the first quarter of 2006 over the
same period in 2005 was primarily due to expansion of our fleet
and improvements in the segment profits and utilization of our
equipment.
Capital Expenditures
Capital expenditures are the main component of our investing
activities. Cash capital expenditures (including for
acquisitions) for the first quarter in 2006 were
$112.3 million as compared to $20.0 million for the
same period in 2005. In the first quarter of 2006, the majority
of our capital expenditures were for business acquisitions,
whereas in 2005, the majority of our capital expenditures were
for the expansion of our fleet. We also added assets through our
capital lease program of approximately $5.2 million in the
first quarter in 2006 compared to $1.0 million in the same
period in 2005. Cash capital expenditures (including
acquisitions) for 2005 were $108.5 million as compared to
$75.0 million in 2004, and $85.4 million in 2003. In
2005 and 2004, the majority of our capital expenditures were for
the expansion of our fleet. In 2003 the majority of our capital
expenditures were for acquisitions. In 2003, we issued
3,650,000 shares of common stock as part of the FESCO
acquisition which added a non-cash cost to acquisitions of
$18.8 million and is in addition to the $85.4 million
spent in 2003. In 2003, we experienced a significant increase in
our acquisition activity as compared to the previous periods
which allowed us to expand our services and regions where we
operate. We also added assets through our capital lease program
of approximately $10.3 million, $10.5 million, and
$10.8 million in 2005, 2004 and 2003, respectively.
For 2006, we currently have planned approximately
$93 million in cash capital expenditures, none of which is
planned for acquisitions. We do not budget acquisitions in the
normal course of business, but we completed three acquisitions
for total consideration paid of $87.5 million, net of cash
acquired during the first quarter of 2006 and expect to make
additional acquisitions in 2006. The $93 million of capital
expenditures planned for property and equipment is primarily for
(1) purchase of additional equipment to expand our
services, (2) continued refurbishment of our well servicing
rigs and (3) replacement of existing equipment. We have
taken delivery of 45 newbuild will servicing rigs since
October 2004 as part of a
102-rig newbuild
commitment. The remainder of these newbuilds is scheduled to be
delivered to us prior to the end of December 2007. As of
March 31, 2006, we had no executed letters of intent for
acquisitions. As of July 11, 2006, we had entered into
letters of intent related to the acquisition of three entities
totaling approximately $30 million.
We regularly engage in discussions related to potential
acquisitions related to the well services industry. At present,
we have not entered into any agreement, commitment or
understanding with respect to any significant acquisition as
significant is defined under SEC rules.
Capital Resources and Financing
Our current primary capital resources are cash flow from our
operations, the ability to enter into capital leases of up to an
additional $25.7 million at March 31, 2006, the
availability under our credit facility of $44.4 million at
March 31, 2006 and a cash balance of $20.0 million at
March 31, 2006. As of April 30, 2006, we had paid down
all amounts under revolving borrowings under our 2005 Credit
Facility with the proceeds from our offering of Senior Notes.
During the first quarter in 2006, we financed activities in
excess of cash flow from operations primarily through the use of
bank debt and capital leases. In 2005, we financed activities in
excess of cash flow from operations primarily through the use of
bank debt and capital leases. During 2004 and 2003, we utilized
bank debt and the issuance of equity for cash as consideration
for acquisitions.
46
We have significant contractual obligations in the future that
will require capital resources. Our primary contractual
obligations are (1) our long-term debt, (2) our
capital leases, (3) our operating leases, (4) our rig
purchase obligations, (5) our asset retirement obligations
and (6) other long-term liabilities. The following table
outlines our contractual obligations as of December 31,
2005 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Obligations Due in Periods Ended | |
|
|
|
|
December 31, | |
|
|
|
|
| |
|
|
Contractual Obligations |
|
Total | |
|
2006 | |
|
2007-2008 | |
|
2009-2010 | |
|
Thereafter | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
Long-term debt (excluding capital
leases)
|
|
$ |
106,000 |
|
|
$ |
1,000 |
|
|
$ |
2,000 |
|
|
$ |
18,000 |
|
|
$ |
85,000 |
|
Capital leases
|
|
|
20,887 |
|
|
|
6,646 |
|
|
|
11,142 |
|
|
|
3,099 |
|
|
|
|
|
Operating leases
|
|
|
4,199 |
|
|
|
1,198 |
|
|
|
1,540 |
|
|
|
998 |
|
|
|
463 |
|
Rig purchase obligations
|
|
|
45,109 |
|
|
|
22,629 |
|
|
|
22,480 |
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
|
569 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
569 |
|
Other long-term liabilities
|
|
|
1,497 |
|
|
|
25 |
|
|
|
1,235 |
|
|
|
|
|
|
|
237 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
178,261 |
|
|
$ |
31,498 |
|
|
$ |
38,397 |
|
|
$ |
22,097 |
|
|
$ |
86,269 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our long-term debt, excluding capital leases, consists primarily
of Term B Loan indebtedness outstanding under our 2005 Credit
Facility. Our capital leases relate primarily to light-duty and
heavy-duty vehicles and trailers. Our operating leases relate
primarily to real estate. Our rig purchase obligations relate to
our commitments to purchase new well servicing rigs. Our other
long-term liabilities relate to contractual obligations under an
employee deferred compensation plan.
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
March 31, 2006, we had a maximum potential obligation of
$21.9 million related to the contingent earn-out
agreements. See note 3 of the notes to our audited and
unaudited historical consolidated financial statements for
additional detail.
The table above also does not reflect $9.6 million of
outstanding standby letters of credit issued under our revolving
line of credit. At May 31, 2006, of the $150.0 million
in financial commitments under the revolving line of credit
under our 2005 Credit Facility, there was $140.4 million of
available capacity with no outstanding balance and
$9.6 million of outstanding standby letters of credit. In
the normal course of business, we have performance obligations
which are supported by surety bonds and letters of credit. These
obligations primarily cover various reclamation and plugging
obligations related to our operations, and collateral for future
workers compensation and liability retained losses.
Our ability to access additional sources of financing will be
dependent on our operating cash flows and demand for our
services, which could be negatively impacted due to the extreme
volatility of commodity prices.
Senior Notes
In April 2006, we completed a private offering for $225,000,000
aggregate principal amount of 7.125% Senior Notes due
April 15, 2016. The Senior Notes are jointly and severally
guaranteed by each of our subsidiaries. The net proceeds from
the offering were used to retire the outstanding Term B Loan
balance and to pay down the outstanding balance under the
revolving credit facility. Remaining proceeds will be used for
general corporate purposes, including acquisitions.
47
We issued the Senior Notes pursuant to an indenture, dated as of
April 12, 2006, by and among us, the guarantor parties
thereto and The Bank of New York Trust Company, N.A., as trustee.
Interest on the Senior Notes will accrue from and including
April 12, 2006 at a rate of 7.125% per year. Interest
on the Senior Notes is payable in cash semi-annually in arrears
on April 15 and October 15 of each year, commencing on
October 15, 2006. The Senior Notes will mature on
April 15, 2016. The Senior Notes and the guarantees are
unsecured and will rank equally with all of our and the
guarantors existing and future unsecured and
unsubordinated obligations. The Senior Notes and the guarantees
will rank senior in right of payment to any of our and the
guarantors existing and future obligations that are, by
their terms, expressly subordinated in right of payment to the
Senior Notes and the guarantees. The Senior Notes and the
guarantees will be effectively subordinated to our and the
guarantors secured obligations, including our senior
secured credit facilities, to the extent of the value of the
assets securing such obligations.
The indenture contains covenants that limit the ability of us
and certain of our subsidiaries to:
|
|
|
|
|
incur additional indebtedness; |
|
|
|
pay dividends or repurchase or redeem capital stock; |
|
|
|
make certain investments; |
|
|
|
incur liens; |
|
|
|
enter into certain types of transactions with affiliates; |
|
|
|
limit dividends or other payments by restricted
subsidiaries; and |
|
|
|
sell assets or consolidate or merge with or into other companies. |
These limitations are subject to a number of important
qualifications and exceptions.
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:
|
|
|
|
|
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 |
|
|
|
we redeem the Senior Notes not more than 90 days after the
closing date of any such equity offering. |
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.
48
Credit Facilities
2005 Credit Facility
Under our Third Amended and Restated Credit Agreement with a
syndicate of lenders (the 2005 Credit Facility), as
amended effective March 28, 2006, Basic Energy Services,
Inc. is the sole borrower and each of our subsidiaries is a
subsidiary guarantor. The 2005 Credit Facility provided for a
$90 million Term B Loan (Term B
Loan), which outstanding balance was repaid in April 2006,
and provides for a $150 million revolving line of credit
(Revolver). The 2005 Credit Facility includes
provisions allowing us to request an increase in commitments
under the Term B Loan or the Revolver of up to
$75 million at any time.
The commitment under the Revolver provides for (1) the
borrowing of funds, (2) the issuance of up to
$30 million of letters of credit and
(3) $2.5 million of swing-line loans. The amounts
outstanding under the Term B Loan required quarterly
amortization at various amounts during each quarter with all
amounts outstanding being due and payable in full on
December 15, 2011. All the outstanding amounts under the
Revolver are due and payable on December 15, 2010. The 2005
Credit Facility is secured by substantially all of our tangible
and intangible assets.
At our option, borrowings under the Term B Loan bear
interest at either (1) the Alternative Base
Rate (i.e., the higher of the banks prime rate or
the federal funds rate plus .50% per year) plus 1.0% or
(2) the London Interbank Offered Rate (LIBOR)
rate plus 2.0%.
At our option, borrowings under the Revolver bear interest at
either (1) the Alternative Base Rate plus a margin ranging
from 0.50% to 1.25% or (2) the LIBOR rate plus a margin
ranging from 1.50% to 2.25%. The margins vary depending on our
leverage ratio. At March 31, 2006, our margin on
Alternative Base Rates and LIBOR tranches was 0.75% and 1.75%,
respectively. Fees on the letters of credit are due quarterly on
the outstanding amount of the letters of credit at a rate
ranging from 1.50% to 2.25% for participation fees and 0.125%
for fronting fees. A commitment fee is due quarterly on the
available borrowings under the Revolver at rates ranging from
0.375% to 0.50%.
At March 31, 2006, we had outstanding $90.0 million
under the Term B Loan and $96.0 million under the
Revolver. However, all the outstanding balance of the
Term B Loan was retired in April 2006 with proceeds from
our offering of Senior Notes.
Pursuant to the 2005 Credit Facility, we must apply proceeds
from certain specified events to reduce principal outstanding
under the Term B Loan, to the extent outstanding, and then
to the Revolver, including:
|
|
|
|
|
assets sales greater than $2.0 million individually or
$7.5 million in the aggregate on an annual basis; |
|
|
|
50% of the proceeds from any equity offering; |
|
|
|
proceeds of any issuance of debt not permitted by the 2005
Credit Facility; |
|
|
|
proceeds of permitted unsecured indebtedness, such as the Senior
Notes, without reducing commitments under the revolver; and |
|
|
|
proceeds in excess of $2.5 million from casualty events. |
Prior to the date on which all Term B Loans were paid in April
2006, the 2005 Credit Facility required us to enter into an
interest rate hedge, acceptable to the lenders, until
May 28, 2006 on at least $65 million of our
then-outstanding indebtedness.
49
The 2005 Credit Facility contains various restrictive covenants
and compliance requirements, including the following:
|
|
|
|
|
limitations on the incurrence of additional indebtedness; |
|
|
|
restrictions on mergers, sales or transfer of assets without the
lenders consent; |
|
|
|
limitation on dividends and distributions; |
|
|
|
limitations on capital expenditures; and |
|
|
|
various financial covenants, including: |
|
|
|
|
|
a maximum leverage ratio of 3.50 to 1.00 reducing to 3.25 to
1.00, and |
|
|
|
a minimum interest coverage ratio of 3.00 to 1.00. |
The 2005 Credit Facility contains customary events of default
(which are subject to customary grace periods and materiality
standards) including, among others: (1) non-payment of any
amounts payable under the 2005 Credit Facility when due;
(2) any representation or warrant made in connection with
the 2005 Credit Facility being incorrect in any material respect
when made or deemed made; (3) default in the observance or
performance of any covenant, condition or agreement contained in
the 2005 Credit Facility or related loan documents and such
default continuing unremedied or not being waived for
30 days; (4) failure to make payments on other
indebtedness involving in excess of $1.0 million;
(5) voluntary or involuntary bankruptcy, insolvency or
reorganization of us or any of our subsidiaries; (6) entry
of fines or judgments against us for payment of an amount in
excess of $2.5 million; (7) an ERISA event which could
reasonably be expected to cause a material adverse effect or the
imposition of a lien on any of our assets; (8) any security
agreement or document under the 2005 Credit Facility ceasing to
create a lien on any assets securing the 2005 Credit Facility;
(9) any guarantee ceasing to be in full force and effect;
(10) any material provision of the 2005 Credit Facility
ceasing to be valid and binding or enforceable; (11) a
change of control as defined in the 2005 Credit Agreement; or
(12) any determination, ruling, decision, decree or order
of any governmental authority that prohibits or restrains us and
our subsidiaries from conducting business and that could
reasonably be expected to cause a material adverse effect. At
March 31, 2006, we were in compliance with our covenants
under our 2005 Credit Facility.
2004 Credit Facility
On December 21, 2004, we amended and restated our credit
facility with a syndicate of lenders (2004 Credit
Facility) which increased aggregate commitments to us from
$170 million to $220 million. The 2004 Credit Facility
provided for a $170 million Term B Loan (2004
Term B Loan) and a $50 million revolving line of
credit (2004 Revolver). The commitment under the
2004 Revolver allowed for (1) the borrowing of funds,
(2) the issuance of up to $20 million of letters of
credit and (3) $2.5 million of swing-line loans. The
amounts outstanding under the 2004 Term B Loan required
quarterly amortization at various amounts during each quarter
with all amounts outstanding being due and payable in full on
October 3, 2009. All the outstanding amounts under the 2004
Revolver would have been due and payable on October 3,
2008. The 2004 Credit Facility was secured by substantially all
of our tangible and intangible assets. We incurred approximately
$0.8 million in debt issuance costs in obtaining the 2004
Credit Facility.
2003 Credit Facility
In October 2003, we refinanced our 2003 Refinancing Facility by
entering into a $170 million credit facility with a
syndicate of lenders (the 2003 Credit Facility). The
interest rates and other terms were similar to our 2004 Credit
Facility, but it provided for a $140 million Term B
loan and $30.0 million revolving line of credit, including
$10.0 million of letters of credit. At the date the 2003
Credit Facility was refinanced by the 2004 Credit Facility, the
outstanding principal balance
50
was approximately $139 million. We incurred approximately
$5.1 million in debt issuance costs in obtaining the 2003
Credit Facility.
2003 Refinancing Facility
In January 2003, we refinanced our then-existing credit
facilities by entering into a $62 million credit facility
with a capital markets group for a combination of term and
revolving loans, and a $22 million revolving line of credit
with a bank (collectively, the 2003 Refinancing
Facility). The interest rates on the loans under the 2003
Refinancing Facility were tied to a variable index plus a
margin. At the date the 2003 Refinancing Facility was terminated
and refinanced by the 2003 Credit Facility, the outstanding
principal balance was approximately $54 million. We
incurred approximately $2.5 million in debt issuance costs
in obtaining the 2003 Refinancing Facility.
Other Debt
We have a variety of other capital leases and notes payable
outstanding that are generally customary in our business. None
of these debt instruments are material individually or in the
aggregate. As of March 31, 2006, we had total capital
leases of approximately $24.3 million.
Losses on Extinguishment of Debt
In April 2006, we recognized a loss on the early extinguishment
of debt of $2.7 million representing unamortized deferred
debt issuance costs in connection with the retirement of the
Term B Loan.
In 2005 we recognized a loss on the early extinguishment of debt
of $627,000 in connection with our 2005 Credit Facility
discussed above. In 2003, we recognized a loss on the early
extinguishment of debt. We paid termination fees of
approximately $1.7 million and wrote off unamortized debt
issuance costs of approximately $3.5 million, which
resulted in a loss of approximately $5.2 million. The 2003
Refinancing Facility was done (1) to provide for a facility
which would better accommodate acquisitions and (2) to
realize better interest rate margins and fees. The 2003 Credit
Facility was primarily done to enable us to fund the significant
acquisitions in the fourth quarter in 2003, which could not be
economically negotiated under the 2003 Refinancing Facility.
In 2003, we adopted Statement of Financial Accounting Standards
No. 145 Rescission of FASB Statements No. 4, 44
and 64, Amendment of FASB Statement No. 13, and Technical
Corrections (SFAS No. 145). The
provisions of SFAS No. 145, which are currently
applicable to us, rescind Statement No. 4, which required
all gains and losses from extinguishment of debt to be
aggregated and classified as an extraordinary item, and instead
require that such gains and losses be reported in income from
operations. We now record gains and losses from the
extinguishment of debt in income from operations and have
reclassified such gains and losses in the consolidated financial
statements for 2002 to conform to the presentation in 2003.
Credit Rating Agencies
Effective November 22, 2005, we received credit ratings of
Ba3 from Moodys and B+ from Standard &
Poors for the 2005 Credit Facility. We received initial
credit ratings of B1 from Moodys and B from Standard and
Poors for the Senior Notes issued in April 2006. None of
our debt or other instruments is dependent upon our credit
ratings. However, the credit ratings may affect our ability to
obtain financing in the future.
51
Preferred Stock
In October 2003, we converted our then-outstanding mandatorily
redeemable preferred stock into shares of our common stock as
part of our debt refinancing process.
Other Matters
Net Operating Losses
We used all of our then-available net operating losses for
federal income tax purposes when we completed a recapitalization
in December 2000, which included a significant amount of debt
forgiveness. In 2002, our profitability suffered and, when
combined with a significant level of capital expenditures, we
ended 2002 with a net operating loss, or NOL, of
$30.4 million. In 2003, we returned to profitability, but
we again made significant investments in existing equipment,
additional equipment and acquisitions. Due to these events, we
again reported a tax loss in 2003 and ended the year with a
$50.7 million NOL, including $7.0 million that was
included in the purchase of FESCO. As of December 31, 2005,
we had approximately $4.9 million of NOL carryforwards
related to the pre-acquisition period of FESCO, which is subject
to an annual limitation of approximately $900,000. The
carryforwards begin to expire in 2017.
Recent Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board
issued Statement of Financial Accounting Standard No. 123R,
Share-Based Payment
(SFAS No. 123R). We adopted the provisions
of SFAS No. 123R on January 1, 2006 using the
modified prospective application. Accordingly, we will recognize
compensation expense for all newly granted awards and awards
modified, repurchased, or cancelled after January 1, 2006.
Compensation cost for the unvested portion of awards that are
outstanding as of January 1, 2006 will be recognized
ratably over the remaining vesting period. The compensation cost
for the unvested portion of awards will be based on the fair
value at date of grant as calculated for our pro forma
disclosure under SFAS No. 123. However, we will
continue to account for any portion of awards outstanding on
January 1, 2006 that were initially measured using the
minimum value method under the intrinsic value method in
accordance with APB No. 25. We began to recognize
compensation expense for awards under our 2003 Incentive Plan on
January 1, 2006.
We estimate that the effect on net income and earnings per share
in the periods following adoption of SFAS No. 123R
will be consistent with our pro forma disclosure under
SFAS No. 123, except that estimated forfeitures will
be considered in the calculation of compensation expense under
SFAS No. 123R and volatility will be considered in
determination of grant date fair value under SFAS 123R.
However, the actual effect on net income and earnings per share
will vary depending upon the number of options granted in future
years compared to prior years and the number of shares exercised
under our 2003 Incentive Plan. Further, we will use the
Black-Scholes-Merton model to calculate fair value.
Impact of Inflation on Operations
Management is of the opinion that inflation has not had a
significant impact on our business.
Quantitative and Qualitative Disclosures about Market Risk
We are exposed to changes in interest rates as a result of our
2005 Credit Facility. We had a total of $106 million of
indebtedness outstanding under our 2005 Credit Facility at
December 31, 2005. The impact of a 1% increase in interest
rates on this amount of debt would result in increased interest
expense (excluding effects of our interest rate hedges) of
approximately $1.1 million annually, or a decrease in net
income of approximately $687,000.
52
However, as of April 30, 2006, we had retired all amounts
outstanding under our Term B Loan and had no amounts
outstanding under the Revolver.
We do not hold or issue derivative instruments for trading
purposes. We did, however, previously have an interest rate
derivative instrument that has been formally designated as a
cash flow hedge instrument. This instrument effectively
converted the variable interest payments on $65 million of
our Term B Loan into fixed interest payments. This hedge
was terminated in April 2006 in connection with our repayment of
the Term B Loan.
The table below provides scheduled principle payments and fair
value information about our market-risk sensitive instruments as
of December 31, 2005 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Year of Maturity |
|
|
|
|
|
2006 |
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
Thereafter |
|
Total |
|
Fair Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable rate
|
|
$ |
1,000 |
|
|
$ |
1,000 |
|
|
$ |
1,000 |
|
|
$ |
1,000 |
|
|
$ |
17,000 |
|
|
$ |
85,000 |
|
|
$ |
106,000 |
|
|
$ |
106,000 |
|
Average interest rate(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Notional Amounts Outstanding(2) |
|
|
|
|
|
2006 |
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
Thereafter |
|
Total |
|
Fair Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Rate
Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable to Fixed
|
|
$ |
26,356 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
26,356 |
|
|
$ |
422 |
|
Average pay rate
|
|
|
3.03 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.03 |
% |
|
|
N/A |
|
Average received rate
|
|
|
4.83 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.83 |
% |
|
|
N/A |
|
|
|
(1) |
At our option, borrowings under the Revolver bear interest at
either (a) the Alternative Base Rate (i.e. the
higher of the banks prime rate or the federal funds rate
plus .5% per annum) plus a margin ranging from 0.50% to
1.25% or (b) the LIBOR rate plus a margin ranging from 1.5%
to 2.25%. The margins vary depending on our leverage ratio. At
December 31, 2005, our margin on Alternative Base Rates and
LIBOR tranches was 0.75% and 1.75%, respectively. |
|
(2) |
The notional amounts of interest rate instruments do not
represent amounts exchanged by the parties and, thus, are not a
measure of our exposure to credit loss. The amounts exchanged
are determined by reference to the notional amount and the other
terms of the contract. The variable component of the interest
rate derivative is based on the LIBOR rate using the forward
yield curve as of March 6, 2006. |
53
BUSINESS
General
We provide a wide range of well site services to oil and gas
drilling and producing companies, including well servicing,
fluid services, drilling and completion services and well site
construction services. These services are fundamental to
establishing and maintaining the flow of oil and gas throughout
the productive life of a well. Our broad range of services
enables us to meet multiple needs of our customers at the well
site. Our operations are managed regionally and are concentrated
in the major United States onshore oil and gas producing regions
in Texas, New Mexico, Oklahoma and Louisiana and the Rocky
Mountain states. We provide our services to a diverse group of
over 1,000 oil and gas companies. We operate the third-largest
fleet of well servicing rigs (also commonly referred to as
workover rigs) in the United States, representing approximately
13% of the overall available U.S. fleet. Our two larger
competitors control approximately 31% and 18%, respectively, as
of May 2006, according to the Association of Energy Services
Companies and other publicly available data.
We currently conduct our operations through the following four
business segments:
|
|
|
|
|
Well Servicing. Our well servicing segment (48% of
our revenues in 2005 and 47% of our revenues in the first
quarter of 2006) currently operates our fleet of over
330 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. |
|
|
|
Fluid Services. Our fluid services segment (29% of
our revenues in 2005 and 28% of our revenues in the first
quarter of 2006) currently utilizes our fleet of over 550 fluid
services trucks and related assets, including specialized tank
trucks, storage tanks, water wells, disposal facilities and
related equipment. These assets provide, transport, store and
dispose of a variety of fluids. These services are required in
most workover, drilling and completion projects and are
routinely used in daily producing well operations. |
|
|
|
Drilling and Completion Services. Our drilling and
completion services segment (13% of our revenues in 2005 and 18%
of our revenues in the first quarter of 2006) currently operates
our fleet of 70 pressure pumping units, 29 air compressor
packages specially configured for underbalanced drilling
operations and 10 cased-hole wireline units. These services
are designed to initiate or stimulate oil and gas production.
The largest portion of this business consists of pressure
pumping services focused on cementing, acidizing and fracturing
services in niche markets. We also entered the fishing and
rental tool business through an acquisition in the first quarter
of 2006. |
|
|
|
Well Site Construction Services. Our well site
construction services segment (10% of our revenues in 2005 and
7% of our revenues in the first quarter of 2006) currently
utilizes our fleet of over 200 operated power units, which
include dozers, trenchers, motor graders, backhoes and other
heavy equipment. We utilize these assets primarily to provide
services for the construction and maintenance of oil and gas
production infrastructure, such as preparing and maintaining
access roads and well locations, installation of small diameter
gathering lines and pipelines and construction of temporary
foundations to support drilling rigs. |
54
Our Competitive Strengths
We believe that the following competitive strengths currently
position us well within our industry:
Significant Market Position. We maintain a
significant market share for our well servicing operations in
our core operating areas throughout Texas and a growing market
share in the other markets that we serve. Our fleet of over
330 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
completion, maintenance, workover and plugging and abandonment
services.
Modern and Active Fleet. We operate a modern and
active fleet of well servicing rigs. We believe over 95% of the
active U.S. well servicing rig fleet was built prior to
1985. Approximately 98, or 30%, of our rigs at March 31,
2006 were either 2000 model year or newer, or have undergone
major refurbishments during the last four years. Since October
2004, we have taken delivery of 45 newbuild well servicing
rigs through March 31, 2006 as part of a
102-rig newbuild
commitment, driven by our desire to maintain one of the most
efficient, reliable and safest fleets in the industry. The
remainder of these newbuilds is scheduled to be delivered to us
prior to the end of December 2007. In addition to our regular
maintenance program, we have an established program to routinely
monitor and evaluate the condition of our fleet. We selectively
refurbish rigs and other assets to maintain the quality of our
service and to provide a safe work environment for our personnel
and have made major refurbishments on 46 of our rigs since the
beginning of 2001. Approximately 98% of our fleet was active or
available for work and the remainder was awaiting refurbishment
at March 31, 2006. We believe only approximately 66% of the
well servicing rig fleet of our two major competitors are active
and available for work. Since 2003, we have obtained annual
independent reviews and evaluations of substantially all of our
assets, which confirmed the location and condition of these
assets.
Extensive Domestic Footprint in the Most Prolific
Basins. Our operations are concentrated in the major
United States onshore oil and gas producing regions in Texas,
New Mexico, Oklahoma and Louisiana and the Rocky Mountain
states. We operate in states that accounted for approximately
57% of the approximately 900,000 existing onshore oil and
gas wells in the 48 contiguous states and approximately 77%
of onshore oil production and 72% of onshore gas production in
2005. We believe that our operations are located in the most
active U.S. well services markets, as we currently focus
our operations on onshore domestic oil and gas production areas
that include both the highest concentration of existing oil and
gas production activities and the largest prospective acreage
for new drilling activity. This extensive footprint allows us to
offer our suite of services to more than 1,000 customers who are
active in those areas and allows us to redeploy equipment
between markets as activity shifts.
Diversified Service Offering for Further Revenue
Growth. Our experience, equipment and network of over 90
service locations position us to market our full range of well
site services to our existing customers. We believe our range of
well site services provides us a competitive advantage over
smaller companies that typically offer fewer services. 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
55
our seven regional managers are responsible for their regional
operations, including asset management, cost control, policy
compliance and training and other aspects of quality control.
With an average of over 28 years of industry experience,
each regional manager has extensive knowledge of the customer
base, job requirements and working conditions in each local
market. Below our seven regional or product line managers, our
66 area managers are directly responsible for customer
relationships, personnel management, accident prevention and
equipment maintenance, the key drivers of our operating
profitability. This management structure allows us to monitor
operating performance on a daily basis, maintain financial,
accounting and asset management controls, integrate
acquisitions, prepare timely financial reports and manage
contractual risk.
Our Business Strategy
We intend to increase our shareholder value by pursuing the
following strategies:
Establish and Maintain Leadership Position in Core
Operating Areas. We strive to establish and maintain
market leadership positions within our core operating areas. To
achieve this goal, we maintain close customer relationships,
seek to expand the breadth of our services and offer high
quality services and equipment that meet the scope of customer
specifications and requirements. In addition, our significant
presence in our core operating areas facilitates employee
retention and attraction, a key factor for success in our
business. Our significant presence in our core operating areas
also provides us with brand recognition that we intend to
utilize in creating leading positions in new operating areas.
Expand Within Our Regional Markets. We intend to
continue strengthening our presence within our existing
geographic footprint through internal growth and acquisitions of
businesses with strong customer relationships, well-maintained
equipment and experienced and skilled personnel. Our larger
competitors have not actively pursued acquisitions of small to
mid-size regional businesses or assets in recent years due to
the small relative scale and financial impact of these potential
acquisitions. In contrast, we have successfully pursued these
types of acquisitions, which remain attractive to us and make a
meaningful impact on our overall operations. We typically enter
into new markets through the acquisition of businesses with
strong management teams that will allow us to expand within
these markets. Management of acquired companies often remain
with us and retain key positions within our organization, which
enhances our attractiveness as an acquisition partner. We have a
record of successfully implementing this strategy, as
demonstrated by our 2003 acquisitions of FESCO
Holdings, Inc., PWI Inc. and New Force Energy
Services, Inc., which expanded our exposure to the active
drilling environment of the Rocky Mountain states, the active
well services and drilling markets along the Gulf Coast and the
pressure pumping business, respectively. Additionally, in
December 2004 we expanded our presence along the Gulf Coast with
the acquisition of three inland barges, two of which have been
refurbished and were available for service in the second quarter
of 2005.
Develop Additional Service Offerings Within the Well
Servicing Market. We intend to continue broadening the
portfolio of services we provide to our clients by leveraging
our well servicing infrastructure. A customer typically begins a
new maintenance or workover project by securing access to a well
servicing rig, which generally stays on site for the duration of
the project. As a result, our rigs are often the first equipment
to arrive at the well site and typically the last to leave,
providing us the opportunity to offer our customers other
complementary services. We believe the fragmented nature of the
well servicing market creates an opportunity to sell more
services to our core customers and to expand our total service
offering within each of our markets. We have expanded our suite
of services available to our customers and increased our
opportunities to cross-sell new services to our core well
servicing customers through recent acquisitions and internal
growth. We expect to continue to develop or selectively acquire
capabilities to provide additional services to expand and
further strengthen our customer relationships.
56
Pursue Growth Through Selective Capital
Deployment. We intend to continue growing our business
through selective acquisitions, continuing a newbuild program
and/or upgrading our existing assets. Our capital investment
decisions are determined by an analysis of the projected return
on capital employed of each of those alternatives. Acquisitions
are evaluated for fit with our area and regional
operations management and are thoroughly reviewed by corporate
level financial, equipment, safety and environmental specialists
to ensure consideration is given to identified risks. We also
evaluate the cost to acquire existing assets from a third party,
the capital required to build new equipment and the point in the
oil and gas commodity price cycle. Based on these factors, we
make capital investment decisions that we believe will support
our long-term growth strategy, and these decisions may involve a
combination of asset acquisitions and the purchase of new
equipment. In 2005, we completed eight separate acquisitions for
an aggregate purchase price of $25.4 million net of cash
acquired, and took delivery of 31 new well
servicing rigs. In the first quarter of 2006, we completed
three separate acquisitions for an aggregate purchase price of
$87.5 million net of cash acquired, and took delivery of
10 new well servicing rigs.
General Industry Overview
Demand for services offered by our industry is a function of our
customers willingness to make operating and capital
expenditures to explore for, develop and produce hydrocarbons in
the U.S., which in turn is affected by current and expected
levels of oil and gas prices. The following industry statistics
illustrate the growing spending dynamic in the U.S. oil and
gas sector (including the offshore sector that we do not serve):
|
|
|
|
|
With the rebound in oil and gas prices in early 1999, oil and
gas companies have increased their drilling and workover
activities. The increased activity resulted in increased
exploration and production spending compared to the prior year
of 16% and 30% in 2004 and 2005, respectively, and is expected
to increase 16% in 2006, according to www.WorldOil.com. |
|
|
|
A survey of 18 U.S. major integrated and 130 independent
oil and gas companies by World Oil Magazine projected the
U.S. drilling activity in 2006 to be skewed more towards
independent players. Specifically, independent oil and gas
companies, which represent over 90% of our revenues, are
expected to drill 27% more wells in 2006 than in 2005, while the
major integrated producers are expected to drill only 16% more
wells over the same period. This trend is primarily driven by
the increased acquisitions of proved oil and gas properties by
independent producers. When these types of properties are
acquired, purchasers typically intensify drilling, workover and
well maintenance activities to accelerate production from the
newly acquired reserves. |
57
Increased spending by oil and gas operators is generally driven
by oil and gas prices. The table below sets forth average daily
closing prices for the Cushing WTI Spot Oil Price and the Energy
Information Agency average wellhead price for natural gas since
1999:
|
|
|
|
|
|
|
|
|
|
|
Cushing WTI Spot | |
|
Average Wellhead Price | |
Period |
|
Oil Price ($/bbl) | |
|
Natural Gas ($mcf) | |
|
|
| |
|
| |
1/1/99 12/31/99
|
|
$ |
19.34 |
|
|
$ |
2.19 |
|
1/1/00 12/31/00
|
|
|
30.38 |
|
|
|
3.69 |
|
1/1/01 12/31/01
|
|
|
25.97 |
|
|
|
4.01 |
|
1/1/02 12/31/02
|
|
|
26.18 |
|
|
|
2.95 |
|
1/1/03 12/31/03
|
|
|
31.08 |
|
|
|
4.98 |
|
1/1/04 12/31/04
|
|
|
41.51 |
|
|
|
5.49 |
|
1/1/05 12/31/05
|
|
|
56.64 |
|
|
|
7.51 |
|
1/1/06 3/31/06
|
|
|
63.27 |
|
|
|
7.49 |
|
Source: U.S. Department of Energy.
Increased expenditures for exploration and production activities
generally involve the deployment of more drilling and well
servicing rigs, which often serves as an indicator of demand for
our services. Rising oil and gas prices since early 1999 and the
corresponding increase in onshore oil exploration and production
spending have led to expanded drilling and well service
activity, as the U.S. land-based drilling rig count
increased approximately 36% from year-end 2002 to year-end 2003,
11% from year-end 2003 to year-end 2004, 22% from year-end 2004
to year-end 2005 and 7% during the first quarter of 2006,
according to Baker Hughes. In addition, the U.S. land-based
workover rig count increased approximately 13% from year-end
2002 to year-end 2003, 10% from year-end 2003 to year-end 2004,
17% from year-end 2004 to year-end 2005 and 3% during the first
quarter of 2006, according to Baker Hughes.
Exploration and production spending is generally categorized as
either an operating expenditure or a capital expenditure.
Activities designed to add hydrocarbon reserves are classified
as capital expenditures, while those associated with maintaining
or accelerating production are categorized as operating
expenditures.
Capital expenditure spending tends to be relatively sensitive to
volatility in oil or gas prices because project decisions are
tied to a return on investment spanning a number of years. As
such, capital expenditure economics often require the use of
commodity price forecasts which may prove inaccurate in the
short amount of time required to plan and execute a capital
expenditure project (such as the drilling of a deep well). When
commodity prices are depressed for even a short period of time,
capital expenditure projects are routinely deferred until prices
return to an acceptable level.
In contrast, both mandatory and discretionary operating
expenditures are substantially more stable than exploration and
drilling expenditures. Mandatory operating expenditure projects
involve activities that cannot be avoided in the short term,
such as regulatory compliance, safety, contractual obligations
and projects to maintain the well and related infrastructure in
operating condition (for example, repairs to a central tank
battery, downhole pump, saltwater disposal system or gathering
system). Discretionary operating expenditure projects may not be
critical to the short-term viability of a lease or field but
these projects are relatively insensitive to commodity price
volatility. Discretionary operating expenditure work is
evaluated according to a simple short-term payout criterion
which is far less dependent on commodity price forecasts.
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 compared to exploration and drilling expenditures.
In contrast,
58
capital expenditures by oil and gas companies for 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:
|
|
|
|
|
maintenance work involving removal, repair and replacement of
down-hole equipment and returning the well to production after
these operations are completed; |
|
|
|
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 |
|
|
|
plugging and abandonment services when a well has reached the
end of its productive life. |
Regardless of the type of work being performed on the well, our
personnel and rigs are often the first to arrive at the well
site and the last to leave. We generally charge our customers an
hourly rate for these services, which rate varies based on a
number of considerations including market conditions in each
region, the type of rig and ancillary equipment required, and
the necessary personnel.
Our fleet included 332 well service rigs as of
March 31, 2006, including 45 newbuilds since October
2004 and 46 rebuilds since the beginning of 2001. We
operate from more than 90 facilities in Texas, Wyoming,
Oklahoma, New Mexico, Louisiana, Colorado, Montana, North
Dakota, Arkansas and Utah, most of which are used jointly for
our business segments. Our rigs are mobile units that generally
operate within a radius of approximately 75 to 100 miles
from their respective bases. Prior to December 2004, our well
servicing segment consisted entirely of land-based equipment.
During December 2004, we acquired three inland barges, two of
which are equipped with rigs, have been refurbished and were
placed into service in the second quarter of 2005. Inland barges
are used to service wells in shallow water marine environments,
such as coastal marshes and bays.
The following table sets forth the location, characteristics and
number of the well servicing rigs that we operated at
March 31, 2006. We categorize our rig fleet by the rated
capacity of the mast, which indicates the maximum weight that
the rig is capable of lifting. This capability is the limiting
factor in our ability to provide services. These figures do not
include 57 new well
59
servicing rigs that we have contracted for delivery from April
2006 through December 2007 as part of a
102-rig newbuild
commitment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Division | |
|
|
|
|
| |
|
|
|
|
Permian | |
|
South | |
|
Ark- | |
|
Mid- | |
|
Northern | |
|
Southern | |
|
|
Rig Type |
|
Rated Capacity |
|
Basin | |
|
Texas | |
|
La-Tex | |
|
Continent | |
|
Rockies | |
|
Rockies | |
|
Stacked | |
|
Total | |
|
|
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Swab
|
|
N/A
|
|
|
3 |
|
|
|
1 |
|
|
|
8 |
|
|
|
4 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
16 |
|
Light Duty
|
|
<90 tons
|
|
|
6 |
|
|
|
2 |
|
|
|
0 |
|
|
|
24 |
|
|
|
2 |
|
|
|
0 |
|
|
|
2 |
|
|
|
36 |
|
Medium Duty
|
|
>90-125 tons
|
|
|
93 |
|
|
|
34 |
|
|
|
20 |
|
|
|
40 |
|
|
|
16 |
|
|
|
16 |
|
|
|
1 |
|
|
|
220 |
|
Heavy Duty
|
|
³125
tons
|
|
|
27 |
|
|
|
3 |
|
|
|
6 |
|
|
|
4 |
|
|
|
6 |
|
|
|
3 |
|
|
|
2 |
|
|
|
51 |
|
24-Hour
|
|
³125
tons
|
|
|
1 |
|
|
|
4 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
5 |
|
Drilling Rigs
|
|
³125
tons
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
2 |
|
|
|
0 |
|
|
|
2 |
|
Inland Barge
|
|
³125
tons
|
|
|
0 |
|
|
|
0 |
|
|
|
2 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
128
|
|
|
130 |
|
|
|
44 |
|
|
|
36 |
|
|
|
72 |
|
|
|
24 |
|
|
|
21 |
|
|
|
5 |
|
|
|
332 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Management currently estimates that there are approximately
3,500 onshore well servicing rigs currently in the U.S.,
owned by an estimated 125 contractors, and that the actual
number that are actively marketed and operable without major
capital expenditures may be as much as 20% lower than this
estimate. Based on information from U.S. contractors
reporting their utilization to Weatherford-AESC, there were
2,508 well servicing rigs working in May 2006. This figure
represents a projected utilization rate of 92% for the available
fleet that are operable without major capital expenditures.
According to the Guiberson Well Service Rig Count, by 1982
substantial new rig construction increased the total well
servicing rig fleet to a total of 8,063 well servicing rigs
operating in the United States owned by a large number of small
companies, several multi-regional contractors and a few large
national contractors. The largest well servicing contractor at
that time had less than 500 rigs, or less than 6% of the
total number of operating rigs. Due to increased competition and
lower day rates, the domestic well servicing fleet has declined
substantially over the last 20 years and has experienced
considerable consolidation that has affected companies of all
sizes, including the consolidation of several larger regional
companies. Specifically, the well servicing segment of our
industry has consolidated from nine large competitors (with 50
or more well servicing rigs) ten years ago to four today. The
excess capacity of rigs that has existed in the industry since
the early 1980s has also been reduced due to the lack of
new rig construction, retirements due to mechanical problems,
casualties, exports to foreign markets and, to some extent,
cannibalization efforts by rig operators, wherein parts are
stripped from idle rigs to outfit refurbishments on an active
rig fleet.
Based on the most recent publicly available information, our two
largest competitors own a combined 2,053 rigs of which
1,351 are operated and 702 are stacked. These two
competitors total rigs represent approximately 59% of the
industrys total fleet. We have the third-largest fleet
with over 340 rigs, or over 10% of the overall available
U.S. industrys fleet. Due to the fragmented nature of
the market, we believe only one company other than us and our
two larger competitors owns more than 50 rigs (with a total
of only approximately 135 rigs) and a total of an estimated
120 companies own the approximately 900 estimated remaining
well servicing rigs, or approximately 26% of the industrys
total fleet.
Maintenance. Regular maintenance is generally required
throughout the life of a well to sustain optimal levels of oil
and gas production. We believe regular maintenance comprises the
largest portion of our work in this business segment. We provide
well service rigs, equipment and crews for these maintenance
services. Maintenance services are often performed on a series
of wells in proximity to each other. These services consist of
routine mechanical repairs necessary to maintain production,
such as repairing inoperable pumping equipment in an oil well or
replacing defective tubing in a gas well, and removing debris
such as sand and paraffin from the well. Other services include
pulling the rods, tubing, pumps and other downhole equipment
60
out of the well bore to identify and repair a production
problem. These downhole equipment failures are typically caused
by the repetitive pumping action of an oil well. Corrosion,
water cut, grade of oil, sand production and other factors can
also result in frequent failures of downhole equipment.
The need for maintenance activity does not directly depend on
the level of drilling activity, although it is somewhat impacted
by short-term fluctuations in oil and gas prices. Demand for our
maintenance services is affected by changes in the total number
of producing oil and gas wells in our geographic service areas.
Accordingly, maintenance services generally experience
relatively stable demand.
Our regular well maintenance services involve relatively
low-cost, short-duration jobs which are part of normal well
operating costs. Demand for well maintenance is driven primarily
by the production requirements of the local oil or gas fields
and, to a lesser degree, the actual prices received for oil and
gas. Well operators cannot delay all maintenance work without a
significant impact on production. Operators may, however, choose
to temporarily shut in producing wells when oil or gas prices
are too low to justify additional expenditures, including
maintenance.
Workover. In addition to periodic maintenance, producing
oil and gas wells occasionally require major repairs or
modifications called workovers, which are typically more complex
and more time consuming than maintenance operations. Workover
services include extensions of existing wells to drain new
formations either through perforating the well casing to expose
additional productive zones not previously produced, deepening
well bores to new zones or the drilling of lateral well bores to
improve reservoir drainage patterns. Our workover rigs are also
used to convert former producing wells to injection wells
through which water or carbon dioxide is then pumped into the
formation for enhanced oil recovery operations. Workovers also
include major subsurface repairs such as repair or replacement
of well casing, recovery or replacement of tubing and removal of
foreign objects from the well bore. These extensive workover
operations are normally performed by a workover rig with
additional specialized auxiliary equipment, which may include
rotary drilling equipment, mud pumps, mud tanks and fishing
tools, depending upon the particular type of workover operation.
Most of our well servicing rigs are designed to perform complex
workover operations. A workover may require a few days to
several weeks and generally requires additional auxiliary
equipment. The demand for workover services is sensitive to oil
and gas producers intermediate and long-term expectations
for oil and gas prices. As oil and gas prices increase, the
level of workover activity tends to increase as oil and gas
producers seek to increase output by enhancing the efficiency of
their wells.
New Well Completion. New well completion services involve
the preparation of newly drilled wells for production. The
completion process may involve selectively perforating the well
casing in the productive zones to allow oil or gas to flow into
the well bore, stimulating and testing these zones and
installing the production string and other downhole equipment.
We provide well service rigs to assist in this completion
process. Newly drilled wells are frequently completed by well
servicing rigs to minimize the use of higher cost drilling rigs
in the completion process. The completion process typically
requires a few days to several weeks, depending on the nature
and type of the completion, and generally requires additional
auxiliary equipment. Accordingly, completion services require
less well-to-well
mobilization of equipment and generally provide higher operating
margins than regular maintenance work. The demand for completion
services is directly related to drilling activity levels, which
are sensitive to expectations relating to and changes in oil and
gas prices.
Plugging and Abandonment. Well servicing rigs are also
used in the process of permanently closing oil and gas wells no
longer capable of producing in economic quantities. Plugging and
abandonment work can be performed with a well servicing rig
along with wireline and cementing equipment; however, this
service is typically provided by companies that specialize in
plugging and abandonment work. Many well operators bid this work
on a turnkey
61
basis, requiring the service company to perform the entire job,
including the sale or disposal of equipment salvaged from the
well as part of the compensation received, and complying with
state regulatory requirements. Plugging and abandonment work can
provide favorable operating margins and is less sensitive to oil
and gas pricing than drilling and workover activity since well
operators must plug a well in accordance with state regulations
when it is no longer productive. We perform plugging and
abandonment work throughout our core areas of operation in
conjunction with equipment provided by other service companies.
Fluid Services Segment
Our fluid services segment provides oilfield fluid supply,
transportation and storage services. These services are required
in most workover, drilling and completion projects and are
routinely used in daily producing well operations. These
services include:
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|
|
|
|
transportation of fluids used in drilling and workover
operations and of salt water produced as a by-product of oil and
gas production; |
|
|
|
sale and transportation of fresh and brine water used in
drilling and workover activities; |
|
|
|
rental of portable frac tanks and test tanks used to store
fluids on well sites; and |
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|
operation of company owned fresh water and brine source wells
and of non-hazardous wastewater disposal wells. |
This segment utilizes our fleet of fluid services trucks and
related assets, including specialized tank trucks, portable
storage tanks, water wells, disposal facilities and related
equipment. The following table sets forth the type, number and
location of the fluid services equipment that we operated at
March 31, 2006:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Division | |
|
|
| |
|
|
Northern | |
|
Permian | |
|
Ark- | |
|
South | |
|
Mid- | |
|
|
|
|
Rockies | |
|
Basin | |
|
La-Tex | |
|
Texas | |
|
Continent | |
|
Stacked | |
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Total | |
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|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Fluid Services Trucks
|
|
|
82 |
|
|
|
126 |
|
|
|
182 |
|
|
|
120 |
|
|
|
38 |
|
|
|
6 |
|
|
|
554 |
|
Salt Water Disposal Wells
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|
|
|
|
|
12 |
|
|
|
20 |
|
|
|
8 |
|
|
|
7 |
|
|
|
|
|
|
|
47 |
|
Fresh/ Brine Water Stations
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|
|
|
|
|
|
28 |
|
|
|
|
|
|
|
3 |
|
|
|
1 |
|
|
|
|
|
|
|
32 |
|
Fluid Storage Tanks
|
|
|
213 |
|
|
|
271 |
|
|
|
681 |
|
|
|
253 |
|
|
|
63 |
|
|
|
|
|
|
|
1,481 |
|
Requirements for minor or incidental fluid services are usually
purchased on a call out basis and charged according
to a published schedule of rates. Larger projects, such as
servicing the requirements of a multi-well drilling program or
frac program, generally involve a bidding process. We compete
for services both on a call out basis and for multi-well
contract projects.
We provide a full array of fluid sales, transportation, storage
and disposal services required on most workover, drilling and
completion projects. Our breadth of capabilities in this
business segment allows us to serve as a one-stop source for our
customers. Many of our smaller competitors in this segment can
provide some, but not all, of the equipment and services
required by customers, requiring them to use several companies
to meet their requirements and increasing their administrative
burden.
As in our well servicing segment, our fluid services segment has
a base level of business volume related to the regular
maintenance of oil and gas wells. Most oil and gas fields
produce residual salt water in conjunction with oil or gas.
Fluid service trucks pick up this fluid from tank batteries at
the well site and transport it to a salt water disposal well for
injection. This regular maintenance work must be performed if a
well is to remain active. Transportation and disposal of
produced water is considered a low value service by most
operators, and it is difficult for us to command a premium over
rates charged by our competition. Our ability to out perform
competitors in this segment depends on our ability to achieve
significant economies relating to
62
logistics specifically, proximity between areas
where salt water is produced and our company owned disposal
wells. Ownership of disposal wells eliminates the need to pay
third parties a fee for disposal. We operate salt water disposal
wells in most of our markets.
Workover, drilling and completion activities also provide the
opportunity for higher operating margins from tank rentals and
fluid sales. Drilling and workover jobs typically require fresh
or brine water for drilling mud or circulating fluid used during
the job. Completion and workover procedures often also require
large volumes of water for fracturing operations, a process of
stimulating a well hydraulically to increase production. Spent
mud and flowback fluids are required to be transported from the
well site to a disposal well.
Competitors in the fluid services industry are mostly small,
regionally focused companies. There are currently no companies
that have a dominant position on a nationwide basis. The level
of activity in the fluid services industry is comprised of a
relatively stable demand for services related to the maintenance
of producing wells and a highly variable demand for services
used in the drilling and completion of new wells. As a result,
the level of onshore drilling activity significantly affects the
level of activity in the fluid services industry. While there
are no industry-wide statistics, the Baker Hughes Land Drilling
Rig Count is an indirect indication of demand for fluid services
because it directly reflects the level of onshore drilling
activity.
Fluid Services and Support Trucks. We currently own and
operate over 550 fluid service tank trucks equipped with a
fluid hauling capacity of up to 150 barrels. Each fluid
service truck is equipped to pump fluids from or into wells,
pits, tanks and other storage facilities. The majority of our
fluid service trucks are also used to transport water to fill
frac tanks on well locations, including frac tanks provided by
us and others, to transport produced salt water to disposal
wells, including injection wells owned and operated by us, and
to transport drilling and completion fluids to and from well
locations. In conjunction with the rental of our frac tanks, we
generally use our fluid service trucks to transport water for
use in fracturing operations. Following completion of fracturing
operations, our fluid service trucks are used to transport the
flowback produced as a result of the fracturing operations from
the well site to disposal wells. Fluid services trucks are
generally provided to oilfield operators within a
50-mile radius of our
nearest yard. Our hot oil trucks are used to remove
paraffin, a by-product of oil production in many fields, from
the well bore. If paraffin is left untreated, it can inhibit a
wells production. Our support trucks are used to move our
fluid storage tanks and other equipment to and from the job
sites of our customers.
Salt Water Disposal Well Services. We own disposal wells
that are permitted to dispose of salt water and incidental
non-hazardous oil and gas wastes. Our transport trucks
frequently transport fluids that are disposed of in these salt
water disposal wells. The disposal wells have injection
capacities ranging up to 3,500 barrels per day. Our salt
water disposal wells are strategically located in close
proximity to our customers producing wells. Most oil and
gas wells produce varying amounts of salt water throughout their
productive lives. In the states in which we generate oil and gas
wastes and salt water produced from oil and gas wells are
required by law to be disposed of in authorized facilities,
including permitted salt water disposal wells. Injection wells
are licensed by state authorities and are completed in permeable
formations below the fresh water table. We maintain separators
at most of our disposal wells permitting us to salvage residual
crude oil, which is later sold for our account.
Fresh and Brine Water Stations. Our network of fresh and
brine water stations, particularly, in the Permian Basin, where
surface water is generally not available, are used to supply
water necessary for the drilling and completion of oil and gas
wells. Our strategic locations, in combination with our other
fluid handling services, give us a competitive advantage over
other service providers in those areas in which these other
companies cannot provide these services. These locations also
allows us to expand our customer base.
63
Fluid Storage Tanks. Our fluid storage tanks can store up
to 500 barrels of fluid and are used by oilfield operators
to store various fluids at the well site, including water,
brine, drilling mud and acid for frac jobs, flowback, temporary
production and mud storage. We transport the tanks on our trucks
to well locations that are usually within a
50-mile radius of our
nearest yard. Frac tanks are used during all phases of the life
of a producing well. We generally rent fluid services tanks at
daily rates for a minimum of three days. A typical fracturing
operation can be completed within four days using 10 to 40 frac
tanks.
Drilling and Completion Services Segment
Our drilling and completion services segment provides oil and
gas operators with a package of services that include the
following:
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niche pressure pumping, such as cementing, acidizing,
fracturing, coiled tubing and pressure testing; |
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cased-hole wireline services; |
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underbalanced drilling in low pressure and fluid sensitive
reservoirs; and |
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oilfield services fishing and rental tool business. |
This segment currently operates 70 pressure pumping units
to conduct a variety of services designed to stimulate oil and
gas production or to enable cement slurry to be placed in or
circulated within a well. As of March 31, 2006, we also
operated 29 air compressor packages, including foam
circulation units, for underbalanced drilling and
10 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
64
sections, steel casing is lowered into the hole and cemented in
place. Pressure pumping equipment is utilized to force a cement
slurry into the area between the rock face and the casing,
thereby securing it. After a well is drilled and completed, the
casing may develop leaks as a result of abrasion from production
tubing, exposure to corrosive elements or inadequate support
from the original attempt to cement it in place. When a leak
develops, it is necessary to place specialized equipment into
the well and to pump cement in such a way as to seal the leak.
Repairing leaks in this manner is known as squeeze
cementing a method that utilizes pressure pumping
equipment.
Our pressure pumping business focuses on single truck, lower
horsepower cementing, acidizing and fracturing services in niche
markets. Major pressure pumping companies have deemphasized new
well cementing and stimulation work in the shallow well markets
and do not aggressively pursue the remedial work available in
many of the deeper well markets.
The following table sets forth the type, number and location of
the drilling and completion services equipment that we operated
at March 31, 2006:
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|
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|
|
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|
|
|
|
|
|
|
|
|
Operating Division |
|
|
|
|
|
Ark- |
|
Mid- |
|
Northern |
|
Southern |
|
|
|
|
La-Tex |
|
Continent |
|
Rockies |
|
Rockies |
|
Total |
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|
|
|
|
|
|
|
|
|
|
Pressure Pumping Units
|
|
|
12 |
|
|
|
55 |
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|
|
3 |
|
|
|
|
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|
|
70 |
|
Coiled Tubing Units
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2 |
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|
1 |
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3 |
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Air/ Foam Packages
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29 |
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|
29 |
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Wireline Units
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10 |
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10 |
|
Currently, there are only three pressure pumping companies that
provide their services on a national basis. These three
companies also control a majority of the activities in the
U.S. market. For the most part, these companies have
concentrated their assets in markets characterized by complex
work with the potential for high profit margins. This has
created an opportunity in the markets for pressure pumping
services in mature areas with less complex requirements. We,
along with a number of smaller, regional companies, have
concentrated our efforts on these markets. One of our major well
servicing competitors also participates in the pressure pumping
business, but primarily outside our core areas of operations for
pumping services.
Like our fluid services business, the level of activity of our
pressure pumping business is tied to drilling and workover
activity. The bulk of pressure pumping work is associated with
cementing casing in place as the well is drilled or pumping
fluid that stimulates production from the well during the
completion phase. Pressure pumping work is awarded based on a
combination of price and expertise. More complex work is less
sensitive to price and routine work is often awarded on the
basis of price alone.
Cased-hole wireline services typically utilize a single truck
equipped with a spool of wireline that is used to lower and
raise a variety of specialized tools in and out of a cased
wellbore. These tools can be used to measure pressures and
temperatures as well as the condition of the casing and the
cement that holds the casing in place. Other applications for
wireline tools include placing equipment in or retrieving
equipment from the wellbore, or 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
65
involves maintaining the pressure in a well at or slightly below
that of the surrounding formation using air, nitrogen, mist,
foam or lightweight drilling fluids instead of conventional
drilling fluid. Underbalanced drilling services are utilized in
areas where conventional drilling fluids or stimulation
techniques will severely damage the producing formation or in
areas where drilling performance can be substantially improved
with a lightened drilling fluid. In these cases, the drilling
fluid is lightened to make the natural pressure of the formation
greater than the hydrostatic pressure of the drilling fluid,
thereby creating a situation where pressure is forcing fluid out
of the formation (i.e., underbalanced) as opposed to into the
formation (i.e., over balanced). The most common method of
lightening drilling fluid is to mix it with air as the fluid is
pumped into the well. By varying the volume of air pumped with
the fluid, the net hydrostatic pressure can be adjusted to the
desired level. In extreme cases, air alone can be used to
circulate rock cuttings from the well.
Since reservoir pressure depletes over time as a well is
produced, it may be desirable to use underbalanced fluids in
workover operations associated with an existing well. Our air
compressors, pressure boosters, trailer mounted foam units and
associated equipment are used in a variety of drilling and
workover applications involving lightened fluids. Due to its
limited application, there is only one service company providing
these services on a national basis. The rest of the market is
serviced by small regional firms or rig contractors who supply
the equipment as part of the rig package.
Our fishing and rental tool business provides a range of
specialized services and equipment that are utilized on a
non-routine basis for both drilling and well servicing
operations. Drilling and well servicing rigs are equipped with a
complement of tools to complete routine operations under normal
conditions for most projects in the geographic area where they
are employed. When problems develop with drilling or servicing
operations, or conditions require non-routine equipment, our
customers will rely on a provider of fishing and rental tools to
augment equipment that is provided with a typical drilling or
well servicing rig package.
The term fishing applies to a wide variety of
downhole operations designed to correct a problem that has
developed when drilling or servicing a well. Most commonly the
problem involves equipment that has become lodged in the well
and cannot be removed without special equipment. Our customers
employ our technicians and our tools that are specifically
suited to retrieve the trapped equipment, or fish,
in order for operations to resume.
Well Site Construction Services Segment
Our well site construction services segment employs an array of
equipment and assets to provide services for the construction
and maintenance of oil and gas production infrastructure. These
services are primarily related to new drilling activities,
although the same equipment is utilized to maintain oil and gas
field infrastructure. Our well site construction services
segment includes dirt work for the following services:
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preparation and maintenance of access roads; |
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building of drilling locations; |
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installation of small gathering lines and pipelines; and |
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maintenance of production facilities. |
This segment utilizes a fleet of power units, including dozers,
trenchers, motor graders, backhoes and other heavy equipment
used in road construction. In addition, we own rock pits in some
markets in our Rocky Mountain division to ensure a reliable
source of rock to support our construction activities. We also
own a substantial quantity of wooden mats in our Gulf Coast
operations to support the well site construction requirements in
that marshy environment. This
66
range of services, coupled with our fluid service capabilities
in the same markets, differentiates us from our more specialized
competitors.
Companies engaged in oilfield construction and maintenance
services are typically privately owned and highly localized.
There are currently no companies that provide these services on
a nationwide basis. Our well site construction services in the
Gulf Coast and the Rocky Mountain states have a significant
presence in these markets. We believe that our existing
infrastructure will allow us to expand these operations.
Contracts for well site construction services are normally
awarded by our customers on the basis of competitive bidding and
may range in scope from several days to several months in
duration.
Properties
Our principal executive offices are currently located at
400 W. Illinois, Suite 800, Midland, Texas 79701.
During 2005 we also purchased and are currently renovating a
facility in Midland County, Texas to consolidate our corporate
office and to expand our refurbishment capacities. We currently
conduct our business from 91 area offices, 47 of which we
own and 44 of which we lease. Each office typically includes a
yard, administrative office and maintenance facility. Of our
91 area offices, 63 are located in Texas, seven are in
Oklahoma, five are in Wyoming, four are in New Mexico, four are
in Colorado, two are in Louisiana, two are in Montana, two are
in North Dakota, 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 2005 and
the first quarter of 2006, we provided services to more than
1,000 customers, with our top five customers comprising
only 16% and 14% of our revenues, respectively. The majority of
our business is with independent oil and gas companies. While we
believe we could redeploy equipment in the current market
environment if we lost a single material customer, or a few of
them, such loss could have an adverse effect on our business
until the equipment is redeployed.
Operating Risks and Insurance
Our operations are subject to hazards inherent in the oil and
gas industry, such as accidents, blowouts, explosions,
craterings, fires and oil spills, that can cause:
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personal injury or loss of life; |
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damage or destruction of property, equipment and the
environment; and |
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suspension of operations. |
In addition, claims for loss of oil and gas production and
damage to formations can occur in the well services industry. If
a serious accident were to occur at a location where our
equipment and services are being used, it could result in our
being named as a defendant in lawsuits asserting large claims.
Because our business involves the transportation of heavy
equipment and materials, we may also experience traffic
accidents which may result in spills, property damage and
personal injury.
Despite our efforts to maintain high safety standards, we from
time to time have suffered accidents in the past and anticipate
that we could experience accidents in the future. In addition to
the property and personal losses from these accidents, the
frequency and severity of these incidents affect our operating
costs and insurability and our relationships with customers,
employees and regulatory agencies. Any significant increase in
the frequency or severity of these incidents, or the general
level of compensation awards, could adversely affect the cost
of, or our
67
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 59% of the well
service market share based on total well servicing rig ownership
based on publicly available data reported by these competitors.
Both of these competitors are public companies or subsidiaries
of public companies that operate in most of the large oil and
gas producing regions in the U.S. These competitors have
centralized management teams that direct their operations and
decision making primarily from corporate and regional
headquarters. In addition, because of their size, these
companies market a large portion of their work to the major oil
and gas companies.
We differentiate ourselves from our major competition by our
operating philosophy. We operate a decentralized organization,
where local management teams are largely responsible for sales
and marketing to develop stronger relationships with our
customers at the field level. We target areas that are
attractive to independent oil and gas operators who in our
opinion tend to be more aggressive in spending, less focused on
price and more likely to award work based on performance. With
the major oil and gas companies divesting mature
U.S. properties, we expect our target customers well
population to grow over time through acquisition of properties
formerly operated by major oil and gas companies. We concentrate
on providing services to a diverse group of large and small
independent oil and gas companies. These independents typically
are relationship driven, make decisions at the local level and
are willing to pay higher rates for services. We have been
successful using this business model and believe it will enable
us to continue to grow our business and maintain or expand our
operating margins.
Safety Program
Our business involves the operation of heavy and powerful
equipment which can result in serious injuries to our employees
and third parties and substantial damage to property. We have
comprehensive safety and training programs designed to minimize
accidents in the work place and improve the efficiency of our
operations. In addition, many of our larger customers now place
greater emphasis on safety and quality management programs of
their contractors. We believe that these factors will gain
further importance in the future. We have directed substantial
resources toward employee safety and quality management training
programs as well as our employee review process. While our
efforts in these areas are not unique, we believe many
competitors, and particularly smaller contractors, have not
undertaken similar training programs for their employees.
We believe our approach to safety management is consistent with
our decentralized management structure. Company mandated
policies and procedures provide the overall framework to ensure
our operations minimize the hazards inherent in our work and are
intended to meet regulatory requirements, while allowing our
operations to satisfy customer mandated policies and local needs
and practices.
68
Environmental Regulation
Our well site servicing operations are subject to stringent
federal, state and local laws regulating the discharge of
materials into the environment or otherwise relating to health
and safety or the protection of the environment. Numerous
governmental agencies, such as the U.S. Environmental
Protection Agency, commonly referred to as the EPA,
issue regulations to implement and enforce these laws, which
often require difficult and costly compliance measures. Failure
to comply with these laws and regulations may result in the
assessment of substantial administrative, civil and criminal
penalties, as well as the issuance of injunctions limiting or
prohibiting our activities. In addition, some laws and
regulations relating to protection of the environment may, in
certain circumstances, impose strict liability for environmental
contamination, rendering a person liable for environmental
damages and cleanup costs without regard to negligence or fault
on the part of that person. Strict adherence with these
regulatory requirements increases our cost of doing business and
consequently affects our profitability. We believe that we are
in substantial compliance with current applicable environmental
laws and regulations and that continued compliance with existing
requirements will not have a material adverse impact on our
operations. However, environmental laws and regulations have
been subject to frequent changes over the years, and the
imposition of more stringent requirements could have a
materially adverse effect upon our capital expenditures,
earnings or our competitive position.
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 strict, joint and several liability for the costs of
investigating and cleaning up hazardous substances that have
been released into the environment, for damages to natural
resources and for the costs of some health studies. In addition,
companies that incur liability frequently confront additional
claims because it is not uncommon for neighboring landowners and
other third parties to file claims for personal injury and
property damage allegedly caused by hazardous substances or
other pollutants released into the environment.
The federal Solid Waste Disposal Act, as amended by the Resource
Conservation and Recovery Act of 1976, referred to as
RCRA, generally does not regulate most wastes
generated by the exploration and production of oil and natural
gas because that act specifically excludes drilling fluids,
produced waters and other wastes associated with the
exploration, development or production of oil and gas from
regulation as hazardous wastes. However, these wastes may be
regulated by the EPA or state agencies as non-hazardous wastes
as long as these wastes are not commingled with regulated
hazardous wastes. Moreover, in the ordinary course of our
operations, industrial wastes such as paint wastes and waste
solvents as well as wastes generated in the course of us
providing well services may be regulated as hazardous waste
under RCRA or hazardous substances under CERCLA.
We currently own or lease, and have in the past owned or leased,
a number of properties that have been used for many years as
service yards in support of oil and natural gas exploration and
production activities. Although we have utilized operating and
disposal practices that were standard in the industry at the
time, there is the possibility that repair and maintenance
activities on rigs and equipment stored in these service yards,
as well as well bore fluids stored at these yards, may have
resulted in the disposal or release of hydrocarbons or other
wastes on or under these yards or other locations where these
wastes have been taken for disposal. In addition, we own or
lease properties that in the past were operated by third parties
whose operations were not under our control. These properties
and the hydrocarbons or wastes
69
disposed thereon may be subject to CERCLA, RCRA and analogous
state laws. Under these laws, we could be required to remove or
remediate previously disposed wastes or property contamination.
We believe that we are in substantial compliance with the
requirements of CERCLA and RCRA.
Our operations are also subject to the federal Clean Water Act
and analogous state laws. Under the Clean Water Act, the
Environmental Protection Agency has adopted regulations
concerning discharges of storm water runoff. This program
requires covered facilities to obtain individual permits, or
seek coverage under a general permit. Some of our properties may
require permits for discharges of storm water runoff and, as
part of our overall evaluation of our current operations, we are
applying for stormwater discharge permit coverage and updating
stormwater discharge management practices at some of our
facilities. We believe that we will be able to obtain, or be
included under, these permits, where necessary, and make minor
modifications to existing facilities and operations that would
not have a material effect on us.
The federal Clean Water Act and the federal Oil Pollution Act of
1990, which contains numerous requirements relating to the
prevention of and response to oil spills into waters of the
United States, require some owners or operators of facilities
that store or otherwise handle oil to prepare and implement
spill prevention, control and countermeasure plans, also
referred to as SPCC plans, relating to the possible
discharge of oil into surface waters. In the course of our
ongoing operations, we recently updated and implemented SPCC
plans for several of our facilities. We believe we are in
substantial compliance with these regulations.
Our underground injection operations are subject to the federal
Safe Drinking Water Act, as well as analogous state and local
laws and regulations. Under Part C of the Safe Drinking
Water Act, the EPA established the Underground Injection Control
program, which established the minimum program requirements for
state and local programs regulating underground injection
activities. The Underground Injection Control program includes
requirements for permitting, testing, monitoring, record keeping
and reporting of injection well activities, as well as a
prohibition against the migration of fluid containing any
contaminant into underground sources of drinking water. The
substantial majority of our saltwater disposal wells are located
in the State of Texas and regulated by the Texas Railroad
Commission, also known as the RRC. We also operate
salt water disposal wells in Oklahoma and Wyoming and are
subject to similar regulatory controls in those states.
Regulations in these states require us to obtain a permit from
the applicable regulatory agencies to operate each of our
underground injection wells. We believe that we have obtained
the necessary permits from these agencies for each of our
underground injection wells and that we are in substantial
compliance with permit conditions and commission rules.
Nevertheless, these regulatory agencies have the general
authority to suspend or modify one or more of these permits if
continued operation of one of our underground injection wells is
likely to result in pollution of freshwater, substantial
violation of permit conditions or applicable rules, or leaks to
the environment. Although we monitor the injection process of
our wells, any leakage from the subsurface portions of the
injection wells could cause degradation of fresh groundwater
resources, potentially resulting in cancellation of operations
of a well, issuance of fines and penalties from governmental
agencies, incurrence of expenditures for remediation of the
affected resource and imposition of liability by third parties
for property damages and personal injuries. In addition, our
sales of residual crude oil 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.
70
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 March 31, 2006, we employed approximately
3,700 people, with approximately 85% employed on an
hourly basis. Our future success will depend partially on our
ability to attract, retain and motivate qualified personnel. We
are not a party to any collective bargaining agreements, and we
consider our relations with our employees to be satisfactory.
Litigation
On September 3, 2004, David Hudson, Jr. et al
commenced a civil action against us in the District Court of
Panola County, Texas, 123rd Judicial District, David
Hudson, Jr. et al v. Basic Energy Services
Company, Cause
No. 2004-A-137.
The complaint alleges that our operation of a saltwater disposal
well has contaminated both the groundwater and the soil in the
surrounding area. The relief requested in the complaint is
monetary damages, injunctive relief, environmental remediation
and a court order requiring us to provide drinking water to the
community. This matter was settled in April 2006 for an
immaterial amount.
On October 18, 2005, Clifford Golden et al commenced a
civil action against us in the 123rd Judicial District
Court of Panola County, Texas, Clifford Golden et al
v. Basic Energy Services, LP. The factual basis for
this complaint and relief are similar to the Hudson litigation,
including claims that our operation of a saltwater disposal well
has contaminated both the groundwater and the soil in the
surrounding area. In addition, this complaint alleges a wrongful
death and personal injuries to unspecified persons. In response
to this complaint, we have retained counsel and intend to defend
ourselves vigorously in this action.
On December 6, 2004, Karon Smith, et al commenced a
civil action against us in the District Court of Hidalgo County,
Texas, 206th Judicial District, Karon Smith, et al
v. Basic Energy Services GP L.L.C., Cause
No. C-42767-04-D.
The complaint alleged that (i) one of our fluid services
truck drivers disposed of oil-based waste at the
plaintiffs waste disposal facility, which was not equipped
to accept oil-based waste, and (ii) the disposal of such
oil-based waste resulted in plaintiffs facility losing
contracts to accept waste. On July 25, 2005, the jury in
this case returned a verdict in favor of the plaintiff and
awarded damages in the amount of $1.2 million. Our
insurance company to date has denied coverage of liability in
this lawsuit. In March 2006, we reached a settlement of this
matter in mediation for $1.0 million, which we had
previously recorded in accrued liabilities as of
December 31, 2005.
We are subject to other claims in the ordinary course of
business. However, we believe that the ultimate dispositions of
the above mentioned and other current legal proceedings will not
have a material adverse effect on our financial condition or
results of operations.
Neither we, nor any entity required to be consolidated with us,
has been required to pay a penalty to the Internal Revenue
Service for failing to make disclosures required with respect to
certain transactions that have been identified by the Internal
Revenue Service as abusive or that have a significant tax
avoidance.
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MANAGEMENT
Directors, Executive Officers and Other Key Employees
Our directors, executive officers and other key employees and
their respective ages and positions are as follows:
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Name |
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Age | |
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Position |
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Steven A. Webster
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54 |
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Chairman of the Board
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Kenneth V. Huseman
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54 |
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President, Chief Executive Officer
and Director
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Alan Krenek
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51 |
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Senior Vice President, Chief
Financial Officer, Treasurer and Secretary
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Charles W. Swift.
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56 |
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Senior Vice President
Rig and Truck Operations
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Dub W. Harrison
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47 |
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Vice President
Equipment & Safety
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Mark D. Rankin
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52 |
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Vice President Risk
Management
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James E. Tyner
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55 |
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Vice President Human
Resources
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James S.
DAgostino, Jr.
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59 |
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Director
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William E. Chiles
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57 |
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Director
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Robert F. Fulton
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54 |
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Director
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Sylvester P. Johnson, IV
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50 |
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Director
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Thomas P.
Moore, Jr.
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67 |
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Director
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H. H. Wommack, III
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50 |
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Director
|
Set forth below is the description of the backgrounds of our
directors, executive officers and other key employees.
Steven A. Webster (Chairman of the Board) has been
the Chairman of our Board of Directors and a director since
January 2001. Mr. Webster has served as Co-Managing Partner
of Avista Capital Holdings, L.P. (Avista), a private
equity firm focused on investments in the energy, media and
healthcare sectors since July 1, 2005. Prior to his
position with Avista, Mr. Webster served as Chairman of
Global Energy Partners, a specialty group within Credit
Suisses asset management business that made investments in
energy companies, from 1999 until June 30, 2005.
Mr. Webster has continued to serve as a consultant to
Credit Suisses asset management business through
arrangements with an affiliate of Avista, and serves on the
boards of, and monitors the operations of, various existing DLJ
Merchant Banking portfolio companies, including Basic Energy
Services. From 1998 to 1999, Mr. Webster served as Chief
Executive Officer and President of R&B Falcon Corporation,
and from 1988 to 1998, Mr. Webster served as Chairman and
Chief Executive Officer of Falcon Drilling Corporation, both
offshore drilling contractors. Mr. Webster serves as a
director of Grey Wolf, Inc., SEACOR Holdings Inc., Hercules
Offshore, Inc., Brigham Exploration Company, Goodrich Petroleum
Corporation, Camden Property Trust, Geokinetics, Inc., and
various privately-held companies. In addition, Mr. Webster
serves as Chairman of Carrizo Oil & Gas, Inc., Crown
Resources Corporation, and Pinnacle Gas Resources, Inc.
Mr. Webster was the founder and an original shareholder of
Falcon Drilling Company, a predecessor to Transocean, Inc., and
was a co-founder and original shareholder of Carrizo
Oil & Gas, Inc. Mr. Webster holds a B.S.I.M. from
Purdue University and an M.B.A. from Harvard Business School.
Kenneth V. Huseman (President Chief Executive
Officer and Director) has 26 years of well
servicing experience. He has been our President, Chief Executive
Officer and Director since 1999. Prior to joining us, he was
Chief Operating Officer at Key Energy Services from 1996 to
1999. He was a Divisional Vice President at WellTech, Inc. from
1993 to 1996. He was a Vice President of Operations at Pool
Energy Services Co. from 1982 to 1993, where he managed
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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 18 years of
related industry experience. He has been our Vice President,
Chief Financial Officer and Treasurer since January 2005. He
became Senior Vice President and Secretary in May 2006. From
October 2002 to January 2005, he served as Vice President and
Controller of Fleetwood Retail Corp., a subsidiary in the
manufactured housing division of Fleetwood Enterprises, Inc.
From March 2002 to August 2002, he was a consultant involved in
management, assessment of operational and financial internal
controls, cost recovery and cash flow management.
Mr. Krenek pursued personal interests from November 2001 to
March 2002. From December 1999 to November 2001, he acted as the
Vice President of Finance and later the Chief Financial Officer
of Digital Commerce Corporation, a
business-to-government
internet-based marketplace solutions company that filed for
Chapter 11 bankruptcy protection in June 2001. From January
1997 to December 1999, Mr. Krenek was the Vice President,
Finance of Global TeleSystems, Inc. From September 1995 to
December 1996, he served as Corporate Controller of Landmark
Graphics Corporation where he was responsible for SEC reporting,
general accounting, financial policies and procedures and
purchasing functions. He worked in various financial management
positions at Pool Energy Services Co. from 1980 to 1993 and at
Noble Corporation from 1993 to 1995. Mr. Krenek graduated
with a B.B.A. degree in Accounting from Texas A&M University
in 1977 and is a certified public accountant.
Charles W. Swift (Senior Vice President Rig
and Truck Operations) has 33 years of related
industry experience including 25 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 the well service and fluid
services businesses. Mr. Swift graduated with a B.B.A.
degree in International Trade from Texas Tech University.
Dub W. Harrison (Vice President
Equipment & Safety) has spent 29 years in
the well services industry. He has been a Vice President since
1995, during which time he established operations in east Texas,
negotiated an acquisition to enter the south Texas market and
implemented a consistent maintenance program. From 1987 to 1995,
he worked in operations and maintenance management at Pool
Energy Services Co.
Mark D. Rankin (Vice President Risk
Management) has 28 years of related industry
experience. He has been a Vice President since 2004. From 1997
to 2004, he was a consultant to oil and gas companies and was
involved in operations research and work process redesign. From
1985 to 1995, he acted as Director of International Marketing
and Marketing for U.S. Operations and a District Manager at
Pool Energy Services. He was an International Sales Manager and
Director of Planning and Market Research at Zapata Off-Shore
Company from 1979 to 1985. From 1977 to 1989, he was a Contract
Manager at Western Oceanic, Inc. He graduated with a B.A. in
Political Science from Texas A&M University.
James E. Tyner (Vice President Human
Resources) has been a Vice President since January 2004.
From 1999 to December 2003, he was the General Manager of Human
Resources at CMS Panhandle Companies, where he directed delivery
of HR Services. Mr. Tyner was the Director of Human
Resources Administration and Payroll Services at Duke
Energys Gas Transmission Group from 1998 to 1999. From
1981 to 1998, Mr. Tyner held various positions at Panhandle
Eastern Corporation. At Panhandle, he managed all Human
Resources functions and developed corporate policies and as a
Certified Safety Professional, he designed and implemented
programs to control workplace hazards. Mr. Tyner received a
B.S. and M.S. from Mississippi State University.
73
James S. DAgostino, Jr. (Director) has
served as a director since February 2004.
Mr. DAgostino has served as Chairman of the Board,
President and Chief Executive Officer of Encore Bank since
November 1999, during which time he initiated turnaround efforts
and raised over $30 million of new equity to create a
unique private banking organization. From 1998 to 1999,
Mr. DAgostino served as Vice Chairman and Group
Executive and from 1997 until 1998, he served as President,
Member of the Office of Chairman and Director of American
General Corporation. Mr. DAgostino graduated with an
economics degree from Villanova University and a J.D. from Seton
Hall University School of Law.
William E. Chiles (Director) has served as a
director since August 2003. Mr. Chiles has served as the
Chief Executive Officer, President and a Director of Bristow
Group Inc. (formerly named Offshore Logistics, Inc.), a provider
of helicopter transportation services to the worldwide offshore
oil and gas industry, since July 2004. Mr. Chiles served as
Executive Vice President and Chief Operating Officer of Grey
Wolf, Inc. from March 2003 until June 2004. Mr. Chiles
served as Vice President of Business Development at ENSCO
International Incorporated from August 2002 until March 2003.
From August 1997 until its merger into an ENSCO International
affiliate in August 2002, Mr. Chiles served as President
and Chief Executive Officer of Chiles Offshore, Inc.
Mr. Chiles has a B.B.A. in Petroleum Land Management from
The University of Texas and an M.B.A. in Finance and Accounting
with honors from Southern Methodist University, Dallas.
Robert F. Fulton (Director) has served as a
director since 2001. Mr. Fulton has served as President and
Chief Executive Officer of Frontier Drilling ASA since September
2002. From December 2001 to August 2002, Mr. Fulton managed
personal investments. He served as Executive Vice President and
Chief Financial Officer of Merlin Offshore Holdings, Inc. from
August 1999 until November 2001. From 1998 to June 1999,
Mr. Fulton served as Executive Vice President of Finance
for R&B Falcon Corporation, during which time he closed the
merger of Falcon Drilling Company with Reading & Bates
Corporation to create R&B Falcon Corporation and then the
merger of R&B Falcon Corporation and Cliffs Drilling
Company. He graduated with a B.S. degree in Accountancy from the
University of Illinois and an M.B.A. in finance from
Northwestern University.
Sylvester P. Johnson, IV (Director) has served as
a director since 2001. Mr. Johnson has served as President,
Chief Executive Officer and a director of Carrizo Oil &
Gas, Inc. since December 1993. Prior to that, he worked for
Shell Oil Company for 15 years. His managerial positions
included Operations Superintendent, Manager of Planning and
Finance and Manager of Development Engineering. Mr. Johnson
is a Registered Petroleum Engineer and has a B.S. in Mechanical
Engineering from the University of Colorado.
Thomas P. Moore, Jr. (Director) has served as
a director since December 2005. Mr. Moore was a Senior
Principal of State Street Global Advisors, the head of Global
Fundamental Strategies, and a member of the Senior Management
Group from 2001 through July 2005. Mr. Moore retired from
this position in July 2005. From 1986 through 2001, he was a
Senior Vice President of State Street Research &
Management Company and was head of the State Street Research
International Equity Team. From 1977 to 1986 he served in
positions of increasing responsibility with Petrolane, Inc.,
including Administrative Vice President (1977-1981), President
of Drilling Tools, Inc., an oilfield equipment rental subsidiary
(1981-1984), and President of Brinkerhoff-Signal, Inc., an oil
well contract drilling subsidiary (1984-1986). Mr. Moore is
a Chartered Financial Analyst and currently serves as a director
of several privately-held companies. Mr. Moore holds an
M.B.A. degree from Harvard Business School.
H. H. Wommack, III (Director) has served
as a director since 1992. Mr. Wommack was our founder and
our Chairman of the Board from 1992 until January 2001.
Mr. Wommack is currently a principal of and Chief Executive
Officer of Saber Resources, LLC, a privately held oil and gas
company that he founded in May 2004. Mr. Wommack served as
Chairman of the Board, President, Chief Executive Officer and a
Director of Southwest Royalties Holdings, Inc. from its
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formation in July 1997 until April 2005 and of Southwest
Royalties, Inc. from its formation in 1983 until its sale in May
2004. Prior to the formation of Southwest Royalties,
Mr. Wommack was a self-employed independent oil and gas
producer. Mr. Wommack is currently Chairman of the Board of
Midland Red Oak Realty, a commercial real estate company
involved in investments in the Southwest. Mr. Wommack is
also currently the President of Fortress Holdings, LLC and
Anchor Resources, LLC. He graduated with a B.A. from the
University of North Carolina and a J.D. from the University of
Texas School of Law.
Board of Directors
Our board of directors currently consists of eight members,
including four independent members
Messrs. DAgostino, Chiles, Moore and Johnson. The
listing requirements of the New York Stock Exchange require that
our board of directors be composed of a majority of independent
directors within one year of the listing of our common stock on
the NYSE. Accordingly, we intend to appoint an additional
independent director to our board of directors or otherwise
satisfy that obligation prior to such time.
Our board of directors is divided into three classes. The
directors serve staggered three-year terms. The current terms of
the directors of each class expire at the annual meetings of
stockholders to be held in 2007 (Class II), 2008
(Class III) and 2009 (Class I). At each annual meeting
of stockholders, one class of directors is elected for a full
term of three years to succeed that class of directors whose
terms are expiring. The classification of directors are as
follows:
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Class II Messrs. Chiles and Fulton; |
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Class III Messrs. DAgostino, Moore
and Huseman; and |
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Class I Messrs. Johnson, Webster and
Wommack. |
Committees
In compliance with the requirements of the Sarbanes Oxley Act of
2002, the NYSE listing standards and SEC rules and regulations,
a majority of the directors on our nominating and corporate
governance and compensation committees are currently independent
and, within one year of listing on the NYSE, these committees
will be fully independent and a majority of our board will be
independent.
Audit Committee
Our audit committee is currently comprised of
Messrs. DAgostino, Chiles and Moore, with
Mr. Moore currently serving as chairman. Our board has
determined that Messrs. DAgostino, Chiles and Moore
are independent directors as defined under and required by the
Securities Exchange Act of 1934, or the Exchange Act, and the
listing requirements of the New York Stock Exchange, or NYSE.
Our board of directors has determined that Messrs. Moore and
DAgostino are audit committee financial
experts. The responsibilities of the Audit Committee
include:
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to appoint, engage and terminate our independent auditors; |
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to approve fees paid to our independent auditors for audit and
permissible non-audit services in advance; |
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to evaluate, at least on an annual basis, the qualifications,
independence and performance of our independent auditors; |
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to review and discuss with our independent auditors reports
provided by the independent auditors to the Audit Committee
regarding financial reporting issues; |
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to review and discuss with management and our independent
auditors our quarterly and annual financial statements prior to
our filing of periodic reports; |
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to review our procedures for internal auditing and the adequacy
of our disclosure controls and procedures and internal control
over financial reporting; and |
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to evaluate its own performance at least on an annual basis. |
To promote the independence of the audit, the Audit Committee
consults separately and jointly with the independent auditors,
the internal auditors and management.
Nominating and Corporate Governance Committee
Our nominating and corporate governance committee currently
consists of Messrs. Johnson, Webster and Moore, with
Mr. Johnson currently serving as chairman. Our board has
determined that Messrs. Johnson and Moore are independent
as required by the listing requirements of the NYSE. The
responsibilities of the Nominating and Corporate Governance
Committee include:
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to identify, recruit and evaluate candidates for membership on
the Board and to develop processes for identifying and
evaluating such candidates; |
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to annually present to the Board a list of nominees recommended
for election to the Board at the annual meeting of stockholders,
and to present to the Board, as necessary, nominees to fill any
vacancies that may occur on the Board; |
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to adopt a policy regarding the consideration of any director
candidates recommended by our stockholders and the procedures to
be followed by such stockholders in making such recommendations; |
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to adopt a process for our stockholders to send communications
to the Board; |
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to evaluate its own performance at least annually and deliver a
report setting forth the results of such evaluation to the Board; |
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to oversee our policies and procedures regarding compliance with
applicable laws and regulations relating to the honest and
ethical conduct of our directors, officers and employees; |
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to have the sole responsibility for granting any waivers under
our Code of Ethics and Corporate Governance Guidelines; and |
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to evaluate annually, based on input from the entire Board, the
performance of the CEO and report the results of such evaluation
to the Compensation Committee of the Board. |
Compensation Committee
Our compensation committee currently consists of
Messrs. Chiles, DAgostino and Wommack, with
Mr. Chiles currently serving as chairman. Our board has
determined that Messrs. Chiles and DAgostino are
independent as required by the listing requirements of the NYSE.
The responsibilities of the Compensation Committee include:
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to evaluate and develop the compensation policies applicable to
our executive officers and make recommendations to the Board
with respect to the compensation to be paid to our executive
officers; |
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to review, approve and evaluate on an annual basis the corporate
goals and objectives with respect to compensation for our Chief
Executive Officer; |
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to determine and approve our Chief Executive Officers
compensation, including salary, bonus, incentive and equity
compensation; |
76
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to review and make recommendations regarding the compensation
paid to non-employee directors; |
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to review and make recommendations to the Board with respect to
our incentive compensation plans and to assist the Board with
the administration of such plans; and |
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to evaluate its own performance at least annually and deliver a
report setting forth the results of such evaluation to the Board. |
Web Access
We provide access through our website at
www.basicenergyservices.com to current information
relating to governance, including a copy of each board committee
charter, our Code of Conduct, our corporate governance
guidelines and other matters impacting our governance
principles. You may also contact our Chief Financial Officer for
paper copies of these documents free of charge.
Compensation Committee Interlocks and Insider
Participation
None of our executive officers serve as a member of the board of
directors or compensation committee of any entity that has one
or more of its executive officers serving as a member of our
board of directors or compensation committee.
77
Compensation of Executive Officers
The following table summarizes all compensation earned by our
Chief Executive Officer and each of our four other most highly
compensated executive officers during the years ended
December 31, 2003, 2004 and 2005, to whom we refer in this
prospectus as our named executive officers.
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Long-Term | |
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Annual | |
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Compensation | |
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Compensation(1) | |
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Restricted | |
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Securities | |
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Fiscal | |
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Stock | |
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Underlying | |
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All Other | |
Name and Principal Position |
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Year | |
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Salary | |
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Bonus | |
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Awards(2) | |
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Options | |
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Compensation(3) | |
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($) | |
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($) | |
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($) | |
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(#) | |
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($) | |
Kenneth V. Huseman
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2005 |
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325,000 |
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275,000 |
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100,000 |
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1,600 |
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President and
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2004 |
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327,884 |
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500,000 |
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3,141,000 |
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2,308 |
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Chief Executive Officer
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2003 |
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269,231 |
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125,000 |
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200,000 |
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16,955 |
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Alan Krenek
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2005 |
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170,769 |
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187,500 |
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125,000 |
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52,331 |
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Senior Vice President
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2004 |
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NA |
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NA |
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NA |
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NA |
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NA |
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Finance and Chief Financial
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2003 |
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NA |
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NA |
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NA |
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NA |
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NA |
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Officer(4)
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James J. Carter(5)
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2005 |
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170,000 |
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60,000 |
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30,000 |
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1,288 |
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Executive Vice President
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2004 |
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168,846 |
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200,000 |
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698,000 |
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and Secretary
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2003 |
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127,692 |
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25,000 |
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60,000 |
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Charles W. Swift
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2005 |
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150,000 |
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95,068 |
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35,000 |
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14,400 |
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Vice President Permian
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2004 |
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151,924 |
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69,894 |
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349,000 |
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9,600 |
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2003 |
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123,077 |
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24,714 |
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50,000 |
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9,600 |
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Dub W. Harrison
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2005 |
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140,000 |
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48,000 |
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25,000 |
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10,240 |
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Vice President
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2004 |
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141,539 |
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60,250 |
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349,000 |
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9,600 |
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Equipment & Safety
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2003 |
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115,385 |
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14,000 |
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50,000 |
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9,600 |
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(1) |
Under the terms of their employment agreements,
Messrs. Huseman, Krenek, Carter, Swift and Harrison are
entitled to the compensation described under Employment
Agreements below. Perquisites and other personal benefits
paid or distributed during fiscal 2003, 2004 and 2005 to the
individuals listed in the table above did not exceed, for any
individual, the lesser of $50,000 or 10 percent of such
individuals total salary and bonus. |
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(2) |
Shares of restricted stock were granted to the named executive
officers during 2004 as follows: Huseman
450,000 shares; Carter 100,000 shares;
Swift 50,000 shares; and Harrison
50,000 shares. The fair market value as of the date of
grant of the shares of restricted stock during February 2004, as
determined by our board of directors, was $6.98. These shares
are subject to vesting in one-fourth increments on each of
February 24, 2005, 2006, 2007 and 2008 for each person
other than Mr. Carter, whose shares vested one-half on
February 24, 2005 and one-half on February 24, 2006.
Cash dividends, if any are paid, would be payable on these
shares of restricted stock, but we will retain any stock
dividends applicable to these shares until the vesting period is
satisfied on the shares on which the stock dividend is issued.
For information concerning grants of and the aggregate holdings
of restricted stock by the named executive officers, see
Employment Agreements below. For information
regarding repurchases of shares of restricted stock by us from
the named executive officers and other officers during 2005 and
2006, see Certain Relationships and Related Party
Transactions below. |
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(3) |
For 2005, includes: for Mr. Huseman, deferred compensation
contributions of $1,600; for Mr. Krenek, moving related
allowance of $52,331; for Mr. Carter, deferred compensation
contributions of $1,288; for Mr. Swift, vehicle allowance
of $9,600 and deferred compensation contributions of $4,800; and
for Mr. Harrison, vehicle allowance of $9,600 and deferred
compensation contributions of $640. For 2004 includes: for
Mr. Huseman, vehicle allowance of $2,308; for each of
Mr. Swift and Mr. Harrison, vehicle allowance of
$9,600. For 2003 includes: |
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for Mr. Huseman, vehicle
allowance of $12,000 and life insurance costs of $4,955; for
each of Mr. Swift and Mr. Harrison, vehicle allowance
of $9,600.
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(4) |
Mr. Krenek has served as our
Chief Financial Officer since January 2005.
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(5) |
Mr. Carter, our former
Executive Vice President and Secretary, retired effective
April 30, 2006.
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Aggregated Option Exercises in 2005 and Fiscal Year-End
Option Values
The following table sets forth information concerning options
exercised during the last fiscal year and held as of
December 31, 2005 by each of the named executive officers.
None of the named executive officers exercised options during
the year ended December 31, 2005. Amounts described in the
following table under the heading Value of Unexercised
In-the-Money Options at
December 31, 2005 are determined by multiplying the
number of shares issued or issuable upon the exercise of the
option by the difference between the closing price of our common
stock at December 31, 2005 and the per share option
exercise price.
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Number of Shares | |
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Underlying Unexercised | |
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Value of Unexercised | |
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Options at | |
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In-the-Money Options at | |
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December 31, 2005 | |
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December 31, 2005 | |
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Exercisable | |
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Unexercisable | |
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Exercisable | |
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Unexercisable | |
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Kenneth V. Huseman
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399,755 |
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166,650 |
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$ |
6,376,092 |
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$ |
2,360,068 |
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Alan Krenek
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125,000 |
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1,803,450 |
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James J. Carter
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128,720 |
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50,000 |
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2,053,084 |
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708,100 |
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Dub W. Harrison
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89,560 |
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41,665 |
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1,428,482 |
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590,057 |
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Charles W. Swift.
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89,560 |
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51,665 |
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1,428,482 |
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719,757 |
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Option Grants in Last Fiscal Year
The following table sets forth information concerning options
granted during the year ended December 31, 2005 to each of
the named executive officers.
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Individual Grants | |
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Potential Realizable | |
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% of Total | |
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Value at Assumed | |
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Number of | |
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Options | |
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Annual Rates of Stock | |
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Securities | |
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Granted to | |
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Exercise | |
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Price Appreciation for | |
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Underlying | |
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Employees | |
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or Base | |
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Option Term | |
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Options | |
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in Fiscal | |
|
Price | |
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Expiration | |
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Name |
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Granted(#)(1) | |
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Year(2) | |
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($/Sh) | |
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Date | |
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5%($) | |
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10%($) | |
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| |
Kenneth V. Huseman
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100,000 |
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10.2 |
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6.98 |
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3/1/2015 |
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$ |
1,383,727 |
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$ |
2,616,803 |
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Alan Krenek(3)
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125,000 |
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12.7 |
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5.52 |
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(4 |
) |
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1,398,557 |
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2,635,975 |
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James J. Carter
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30,000 |
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3.1 |
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6.98 |
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3/1/2015 |
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415,118 |
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785,041 |
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Charles W. Swift
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35,000 |
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3.6 |
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6.98 |
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3/1/2015 |
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484,305 |
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915,881 |
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Dub W. Harrison
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25,000 |
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2.5 |
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6.98 |
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3/1/2015 |
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|
345,932 |
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654,201 |
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(1) |
Except as provided in note (3) below, all options reflected
in the table were earned in fiscal 2005 and granted on
March 2, 2005. No stock appreciation rights
(SARs) were granted in tandem with the options
reflected in this table. Except as provided in note (3)
below, these options vest in equal one-fourth increments on each
of January 1, 2007, 2008, 2009 and 2010. |
|
(2) |
Reflects the percentage of total options granted in fiscal 2005. |
|
(3) |
Includes options to purchase 100,000 shares of common stock
granted to Mr. Krenek on January 26, 2005 in
connection with the commencement of his employment with us.
These options vest in equal one-third increments on each of
January 26, 2006, 2007 and 2008. |
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(4) |
Options to purchase 100,000 shares of common stock expire
on January 25, 2015 and options to purchase
25,000 shares of common stock expire on March 1, 2015. |
Compensation of Directors
Directors who are our employees do not receive a retainer or
fees for service on the board or any committees. We pay
non-employee members of the board for their service as
directors. Directors who are not employees receive, effective
May 1, 2005, an annual fee of $30,000. In addition, the
chairman of each committee receives the following annual fees:
audit committee $10,000; compensation
committee $6,000; and nominating and corporate
governance committee $6,000. Directors who are not
employees currently receive a fee of $2,000 for each board
meeting attended in person, and a fee of $1,000 for attendance
at a board meeting held telephonically. For committee meetings,
directors who are not employees currently receive a fee of
$3,000 for each committee meeting attended in person, and a fee
of $1,500 for attendance at a committee meeting held
telephonically. In addition, each non-employee director has
received, upon election to the board, a stock option to purchase
37,500 shares of our common stock at the market price on
the date of grant that vests ratably over three years. Directors
are reimbursed for reasonable
out-of-pocket expenses
incurred in attending meetings of the board or committees and
for other reasonable expenses related to the performance of
their duties as directors.
Second Amended and Restated 2003 Incentive Plan
Our 2003 Incentive Plan, which was adopted by our Board of
Directors and has been approved by our stockholders as amended,
covers stock awards issued under our original 2003 Incentive
Plan and predecessor equity plan. This incentive plan permits
the granting of any or all of the following types of awards:
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stock options; |
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restricted stock; |
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performance awards; |
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phantom shares; |
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other stock-based awards; |
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bonus shares; and |
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cash awards. |
All non-employee directors and employees of, and any consultants
to, us or any of our affiliates are eligible for participation
under the incentive plan.
The number of shares with respect to which awards may be granted
under the 2003 Incentive Plan may not exceed
5,000,000 shares, of which awards for 3,680,050 shares
have been issued as of March 31, 2006. The incentive plan
will be administered by the compensation committee of our board
of directors. The compensation committee will select the
participants who will receive awards, determine the type and
terms of the awards to be granted and interpret and administer
the incentive plan. No awards may be granted under the incentive
plan after April 12, 2014.
The options granted pursuant to the 2003 Incentive Plan may be
either incentive options qualifying for beneficial tax treatment
for the recipient as incentive stock options under
Section 422 of the Code or non-qualified options. No person
may be issued incentive stock options that first become
exercisable in any calendar year with respect to shares having
an aggregate fair market value, at the date of grant, in excess
of $100,000. No incentive stock option may be granted to a
person if at the time such option is granted the person owns
stock
80
possessing more than 10% of the total combined voting power of
all classes of our stock or any of our subsidiaries as defined
in Section 424 of the Code, unless at the time incentive
stock options are granted the purchase price for the option
shares is at least 110% of the fair market value of the option
shares on the date of grant and the incentive stock options are
not exercisable five years after the date of grant.
The 2003 Incentive Plan permits the payment of qualified
performance-based compensation within the meaning of
Section 162(m) of the Code, which generally limits the
deduction that we may take for compensation paid in excess of
$1,000,000 to certain of our covered officers in any
one calendar year unless the compensation is qualified
performance-based compensation within the meaning of
Section 162(m) of the Code. The 2003 Incentive Plan was
approved by our stockholders prior to this initial public
offering. This prior stockholder approval (assuming no further
material modifications of the plan) will satisfy the stockholder
approval requirements of Section 162(m) following this
initial public offering for a transition period ending not later
than our annual meeting of stockholders in 2009.
Tax Treatment for Our 2003 Incentive Plan
The following is a brief summary of certain of the United States
federal income tax consequences relating to our 2003 Incentive
Plan based on federal income tax laws currently in effect. This
summary applies to the plan as normally operated and is not
intended to provide or supplement tax advice. Individual
circumstances may vary these results, and we recommend that each
participant consult his or her own tax counsel for advice
regarding tax treatment under the plan. The summary contains
general statements based on current United States federal income
tax statutes, regulations and currently available
interpretations thereof. This summary is not intended to be
exhaustive and does not describe state, local or foreign tax
consequences or the effect, if any, of gift, estate and
inheritance taxes.
Non-qualified Stock Options. An optionee will not
recognize any taxable income upon the grant of a non-qualified
stock option. We will not be entitled to a federal income tax
deduction with respect to the grant of a non-qualified stock
option. Upon exercise of a non-qualified stock option, the
excess of the fair market value of the common stock transferred
to the optionee over the option exercise price will be taxable
as compensation income to the optionee and will be subject to
applicable withholding taxes. Such fair market value generally
will be determined on the date the shares of common stock are
transferred pursuant to the exercise. We generally will be
entitled to a federal income tax deduction at such time in the
amount of such compensation income. The optionees federal
income tax basis for the common stock received pursuant to the
exercise of a non-qualified stock option will equal the sum of
the compensation income recognized and the exercise price. In
the event of a sale of common stock received upon the exercise
of a non-qualified stock option, any appreciation or
depreciation after the exercise date generally will be taxed as
capital gain or loss.
Incentive Stock Options. An optionee will not
recognize any taxable income at the time of grant or timely
exercise of an incentive stock option (but in some circumstances
may be subject to an alternative minimum tax as a result of
exercise), and we will not be entitled to a federal income tax
deduction with respect to such grant or exercise. A sale or
exchange by an optionee of shares acquired upon the exercise of
an incentive stock option more than one year after the transfer
of the shares to such optionee and more than two years after the
date of grant of the incentive stock option will result in the
difference between the amount realized and the exercise price,
if any, being treated as long-term capital gain (or loss) to the
optionee. If such sale or exchange takes place within two years
after the date of grant of the incentive stock option or within
one year from the date of transfer of the shares to the
optionee, such sale or exchange generally will constitute a
disqualifying disposition of such shares that will
have the following result: any excess of (a) the lesser of
(1) the fair market value of the shares at the time of
exercise of the incentive stock option and (2) the amount
realized on such disqualifying
81
disposition of the shares over (b) the option exercise
price of such shares, will be ordinary income to the optionee,
and we generally will be entitled to a federal income tax
deduction in the amount of such income. The balance, if any, of
the optionees gain upon a disqualifying disposition will
qualify as capital gain and will not result in any deduction by
us.
Restricted Stock. A grantee generally will not
recognize taxable income upon the grant of restricted stock, and
the recognition of any income will be postponed until such
shares are no longer subject to restrictions on transfer or the
risk of forfeiture. When either the transfer restrictions or the
risk of forfeiture lapses, the grantee will recognize ordinary
income equal to the fair market value of the restricted stock at
the time of such lapse and, subject to satisfying applicable
income reporting requirements and any deduction limitation under
Section 162(m) of the Code, we will be entitled to a
federal income tax deduction in the same amount and at the same
time as the grantee recognized ordinary income. A grantee may
elect to be taxed at the time of the grant of restricted stock
and, if this election is made, the grantee will recognize
ordinary income equal to the excess of the fair market value of
the restricted stock at the time of grant (determined without
regard to any of the restrictions thereon) over the amount paid,
if any, by the grantee for such shares. We generally will be
entitled to a federal income tax deduction in the same amount
and at the same time as the grantee recognizes ordinary income.
Performance Awards, Phantom Shares and Other Stock-Based
Awards. Generally, a grantee will not recognize any
taxable income and we will not be entitled to a deduction upon
the award of performance awards, phantom shares and other
stock-based awards. Upon vesting, the participant would include
in ordinary income the value of any shares received and an
amount equal to any cash received. Subject to satisfying
applicable income reporting requirements and any deduction
limitation under Section 162(m) of the Code, we will be
entitled to a federal income tax deduction equal to the amount
of ordinary income recognized by the grantee.
Bonus Shares and Cash Awards. Upon the receipt of
bonus shares and cash awards, the grantee would include in
ordinary income the value of any shares received and an amount
equal to any cash received. Subject to satisfying applicable
income reporting requirements and any deduction limitation under
Section 162(m) of the Code, we will be entitled to a
federal income tax deduction equal to the amount of ordinary
income recognized by the grantee.
Deferred Compensation and Parachute Taxes.
Section 409A of the Code provides for an additional 20%
tax, among other things, on awards that, if subject to
Section 409A, do not comply with the requirements of this
section. We intend for awards to comply with Section 409A.
In addition, if, upon a change of control of us, the vesting or
payment of awards to certain disqualified
individuals exceeds certain amounts, that individual will
be subject to a 20% excise tax on such payments and those
amounts will not be deductible by us.
Employment Agreements
Under the current employment agreement with Mr. Huseman
effective March 1, 2004 through February 2007,
Mr. Huseman is entitled to an annual salary of $325,000 and
an annual bonus ranging from $50,000 to $325,000 based on
Mr. Husemans performance. Under this employment
agreement, Mr. Huseman is eligible from time to time to
receive grants of stock options and other long-term equity
incentive compensation under our Amended and Restated 2003
Incentive Plan. In addition, upon a qualified termination of
employment Mr. Huseman would be entitled to three times his
base salary plus his current annual incentive target bonus for
the full year in which the termination of employment occurred.
Similarly, following a change of control of our company,
Mr. Huseman would be entitled to a lump sum payment of two
times his base salary plus his current annual incentive target
bonus for the full year in which the change of control occurred.
Mr. Husemans bonus in 2005 was unanimously approved
by our Board of Directors, including the independent directors.
In 2005 the Board of Directors approved the payment of a
82
$275,000 bonus to Mr. Huseman, and the Board has approved a
salary for Mr. Huseman effective in March 2006 of $400,000.
We have also entered into employment agreements with Dub W.
Harrison and Charles W. Swift, as amended in July 2006, for a
term through June 2009, and with James E. Tyner through January
2007. Pursuant to the July 2006 amendments, Mr. Harrison is
entitled to an annual salary of $150,000 and Mr. Swift is
entitled to an annual salary of $200,000. Mr. Tyner is
entitled to an annual salary of $110,000 under his employment
agreement. Under these agreements, if the officers
employment is terminated for certain reasons, he would be
entitled to a lump sum severance payment equal to six
months salary, or 18 months salary
(12 months salary in the case of Mr. Tyner) if
termination is on or following a change of control of our
company. The Board approved a 2006 salary for Mr. Tyner
effective in March 2006 of $140,000.
Under an employment agreement with Alan Krenek effective
January 26, 2005 through January 2008, Mr. Krenek is
entitled to an annual salary of $185,000 and an annual bonus,
based on Mr. Kreneks performance, ranging from
$25,000 to $138,750. Mr. Krenek is also eligible to
participate in our 2003 Incentive Plan. Under this employment
agreement, Mr. Krenek received a one-time cash bonus of
$37,500 and an initial grant of options to purchase
100,000 shares of stock. Under this agreement, if
Mr. Kreneks employment is terminated for certain
reasons, he would be entitled to a lump sum severance payment
equal to 12 months salary plus his current annual
incentive target bonus for the full year in which the
termination of employment occurred, such lump sum to be
increased by 50% if termination is on or following a change of
control of our company. The Board has approved a 2006 salary for
Mr. Krenek of $240,000 effective in March 2006.
James J. Carter, our former Executive Vice President and
Secretary, retired effective April 30, 2006. Mr.
Carters employment agreement entitled him to an annual
salary of $130,000, and the Board approved a 2006 annual salary
of $170,000 for Mr. Carter that was effective prior to his
retirement.
Indemnification Agreements
We have also entered into indemnification agreements with all of
our directors and some of our executive officers. These
indemnification agreements are intended to permit
indemnification to the fullest extent now or hereafter permitted
by the General Corporation Law of the State of Delaware. It is
possible that the applicable law could change the degree to
which indemnification is expressly permitted.
The indemnification agreements cover expenses (including
attorneys fees), judgments, fines and amounts paid in
settlement incurred as a result of the fact that such person, in
his or her capacity as a director or officer, is made or
threatened to be made a party to any suit or proceeding. The
indemnification agreements generally cover claims relating to
the fact that the indemnified party is or was an officer,
director, employee or agent of us or any of our affiliates, or
is or was serving at our request in such a position for another
entity. The indemnification agreements also obligate us to
promptly advance all reasonable expenses incurred in connection
with any claim. The indemnitee is, in turn, obligated to
reimburse us for all amounts so advanced if it is later
determined that the indemnitee is not entitled to
indemnification. The indemnification provided under the
indemnification agreements is not exclusive of any other
indemnity rights; however, double payment to the indemnitee is
prohibited.
83
We are not obligated to indemnify the indemnitee with respect to
claims brought by the indemnitee against:
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claims regarding the indemnitees rights under the
indemnification agreement; |
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claims to enforce a right to indemnification under any statute
or law; and |
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counter-claims against us in a proceeding brought by us against
the indemnitee; or |
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any other person, except for claims approved by our board of
directors. |
We have also agreed to obtain and maintain director and officer
liability insurance for the benefit of each of the above
indemnitees. These policies will include coverage for losses for
wrongful acts and omissions and to ensure our performance under
the indemnification agreements. Each of the indemnitees will be
named as an insured under such policies and provided with the
same rights and benefits as are accorded to the most favorably
insured of our directors and officers.
84
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Transactions with Officers and Directors
We performed well servicing and fluid services for Southwest
Royalties, Inc. in exchange for $1.3 million, $140,000 and
$0 for the years ended 2003, 2004 and 2005, respectively. We
believe prices charged to Southwest Royalties to be comparable
to prices charged in the region. Mr. Wommack, one of our
directors, served as President and Chairman of the Board of
Southwest Royalties from 1983 until May 2004. Southwest
Royalties Holdings, Inc., a former stockholder of Southwest
Royalties, owned shares of our common stock, and transferred
those shares to Fortress Holdings, LLC in April 2005.
Mr. Wommack is the President and a board member of Fortress
Holdings. Fortress Holdings also owns an equity interest in
Anchor Resources, LLC, which is the general partner of two of
our stockholders, Southwest Partners II, L.P. and Southwest
Partners III, L.P. Mr. Wommack serves as President and
is a board member of Anchor Resources.
We performed well servicing and fluid services for Saber
Resources, LLC in exchange for approximately $67,000 during the
year ended December 31, 2005. We believe prices charged to
Saber Resources to be comparable to prices charged in the
region. Mr. Wommack, one of our directors, is the President
and Chairman of the Board of Saber Resources.
Prior to our initial public offering, we entered into Share
Tender and Repurchase Agreements with ten of our officers.
Pursuant to these agreements, we repurchased, and nine of the
officers sold, an aggregate of 135,326 shares of our common
stock at $18.70 per share, the initial public offering
price, less underwriting discounts and commissions, on the
closing date of our initial public offering. These shares were
repurchased to provide such officers the cash amounts necessary
to pay certain tax liabilities associated with the vesting of
restricted shares owned by them. The shares repurchased
represented up to 39.2% of the vested shares of each officer
issued as compensation. We withheld minimum tax liability
requirements from these proceeds and paid the remainder of the
proceeds to the officers for their use in paying estimated tax
liabilities. The four executive officers and number of shares
that we repurchased from them upon the closing of our initial
public offering were as follows: Kenneth V. Huseman
101,975 shares; James J. Carter
10,005 shares; Dub W. Harrison
11,184 shares; and Charles W. Swift
4,161 shares. The remaining five officers who sold shares
were not executive officers.
In addition to the repurchase of shares on the closing date of
our initial public offering, under the Share Tender and
Repurchase Agreements, we repurchased, and nine of the officers
sold, an aggregate of 78,656 shares of our common stock on
February 24, 2006 at $25.00 per share, the closing
price per share of common stock on that date. These shares were
repurchased to provide such officers the cash amounts necessary
to pay certain tax liabilities associated with the vesting of
restricted shares owned by them and represented up to 36.45% of
the restricted shares owned by each officer that vest on that
date. We withheld minimum tax liability requirements from these
proceeds and paid the remainder of the proceeds to the officers
for their use in paying estimated tax liabilities. The four
executive officers and number of shares that we repurchased from
them on February 24, 2006 were as follows: Kenneth V.
Huseman 41,000 shares; James J.
Carter 18,225 shares; Dub W.
Harrison 4,557 shares; and Charles W.
Swift 4,557 shares.
Summary of Certain Equity Issuances
During the past three years, we have completed the following
issuances of equity, including to affiliates and other selling
stockholders participating in this offering, outside the
issuance of awards pursuant to our 2003 Incentive Plan and the
exchange of shares in our holding company reorganization on
January 24, 2003 described in this prospectus under
The Company. We
85
believe these transactions were on terms at least as favorable
as we could have obtained from unaffiliated third parties as a
result of arms-length negotiations.
In February 2002, our predecessor issued 3,000,000 shares
of our common stock, together with warrants exercisable for an
aggregate of 600,000 shares of our common stock, to DLJ
Merchant Banking and its affiliated funds for aggregate cash
consideration of $12 million.
On June 25, 2002, our predecessor issued
150,000 shares of Series A 10% Cumulative Preferred
Stock, together with warrants exercisable for an aggregate of
3,750,000 shares of our common stock, to DLJ Merchant
Banking and its affiliated funds for aggregate cash
consideration of $15 million. Offering expenses related to
this transaction totaled $58,000.
On May 5, 2003, we issued an aggregate of
771,740 shares of common stock upon the exercise of all of
our EBITDA Contingent Warrants, which were issued during
December 2000 and August 2001 to our prior stockholders and
certain members of management, for aggregate consideration of
$1,543.48.
On October 3, 2003, in connection with the refinancing of
certain indebtedness and request of our lenders, we exchanged an
aggregate of 3,304,085 shares of our common stock for
outstanding shares of our Series A 10% Cumulative Preferred
Stock at an exchange rate of one share of our common stock for
each $5.1584 of outstanding liquidation value ($100.00 per
share) of our Series A 10% Cumulative Preferred Stock and
accrued but unpaid interest thereon, as of the date of exchange.
The holders of these shares at the time of exchange were
DLJ Merchant Banking and its affiliated funds.
On October 3, 2003, we issued an aggregate of
3,650,000 shares of common stock, including
730,000 shares of common stock issued into escrow, to the
former stockholders of FESCO Holdings, Inc. as consideration for
all of the outstanding shares of FESCO Holdings, Inc. The
implied value per share in connection with the share exchange
was $5.16 per share. Former stockholders of FESCO Holdings,
Inc. include First Reserve Fund VIII, L.P.
Relationships with Certain Directors
Steven A. Webster, the Chairman of our Board of Directors, is
the Co-Managing Partner
of Avista Capital Holdings, L.P. (Avista), 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 of interest may not always be in our
stockholders best interest. We expect to address
transactions involving potential conflicts of interest by having
such transactions approved by the disinterested members of our
Board of Directors.
86
PRINCIPAL STOCKHOLDERS
The following table sets forth information with respect to the
beneficial ownership of our common stock as of July 13,
2006 by:
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each person who is known by us to own beneficially 5% or more of
our outstanding common stock; |
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each of our named executive officers; |
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each of our directors; and |
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all of our executive officers and directors as a group
(15 persons). |
Except as otherwise indicated, the person or entities listed
below have sole voting and investment power with respect to all
shares of our common stock beneficially owned by them, except to
the extent this power may be shared with a spouse. Unless
otherwise indicated, the address of each stockholder listed
below is 400 W. Illinois, Suite 800, Midland,
TX 79701. The following information was obtained by us in
reliance upon information set forth in statements filed by the
principal stockholders on Schedules 13D and 13G, on
Forms 3 or 4 pursuant to Section 16 of the Securities
and Exchange Act of 1934 or questionnaires provided by such
stockholders.
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Shares Beneficially | |
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Owned | |
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Name of Beneficial Owner |
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Number | |
|
Percent | |
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| |
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| |
DLJ Merchant Banking
Partners III, L.P. and affiliated funds(1)
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18,059,424 |
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47.4 |
% |
RS Investment Management Co. LLC(2)
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1,754,400 |
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5.2 |
% |
Fortress Holdings, LLC(3)(4)
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667,205 |
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2.0 |
% |
Anchor Resources, LLC(3)(4)
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1,434,436 |
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4.2 |
% |
Kenneth V. Huseman(5)
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1,022,725 |
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3.0 |
% |
Alan Krenek(6)
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33,535 |
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* |
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James J. Carter(7)
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157,082 |
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* |
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Dub W. Harrison(8)
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146,514 |
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* |
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Charles W. Swift(9)
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158,378 |
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* |
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Steven A. Webster(10)
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62,500 |
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* |
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James S.
DAgostino, Jr.(11)
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35,870 |
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* |
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William E. Chiles(12)
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35,000 |
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* |
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Robert F. Fulton(10)
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62,500 |
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* |
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Sylvester P. Johnson, IV(10)
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62,500 |
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* |
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Thomas P. Moore, Jr.(13)
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10,000 |
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H.H. Wommack, III(3)(4)(14)
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2,164,141 |
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6.4 |
% |
Directors and Executive Officers as
a Group (15 persons)(15)
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3,985,835 |
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11.5 |
% |
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(1) |
Includes 13,709,424 shares of common stock and
4,350,000 shares of common stock issuable upon exercise of
warrants owned by DLJ Merchant Banking Partners III, L.P.
and affiliated funds as follows: DLJ Merchant Banking
Partners III, L.P. (9,556,892 shares and warrants
exercisable for 3,093,225 shares); DLJ ESC II, L.P.
(1,493,185 shares); DLJ Offshore Partners III,
C.V. (416,670 shares and warrants exercisable for
29,195 shares); DLJ Offshore
Partners III-1,
C.V. (24,488 shares and warrants exercisable for
7,530 shares); DLJ Offshore
Partners III-2,
C.V. (17,441 shares and warrants exercisable for
5,365 shares); DLJ Merchant Banking III, Inc., as
Advisory General Partner on behalf of DLJ Offshore
Partners III, C.V. (251,846 shares and warrants
exercisable for |
87
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186,820 shares); DLJ Merchant Banking III, Inc., as
Advisory General Partner on behalf of DLJ Offshore
Partners III-1,
C.V. and as
attorney-in-fact for
DLJ Merchant Banking III, L.P., as Associate General
Partner of DLJ Offshore
Partners III-1,
C.V. (147,981 shares and warrants exercisable for
48,285 shares); DLJ Merchant Banking III, Inc., as
Advisory General Partner on behalf of DLJ Offshore
Partners III-2, C.V. and as
attorney-in-fact for
DLJ Merchant Banking III, L.P., as Associate General
Partner of DLJ Offshore
Partners III-2,
C.V. (105,421 shares and warrants exercisable for
34,395 shares); DLJMB Partners III GmbH & Co.
KG (81,518 shares and warrants exercisable for
26,380 shares); DLJMB Funding III, Inc.
(132,220 shares); Millennium Partners II, L.P.
(16,211 shares and warrants exercisable for
5,305 shares); MBP III Plan Investors, L.P.
(1,465,551 shares and warrants exercisable for
913,500 shares). |
Credit Suisse, a Swiss bank, owns the majority of the voting
stock of Credit Suisse Holdings (USA), Inc., a Delaware
corporation which in turn owns all of the voting stock of Credit
Suisse (USA) Inc., a Delaware corporation
(CS-USA).
The entities discussed in the above paragraph are merchant
banking funds managed by indirect subsidiaries of
CS-USA and form part of
Credit Suisses asset management business. The ultimate
parent company of Credit Suisse is Credit Suisse Group
(CSG). CSG disclaims beneficial ownership of the
reported common stock that is beneficially owned by its direct
and indirect subsidiaries. Steven A. Webster served as the
Chairman of Global Energy Partners, a specialty group within
Credit Suisses asset management business, from 1999 until
June 30, 2005 and remains a consultant to Credit
Suisses asset management business.
All of the DLJ Merchant Banking entities can be contacted at
Eleven Madison Avenue, New York, New York 10010-3629 except for
the three Offshore Partners entities, which can be
contacted at John B. Gosiraweg, 14, Willemstad, Curacao,
Netherlands Antilles.
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(2) |
RS Investment Management Co. LLC is the parent company of
registered investment advisers whose clients have the right to
receive or the power to direct the receipt of dividends from, or
the proceeds from the sale of, the shares. No individual
clients holdings of the shares, except for RS Global
Natural Resources Fund, are more than five percent of our
outstanding common stock. |
RS Investment Management, L.P. is a registered adviser, managing
member of registered investment advisers, and the investment
adviser to RS Global Natural Resources Fund, a registered
investment company. RS Investment Management Co. LLC is the
General Partner of RS Investment Management, L.P. George R.
Hecht is a control person of RS Investment Management Co. LLC
and RS Investment Management, L.P. RS Investment Management Co.
LLC can be contacted at 388 Market Street, Suite 1700,
San Francisco, CA 94111.
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(3) |
Fortress Holdings, LLC, successor in interest to Southwest
Royalties Holdings, Inc., directly owns 667,205 shares, or
2.0% of total shares outstanding. Mr. Wommack, our
director, is also a director and President of Fortress Holdings,
LLC. The members of Fortress Holdings, LLC who beneficially own
5% or more of the outstanding units of Fortress Holdings, LLC
are H. H. Wommack, III, Galloway Bend, Ltd., Sagebrush Oil
Company and H. Allen Corey, who own approximately 33%, 32%, 5%
and 5% of its outstanding units, respectively. Does not include
shares in which Fortress Holdings, LLC has an indirect interest
as a member of Anchor Resources, LLC as described in
footnote 4 below. |
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(4) |
Includes 477,366 shares owned directly by Southwest
Partners II, L.P. and 957,070 shares owned directly by
Southwest Partners III, L.P. Anchor Resources, LLC,
controls the vote of all shares owned by Southwest
Partners II, L.P. and Southwest Partners III, L.P. as
managing general partner of each of the two partnerships. The
number of beneficially owned shares and percentage of class
listed above reflect this control. Anchor Resources, LLC owns a
15% managing general partner interest and a 1.7% limited partner
interest in |
88
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Southwest Partners II. No other person owns 5% or more of
the partnership interests in Southwest Partners II. Anchor
Resources, LLC owns a 15% managing general partner interest and
a 0.2% limited partner interest in Southwest Partners III.
No other person owns 5% or more of the partnership interests in
Southwest Partners III. Mr. Wommack, our director, is
also a director and President of Anchor Resources, LLC. The
members of Anchor Resources, LLC who beneficially own 5% or more
of the units of Anchor Resources, LLC are Bosworth &
Co., Fortress Holdings, LLC, Harvard & Co., Bear
Stearns Securities Corp., and Cudd & Co., who own
approximately 25%, 23%, 13%, 11% and 10% of its units,
respectively. |
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(5) |
Includes 307,025 shares of restricted stock, of which
225,000 remain subject to vesting in one-half increments on
February 24, 2007 and 2008, and 466,405 shares
issuable within 60 days upon the exercise of options
granted under our 2003 Incentive Plan. Does not include
160,000 shares underlying options that are not exercisable
within 60 days granted under our 2003 Incentive Plan. Also
includes an aggregate of 91,060 shares owned directly by
the Kenneth V. Huseman Grantor Retained Annuity Trust and
the Jaye M. Huseman Grantor Retained Annuity Trust. |
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(6) |
Includes 33,335 shares issuable within 60 days upon
the exercise of options granted under our 2003 Incentive Plan.
Does not include 116,665 shares underlying options that are
not exercisable within 60 days granted under our 2003
Incentive Plan. |
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(7) |
Includes 56,770 shares of restricted stock, which are fully
vested. Mr. Carter resigned effective April 30, 2006. |
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(8) |
Includes 34,259 shares of restricted stock, of which 25,000
remain subject to vesting in one-half increments on
February 24, 2007 and 2008, and 91,225 shares issuable
within 60 days upon the exercise of options granted under
our 2003 Incentive Plan. Does not include 40,000 shares
underlying options that are not exercisable within 60 days
granted under our 2003 Incentive Plan. |
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(9) |
Includes 41,282 shares of restricted stock, of which 25,000
remain subject to vesting in one-half increments on
February 24, 2007 and 2008, and 102,225 shares
issuable within 60 days upon the exercise of options
granted under our 2003 Incentive Plan. Does not include
50,000 shares underlying options that are not exercisable
within 60 days granted under our 2003 Incentive Plan. |
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(10) |
Includes 62,500 shares issuable within 60 days upon
the exercise of options granted under our 2003 Incentive Plan.
Does not include 35,000 shares underlying options that are not
exercisable within 60 days granted under our 2003 Incentive
Plan. |
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(11) |
Includes 31,670 shares issuable within 60 days upon
the exercise of options granted under our 2003 Incentive Plan.
Does not include 45,830 shares underlying options that are
not exercisable within 60 days granted under our 2003
Incentive Plan. |
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(12) |
Includes 35,000 shares issuable within 60 days upon
the exercise of options granted under our 2003 Incentive Plan.
Does not include 47,500 shares underlying options that are
not exercisable within 60 days granted under our 2003
Incentive Plan. |
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(13) |
Does not include 42,500 shares underlying options that are
not exercisable within 60 days granted under our 2003
Incentive Plan. |
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(14) |
Includes 62,500 shares issuable within 60 days upon
the exercise of options granted under our 2003 Incentive Plan.
Does not include 35,000 shares underlying options that are not
exercisable within 60 days granted under our 2003 Incentive
Plan. Also reflects the beneficial ownership of an aggregate of
2,101,641 shares beneficially owned by Fortress Holdings,
LLC and Anchor Resources, LLC. H. H. Wommack, III is a
significant unitholder of Fortress Holdings, LLC and a director,
manager and the President of each of Fortress |
89
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Holdings, LLC and Anchor Resources, LLC with the intercompany
relationships discussed in footnotes 3 and 4 above. Mr.
Wommack disclaims beneficial ownership of the shares
beneficially owned directly by Fortress Holdings, LLC and
indirectly by Anchor Resources, LLC other than to the extent of
his pecuniary interest in such shares. |
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(15) |
Includes an aggregate of 454,336 restricted shares, of which
275,000 remain subject to vesting, and an aggregate of
1,062,200 shares issuable within 60 days upon the
exercise of options granted under our 2003 Incentive Plan. Does
not include 754,155 shares underlying options that are not
exercisable within 60 days granted under our 2003 Incentive
Plan. |
90
DISTRIBUTING STOCKHOLDERS
The following table and related footnotes set forth certain
information regarding the stockholders. The number of shares in
the column Number of Shares Offered represents all
of the shares that each distributing stockholder may offer and
distribute under this prospectus. To our knowledge, each of the
distributing stockholders has sole voting and investment power
as to the shares shown, except as disclosed in this prospectus.
Beneficial ownership as shown in the table below has been
determined in accordance with the applicable rules and
regulations promulgated under the Exchange Act. Except as noted
in this prospectus, none of the distributing stockholders is a
director, officer or employee of ours or an affiliate of such
person.
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Beneficial | |
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Beneficial | |
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Ownership Prior to | |
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Ownership After | |
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the Distribution | |
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the Distribution | |
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|
Number | |
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|
Number | |
|
Percent | |
|
of Shares | |
|
Number | |
|
Percent | |
Distributing Stockholders |
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of Shares | |
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of Class | |
|
Distributed | |
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of Shares | |
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of Class | |
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| |
Fortress Holdings, LLC(1)
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667,205 |
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2.0 |
% |
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667,205 |
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0 |
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0 |
% |
Southwest Partners II, L.P.(1)
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477,366 |
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(1) |
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477,366 |
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0 |
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0 |
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Southwest Partners III, L.P.(1)
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957,070 |
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(1) |
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957,070 |
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0 |
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0 |
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(1) |
See footnotes (3) and (4) under the table for
Principal Stockholders and related beneficial
ownership disclosure in table. |
91
DESCRIPTION OF CAPITAL STOCK
Upon the completion of this offering, our authorized capital
stock will consist of:
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80,000,000 shares of common stock, $0.01 par
value; and |
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5,000,000 shares of preferred stock, $0.01 par value,
none of which are currently designated. |
As of August 4, 2006, there were 33,827,015 shares of
common stock and no shares of preferred stock outstanding.
The following summarizes the material provisions of our capital
stock and important provisions of our certificate of
incorporation and bylaws. This summary is qualified by our
certificate of incorporation and bylaws, copies of which have
been filed as exhibits to the registration statement of which
this prospectus is a part and by the provisions of applicable
law.
Common Stock
Holders of common stock are entitled to one vote per share on
all matters to be voted upon by the stockholders. Because
holders of common stock do not have cumulative voting rights,
the holders of a majority of the shares of common stock can
elect all of the members of the board of directors standing for
election. The holders of common stock are entitled to receive
dividends as may be declared by the board of directors. Upon our
liquidation, dissolution or winding up, and subject to any prior
rights of outstanding preferred stock, the holders of our common
stock will be entitled to share pro rata in the distribution of
all of our assets available for distribution to our stockholders
after satisfaction of all of our liabilities and the payment of
the liquidation preference of any preferred stock that may be
outstanding. There are no redemption or sinking fund provisions
applicable to the common stock. All outstanding shares of common
stock are fully paid and non-assessable. The holders of our
common stock will have no preemptive or other subscription
rights to purchase our common stock.
Preferred Stock
Subject to the provisions of the certificate of incorporation
and limitations prescribed by law, the board of directors will
have the authority to issue up to 5,000,000 shares of
preferred stock in one or more series and to fix the rights,
preferences, privileges and restrictions of the preferred stock,
including dividend rights, dividend rates, conversion rates,
voting rights, terms of redemption, redemption prices,
liquidation preferences and the number of shares constituting
any series or the designation of the series, which may be
superior to those of the common stock, without further vote or
action by the stockholders. We have no present plans to issue
any shares of preferred stock.
One of the effects of undesignated preferred stock may be to
enable the board of directors to render more difficult or to
discourage an attempt to obtain control of us by means of a
tender offer, proxy contest, merger or otherwise, and, as a
result, protect the continuity of our management. The issuance
of shares of the preferred stock under the board of
directors authority described above may adversely affect
the rights of the holders of common stock. For example,
preferred stock issued by us may rank prior to the common stock
as to dividend rights, liquidation preference or both, may have
full or limited voting rights and may be convertible into shares
of common stock. Accordingly, the issuance of shares of
preferred stock may discourage bids for the common stock or may
otherwise adversely affect the market price of the common stock.
92
Warrants
There are currently outstanding warrants held by DLJ Merchant
Banking to purchase up to 4,350,000 shares of our common
stock. These warrants are exercisable at a purchase price of
$4.00 per share. Warrants to purchase 600,000 shares
expire on February 13, 2007 and warrants to
purchase 3,750,000 shares expire on June 30,
2007. These warrants were issued by us in 2002 in connection
with the issuance and sale by us of our common stock and
preferred stock.
Provisions of Our Certificate of Incorporation and Bylaws
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Written Consent of Stockholders |
Our certificate of incorporation and bylaws provide that any
action required or permitted to be taken by our stockholders
must be taken at a duly called meeting of stockholders and not
by written consent.
Under Delaware law, the power to adopt, amend or repeal bylaws
is conferred upon the stockholders. A corporation may, however,
in its certificate of incorporation also confer upon the board
of directors the power to adopt, amend or repeal its bylaws. Our
charter and bylaws grant our board the power to adopt, amend and
repeal our bylaws on the affirmative vote of a majority of the
directors then in office. Our stockholders may adopt, amend or
repeal our bylaws but only at any regular or special meeting of
stockholders by the holders of not less than
662/3
% of the voting power of all outstanding voting stock.
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Special Meetings of Stockholders |
Our bylaws preclude the ability of our stockholders to call
special meetings of stockholders.
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Other Limitations on Stockholder Actions |
Advance notice is required for stockholders to nominate
directors or to submit proposals for consideration at meetings
of stockholders. In addition, the ability of our stockholders to
remove directors without cause is precluded.
Only one of three classes of directors is elected each year. See
Management Board of Directors.
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Limitation of Liability of Officers and Directors |
Our certificate of incorporation provides that no director shall
be personally liable to us or our stockholders for monetary
damages for breach of fiduciary duty as a director, except for
liability as follows:
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|
for any breach of the directors duty of loyalty to us or
our stockholders; |
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for acts or omissions not in good faith or which involve
intentional misconduct or a knowing violation of laws; |
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|
for unlawful payment of a dividend or unlawful stock purchase or
stock redemption; and |
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for any transaction from which the director derived an improper
personal benefit. |
The effect of these provisions is to eliminate our rights and
our stockholders rights, through stockholders
derivative suits on our behalf, to recover monetary damages
against a director for
93
a breach of fiduciary duty as a director, including breaches
resulting from grossly negligent behavior, except in the
situations described above.
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Business Combination Under Delaware Law |
We are subject to the provisions of Section 203 of the
Delaware General Corporation Law. In general, Section 203
prohibits a publicly held Delaware corporation from engaging in
a business combination with an interested
stockholder for a period of three years after the date of
the transaction in which the person became an interested
stockholder, unless the business combination is approved in a
prescribed manner.
Section 203 defines a business combination as a
merger, asset sale or other transaction resulting in a financial
benefit to the interested stockholders. Section 203 defines
an interested stockholder as a person who, together
with affiliates and associates, owns, or, in some cases, within
three years prior, did own, 15% or more of the
corporations voting stock. Under Section 203, a
business combination between us and an interested stockholder is
prohibited unless:
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|
|
our board of directors approved either the business combination
or the transaction that resulted in the stockholders becoming an
interested stockholder prior to the date the person attained the
status; |
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|
upon consummation of the transaction that resulted in the
stockholder becoming an interested stockholder, the interested
stockholder owned at least 85% of our voting stock outstanding
at the time the transaction commenced, excluding, for purposes
of determining the number of shares outstanding, shares owned by
persons who are directors and also officers and issued employee
stock plans, under which employee participants do not have the
right to determine confidentially whether shares held under the
plan will be tendered in a tender or exchange offer; or |
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|
the business combination is approved by our board of directors
on or subsequent to the date the person became an interested
stockholder and authorized at an annual or special meeting of
the stockholders by the affirmative vote of the holders of at
least
662/3
% of the outstanding voting stock that is not owned by
the interested stockholder. |
This provision has an anti-takeover effect with respect to
transactions not approved in advance by our board of directors,
including discouraging takeover attempts that might result in a
premium over the market price for the shares of our common
stock. With approval of our stockholders, we could amend our
certificate of incorporation in the future to elect not to be
governed by the anti-takeover law. This election would be
effective 12 months after the adoption of the amendment and
would not apply to any business combination between us and any
person who became an interested stockholder on or before the
adoption of the amendment.
Registration Rights
Under the terms of our Second Amended and Restated
Stockholders Agreement dated as of April 2, 2004, DLJ
Merchant Banking has demand rights to require us to register
shares of our common stock. These stockholders may require us to
register shares of common stock on up to three occasions after
the completion of an initial public offering, provided that the
proposed offering proceeds for the offering equal or exceed
$10 million (or $5 million if we are able to register
on Form S-3).
Under this agreement, Fortress Holdings, LLC, Southwest
Partners II, L.P. and Southwest Partners III, L.P.,
which we call the Southwest Parties, also currently
have demand rights to require us to register shares of our
common stock. The Southwest Parties may make one request to us
to register shares of our common stock, provided that the
proceeds from the sale of such shares pursuant to such
registration are expected to be at least $10 million (or
$5 million if we are able to register such shares on
Form S-3) and, at
the time of such
94
demand, DLJ Merchant Banking beneficially owns less than 25% of
their percentage ownership of our common stock immediately
following the closing of the Securities Purchase Agreement dated
as of December 21, 2000, by and among DLJ Merchant Banking
and us. In addition, all stockholders who continue to own
Registrable Shares under the stockholders
agreement may generally require us to include shares of common
stock in a registration statement filed by us other than on
Forms S-4 or
S-8 or any successor
forms. The rights granted under this agreement terminate
whenever the shares covered by this agreement may be sold under
Rule 144(k) or when these shares have been disposed of in
connection with a registration statement or under Rule 144.
The rights granted under this agreement have terminated with
respect to certain parties thereto who are no longer our
affiliates and have held shares for over two years. Since we are
registering all of the shares of the Southwest Parties under
this prospectus, their demand registration rights under the
agreement shall terminate.
Transfer Agent and Registrar
The transfer agent and registrar for the common stock is
American Stock Transfer & Trust Company.
Listing
Our shares of common stock are listed on the NYSE under the
symbol BAS.
95
SHARES ELIGIBLE FOR FUTURE SALE
As of August 4, 2006, there were 33,827,105 shares of
common stock outstanding. In addition to shares issuable upon
the exercise of options issued under our 2003 Incentive Plan,
there are 4,350,000 shares that may be issued upon the
exercise of warrants held by DLJ Merchant Banking. Of these
outstanding shares, after this distribution,
17,708,335 shares will be freely tradable without
restriction under the Securities Act except for any shares
purchased by one of our affiliates as defined in
Rule 144 under the Securities Act. After this distribution,
a total of 16,118,770 shares will be restricted
securities within the meaning of Rule 144 under the
Securities Act.
The restricted securities generally may not be sold unless they
are registered under the Securities Act or are sold under an
exemption from registration, such as the exemption provided by
Rule 144 under the Securities Act. After this distribution,
the holders of 13,709,424 shares (not including shares
issuable upon the exercise of warrants held by DLJ Merchant
Banking) will have rights, subject to some limited conditions,
to demand that we include their shares in registration
statements that we file on their behalf, on our behalf or on
behalf of other stockholders. By exercising their registration
rights and selling a large number of shares, these holders could
cause the price of our common stock to decline. Furthermore, if
we file a registration statement to offer additional shares of
our common stock and have to include shares held by those
holders, it could impair our ability to raise needed capital by
depressing the price at which we could sell our common stock.
As restrictions on resale end, the market price of our common
stock could drop significantly if the holders of these
restricted shares sell them, or are perceived by the market as
intending to sell them.
We have filed a registration statement with the SEC on
Form S-8 providing
for the registration of 5,000,000 shares of our common
stock issued or reserved for issuance under our stock option
plans. Subject to the exercise of unexercised options or the
expiration or waiver of vesting conditions for restricted stock
and the expiration of lock-ups we and our stockholders have
entered into, shares registered under this registration
statement on
Form S-8 will be
available for resale immediately in the public market without
restriction.
Rule 144
In general, under Rule 144 as currently in effect, any
person (or persons whose shares are aggregated), including an
affiliate, who has beneficially owned shares for a period of at
least one year is entitled to sell, within any three-month
period, a number of shares that does not exceed the greater of:
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1% of the then outstanding shares of common stock; and |
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the average weekly trading volume in the common stock on the
NYSE during the four calendar weeks immediately preceding the
date on which the notice of the sale on Form 144 is filed
with the Securities Exchange Commission. |
Sales under Rule 144 are also subject to other provisions
relating to notice and manner of sale and the availability of
current public information about us.
Rule 144(k)
Under Rule 144(k), a person who is not deemed to have been
one of our affiliates at any time during the 90 days
preceding a sale, and who has beneficially owned the shares
proposed to be sold for at least two years, including the
holding period of any prior owner other than an
affiliate, is entitled to sell the shares without
complying with the manner of sale, public information, volume
limitation or notice provision of Rule 144.
96
LEGAL MATTERS
The validity of the shares of common stock distributed by the
distributing holders under this prospectus will be passed upon
for us by Andrews Kurth LLP, Houston, Texas.
EXPERTS
The consolidated financial statements of Basic Energy Services,
Inc. and subsidiaries as of December 31, 2004 and 2005, and
for each of the years in the three-year period ended
December 31, 2005, have been included in this prospectus
and in the registration statement in reliance upon the report of
KPMG LLP, an independent registered public accounting firm,
appearing elsewhere in this prospectus, and upon the authority
of said firm as experts in accounting and auditing. The audit
report covering the December 31, 2005 consolidated
financial statements refers to a change in the method of
accounting for asset retirement obligations as of
January 1, 2003.
WHERE YOU CAN FIND MORE INFORMATION
We have filed with the SEC a registration statement on
Form S-1 regarding
the common stock offered by this prospectus. This prospectus
does not contain all of the information found in the
registration statement. For further information regarding us and
the common stock offered in this prospectus, you may desire to
review the full registration statement, including its exhibits.
The registration statement, including the exhibits, may be
inspected and copied at the public reference facilities
maintained by the SEC at 100 F Street, N.E., Washington
D.C. 20549. Copies of this material can also be obtained upon
written request from the Public Reference Section of the SEC at
prescribed rates, or accessed at the SECs website on the
Internet at http://www.sec.gov. Please call the SEC at
1-800-SEC-0330 for
further information on its public reference room. In addition,
our future public filings can also be inspected and copied at
the offices of the New York Stock Exchange, Inc., 20 Broad
Street, New York, New York 10005.
You should rely only on the information contained in this
prospectus. We have not, and the underwriters have not,
authorized any other person to provide you with different
information. If anyone provides you with different or
inconsistent information, you should not rely on it. We are not,
and the underwriters are not, making an offer to sell these
securities in any jurisdiction where an offer or sale is not
permitted. You should assume that the information appearing in
this prospectus is accurate as of the date on the front cover of
this prospectus only. Our business, financial condition, results
of operations and prospects may have changed since that date.
We file with or furnish to the SEC periodic reports and other
information. These reports and other information may be
inspected and copied at the public reference facilities
maintained by the SEC or obtained from the SECs website as
provided above. Our website on the Internet is located at
http://www.basicenergyservices.com, and we make our
periodic reports and other information filed with or furnished
to the SEC available, free of charge, through our website, as
soon as reasonably practicable after those reports and other
information are electronically filed with or furnished to the
SEC. Information on our website or any other website is not
incorporated by reference into this prospectus and does not
constitute a part of this prospectus. You may also request a
copy of these filings at no cost, by writing or telephoning us
at the following address: Basic Energy Services, Inc.,
Attention: Chief Financial Officer, 400 W. Illinois,
Suite 800, Midland, Texas 79701, (432) 620-5500.
97
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
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Page |
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Audited Consolidated Financial
Statements
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F1-1 |
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F1-2 |
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F1-3 |
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F1-4 |
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F1-5 |
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F1-6 |
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Financial Statement
Schedule II Valuation and Qualifying Accounts
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F1-37 |
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Unaudited Consolidated Financial
Statements
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F2-1 |
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F2-2 |
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F2-3 |
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F2-4 |
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F2-5 |
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F-1
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Basic Energy Services, Inc.:
We have audited the accompanying consolidated balance sheets of
Basic Energy Services, Inc. and subsidiaries as of
December 31, 2005 and 2004, and the related consolidated
statements of operations and comprehensive income (loss),
stockholders equity, and cash flows for each of the years
in the three-year period ended December 31, 2005. In
connection with our audits of the consolidated financial
statements, we also have audited the accompanying financial
statement schedule. These consolidated financial statements and
financial statement schedule are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these consolidated financial statements and financial
statement schedules based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of Basic Energy Services, Inc. and subsidiaries as of
December 31, 2005 and 2004, and the results of their
operations and their cash flows for each of the years in the
three-year period ended December 31, 2005, in conformity
with U.S. generally accepted accounting principles. Also in
our opinion, the related financial statement schedule, when
considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly, in all material
respects, the information set forth therein.
As discussed in Note 2 of the consolidated financial
statements, effective January 1, 2003, the Company changed
its method of accounting for asset retirement obligations in
accordance with Statement of Financial Accounting Standards
No. 143 Accounting for Asset Retirement
Obligations.
Dallas, Texas
March 20, 2006
F1-1
Basic Energy Services, Inc.
Consolidated Balance Sheets
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December 31, | |
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|
| |
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2005 | |
|
2004 | |
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| |
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| |
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|
(In thousands, | |
|
|
except share data) | |
ASSETS |
Current assets:
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
32,845 |
|
|
$ |
20,147 |
|
|
Trade accounts receivable, net of
allowance of $2,775 and $3,108, respectively
|
|
|
86,932 |
|
|
|
56,651 |
|
|
Accounts receivable
related parties
|
|
|
65 |
|
|
|
103 |
|
|
Inventories
|
|
|
1,648 |
|
|
|
1,176 |
|
|
Prepaid expenses
|
|
|
3,112 |
|
|
|
1,798 |
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|
Other current assets
|
|
|
2,060 |
|
|
|
2,454 |
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|
Deferred tax assets
|
|
|
6,020 |
|
|
|
4,899 |
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
132,682 |
|
|
|
87,228 |
|
|
|
|
|
|
|
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Property and equipment, net
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|
309,075 |
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|
|
233,451 |
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|
Deferred debt costs, net of
amortization
|
|
|
4,833 |
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|
|
4,709 |
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Goodwill
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|
|
48,227 |
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|
|
39,853 |
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|
Other assets
|
|
|
2,140 |
|
|
|
2,360 |
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|
|
|
|
|
|
|
|
|
$ |
496,957 |
|
|
$ |
367,601 |
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|
LIABILITIES AND
STOCKHOLDERS EQUITY |
Current liabilities:
|
|
|
|
|
|
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|
Accounts payable
|
|
$ |
13,759 |
|
|
$ |
11,388 |
|
|
Accrued expenses
|
|
|
33,548 |
|
|
|
20,486 |
|
|
Income taxes payable
|
|
|
7,210 |
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|
|
|
|
|
Current portion of long-term debt
|
|
|
7,646 |
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|
|
11,561 |
|
|
Other current liabilities
|
|
|
1,124 |
|
|
|
545 |
|
|
|
|
|
|
|
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|
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Total current liabilities
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|
63,287 |
|
|
|
43,980 |
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|
|
|
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|
|
Long-term debt
|
|
|
119,241 |
|
|
|
170,915 |
|
Deferred income
|
|
|
17 |
|
|
|
44 |
|
Deferred tax liabilities
|
|
|
53,770 |
|
|
|
30,247 |
|
Other long-term liabilities
|
|
|
2,067 |
|
|
|
629 |
|
Commitments and contingencies
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|
|
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Stockholders equity:
|
|
|
|
|
|
|
|
|
|
Common stock; $.01 par value;
80,000,000 shares authorized; 33,931,935 shares
issued, 33,785,359 shares outstanding at December 31,
2005 and 28,931,935 shares issued and outstanding at
December 31, 2004, respectively
|
|
|
339 |
|
|
|
58 |
|
Additional paid-in capital
|
|
|
239,218 |
|
|
|
142,802 |
|
Deferred compensation
|
|
|
(7,341 |
) |
|
|
(4,990 |
) |
Retained earnings (deficit)
|
|
|
28,654 |
|
|
|
(16,127 |
) |
Treasury stock, 146,576 shares
at December 31, 2005, at cost
|
|
|
(2,531 |
) |
|
|
|
|
Accumulated other comprehensive
income
|
|
|
236 |
|
|
|
43 |
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
258,575 |
|
|
|
121,786 |
|
|
|
|
|
|
|
|
|
|
$ |
496,957 |
|
|
$ |
367,601 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F1-2
Basic Energy Services, Inc.
Consolidated Statements of Operations and Comprehensive
Income
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Years Ended December 31 | |
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| |
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2005 | |
|
2004 | |
|
2003 | |
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| |
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| |
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| |
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|
(Dollars in thousands, except | |
|
|
per share amounts) | |
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
$ |
221,993 |
|
|
$ |
142,551 |
|
|
$ |
104,097 |
|
|
Fluid services
|
|
|
132,280 |
|
|
|
98,683 |
|
|
|
52,810 |
|
|
Drilling and completion services
|
|
|
59,832 |
|
|
|
29,341 |
|
|
|
14,808 |
|
|
Well site construction services
|
|
|
45,647 |
|
|
|
40,927 |
|
|
|
9,184 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
459,752 |
|
|
|
311,502 |
|
|
|
180,899 |
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
|
137,392 |
|
|
|
98,058 |
|
|
|
73,244 |
|
|
Fluid services
|
|
|
82,551 |
|
|
|
65,167 |
|
|
|
34,420 |
|
|
Drilling and completion services
|
|
|
30,900 |
|
|
|
17,481 |
|
|
|
9,363 |
|
|
Well site construction services
|
|
|
32,000 |
|
|
|
31,454 |
|
|
|
6,586 |
|
|
General and administrative,
including stock-based compensation of $2,890, $1,587, and $994
in 2005, 2004 and 2003, respectively
|
|
|
55,411 |
|
|
|
37,186 |
|
|
|
22,722 |
|
|
Depreciation and amortization
|
|
|
37,072 |
|
|
|
28,676 |
|
|
|
18,213 |
|
|
(Gain) loss on disposal of assets
|
|
|
(222 |
) |
|
|
2,616 |
|
|
|
391 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
375,104 |
|
|
|
280,638 |
|
|
|
164,939 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
84,648 |
|
|
|
30,864 |
|
|
|
15,960 |
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(13,065 |
) |
|
|
(9,714 |
) |
|
|
(5,234 |
) |
|
Interest income
|
|
|
405 |
|
|
|
164 |
|
|
|
60 |
|
|
Loss on early extinguishment of debt
|
|
|
(627 |
) |
|
|
|
|
|
|
(5,197 |
) |
|
Other income (expense)
|
|
|
220 |
|
|
|
(398 |
) |
|
|
146 |
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
before income taxes
|
|
|
71,581 |
|
|
|
20,916 |
|
|
|
5,735 |
|
Income tax expense
|
|
|
(26,800 |
) |
|
|
(7,984 |
) |
|
|
(2,772 |
) |
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
|
44,781 |
|
|
|
12,932 |
|
|
|
2,963 |
|
Discontinued operations, net of tax
|
|
|
|
|
|
|
(71 |
) |
|
|
22 |
|
Cumulative effect of accounting
change, net of tax
|
|
|
|
|
|
|
|
|
|
|
(151 |
) |
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
44,781 |
|
|
|
12,861 |
|
|
|
2,834 |
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividend
|
|
|
|
|
|
|
|
|
|
|
(1,525 |
) |
Accretion of preferred stock
discount
|
|
|
|
|
|
|
|
|
|
|
(3,424 |
) |
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to
common stockholders
|
|
$ |
44,781 |
|
|
$ |
12,861 |
|
|
$ |
(2,115 |
) |
|
|
|
|
|
|
|
|
|
|
Basic earnings per share of common
stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$ |
1.57 |
|
|
$ |
0.46 |
|
|
$ |
(0.09 |
) |
|
Discontinued operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to
common stockholders
|
|
$ |
1.57 |
|
|
$ |
0.46 |
|
|
$ |
(0.09 |
) |
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share of
common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$ |
1.35 |
|
|
$ |
0.42 |
|
|
$ |
(0.09 |
) |
|
Discontinued operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to
common stockholders
|
|
$ |
1.35 |
|
|
$ |
0.42 |
|
|
$ |
(0.09 |
) |
|
|
|
|
|
|
|
|
|
|
Comprehensive Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
44,781 |
|
|
$ |
12,861 |
|
|
$ |
2,834 |
|
Unrealized gains on hedging
activities
|
|
|
193 |
|
|
|
43 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income:
|
|
$ |
44,974 |
|
|
$ |
12,904 |
|
|
$ |
2,834 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F1-3
Basic Energy Services, Inc.
Consolidated Statements of Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated | |
|
|
|
|
Common Stock | |
|
Additional | |
|
|
|
|
|
Retained | |
|
Other | |
|
Total | |
|
|
| |
|
Paid-in | |
|
Deferred | |
|
Treasury | |
|
Earnings | |
|
Comprehensive | |
|
Stockholders | |
|
|
Shares | |
|
Amount | |
|
Capital | |
|
Compensation | |
|
Stock | |
|
(Deficit) | |
|
Income | |
|
Equity | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(In thousands, except share data) | |
Balance
December 31, 2002
|
|
|
20,368,610 |
|
|
$ |
41 |
|
|
$ |
97,294 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(24,777 |
) |
|
$ |
|
|
|
$ |
72,558 |
|
Exercise of EBITDA contingent
warrants
|
|
|
771,740 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
EBITDA contingent warrants
|
|
|
|
|
|
|
|
|
|
|
3,571 |
|
|
|
|
|
|
|
|
|
|
|
(2,660 |
) |
|
|
|
|
|
|
911 |
|
FESCO Holdings, Inc. acquisition
|
|
|
3,650,000 |
|
|
|
7 |
|
|
|
18,820 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18,827 |
|
Stock-based compensation awards
|
|
|
|
|
|
|
|
|
|
|
380 |
|
|
|
(380 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of deferred
compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
83 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
83 |
|
Preferred stock conversion to
common stock
|
|
|
3,304,085 |
|
|
|
6 |
|
|
|
16,459 |
|
|
|
|
|
|
|
|
|
|
|
564 |
|
|
|
|
|
|
|
17,029 |
|
Accretion of preferred stock
discount
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,424 |
) |
|
|
|
|
|
|
(3,424 |
) |
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,525 |
) |
|
|
|
|
|
|
(1,525 |
) |
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,834 |
|
|
|
|
|
|
|
2,834 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
December 31, 2003
|
|
|
28,094,435 |
|
|
|
56 |
|
|
|
136,524 |
|
|
|
(297 |
) |
|
|
|
|
|
|
(28,988 |
) |
|
|
|
|
|
|
107,295 |
|
Issuance of restricted stock and
stock options
|
|
|
837,500 |
|
|
|
2 |
|
|
|
6,278 |
|
|
|
(6,280 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of deferred
compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,587 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,587 |
|
Unrealized gain on interest rate
swap agreement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
43 |
|
|
|
43 |
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,861 |
|
|
|
|
|
|
|
12,861 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
December 31, 2004
|
|
|
28,931,935 |
|
|
|
58 |
|
|
|
142,802 |
|
|
|
(4,990 |
) |
|
|
|
|
|
|
(16,127 |
) |
|
|
43 |
|
|
|
121,786 |
|
Stock-based compensation awards
|
|
|
|
|
|
|
|
|
|
|
5,241 |
|
|
|
(5,241 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of deferred
compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,890 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,890 |
|
Unrealized gain on interest rate
swap agreement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
193 |
|
|
|
193 |
|
Forfeited 11,250 shares at
cost of $0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of stock split
|
|
|
|
|
|
|
231 |
|
|
|
(231 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from common stock
issuance, net of $2,044 of offering costs
|
|
|
5,000,000 |
|
|
|
50 |
|
|
|
91,406 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91,456 |
|
Purchase of 135,326 of treasury
stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,531 |
) |
|
|
|
|
|
|
|
|
|
|
(2,531 |
) |
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44,781 |
|
|
|
|
|
|
|
44,781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
December 31, 2005
|
|
|
33,931,935 |
|
|
$ |
339 |
|
|
$ |
239,218 |
|
|
$ |
(7,341 |
) |
|
$ |
(2,531 |
) |
|
$ |
28,654 |
|
|
$ |
236 |
|
|
$ |
258,575 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F1-4
Basic Energy Services, Inc.
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Cash flows from operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
44,781 |
|
|
$ |
12,861 |
|
|
$ |
2,834 |
|
|
|
Adjustments to reconcile net income
to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
37,072 |
|
|
|
28,676 |
|
|
|
18,213 |
|
|
|
|
Accretion on asset retirement
obligation
|
|
|
42 |
|
|
|
33 |
|
|
|
28 |
|
|
|
|
Change in allowance for doubtful
accounts
|
|
|
(333 |
) |
|
|
1,150 |
|
|
|
1,279 |
|
|
|
|
Non-cash interest expense
|
|
|
1,062 |
|
|
|
970 |
|
|
|
694 |
|
|
|
|
Non-cash compensation
|
|
|
2,890 |
|
|
|
1,587 |
|
|
|
994 |
|
|
|
|
Loss on early extinguishment of debt
|
|
|
627 |
|
|
|
|
|
|
|
3,588 |
|
|
|
|
(Gain) loss on disposal of assets
|
|
|
(222 |
) |
|
|
2,616 |
|
|
|
391 |
|
|
|
|
Deferred income taxes
|
|
|
18,301 |
|
|
|
7,984 |
|
|
|
2,840 |
|
|
|
|
Other non-cash items
|
|
|
|
|
|
|
|
|
|
|
(11 |
) |
|
|
|
Non-cash effect of discontinued
operations
|
|
|
|
|
|
|
|
|
|
|
13 |
|
|
|
|
Cumulative effect of accounting
change
|
|
|
|
|
|
|
|
|
|
|
151 |
|
|
Changes in operating assets and
liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(27,577 |
) |
|
|
(13,841 |
) |
|
|
(12,120 |
) |
|
|
|
Inventories
|
|
|
(262 |
) |
|
|
394 |
|
|
|
125 |
|
|
|
|
Prepaid expenses and other current
assets
|
|
|
304 |
|
|
|
446 |
|
|
|
(1,243 |
) |
|
|
|
Other assets
|
|
|
(49 |
) |
|
|
(569 |
) |
|
|
1,261 |
|
|
|
|
Accounts payable
|
|
|
2,174 |
|
|
|
3,416 |
|
|
|
2,863 |
|
|
|
|
Income tax payable
|
|
|
7,013 |
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income and other
liabilities
|
|
|
374 |
|
|
|
127 |
|
|
|
(11 |
) |
|
|
|
Accrued expenses
|
|
|
12,992 |
|
|
|
689 |
|
|
|
7,926 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
|
99,189 |
|
|
|
46,539 |
|
|
|
29,815 |
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of property and equipment
|
|
|
(83,095 |
) |
|
|
(55,674 |
) |
|
|
(23,501 |
) |
|
|
|
Proceeds from sale of assets
|
|
|
2,436 |
|
|
|
2,484 |
|
|
|
660 |
|
|
|
|
Payments for other long-term assets
|
|
|
(1,642 |
) |
|
|
(1,113 |
) |
|
|
(177 |
) |
|
|
|
Payments for businesses, net of
cash acquired
|
|
|
(25,378 |
) |
|
|
(19,284 |
) |
|
|
(61,885 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing
activities
|
|
|
(107,679 |
) |
|
|
(73,587 |
) |
|
|
(84,903 |
) |
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from debt
|
|
|
16,000 |
|
|
|
43,500 |
|
|
|
203,012 |
|
|
|
|
Payments of debt
|
|
|
(81,924 |
) |
|
|
(21,236 |
) |
|
|
(115,603 |
) |
|
|
|
Proceeds from common stock, net of
$2,044 of offering costs
|
|
|
91,456 |
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of treasury stock
|
|
|
(2,531 |
) |
|
|
|
|
|
|
|
|
|
|
|
Collections of notes receivable
|
|
|
|
|
|
|
|
|
|
|
9 |
|
|
|
|
Proceeds from exercise of EBITDA
contingent warrants
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
|
Deferred loan costs and other
financing activities
|
|
|
(1,813 |
) |
|
|
(766 |
) |
|
|
(7,561 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing
activities
|
|
|
21,188 |
|
|
|
21,498 |
|
|
|
79,859 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and
equivalents
|
|
|
12,698 |
|
|
|
(5,550 |
) |
|
|
24,771 |
|
|
Cash and cash
equivalents beginning of year
|
|
|
20,147 |
|
|
|
25,697 |
|
|
|
926 |
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash
equivalents end of year
|
|
$ |
32,845 |
|
|
$ |
20,147 |
|
|
$ |
25,697 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F1-5
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
December 31, 2005, 2004, and 2003
|
|
1. |
Nature of Operations and Basis of Presentation |
Organization and Restructuring
|
|
|
Basic Energy Services, Inc. (predecessor entity), a Delaware
corporation (Historical Basic) commenced operations
in 1992. Effective January 24, 2003, Historical Basic
changed its corporate structure to a holding company format. The
purpose of this corporate restructuring was to provide greater
operational, administrative and financial flexibility to
Historical Basic, as well as improved economics. In connection
with this restructuring, Historical Basic merged with a newly
formed subsidiary of BES Holding Co. (New Basic), a
Delaware corporation incorporated on January 7, 2003 as a
wholly-owned subsidiary of New Basic. The merger was structured
as a tax-free reorganization to Historical Basic stockholders.
As a result of the merger, each share of outstanding common
stock of Historical Basic was exchanged for one share of common
stock of New Basic, and each share of outstanding Series A
10% Cumulative Preferred Stock of Historical Basic was exchanged
for one share of Series A 10% Cumulative Preferred Stock of
New Basic, and with respect to any accrued and unpaid dividends,
shares of additional preferred stock with a liquidation
preference equal to such accrued and unpaid dividends.
Historical Basic survived the merger and was subsequently
converted to a Delaware limited partnership now known as Basic
Energy Services, L.P., which is currently an indirect
wholly-owned subsidiary of New Basic. On April 2, 2004, BES
Holding Co. changed its name to Basic Energy Services, Inc.
Historical Basic prior to January 24, 2003 and New Basic
thereafter are referred to in these Notes to Consolidated
Financial Statements as Basic. |
Basis of Presentation
|
|
|
The historical consolidated financial statements presented
herein of Basic prior to its formation are the historical
results of Historical Basic since the ownership of Basic and
Historical Basic at the merger date were identical. The
financial results of New Basic and Historical Basic are combined
to present the consolidated financial statements of Basic. |
Nature of Operations
|
|
|
Basic provides a range of well site services to oil and gas
drilling and producing companies, including well servicing,
fluid services, drilling and completion services and well site
construction services. These services are primarily provided by
Basics fleet of equipment. Basics operations are
concentrated in the major United States onshore oil and gas
producing regions in Texas, New Mexico, Oklahoma and Louisiana,
and the Rocky Mountain states. |
|
|
2. |
Summary of Significant Accounting Policies |
Principles of Consolidation
|
|
|
The accompanying consolidated financial statements include the
accounts of Basic and its wholly-owned subsidiaries. Basic has
no interest in any other organization, entity, partnership, or
contract that could require any evaluation under FASB
Interpretation No. 46R or Accounting Research
Bulletin No. 51. All inter-company transactions and
balances have been eliminated. |
Estimates and Uncertainties
|
|
|
Preparation of the accompanying consolidated financial
statements in conformity with accounting principles generally
accepted in the United States of America requires management to
make estimates and assumptions that affect the reported amount
of assets and liabilities and |
F1-6
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
|
disclosures of contingent assets and liabilities at the date of
the consolidated financial statements and the reported amounts
of revenues and expenses during the reporting period. Actual
results could differ from those estimates. Areas where critical
accounting estimates are made by management include: |
|
|
|
|
|
Depreciation and amortization of property and equipment and
intangible assets |
|
|
|
Impairment of property and equipment and goodwill |
|
|
|
Allowance for doubtful accounts |
|
|
|
Litigation and self-insured risk reserves |
|
|
|
Fair value of assets acquired and liabilities assumed |
|
|
|
Stock-based compensation |
|
|
|
Income taxes |
|
|
|
Asset retirement obligation |
Revenue Recognition
|
|
|
Well Servicing Well servicing consists
primarily of maintenance services, workover services, completion
services and plugging and abandonment services. Basic recognizes
revenue when services are performed, collection of the relevant
receivables is probable, persuasive evidence of an arrangement
exists and the price is fixed or determinable. Basic prices well
servicing by the hour of service performed. |
Fluid Services Fluid services consists
primarily of the sale, transportation, storage and disposal of
fluids used in drilling, production and maintenance of oil and
natural gas wells. Basic recognizes revenue when services are
performed, collection of the relevant receivables is probable,
persuasive evidence of an arrangement exists and the price is
fixed or determinable. Basic prices fluid services by the job,
by the hour or by the quantities sold, disposed of or hauled.
Drilling and Completion Services Basic
recognizes revenue when services are performed, collection of
the relevant receivables is probable, persuasive evidence of an
arrangement exists and the price is fixed or determinable. Basic
prices drilling and completion services by the hour, day, or
project depending on the type of service performed. When Basic
provides multiple services to a customer, revenue is allocated
to the services performed based on the fair values of the
services.
Well Site Construction Services Basic
recognizes revenue when services are performed, collection of
the relevant receivables is probable, persuasive evidence of an
arrangement exists and the price is fixed or determinable. Basic
prices well site construction services by the hour, day, or
project depending on the type of service performed.
Cash and Cash Equivalents
|
|
|
Basic considers all highly liquid instruments purchased with a
maturity of three months or less to be cash equivalents. Basic
maintains its excess cash in various financial institutions,
where deposits may exceed federally insured amounts at times. |
F1-7
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
Fair Value of Financial Instruments
|
|
|
The carrying value amount of cash, accounts receivable, accounts
payable and accrued liabilities approximate fair value due to
the short maturity of these instruments. The carrying amount of
long-term debt approximates fair value because Basics
current borrowing rate is based on a variable market rate of
interest. |
Inventories
|
|
|
Inventories, consisting mainly of rig components, repair parts,
drilling and completion materials and gravel, are held for use
in the operations of Basic and are stated at the lower of cost
or market, with cost being determined on the
first-in, first-out
(FIFO) method. |
Property and Equipment
|
|
|
Property and equipment are stated at cost, or at estimated fair
value at acquisition date if acquired in a business combination.
Expenditures for repairs and maintenance are charged to expense
as incurred and additions and improvements that significantly
extend the lives of the assets are capitalized. Upon sale or
other retirement of depreciable property, the cost and
accumulated depreciation and amortization are removed from the
related accounts and any gain or loss is reflected in
operations. All property and equipment are depreciated or
amortized (to the extent of estimated salvage values) on the
straight-line method and the estimated useful lives of the
assets are as follows: |
|
|
|
|
|
Building and improvements
|
|
|
20-30 years |
|
Well servicing rigs and equipment
|
|
|
3-15 years |
|
Fluid service equipment
|
|
|
5-10 years |
|
Brine/fresh water stations
|
|
|
15 years |
|
Frac/test tanks
|
|
|
10 years |
|
Pressure pumping equipment
|
|
|
5-10 years |
|
Construction equipment
|
|
|
3-10 years |
|
Disposal facilities
|
|
|
10-15 years |
|
Vehicles
|
|
|
3-7 years |
|
Rental equipment
|
|
|
3-15 years |
|
Software and computers
|
|
|
3 years |
|
Aircraft
|
|
|
20 years |
|
The components of a well servicing rig generally require
replacement or refurbishment during the well servicing
rigs life and are depreciated over their estimated useful
lives, which ranges from 3 to 15 years. The costs of the
original components of a purchased or acquired well servicing
rig are not maintained separately from the base rig.
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 |
F1-8
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
|
lowest identifiable level. If the carrying amount of such assets
exceeds its estimated future cash flows, an impairment charge is
recognized by the amount by which the carrying amount of such
assets exceeds the fair value of the assets. Assets to be
disposed of would be separately presented in the consolidated
balance sheet and reported at the lower of the carrying amount
or fair value less costs to sell, and are no longer depreciated.
The assets and liabilities, if material, of a disposed group
classified as held for sale would be presented separately in the
appropriate asset and liability sections of the consolidated
balance sheet. |
Goodwill and intangible assets not subject to amortization are
tested annually for impairment, and are tested for impairment
more frequently if events and circumstances indicate that the
asset might be impaired. An impairment loss is recognized to the
extent that the carrying amount exceeds the assets fair
value.
Basic had no impairment expense in 2005, 2004 or 2003.
Deferred Debt Costs
|
|
|
Basic capitalizes certain costs in connection with obtaining its
borrowings, such as lenders fees and related
attorneys fees. These costs are being amortized to
interest expense using the straight line method which
approximates the effective interest method over the terms of the
related debt. |
Deferred debt costs of approximately $7.0 million at
December 31, 2005 and $5.8 million at
December 31, 2004, respectively, represent debt issuance
costs and are recorded net of accumulated amortization of
$2.2 million, and $1.1 million at December 31,
2005 and December 31, 2004, respectively. Amortization of
deferred debt costs totaled approximately $1,062,000, $907,000
and $694,000 for the years ended December 31, 2005, 2004
and 2003, respectively.
In 2005, Basic recognized a loss on early extinguishment of debt
related to deferred debt costs. (See note 5)
Goodwill
|
|
|
Statement of Financial Accounting Standards No. 142,
Goodwill and Other Intangible Assets
(SFAS No. 142) eliminates the
amortization of goodwill and other intangible assets with
indefinite lives. Intangible assets with lives restricted by
contractual, legal, or other means will continue to be amortized
over their useful lives. Goodwill and other intangible assets
not subject to amortization are tested for impairment annually
or more frequently if events or changes in circumstances
indicate that the asset might be impaired.
SFAS No. 142 requires a two-step process for testing
impairment. First, the fair value of each reporting unit is
compared to its carrying value to determine whether an
indication of impairment exists. If impairment is indicated,
then the fair value of the reporting units goodwill is
determined by allocating the units fair value to its
assets and liabilities (including any unrecognized intangible
assets) as if the reporting unit had been acquired in a business
combination. The amount of impairment for goodwill is measured
as the excess of its carrying value over its fair value. Basic
completed its assessment of goodwill impairment as of the date
of adoption and completed a subsequent annual impairment
assessment as of December 31 each year thereafter. The
assessments did not result in any indications of goodwill
impairment. |
Intangible assets subject to amortization under
SFAS No. 142 consist of non-compete agreements.
Amortization expense for the non-compete agreements is
calculated using the straight-line method over the period of the
agreement, ranging from three to five years. The
F1-9
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
weighted average amortization period for non-compete agreements
acquired during 2005 and 2004 is 60 months.
The gross carrying amount of non-compete agreements subject to
amortization totaled approximately $2.7 million and
$3.7 million at December 31, 2005 and 2004,
respectively. Accumulated amortization related to these
intangible assets totaled approximately $1.6 and
$2.4 million at December 31, 2005 and 2004,
respectively. Amortization expense for the years ended
December 31, 2005, 2004 and 2003 was approximately
$519,000, $457,000, and $364,000, respectively. Amortization
expense for the next five succeeding years is estimated to be
approximately $461,000, $325,000, $223,000, $122,000, and
$22,000 in 2006, 2007, 2008, 2009, and 2010 respectively.
Basic has identified its reporting units to be well servicing,
fluid services, drilling and completion services and well site
construction services. The goodwill allocated to such reporting
units as of December 31, 2005 is $9.9 million,
$20.6 million, $14.0 million and $3.7 million,
respectively. The change in the carrying amount of goodwill for
the year ended December 31, 2005 of $8.4 million
relates to goodwill from acquisitions and payments pursuant to
contingent earn-out agreements, with approximately
$1.1 million, $2.2 million and $5.1 million of
goodwill additions relating to the well servicing, fluid
services and drilling and completion units, respectively.
Stock-Based Compensation
|
|
|
Basic accounts for stock-based compensation using the intrinsic
value method prescribed by Accounting Principles Board Opinion
No. 25, Accounting for Stock Issued to
Employees (APB No. 25). Accordingly,
Basic has adopted the disclosure provisions of Statement of
Financial Accounting Standards No. 123, Accounting
for Stock-Based Compensation
(SFAS No. 123). |
F1-10
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
Statement of Financial Accounting Standards No. 123,
Accounting for Stock-Based Compensation
(SFAS No. 123) sets forth alternative
accounting and disclosure requirements for stock-based
compensation arrangements. Companies may continue to follow the
provisions of APB No. 25 to measure and recognize employee
stock-based compensation; however, SFAS No. 123
requires disclosure of pro forma net income and earnings per
share that would have been reported under the fair value based
recognition provisions of SFAS No. 123. The following
table illustrates the effect on net income if Basic had applied
the fair value recognition provisions of SFAS No. 123
to stock-based employee compensation.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Net income (loss) available to
common stockholders as reported
|
|
$ |
44,781 |
|
|
$ |
12,861 |
|
|
$ |
(2,115 |
) |
Add: Stock-based employee
compensation expense included in statement of operations, net of
tax
|
|
|
1,806 |
|
|
|
986 |
|
|
|
523 |
|
Deduct: Stock-based employee
compensation expense determined under fair-value based method
for all awards, net of tax
|
|
|
(2,231 |
) |
|
|
(1,283 |
) |
|
|
(779 |
) |
|
|
|
|
|
|
|
|
|
|
Net income available to common
stockholders pro forma basis
|
|
$ |
44,356 |
|
|
$ |
12,564 |
|
|
$ |
(2,371 |
) |
|
|
|
|
|
|
|
|
|
|
Basic earnings per share of common
stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As reported
|
|
$ |
1.57 |
|
|
$ |
0.46 |
|
|
$ |
(0.09 |
) |
|
Pro forma
|
|
$ |
1.55 |
|
|
$ |
0.45 |
|
|
$ |
(0.11 |
) |
Diluted earnings per share of
common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As reported
|
|
$ |
1.35 |
|
|
$ |
0.42 |
|
|
$ |
(0.09 |
) |
|
Pro forma
|
|
$ |
1.34 |
|
|
$ |
0.41 |
|
|
$ |
(0.11 |
) |
Under SFAS No. 123, the fair value of each stock
option grant is estimated on the date of grant using the
Black-Scholes-Merton option pricing model with the following
weighted average assumptions used for grants during the years
ended December 31, 2005, 2004, and 2003:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Risk-free interest rate
|
|
|
4.5 |
% |
|
|
4.4 |
% |
|
|
2.9 |
% |
Expected life
|
|
|
9.9 |
|
|
|
10.0 |
|
|
|
10.0 |
|
Expected volatility
|
|
|
0.5 |
% |
|
|
0.0 |
% |
|
|
0.0 |
% |
Expected dividend yield
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Taxes
|
|
|
Basic accounts for income taxes based upon Statement of
Financial Accounting Standards No. 109, Accounting
for Income Taxes (SFAS 109). Under
SFAS No. 109, deferred tax assets and liabilities are
recognized for the future tax consequences attributable to
differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases.
Deferred tax assets and liabilities are measured using statutory
tax rates expected to apply to taxable income in the years in
which those temporary differences are expected to be recovered
or settled. The effect on deferred tax assets and liabilities of
a change in tax rate is recognized in the period that includes
the statutory enactment date. A valuation allowance for deferred
tax assets is recognized when it is more likely than not that
the benefit of deferred tax assets will not be realized. |
F1-11
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
Concentrations of Credit Risk
|
|
|
Financial instruments, which potentially subject Basic to
concentration of credit risk, consist primarily of temporary
cash investments and trade receivables. Basic restricts
investment of temporary cash investments to financial
institutions with high credit standing. Basics customer
base consists primarily of multi-national and independent oil
and natural gas producers. It performs ongoing credit
evaluations of its customers but generally does not require
collateral on its trade receivables. Credit risk is considered
by management to be limited due to the large number of customers
comprising its customer base. Basic maintains an allowance for
potential credit losses on its trade receivables, and such
losses have been within managements expectations. |
Basic did not have any one customer which represented 10% or
more of consolidated revenue for 2005, 2004, or 2003.
|
|
|
Derivative Instruments and Hedging Activities |
|
|
|
In June 1998, the Financial Accounting Standards Board
(FASB) issued Statement of Financial Accounting
Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities
(SFAS No. 133), which establishes
standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for
hedging activities. It requires that an entity recognize all
derivative as either assets or liabilities on the balance sheet
and measure those instruments at fair value. It establishes
conditions under which a derivative may be designated as a
hedge, and establishes standards for reporting changes in the
fair value of a derivative. Basic adopted
SFAS No. 133, as amended by SFAS No. 138, on
January 1, 2001. Basic adopted the additional amendments
pursuant to SFAS No. 149 for contracts entered or
modified after June 30, 2003, if any. At inception, Basic
formally documents the relationship between the hedging
instrument and the underlying hedged item as well as risk
management objective and strategy. Basic assesses, both at
inception and on an ongoing basis, whether the derivative used
in hedging transition is highly effective in offsetting changes
in the fair value of cash flows of the respective hedged item. |
Basic had no derivative contacts in 2003. In May 2004, Basic
implemented a cash flow hedge to protect itself from fluctuation
in cash flows associated with its credit facility. Changes in
fair value of the hedging derivative are initially recorded in
other comprehensive income, then recognized in income in the
same period(s) in which the hedged transaction affects income.
Ineffective portions of a cash flow hedging derivatives
change in fair value are recognized currently in earnings. Basic
had no ineffectiveness related to its cash flow hedge in 2005 or
2004.
Asset Retirement Obligations
|
|
|
As of January 1, 2003, Basic adopted Statement of Financial
Accounting Standards No. 143, Accounting for Asset
Retirement Obligation
(SFAS No. 143). SFAS No. 143
requires Basic to record the fair value of an asset retirement
obligation as a liability in the period in which it incurs a
legal obligation associated with the retirement of tangible
long-lived assets and capitalize on equal amount as a cost of
the asset depreciating it over the life of the asset. Subsequent
to the initial measurement of the asset retirement obligation,
the obligation is adjusted at the end of each quarter to reflect
the passage of time, changes in the estimated future cash flows
underlying the obligation, acquisition or construction of
assets, and settlements of obligations. On January 1, 2003,
Basic recorded additional costs, net of accumulated depreciation
of approximately $102,000, an asset retirement obligation of
approximately $340,000, and an after-tax charge of approximately
$151,000 for the cumulative effect on prior years
depreciation of the |
F1-12
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
|
additional costs and the accretion expense on the liability
related to the expected abandonment costs. |
Basic owns and operates salt water disposal sites, brine water
wells, gravel pits and land farm sites, each of which is subject
to rules and regulations regarding usage and eventual closure.
The following table reflects the changes in the liability during
years ended December 31, 2005 and 2004 (in thousands):
|
|
|
|
|
Balance, December 31, 2003
|
|
$ |
415 |
|
Additional asset retirement
obligations recognized through acquisitions
|
|
|
36 |
|
Accretion expense
|
|
|
33 |
|
Settlements
|
|
|
(11 |
) |
|
|
|
|
Balance, December 31, 2004
|
|
$ |
473 |
|
Additional asset retirement
obligations recognized through acquisitions
|
|
|
74 |
|
Accretion expense
|
|
|
42 |
|
Settlements
|
|
|
(20 |
) |
|
|
|
|
Balance, December 31, 2005
|
|
$ |
569 |
|
|
|
|
|
The pro forma net income (loss) and related per share amounts
assuming SFAS no. 143 had been applied in 2003 are as follows
(in thousands, except per share data):
|
|
|
|
|
|
|
|
2003 | |
|
|
| |
Pro forma net income (loss)
available to common shareholders(a)
|
|
$ |
(1,964 |
) |
Pro forma earnings per share of
common stock Basic
|
|
|
|
|
|
Basic
|
|
$ |
(0.09 |
) |
|
Diluted
|
|
$ |
(0.09 |
) |
|
|
|
(a) |
|
The net income available to common stockholders in 2003 has been
adjusted to remove the $151,000 cumulative effect of accounting
change attributable to SFAS No. 143. |
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). |
F1-13
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
Comprehensive Income
|
|
|
Basic follows the provisions of Statement of Financial
Accounting Standards No. 130, Reporting of
Comprehensive Income
(SFAS No. 130). SFAS No. 130
establishes standards for reporting and presentation of
comprehensive income and its components. SFAS No. 130
requires all items that are required to be recognized under
accounting standards as components of comprehensive income to be
reported in a financial statement that is displayed with the
same prominence as other financial statements. In accordance
with the provisions of SFAS No. 130, gains and losses
on cash flow hedging derivatives, to the extent effective, are
included in other comprehensive income (loss). |
Reclassifications
|
|
|
Certain reclassifications of prior year financial statement
amounts have been made to conform to current year presentations. |
Recent Accounting Pronouncements
|
|
|
In December 2004, the Financial Accounting Standards Board
issued Statement of Financial Accounting Standard No. 123R,
Share-Based
Payment(SFAS No. 123R). Basic
will adopt the provisions of SFAS No. 123R on
January 1, 2006 using the modified prospective application.
Accordingly, Basic will recognize compensation expense for all
newly granted awards and awards modified, repurchased, or
cancelled after January 1, 2006. |
Compensation cost for the unvested portion of awards that are
outstanding as of January 1, 2006 will be recognized
ratably over the remaining vesting period. The compensation cost
for the unvested portion of awards will be based on the fair
value at date of grant as calculated for Basics pro forma
disclosure under SFAS No. 123. However, Basic will
continue to account for any portion of awards outstanding on
January 1, 2006 that were initially measured using the
minimum value method under the intrinsic value method in
accordance with APB No. 25. Basic will recognize
compensation expense for awards under its Second Amended and
Restated 2003 Incentive Plan (the Incentive Plan)
beginning in January 1, 2006.
Basic estimates that the effect on net income and earnings per
share in the periods following adoption of
SFAS No. 123R will be consistent with its pro forma
disclosure under SFAS No. 123, except that estimated
forfeitures will be considered in the calculation of
compensation expense under SFAS No. 123R and
volatility will be considered in determination of grant date
fair value under SFAS 123R. However, the actual effect on
net income and earnings per share will vary depending upon the
number of options granted in future years compared to prior
years and the number of shares exercised under the Incentive
Plan. Further, Basic will use the Black-Scholes-Merton model to
calculate fair value.
F1-14
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
In 2005, 2004 and 2003, Basic acquired either substantially all
of the assets or all of the outstanding capital stock of each of
the following businesses, each of which were accounted for using
the purchase method of accounting (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Cash Paid | |
|
|
|
|
(net of cash | |
|
|
Closing Date | |
|
acquired) | |
|
|
| |
|
| |
New Force Energy Services
|
|
|
January 27, 2003 |
|
|
$ |
7,665 |
|
S & S Bulk Cement
|
|
|
April 17, 2003 |
|
|
|
195 |
|
Briscoe Oil Tools
|
|
|
June 13, 2003 |
|
|
|
260 |
|
FESCO Holdings, Inc.(a)
|
|
|
October 3, 2003 |
|
|
|
19,093 |
|
PWI, Inc.
|
|
|
October 3, 2003 |
|
|
|
25,104 |
|
Pennant Service Company
|
|
|
October 3, 2003 |
|
|
|
7,387 |
|
Graham Acidizing
|
|
|
December 1, 2003 |
|
|
|
2,181 |
|
|
|
|
|
|
|
|
Total 2003
|
|
|
|
|
|
$ |
61,885 |
|
|
|
|
|
|
|
|
Action Trucking Curtis
Smith, Inc.
|
|
|
April 27, 2004 |
|
|
$ |
821 |
|
Rolling Plains
|
|
|
May 30, 2004 |
|
|
|
3,022 |
|
Perrys Pump Service
|
|
|
May 30, 2004 |
|
|
|
1,379 |
|
Lone Tree Construction
|
|
|
June 23, 2004 |
|
|
|
211 |
|
Hayes Services
|
|
|
July 1, 2004 |
|
|
|
1,595 |
|
Western Oil Well
|
|
|
July 30, 2004 |
|
|
|
854 |
|
Summit Energy
|
|
|
August 19, 2004 |
|
|
|
647 |
|
Energy Air Drilling
|
|
|
August 30, 2004 |
|
|
|
6,500 |
|
AWS Wireline
|
|
|
November 1, 2004 |
|
|
|
4,255 |
|
|
|
|
|
|
|
|
Total 2004
|
|
|
|
|
|
$ |
19,284 |
|
|
|
|
|
|
|
|
R & R Hot Oil Service
|
|
|
January 5, 2005 |
|
|
|
1,702 |
|
Premier Vacuum Service,
Inc.
|
|
|
January 28, 2005 |
|
|
|
1,009 |
|
Spencers Coating Specialist
|
|
|
February 9, 2005 |
|
|
|
619 |
|
Marks Well Service
|
|
|
February 25, 2005 |
|
|
|
579 |
|
Max-Line, Inc.
|
|
|
April 28, 2005 |
|
|
|
1,498 |
|
MD Well Service, Inc.
|
|
|
May 17, 2005 |
|
|
|
4,478 |
|
179 Disposal, Inc.
|
|
|
August 4, 2005 |
|
|
|
1,729 |
|
Oilwell Fracturing Services,
Inc.
|
|
|
October 11, 2005 |
|
|
|
13,764 |
|
|
|
|
|
|
|
|
Total 2005
|
|
|
|
|
|
$ |
25,378 |
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
This acquisition was funded through the issuance of Basics
common stock. The total cash paid represents the retirement of
debt at closing and transaction costs incurred net of the cash
acquired. |
The operations of each of the acquisitions listed above are
included in Basics statement of operations as of each
respective closing date. The acquisitions of New Force Energy
Services (New Force), FESCO Holding, Inc.
(FESCO) and PWI, Inc. and certain other affiliated
entities (PWI) in 2003 are deemed significant and
discussed below in further detail.
F1-15
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
New Force Energy Services
|
|
|
On January 27, 2003, Basic acquired substantially all of
the assets of New Force for $7.7 million plus a
$2.7 million contingent earn-out payment. The contingent
earn-out payment will be paid upon the New Force assets meeting
certain financial objectives in the future. The preliminary cash
cost of the New Force acquisition was $7.7 million
(including other direct acquisition costs) which was allocated
$6.3 million to property and equipment, $1.3 million
to goodwill, $105,000 to inventory and $10,000 to non-compete
agreements. |
FESCO Holdings, Inc.
|
|
|
On October 3, 2003, Basic acquired all the capital stock of
FESCO. As consideration for the acquisition of FESCO, Basic
issued 3,650,000 shares of its common stock, based on an
estimated fair value of the stock of $5.16 per share (a
total fair value of approximately $18.8 million), and paid
approximately $19.1 million in net cash at the closing,
representing the retirement of debt of FESCO at closing and the
payment of transaction costs incurred, net of the cash held by
FESCO. In addition to assuming the working capital of FESCO,
Basic incurred other direct acquisition costs and assumed
certain other liabilities of FESCO, resulting in Basic recording
an aggregate purchase price of approximately $37.9 million.
The following table summarizes the estimated fair value of the
assets acquired and liabilities assumed at the date of
acquisition (in thousands): |
|
|
|
|
|
|
Current assets, excluding cash
|
|
$ |
12,855 |
|
Property and equipment
|
|
|
32,344 |
|
Other assets
|
|
|
38 |
|
|
|
|
|
|
Total assets acquired
|
|
|
45,237 |
|
|
|
|
|
Current liabilities
|
|
|
5,592 |
|
Deferred tax liability
|
|
|
1,725 |
|
|
|
|
|
|
Total liabilities assumed
|
|
|
7,317 |
|
|
|
|
|
Net assets acquired
|
|
$ |
37,920 |
|
|
|
|
|
PWI, Inc.
|
|
|
On October 3, 2003, Basic acquired substantially all the
assets of PWI for $25.1 million plus a $2.5 million
contingent earn-out payment. The contingent earn-out agreement
was terminated by the parties entering into an agreement to pay
$75,000 per year for four years beginning in October 2005.
The cash cost of the PWI acquisition was $25.1 million
(including other direct acquisition costs) which was allocated
$16.4 million to property and equipment, $8.6 million
to goodwill, $250,000 to non-compete agreements and $200,000 to
liabilities assumed. |
Contingent Earn-out Arrangements and Final Purchase Price
Allocations
|
|
|
Contingent earn-out arrangements are generally arrangements
entered in certain acquisitions to encourage the owner/manager
to continue operating and building the business after the
purchase transaction. The contingent earn-out arrangements of
the related acquisitions are generally linked to certain
financial measures and performance of the assets acquired in the
various acquisitions. All amounts paid or reasonably accrued for
related to the contingent earn-out payments are reflected as
increases to the goodwill associated with the acquisition. |
F1-16
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
The following presents a summary of acquisitions that have a
contingent earn-out arrangement in effect as of
December 31, 2005 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Termination | |
|
Maximum | |
|
|
|
|
Date of | |
|
Exposure of | |
|
|
|
|
Contingent | |
|
Contingent | |
|
Amount Paid or | |
|
|
Earn-out | |
|
Earn-out | |
|
Accrued Through | |
Acquisition |
|
Arrangement | |
|
Arrangement | |
|
December 31, 2005 | |
|
|
| |
|
| |
|
| |
Advantage Services,
Inc.
|
|
|
October 9, 2005 |
|
|
$ |
250 |
|
|
$ |
219 |
|
New Force Energy Services
|
|
|
January 27, 2008 |
|
|
|
2,700 |
|
|
|
1,639 |
|
S&S Bulk Cement
|
|
|
April 20, 2008 |
|
|
|
115 |
|
|
|
115 |
|
Briscoe Oil Tools
|
|
|
June 12, 2008 |
|
|
|
125 |
|
|
|
82 |
|
Rolling Plains
|
|
|
April 30, 2009 |
|
|
|
* |
|
|
|
588 |
|
Premier Vacuum Services,
Inc.
|
|
|
February 1, 2010 |
|
|
|
900 |
|
|
|
226 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
4,090 |
|
|
$ |
2,869 |
|
|
|
* |
Basic will pay to the sellers an amount for each of the five
consecutive 12 month periods beginning on May 1, 2004
equal to 50% of the amount by which annual EBITDA exceeds an
annual targeted EBITDA. There is no guarantee or assurance that
the targeted EBITDA will be reached |
The following unaudited pro forma results of operations have
been prepared as though the New Force, FESCO and PWI
acquisitions had been completed on January 1, 2003. Pro
forma amounts are based on the final purchase price allocations
of the significant acquisitions and are not necessarily
indicative of the results that may be reported in the future (in
thousands, except per share data).
|
|
|
|
|
|
|
Year Ended |
|
|
December 31, 2003 |
|
|
|
|
|
(Unaudited) |
Revenues
|
|
$ |
228,059 |
|
Income (loss) from continuing
operations less preferred stock dividends and accretion
|
|
$ |
(1,182 |
) |
Earnings per common
share basic
|
|
$ |
(0.05 |
) |
Earnings per common
share diluted
|
|
$ |
(0.05 |
) |
Basic does not believe the pro-forma effect of the remainder of
the acquisitions completed in 2003, 2004, or 2005 is material,
either individually or when aggregated, to the reported results
of operations.
F1-17
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, | |
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
Land
|
|
$ |
1,902 |
|
|
$ |
1,573 |
|
Buildings and improvements
|
|
|
8,634 |
|
|
|
6,615 |
|
Well service units and equipment
|
|
|
199,070 |
|
|
|
138,957 |
|
Fluid services equipment
|
|
|
59,104 |
|
|
|
53,111 |
|
Brine and fresh water stations
|
|
|
7,746 |
|
|
|
7,722 |
|
Frac/test tanks
|
|
|
31,475 |
|
|
|
19,707 |
|
Pressure pumping equipment
|
|
|
31,101 |
|
|
|
14,971 |
|
Construction equipment
|
|
|
24,224 |
|
|
|
21,964 |
|
Disposal facilities
|
|
|
16,828 |
|
|
|
14,079 |
|
Vehicles
|
|
|
23,329 |
|
|
|
18,881 |
|
Rental equipment
|
|
|
6,519 |
|
|
|
4,885 |
|
Aircraft
|
|
|
3,236 |
|
|
|
3,335 |
|
Other
|
|
|
8,602 |
|
|
|
7,780 |
|
|
|
|
|
|
|
|
|
|
|
421,770 |
|
|
|
313,580 |
|
Less accumulated depreciation and
amortization
|
|
|
112,695 |
|
|
|
80,129 |
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
$ |
309,075 |
|
|
$ |
233,451 |
|
|
|
|
|
|
|
|
Basic is obligated under various capital leases for certain
vehicles and equipment that expire at various dates during the
next five years. The gross amount of property and equipment and
related accumulated amortization recorded under capital leases
and included above consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
December 31, | |
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
Light vehicles
|
|
$ |
17,912 |
|
|
$ |
12,993 |
|
Fluid services equipment
|
|
|
14,011 |
|
|
|
10,558 |
|
Construction equipment
|
|
|
1,300 |
|
|
|
840 |
|
|
|
|
|
|
|
|
|
|
|
33,223 |
|
|
|
24,391 |
|
Less accumulated amortization
|
|
|
8,474 |
|
|
|
7,201 |
|
|
|
|
|
|
|
|
|
|
$ |
24,749 |
|
|
$ |
17,190 |
|
|
|
|
|
|
|
|
Amortization of assets held under capital leases of
approximately $1.8 million, $1.8 million, and
$2.5 million for the years ended December 31, 2005,
2004, and 2003, respectively, is included in depreciation and
amortization expense in the consolidated statements of
operations.
F1-18
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
Long-term debt consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
December 31, | |
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
Credit Facilities:
|
|
|
|
|
|
|
|
|
|
Term B Loan
|
|
$ |
90,000 |
|
|
$ |
166,500 |
|
|
Revolver
|
|
|
16,000 |
|
|
|
|
|
Capital leases and other notes
|
|
|
20,887 |
|
|
|
15,976 |
|
|
|
|
|
|
|
|
|
|
|
126,887 |
|
|
|
182,476 |
|
Less current portion
|
|
|
7,646 |
|
|
|
11,561 |
|
|
|
|
|
|
|
|
|
|
$ |
119,241 |
|
|
$ |
170,915 |
|
|
|
|
|
|
|
|
2005 Credit Facility
|
|
|
On December 15, 2005, Basic entered into a
$240 million Third Amended and Restated Credit Agreement
with a syndicate of lenders (2005 Credit Facility)
which refinanced all of its then existing credit facilities. The
2005 Credit Facility provides for a $90 million Term B Loan
(2005 Term B Loan) and a $150 million revolving
line of credit (Revolver). The commitment under the
Revolver allows for (a) the borrowing of funds
(b) issuance of up to $20 million of letters of credit
and (c) $2.5 million of swing-line loans (next day
borrowing). The amounts outstanding under the 2005 Term B Loan
require quarterly amortization at various amounts during each
quarter with all amounts outstanding on December 15, 2011
being due and payable in full. All the outstanding amounts under
the Revolver are due and payable on December 15, 2010. The
2005 Credit Facility is secured by substantially all of
Basics tangible and intangible assets. Basic incurred
approximately $1.8 million in debt issuance costs in
obtaining the 2005 Credit Facility. |
At Basics option, borrowings under the 2005 Term B Loan
bear interest at either the (a) Alternative Base
Rate (i.e. the higher of the banks prime rate or the
federal funds rate plus .5% per annum) plus 1% or
(b) the LIBOR rate plus 2.0%. At December 31, 2005,
Basics weighted average interest rate on its Term B Loan
was 6.4%.
At Basics option, borrowings under the 2005 Revolver bear
interest at either the (a) Alternative Base
Rate (i.e. the higher of the banks prime rate or the
federal funds rate plus .5% per annum) plus a margin
ranging from .50% to 1.25% or (b) the LIBOR rate plus a
margin ranging from 1.5% to 2.25%. The margins vary depending on
Basics leverage ratio. At December 31, 2005,
Basics margin on Alternative Base Rates and LIBOR tranches
was .75% and 1.75%, respectively. Fees on the letters of credit
are due quarterly on the outstanding amount of the letters of
credit at a rate ranging from 1.5% to 2.25% for participation
fees and .125% for fronting fees. A commitment fee is due
quarterly on the available borrowings under the Revolver at
rates ranging from .375% to .5%.
At December 31, 2005 Basic, under its Revolver, had
outstanding $16 million of borrowings and $9.6 million
of letters of credit and no amounts outstanding in swing-line
loans. At December 31, 2005 Basic had availability under
its Revolver of $124.4 million.
Pursuant to the 2005 Credit Facility, Basic must apply proceeds
to reduce principal outstanding under the 2005 Term B Revolver
from (a) individual assets sales greater than
$2 million or $7.5 million in the aggregate on an
annual basis, and (b) 50% of the proceeds from
F1-19
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
any equity offering. The 2005 Credit Facility required Basic to
enter into an interest rate hedge, acceptable to the lenders,
through May 28, 2006 on at least $65 million of
Basics then outstanding indebtedness. Paydowns on the 2005
Term B Loan may not be reborrowed.
The 2005 Credit Facility contains various restrictive covenants
and compliance requirements, which include (a) limiting of
the incurrence of additional indebtedness, (b) restrictions
on mergers, sales or transfers of assets without the
lenders consent, (c) limitation on dividends and
distributions and (d) various financial covenants,
including (1) a maximum leverage ratio of 3.5 to 1.0
reducing over time to 3.25 to 1.0, (2) a minimum interest
coverage ratio of 3.0 to 1.0 and (e) limitations on capital
expenditures in any period of four consecutive quarters in
excess of 20% of Consolidated Net Worth unless certain criteria
are met. At December 31, 2005 and December 31, 2004,
Basic was in compliance with its covenants.
2004 Credit Facility
|
|
|
On December 21, 2004, Basic entered into a
$220 million Second Amended and Restated Credit Agreement
with a syndicate of lenders (2004 Credit Facility)
which refinanced all of its then existing credit facilities. The
2004 Credit Facility provided for a $170 million Term B
Loan (2004 Term B Loan) and a $50 million
revolving line of credit (2004 Revolver). The
commitment under the 2004 Revolver allowed for (a) the
borrowing of funds (b) issuance of up to $20 million
of letters of credit and (c) $2.5 million of
swing-line loans (next day borrowing). The amounts outstanding
under the 2004 Term B Loan required quarterly amortization at
various amounts during each quarter with all amounts outstanding
on October 3, 2009 being due and payable in full. All the
outstanding amounts under the 2004 Revolver were due and payable
on October 3, 2008. The 2004 Credit Facility was secured by
substantially all of Basics tangible and intangible
assets. Basic incurred approximately $766,000 in debt issuance
costs in obtaining the 2004 Credit Facility. |
At Basics option, borrowings under the 2004 Term B Loan
bore interest at either (a) the Alternative Base
Rate (i.e. the higher of the banks prime rate or the
federal funds rate plus .5% per annum) plus 2% or
(b) LIBOR plus 3%. At December 31, 2004, Basics
weighted average interest rate on its 2004 Term B Loan was 5.5%.
At Basics option, borrowings under the 2004 Revolver bore
interest at either the (a) the Alternative Base
Rate (i.e. the higher of the banks prime rate or the
federal funds rate plus .5% per annum) plus a margin
ranging from 1.5% to 2.0% or (b) the LIBOR rate plus a
margin ranging from 2.5% to 3.0%. The margins varied depending
on Basics leverage ratio. At December 31, 2004,
Basics margin on Alternative Base Rates and LIBOR tranches
was 2.0% and 3.0%, respectively. Fees on the letters of credit
were due quarterly on the outstanding amount of the letters of
credit at a rate ranging from 2.5% to 3.0% for participation
fees and .125% for fronting fees. A commitment fee was due
quarterly on the available borrowings under the 2004 Revolver at
rates ranging from .375% to .5%.
At December 31, 2004, Basic, under its 2004 Revolver, had
outstanding $8.3 million of letters of credit and no
amounts outstanding in swing-line loans. At December 31,
2004, Basic had availability under its 2004 Revolver of
$41.7 million.
2003 Credit Facility
|
|
|
On October 3, 2003, Basic entered into a $170 million
credit facility with a syndicate of lenders (2003 Credit
Facility) which refinanced all of its then existing credit
facilities. The 2003 Credit Facility provided for a
$140 million Term B Loan (2003 Term B Loan) and
a $30 million |
F1-20
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
|
revolving line of credit (2003 Revolver). The
commitment under the 2003 Revolver allowed for (a) the
borrowing of funds (b) issuance of up to $10 million
of letters of credits and (c) $2.5 million of
swing-line loans (next day borrowing). The amounts outstanding
under the 2003 Term B Loan required quarterly amortization at
various amounts during each quarter with all amounts outstanding
on October 3, 2009 being due and payable in full. All the
outstanding amounts under the 2003 Revolver were due and payable
on October 3, 2008. The 2003 Credit Facility was secured by
substantially all of Basics tangible and intangible
assets. Basic incurred approximately $5.1 million in debt
issuance costs in obtaining the 2003 Credit Facility. |
At Basics option, borrowings under the 2003 Term B Loan
bore interest at either (a) the Alternative Base
Rate (i.e. the higher of the banks prime rate of the
federal funds rate plus .5% per annum) plus 2.5% or
(b) the LIBOR rate plus 3.5%. At December 31, 2003,
Basics weighted average interest rate on its 2003 Term B
Loan was 4.67%.
At Basics option, borrowings under the 2003 Revolver bore
interest at either the (a) the Alternative Base
Rate (i.e. the higher of the banks prime rate or the
federal funds rate plus .5% per annum) plus a margin
ranging from 1.5% to 2.0% or (b) the Libor rate plus a
margin ranging from 2.5% to 3.0%. The margins varied depending
on Basics leverage ration. At December 31, 2003,
Basics margin on Alternative Base Rates and LIBOR tranches
was 2.0% and 3.0%, respectively. Fees on the letters of credit
were due quarterly on the outstanding amount of the letters of
credit at a rate ranging from 2.5% to 3.0% for participations
fees and .125% for fronting fees. A commitment fee was due
quarterly on the available borrowings under the 2003 Revolver at
rates ranging from .5% to .375%.
At December 31, 2003, Basic, under its 2003 Revolver, had
$5.3 million of outstanding letters of credit and no
amounts outstanding in swing-line loans. At December 31,
2003, Basic had availability under its 2003 Revolver of
$24.7 million.
Other Debt
|
|
|
Basic has a variety of other capital leases and notes payable
outstanding that are generally customary in its business. None
of these debt instruments are material individually or in the
aggregate. |
As of December 31, 2005, the aggregate maturities of debt,
including capital leases, for the next five years and thereafter
are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Debt | |
|
Capital Leases | |
|
|
| |
|
| |
2006
|
|
$ |
1,000 |
|
|
$ |
6,646 |
|
2007
|
|
|
1,000 |
|
|
|
6,024 |
|
2008
|
|
|
1,000 |
|
|
|
5,118 |
|
2009
|
|
|
1,000 |
|
|
|
2,713 |
|
2010
|
|
|
17,000 |
|
|
|
386 |
|
Thereafter
|
|
|
85,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
106,000 |
|
|
$ |
20,887 |
|
|
|
|
|
|
|
|
F1-21
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
Basics interest expense consisted of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Cash payments for interest
|
|
$ |
11,421 |
|
|
$ |
8,159 |
|
|
$ |
3,934 |
|
Commitment and other fees paid
|
|
|
185 |
|
|
|
25 |
|
|
|
109 |
|
Amortization of debt issuance costs
|
|
|
1,062 |
|
|
|
970 |
|
|
|
694 |
|
Other
|
|
|
397 |
|
|
|
560 |
|
|
|
497 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
13,065 |
|
|
$ |
9,714 |
|
|
$ |
5,234 |
|
|
|
|
|
|
|
|
|
|
|
Losses on Extinguishment of Debt
|
|
|
In 2005, Basic recognized a loss on the early extinguishment of
debt. Basic wrote-off unamortized debt issuance costs of
approximately $627,000. |
In 2003, Basic recognized a loss on the early extinguishment of
debt. Basic paid termination fees of approximately
$1.7 million and wrote-off unamortized debt issuance costs
of approximately $3.5 million which resulted in a loss of
approximately $5.2 million.
In 2003, Basic adopted Statement of Financial Accounting
Standards No. 145 Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13,
and Technical Corrections
(SFAS No. 145). The provisions of
SFAS No. 145, which are currently applicable to Basic,
rescind Statement No. 4, which required all gains and
losses from extinguishment of debt to be aggregated and
classified as an extraordinary item, and instead require that
such gains and losses be reported as ordinary income or loss.
Basic now records gains and losses from the extinguishment of
debt as ordinary income or loss.
Income tax provision (benefit) was allocated as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Income from continuing operations
|
|
$ |
26,800 |
|
|
$ |
7,984 |
|
|
$ |
2,772 |
|
Discontinued operations
|
|
|
|
|
|
|
(38 |
) |
|
|
13 |
|
Cumulative effect of accounting
change
|
|
|
|
|
|
|
|
|
|
|
(88 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
26,800 |
|
|
$ |
7,946 |
|
|
$ |
2,697 |
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit) attributable to income (loss) from
continuing operations consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Current
|
|
$ |
8,499 |
|
|
$ |
|
|
|
$ |
(68 |
) |
Deferred
|
|
|
18,301 |
|
|
|
7,984 |
|
|
|
2,840 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
26,800 |
|
|
$ |
7,984 |
|
|
$ |
2,772 |
|
|
|
|
|
|
|
|
|
|
|
F1-22
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
Basic paid federal income taxes of $1,325,000 during 2005. No
federal income taxes were paid or received in 2004. In 2003
Basic received an income tax refund, net, of approximately
$1.5 million.
Reconciliation between the amount determined by applying the
federal statutory rate of 35% to the income (loss) from
continuing operations with the provision (benefit) for income
taxes is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Statutory federal income tax
|
|
$ |
25,053 |
|
|
$ |
7,321 |
|
|
$ |
2,007 |
|
Meals and entertainment
|
|
|
324 |
|
|
|
265 |
|
|
|
166 |
|
State taxes, net of federal benefit
|
|
|
1,415 |
|
|
|
421 |
|
|
|
138 |
|
Change in tax rates
|
|
|
|
|
|
|
|
|
|
|
542 |
|
Changes in estimates and other
|
|
|
8 |
|
|
|
(23 |
) |
|
|
(81 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
26,800 |
|
|
$ |
7,984 |
|
|
$ |
2,772 |
|
|
|
|
|
|
|
|
|
|
|
The tax effects of temporary differences that give rise to
significant portions of the deferred tax assets and deferred tax
liabilities are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
Current deferred taxes:
|
|
|
|
|
|
|
|
|
|
Receivables allowance
|
|
$ |
1,025 |
|
|
$ |
1,148 |
|
|
Interest rate derivative
|
|
|
(186 |
) |
|
|
|
|
|
EBITDA contingent warrants
|
|
|
|
|
|
|
337 |
|
|
Accrued liabilities
|
|
|
5,181 |
|
|
|
3,414 |
|
|
|
|
|
|
|
|
|
|
Net current deferred tax asset
|
|
$ |
6,020 |
|
|
$ |
4,899 |
|
|
|
|
|
|
|
|
Noncurrent deferred taxes:
|
|
|
|
|
|
|
|
|
|
Operating loss and tax credit
carryforwards
|
|
$ |
1,856 |
|
|
$ |
20,782 |
|
|
Property and equipment
|
|
|
(55,768 |
) |
|
|
(51,194 |
) |
|
Goodwill and intangibles
|
|
|
(1,208 |
) |
|
|
(602 |
) |
|
Deferred Compensation
|
|
|
1,140 |
|
|
|
617 |
|
|
Asset retirement obligation
|
|
|
210 |
|
|
|
175 |
|
|
Other
|
|
|
|
|
|
|
(25 |
) |
|
|
|
|
|
|
|
|
|
Net noncurrent deferred tax
liability
|
|
$ |
(53,770 |
) |
|
$ |
(30,247 |
) |
|
|
|
|
|
|
|
Basic provides a valuation allowance when it is more likely than
not that some portion of the deferred tax assets will not be
realized. There was no valuation allowance necessary as of
December 31, 2005 or 2004.
As of December 31, 2005, Basic had approximately
$4.9 million of net operating loss carryforwards
(NOL) for U.S. federal income tax purposes
related to the preacquisition period of FESCO, which are subject
to an annual limitation of approximately $900,000. The
carryforwards begin to expire in 2017.
F1-23
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
7. |
Commitments and Contingencies |
Environmental
|
|
|
Basic is subject to various federal, state and local
environmental laws and regulations that establish standards and
requirements for protection of the environment. Basic cannot
predict the future impact of such standards and requirements
which are subject to change and can have retroactive
effectiveness. Basic continues to monitor the status of these
laws and regulations. Management believes that the likelihood of
the disposition of any of these items resulting in a material
adverse impact to Basics financial position, liquidity,
capital resources or future results of operations is remote. |
Currently, Basic has not been fined, cited or notified of any
environmental violations that would have a material adverse
effect upon its financial position, liquidity or capital
resources. However, management does recognize that by the very
nature of its business, material costs could be incurred in the
near term to bring Basic into total compliance. The amount of
such future expenditures is not determinable due to several
factors including the unknown magnitude of possible
contamination, the unknown timing and extent of the corrective
actions which may be required, the determination of Basics
liability in proportion to other responsible parties and the
extent to which such expenditures are recoverable from insurance
or indemnification.
Litigation
|
|
|
From time to time, Basic is a party to litigation or other legal
proceedings that Basic considers to be a part of the ordinary
course of business. Basic is not currently involved in any legal
proceedings that it considers probable or reasonably possible,
individually or in the aggregate, to result in a material
adverse effect on its financial condition, results of operations
or liquidity. |
On September 3, 2004, a group of plaintiffs commenced a
civil action against Basic in the District Court of Panola
County, Texas, 123rd Judicial District. The complaint
alleges that Basics operation of a saltwater disposal well
has contaminated both the groundwater and the soil in the
surrounding area. The relief requested in the complaint is
monetary damages, injunctive relief, environmental remediation
and a court order requiring Basic to provide drinking water to
the community. In response to the complaint, Basic has retained
counsel and filed a general denial. Basic is in the beginning
stages of discovery and settlement negotiations are underway.
Should negotiations fail, Basic intends to defend itself
vigorously in this action.
On October 18, 2005, a group of plaintiffs commenced a
civil action against Basic in the 123rd Judicial District
Court of Panola County, Texas. The factual basis for this
complaint and relief claims that Basics operation of a
saltwater disposal well has contaminated both the groundwater
and the soil in the surrounding area. In addition, this
complaint alleges a wrongful death and personal injuries to
unspecified persons. In response to this complaint, Basic has
retained counsel and intends to defend itself vigorously in this
action.
On July 25, 2005, a jury returned a verdict in favor of a
salt water disposal operator who had filed suit against Basic.
The jury awarded the plaintiff $1.2 million in damages.
Basics insurance company denied coverage of liability.
Basic believes that it has reached a settlement of this matter
in connection with a mediation in March 2006 for
$1.0 million. As of December 31, 2005, Basic accrued a
$1.0 million loss for this contingency.
F1-24
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
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, 2005, the future minimum lease payments
under non-cancelable operating leases are as follows (in
thousands):
|
|
|
|
|
Year Ended December 31, |
|
|
|
|
|
2006
|
|
$ |
1,198 |
|
2007
|
|
|
816 |
|
2008
|
|
|
724 |
|
2009
|
|
|
570 |
|
2010
|
|
|
428 |
|
Thereafter
|
|
|
463 |
|
Rent expense approximated $7.0 million, $5.6 million,
and $3.0 million for 2005, 2004, and 2003, respectively.
Basic leases rights for the use of various brine and fresh water
wells and disposal wells ranging in terms from
month-to-month up to
99 years. The above table reflects the future minimum lease
payments if the lease contains a periodic rental. However, the
majority of these leases require payments based on a royalty
percentage or a volume usage.
Employment Agreements
|
|
|
Under the employment agreement with Mr. Huseman, chief
executive officer and president of Basic, effective
March 1, 2004 through February 2007, Mr. Huseman will
be entitled to an annual salary of $325,000 and an annual bonus
ranging from $50,000 to $325,000 based on the level of
performance objectives achieved by Basic. Under this employment
agreement, Mr. Huseman is eligible from time to time to
receive grants of stock options and other long-term equity
incentive compensation under our Amended and Restated 2003
Incentive Plan. In addition, upon a qualified termination of
employment, Mr. Huseman would be entitled to three times
his base salary plus his current annual incentive target bonus
for the full year in which the termination of employment
occurred. Similarly, following a change of control of Basic,
Mr. Huseman would be entitled to a lump sum payment of two
times his base salary plus his current annual incentive target
bonus for the full year in which the change of control occurred. |
Basic has entered into employment agreements with various other
executive officers of Basic that range in term up through 2007.
Under these agreements, if the officers employment is
terminated for certain reasons, he would be entitled to a lump
sum severance payment equal to six months annual salary, or 12
to 36 months annual salary if termination is on or
following a change of control of Basic.
Self-Insured Risk Accruals
|
|
|
Basic is self-insured up to retention limits as it relates to
workers compensation and medical and dental coverage of
its employees. Basic, generally, maintains no physical property
damage coverage on its workover rig fleet, with the exception of
certain of its 24-hour
workover rigs and newly manufactured rigs. Basic has deductibles
per occurrence for workers compensation and medical and
dental coverage of $150,000 and $125,000, respectively. Basic
has lower deductibles per occurrence for automobile liability
and general liability. Basic maintains |
F1-25
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
|
accruals in the accompanying consolidated balance sheets related
to self-insurance retentions by using third-party data and
historical claims history. |
At December 31, 2005 and December 31, 2004,
self-insured risk accruals, net of related
recoveries/receivables totaled approximately $9.5 million
and $6.6 million, respectively.
|
|
8. |
Mandatorily Redeemable Preferred Stock and Stockholders
Equity |
Common Stock
|
|
|
In February 2002, a group of related investors purchased a total
of 3,000,000 shares of Basics common stock at a
purchase price of $4 per share, for a total purchase price
of $12 million. As part of the purchase, 600,000 common
stock warrants were issued in connection with this transaction,
the fair value of which was approximately $1.2 million
(calculated using an option valuation model). The warrants allow
the holder to purchase 600,000 shares of Basics
common stock at $4 per share. The warrants are exercisable
in whole or in part after June 30, 2002 and prior to
February 13, 2007. |
In May 2003, the holders of the exercisable EBITDA Contingent
Warrants purchased 771,740 shares of Basics common
stock as a price of $.01 per share. See note 11. In
October, 2003 Basic issued 3,650,000 shares of its common
stock to acquire all the capital sock of FESCO. See note 3.
In February 2004, Basic granted certain officers and directors
837,500 restricted shares of common stock. The shares vest
25% per year for four years from the award date and are
subject to other vesting and forfeiture provisions. The
estimated fair value of the restricted shares was
$5.8 million at the date of the grant and was recorded as
deferred compensation, a component of stockholders equity.
This amount is being charged to expense over the respective
vesting period and totaled approximately $1.6 million and
$1.3 million for the years ended December 31, 2005 and
2004, respectively.
On August 3, 2005, the board of directors of Basic approved
a resolution to effect a
5-for-1 stock split of
the Companys common stock in the form of a stock dividend
resulting in 28,931,935 shares of common stock outstanding,
and to amend the Companys certificate of incorporation to
increase the authorized common stock to 80,000,000 shares.
The earnings per share information and all common stock
information have been retroactively restated for all periods
presented to reflect this stock split. On September 22,
2005 the pricing committee set the record date and distribution
date for the stock dividend, and the stock dividend was paid on
September 26, 2005 to holders of record on
September 23, 2005. The Company retained the current par
value of $.01 per share for all common shares.
In December 2005, Basic issued 5,000,000 shares of common
stock during the Companys Initial Public Offering to a
group of investors for $100 million or $20 per share.
After deducting fees, this resulted in net proceeds to Basic
totaling approximately $91.5 million.
Preferred Stock
|
|
|
In June 2002, Basic issued 150,000 shares of mandatorily
redeemable Series A 10% Cumulative Preferred Stock
(Series A Preferred Stock) to a group of
investors for $15 million or $100 per share. After
deducting fees, this resulted in net proceeds to Basic totaling
approximately $14.9 million. |
Dividends on each share of Series A Preferred Stock accrued
on a daily basis at the rate of 10% per annum of the sum of
the Liquidation Value ($100) thereof plus all accrued and unpaid
F1-26
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
dividends thereon from and including the date of issuance of
such share. All dividends which had accrued on the Series A
Preferred Stock were payable on March 31, June 30,
September 30 and December 31 of each year, beginning
September 30, 2002. all dividends which had accrued on
Series A shares outstanding remained as accumulated
dividends until paid to the holders thereof.
Basic could redeem all or any portion of the Series A
Preferred Stock by paying a price per share equal to the
Liquidation Value ($100) plus all accrued and unpaid dividends
plus a premium equal to 1% of the sum of the Liquidation Value
plus all accrued and unpaid dividends on or prior to
March 31, 2008. Basic was required to redeem all
Series A Preferred Stock on March 31, 2008 (including
accrued and unpaid dividends).
The difference between the $15 million face value of the
Series A Preferred Stock and ultimate redemption value of
approximately $26,975,000 (assuming Basic paid no dividends in
cash prior to redemption) was being accreted to the face value
of the Series A Preferred Stock from the date of issuance
to the mandatory redemption date of March 31, 2008
utilizing the effective interest method.
In connection with the Series A Preferred Stock financing
transaction, Basic granted 3,750,000 common stock warrants to
acquire a total of 3,750,000 shares of common stock at a
price of $4 per share, exercisable in whole or in part from
June 30, 2002 through June 30, 2007 to the holders of
Series A Preferred Stock, the relative fair value of which
(the initial fair value was approximately $5.9 million,
calculated using an option valuation model, and the relative
fair value was approximately $4.4 million) was recorded as
a discount on the Series A Preferred and included in
additional pain-in capital. The Series A Preferred Stock
discount, consisting of the warrant fair value of
$4.3 million and $58,000 of offering expenses, was being
accreted to the Series A Preferred Stock face value from
the date of issuance to the mandatory redemption date of
March 31, 2008 utilizing the effective interest method.
In January 2003, Basic issued an additional 9,020 shares of
Series A Preferred Stock in lieu of cash of approximately
$902,000 for accrued dividends on the Series A Preferred
Stock.
On October 3, 2003, all the Series A Preferred Stock,
plus accrued dividends, was converted into 3,304,085 shares
of Basics common stock, at which time the estimated fair
value of Basics common stock was $5.16 per share,
pursuant to a share exchange agreement dated September 22,
2003. This conversion did not include the 3,750,000 common stock
warrants which remain outstanding at December 31, 2005. The
excess of the consideration received by the preferred
shareholders over the book value of the preferred stock at the
conversion date has been treated as a reduction in net income
available to common stockholders.
|
|
9. |
Stockholders Agreement |
Basic has a Stockholders Agreement, as amended on
April 2, 2004 (Stockholders Agreement),
which provides for rights relating to the shares of our
stockholders and certain corporate governance matters.
The Stockholders Agreement imposes transfer restrictions
on the stockholders prior to December 21, 2007 (or earlier
upon either (i) DLJ Merchant Banking and its affiliates
ceasing to own at least 25% of its percentage based on their
initial equity positions, or (ii) the end of a contractual
lock-up period imposed
by underwriters after in initial public offering). During this
period, stockholders are generally prohibited from transferring
shares to persons other than permitted assignees. The
Stockholders Agreement provides for participation rights
of the other stockholders to require affiliates of DLJ Merchant
Banking to offer to include a specified percentage of their
shares whenever affiliates of DLJ Merchant Banking sell their
shares for
F1-27
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
value, other than a public offering or a sale in which all of
the parties to the Stockholders Agreement agree to
participate. The Stockholders Agreement also contains
drag-along rights. The drag-along rights
entitle the affiliated of DLJ Merchant Banking to require the
other stockholders who are a party to this agreement to sell a
portion of their shares of common stock and common stock
equivalents in the sale in any proposed to sale of shares of
common stock and common stock equivalents representing more than
50% of such equity interest held by the affiliates of DLJ
Merchant Banking to a person or persons who are not an affiliate
of them.
The Stockholders Agreement also provided for demand
registration rights after an initial public offering, and
piggyback registration rights both in and after an initial
public offering of Basics common stock.
In May 2003, Basics board of directors and stockholders
approved the Basic 2003 Incentive Plan (the Plan)
(as amended effective April 22, 2005) which provides for
granting of incentive awards in the form of stock options,
restricted stock, performance awards, bonus shares, phantom
shares, cash awards and other stock-based awards to officers,
employees, directors and consultants of Basic. The Plan assumed
awards of the plans of Basics successors that were awarded
and remained outstanding prior to adoption of the Plan. The Plan
provides for the issuance of 5,000,000 shares. The Plan is
administered by the Plan committee, and in the absence of a Plan
committee, by the Board of Directors, which determines the
awards, and the associated terms of the awards and interprets
its provisions and adopts policies for implementing the Plan.
The number of shares authorized under the Plan and the number of
shares subject to an award under the Plan will be adjusted for
stock splits, stock dividends, recapitalizations, mergers and
other changes affecting the capital stock of Basic.
On January 26, 2005, March 2, 2005, May 16, 2005,
and on December 16, 2005 the board of directors granted
various employees options to purchase 100,000, 865,000,
5,000 and 37,500 shares, respectively, of common stock of
Basic at exercise prices of $5.16, $6.98, $6.98, and
$21.01 per share, respectively. Of the 1,007,500 options
granted in 2005, 970,000 options vest over a five-year period
and expire 10 years from the date they are granted. The
remaining 37,500 options vest over a three-year period and
expire 10 years from the date they are granted. In
connection with the stock option grants, Basic recorded deferred
compensation of approximately $5.2 million which is being
amortized over the related vesting period.
Options granted under the Plan expire 10 years from the
date they are granted, and generally vest over a three to five
year service period.
F1-28
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
The following table reflects the summary of the stock options
outstanding for the years ended December 31, 2005, 2004,
and 2003 and the changes during the years then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
2004 |
|
2003 |
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
Weighted |
|
|
|
Weighted |
|
|
Number of |
|
Average |
|
Number of |
|
Average |
|
Number of |
|
Average |
|
|
Options |
|
Price |
|
Options |
|
Price |
|
Options |
|
Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-statutory stock options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, beginning of year
|
|
|
1,463,300 |
|
|
$ |
4.17 |
|
|
|
1,290,800 |
|
|
$ |
4.03 |
|
|
|
700,800 |
|
|
$ |
4.00 |
|
|
|
Options granted
|
|
|
1,007,500 |
|
|
$ |
7.32 |
|
|
|
197,500 |
|
|
$ |
5.16 |
|
|
|
642,500 |
|
|
$ |
4.06 |
|
|
|
Options forfeited
|
|
|
(25,000 |
) |
|
$ |
6.98 |
|
|
|
(25,000 |
) |
|
$ |
5.16 |
|
|
|
(52,500 |
) |
|
$ |
4.00 |
|
|
|
Options exercised
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of year
|
|
|
2,445,800 |
|
|
$ |
5.44 |
|
|
|
1,463,300 |
|
|
$ |
4.17 |
|
|
|
1,290,800 |
|
|
$ |
4.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, end of year
|
|
|
1,126,665 |
|
|
|
|
|
|
|
872,440 |
|
|
|
|
|
|
|
421,675 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average fair value of
options granted during the year
|
|
$ |
8.00 |
|
|
|
|
|
|
$ |
3.14 |
|
|
|
|
|
|
$ |
1.61 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes information about Basics
stock options outstanding and options exercisable at
December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding |
|
Options Exercisable |
|
|
|
|
|
|
|
Number of Options |
|
Weighted Average |
|
Weighted |
|
Number of Options |
|
Weighted |
Range of |
|
Outstanding at |
|
Remaining |
|
Average |
|
Outstanding at |
|
Average |
Exercise Prices |
|
December 31, 2005 |
|
Contractual Life |
|
Exercise Price |
|
December 31, 2005 |
|
Exercise Price |
|
|
|
|
|
|
|
|
|
|
|
$ 4.00
|
|
|
1,253,300 |
|
|
|
6.43 years |
|
|
$ |
4.00 |
|
|
|
1,074,166 |
|
|
$ |
4.00 |
|
$ 5.16
|
|
|
310,000 |
|
|
|
8.48 years |
|
|
$ |
5.16 |
|
|
|
52,499 |
|
|
$ |
5.16 |
|
$ 6.98
|
|
|
845,000 |
|
|
|
9.17 years |
|
|
$ |
6.98 |
|
|
|
|
|
|
$ |
|
|
$21.01
|
|
|
37,500 |
|
|
|
9.96 years |
|
|
$ |
21.01 |
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,445,800 |
|
|
|
|
|
|
|
|
|
|
|
1,126,665 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11. |
EBITDA Contingent Warrants |
On December 21, 2000, Basic issued EBITDA Contingent
Warrants to purchase up to an aggregate of
(a) 1,149,705 shares, at $.01 per share, of its
common stock as a dividend to stockholders of record on
December 18, 2000 and (b) 287,425 shares, at
$0.01 per share, as part of an authorized issuance to
certain members of management of Basic. The determination of the
ultimate number of EBITDA Contingent Warrants that may be
exercised was dependent of Basic achieving certain levels of
financial performance in 2001 and 2002. The warrants became
exercisable no later than March 31, 2003 based on the
actual financial performance for 2001 and 2002 and expired on
May 1, 2003.
On August 23, 2001, Basic issued additional EBITDA
Contingent Warrants to purchase up to an aggregate of
106,310 shares, at $0.01 per share, of Basics
common stock as part of an authorized issuance to certain
members of its management. The determination of the ultimate
number of EBITDA Contingent Warrants that may be exercised was
dependent on Basics achieving certain levels of financial
performance in 2001 and 2002. The warrants became exercisable,
and were not subject to forfeiture for termination, no later
than March 31, 2003 based on actual financial performance
for 2001 and 2002 and expired on May 1, 2003.
F1-29
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
In 2003, it was determined that Basic did not meet the financial
performance objectives as set forth in the EBITDA Contingent
Warrant grants. However, the board of directors evaluated other
subjective matters regarding these grants and authorized the
award of 574,860 warrants to the stockholders and 196,880
warrants to certain members of management even though the
performance criteria was not met. As a result, Basic recognized
the compensation expense of $911,000 related to the portion of
the warrants issued to management in 2003. In 2003, all holders
of the warrants exercised all of their rights and acquired
common stock of Basic. The value of the warrants associated with
the common stock dividend was recorded in 2003 when the number
of warrants to be issued was known.
|
|
12. |
Related Party Transactions |
Basic provided services and products for workover, maintenance
and plugging of existing oil and gas wells to Southwest
Royalties, Inc., an affiliate of a director and other
significant stockholders of Basic, for approximately $0,
$140,000, and $1.3 million in 2005, 2004, and 2003,
respectively. Basic had no receivables from this related party
as of December 31, 2005 or 2004. Basic had receivables from
employees totaling $65,000 and $64,900 as of December 31,
2005 and 2004 respectively.
Basic has a 401(k) profit sharing plan that covers substantially
all employees with more than 90 days of service. Employees
may contribute up to their base salary not to exceed the annual
Federal maximum allowed for such plans. Basic makes a matching
contribution proportional to each employees contribution.
Employee contributions are fully vested at all times. Employer
matching contributions vest incrementally, with full vesting
occurring after five years of service. Employer contributions to
the 401(k) plan approximated $468,000, $363,000 and $180,000 in
2005, 2004, and 2003, respectively.
|
|
14. |
Deferred Compensation Plan |
In April 2005, Basic established a deferred compensation plan
for certain employees. Participants may defer up to 50% of their
salary and 100% of any cash bonuses. Basic makes matching
contributions of 20% of the participants deferrals.
Employer matching contributions and earnings thereon are subject
to a five-year vesting schedule with full vesting occurring
after five years of service. Employer contributions to the
deferred compensation plan approximated $56,000, $0, and $0 in
2005, 2004, and 2003, respectively.
F1-30
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, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Numerator (both basic and
diluted):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$ |
44,781 |
|
|
$ |
12,932 |
|
|
$ |
(1,986 |
) |
|
Discontinued operations, net of tax
|
|
|
|
|
|
|
(71 |
) |
|
|
22 |
|
|
Cumulative effect of accounting
change
|
|
|
|
|
|
|
|
|
|
|
(151 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net income available to common
stockholders
|
|
$ |
44,781 |
|
|
$ |
12,861 |
|
|
$ |
(2,115 |
) |
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common stock
outstanding
|
|
|
28,381,853 |
|
|
|
28,094,435 |
|
|
|
22,575,940 |
|
|
Vested restricted stock
|
|
|
199,058 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for basic earnings per
share
|
|
|
28,580,911 |
|
|
|
28,094,435 |
|
|
|
22,575,940 |
|
|
Stock options
|
|
|
789,991 |
|
|
|
389,975 |
|
|
|
|
|
|
Unvested restricted stock
|
|
|
638,442 |
|
|
|
837,500 |
|
|
|
|
|
|
Common stock warrants
|
|
|
3,159,035 |
|
|
|
1,333,310 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted earnings
per share
|
|
|
33,168,379 |
|
|
|
30,655,220 |
|
|
|
22,575,940 |
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per common
share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
less preferred stock dividends and accretion
|
|
$ |
1.57 |
|
|
$ |
0.46 |
|
|
$ |
(0.09 |
) |
|
Discontinued operations, net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to
common stockholders
|
|
$ |
1.57 |
|
|
$ |
0.46 |
|
|
$ |
(0.09 |
) |
|
|
|
|
|
|
|
|
|
|
Diluted earnings per common
share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
less preferred stock dividends and accretion
|
|
$ |
1.35 |
|
|
$ |
0.42 |
|
|
$ |
(0.09 |
) |
|
Discontinued operations, net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to
common stockholders
|
|
$ |
1.35 |
|
|
$ |
0.42 |
|
|
$ |
(0.09 |
) |
|
|
|
|
|
|
|
|
|
|
The diluted earnings per share calculation for 2003 excludes the
effects of all stock options and common stock warrants as the
effects would be anti-dilutive as a result of the net loss.
|
|
16. |
Assets Held for Sale and Discontinued Operations |
In August, 2003 Basics management and board of directors
made the decision to dispose of its fluid services operations in
Alaska it acquired in the FESCO acquisition prior to closing of
the acquisition. After this disposal Basic no longer had any
operations in Alaska.
F1-31
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
The following are the results of operations, since their
acquisition in October 2003, from the discontinued operations
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended | |
|
|
December 31, | |
|
|
| |
|
|
2004 | |
|
2003 | |
|
|
| |
|
| |
Revenues
|
|
$ |
1,705 |
|
|
$ |
550 |
|
Operating costs
|
|
|
(1,814 |
) |
|
|
(515 |
) |
Income taxes deferred
|
|
|
38 |
|
|
|
(13 |
) |
|
|
|
|
|
|
|
|
Loss from discontinued operations,
net of tax
|
|
$ |
(71 |
) |
|
$ |
22 |
|
|
|
|
|
|
|
|
|
|
17. |
Business Segment Information |
Basics reportable business segments are well servicing,
fluid services, drilling and completion services and well site
construction services. The following is a description of the
segments:
Well Servicing: This business segment encompasses
a full range of services performed with a mobile well servicing
rig, including the installation and removal of downhole
equipment and elimination of obstructions in the well bore to
facilitate the flow of oil and gas. These services are performed
to establish, maintain and improve production throughout the
productive life of an oil and gas well and to plug and abandon a
well at the end of its productive life. Basic well servicing
equipment and capabilities are essential to facilitate most
other services performed on a well.
Fluid Services: This segment utilizes a fleet of
trucks and related assets, including specialized tank trucks,
storage tanks, water wells, disposal facilities and related
equipment. Basic employs these assets to provide, transport,
store and dispose of a variety of fluids. These services are
required in most workover, drilling and completion projects as
well as part of daily producing well operations.
Drilling and completion Services: This segment
focuses on a variety of services designed to stimulate oil and
gas production or to enable cement slurry to be placed in or
circulated within a well. These services are carried out in
niche markets for jobs requiring a single truck and lower
horsepower.
Well Site Construction Services: This segment
utilizes a fleet of power units, dozers, trenchers, motor
graders, backhoes and other heavy equipment. Basic employs these
assets to provide services for the construction and maintenance
of oil and gas production infrastructure, such as preparing and
maintaining access roads and well locations, installation of
small diameter gathering lines and pipelines and construction of
temporary foundations to support drilling rigs.
F1-32
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
Basics management evaluates the performance of its
operating segments based on operating revenues and segment
profits. Corporate expenses include general corporate expenses
associated with managing all reportable operating segments.
Corporate assets consist principally of working capital and debt
financing costs. The following table sets forth certain
financial information with respect to Basics reportable
segments (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and | |
|
Well Site | |
|
|
|
|
|
|
Well | |
|
Fluid | |
|
Completion | |
|
Construction | |
|
Corporate | |
|
|
|
|
Servicing | |
|
Services | |
|
Services | |
|
Services | |
|
and Other | |
|
Total | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Year ended December 31,
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$ |
221,993 |
|
|
$ |
132,280 |
|
|
$ |
59,832 |
|
|
$ |
45,647 |
|
|
$ |
|
|
|
$ |
459,752 |
|
Direct operating costs
|
|
|
(137,392 |
) |
|
|
(82,551 |
) |
|
|
(30,900 |
) |
|
|
(32,000 |
) |
|
|
|
|
|
|
(282,843 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profits
|
|
$ |
84,601 |
|
|
$ |
49,729 |
|
|
$ |
28,932 |
|
|
$ |
13,647 |
|
|
$ |
|
|
|
$ |
176,909 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$ |
18,671 |
|
|
$ |
9,415 |
|
|
$ |
3,644 |
|
|
$ |
2,808 |
|
|
$ |
2,534 |
|
|
$ |
37,072 |
|
Capital expenditures, (excluding
acquisitions)
|
|
$ |
42,838 |
|
|
$ |
21,602 |
|
|
$ |
8,361 |
|
|
$ |
6,443 |
|
|
$ |
3,851 |
|
|
$ |
83,095 |
|
Identifiable assets
|
|
$ |
169,487 |
|
|
$ |
100,959 |
|
|
$ |
45,850 |
|
|
$ |
28,376 |
|
|
$ |
152,621 |
|
|
$ |
497,293 |
|
Year ended December 31,
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$ |
142,551 |
|
|
$ |
98,683 |
|
|
$ |
29,341 |
|
|
$ |
40,927 |
|
|
$ |
|
|
|
$ |
311,502 |
|
Direct operating costs
|
|
|
(98,058 |
) |
|
|
(65,167 |
) |
|
|
(17,481 |
) |
|
|
(31,454 |
) |
|
|
|
|
|
|
(212,160 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profits
|
|
$ |
44,493 |
|
|
$ |
33,516 |
|
|
$ |
11,860 |
|
|
$ |
9,473 |
|
|
$ |
|
|
|
$ |
99,342 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$ |
14,125 |
|
|
$ |
8,316 |
|
|
$ |
2,402 |
|
|
$ |
1,857 |
|
|
$ |
1,976 |
|
|
$ |
28,676 |
|
Capital expenditures, (excluding
acquisitions)
|
|
$ |
27,918 |
|
|
$ |
16,436 |
|
|
$ |
3,670 |
|
|
$ |
4,748 |
|
|
$ |
2,902 |
|
|
$ |
55,674 |
|
Identifiable assets
|
|
$ |
126,208 |
|
|
$ |
87,349 |
|
|
$ |
24,246 |
|
|
$ |
24,064 |
|
|
$ |
105,993 |
|
|
$ |
367,860 |
|
Year ended December 31,
2003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$ |
104,097 |
|
|
$ |
52,810 |
|
|
$ |
14,808 |
|
|
$ |
9,184 |
|
|
$ |
|
|
|
$ |
180,899 |
|
Direct operating costs
|
|
|
(73,244 |
) |
|
|
(34,420 |
) |
|
|
(9,363 |
) |
|
|
(6,586 |
) |
|
|
|
|
|
|
(123,613 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profits
|
|
$ |
30,853 |
|
|
$ |
18,390 |
|
|
$ |
5,445 |
|
|
$ |
2,598 |
|
|
$ |
|
|
|
$ |
57,286 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$ |
9,100 |
|
|
$ |
5,201 |
|
|
$ |
2,575 |
|
|
$ |
850 |
|
|
$ |
487 |
|
|
$ |
18,213 |
|
Capital expenditures, (excluding
acquisitions)
|
|
$ |
13,217 |
|
|
$ |
6,298 |
|
|
$ |
676 |
|
|
$ |
2,412 |
|
|
$ |
898 |
|
|
$ |
23,501 |
|
Identifiable assets
|
|
$ |
102,948 |
|
|
$ |
73,841 |
|
|
$ |
10,387 |
|
|
$ |
31,322 |
|
|
$ |
84,155 |
|
|
$ |
302,653 |
|
The following table reconciles the segment profits reported
above to the operating income as reported in the consolidated
statements of operations (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Segment profits
|
|
$ |
176,909 |
|
|
$ |
99,342 |
|
|
$ |
57,286 |
|
General and administrative expenses
|
|
|
(55,411 |
) |
|
|
(37,186 |
) |
|
|
(22,722 |
) |
Depreciation and amortization
|
|
|
(37,072 |
) |
|
|
(28,676 |
) |
|
|
(18,213 |
) |
Gain (loss) on disposal of assets
|
|
|
222 |
|
|
|
(2,616 |
) |
|
|
(391 |
) |
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$ |
84,648 |
|
|
$ |
30,864 |
|
|
$ |
15,960 |
|
|
|
|
|
|
|
|
|
|
|
F1-33
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
The accrued expenses are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
Compensation related
|
|
$ |
10,576 |
|
|
$ |
6,764 |
|
Workers compensation
self-insured risk reserve
|
|
|
7,461 |
|
|
|
5,469 |
|
Health self-insured risk reserve
|
|
|
2,200 |
|
|
|
1,490 |
|
Accrual for receipts
|
|
|
1,841 |
|
|
|
903 |
|
Authority for expenditure accrual
|
|
|
3,052 |
|
|
|
879 |
|
Ad valorem taxes
|
|
|
935 |
|
|
|
845 |
|
Sales tax
|
|
|
2,407 |
|
|
|
692 |
|
Insurance obligations
|
|
|
673 |
|
|
|
586 |
|
Purchase order accrual
|
|
|
96 |
|
|
|
409 |
|
Professional fee accrual
|
|
|
1,079 |
|
|
|
392 |
|
Diesel tax accrual
|
|
|
385 |
|
|
|
336 |
|
Acquired contingent earnout
obligation
|
|
|
|
|
|
|
273 |
|
Retainers
|
|
|
1,042 |
|
|
|
250 |
|
Fuel accrual
|
|
|
368 |
|
|
|
317 |
|
Accrued interest
|
|
|
391 |
|
|
|
232 |
|
Contingent liability
|
|
|
1,000 |
|
|
|
|
|
Other
|
|
|
42 |
|
|
|
649 |
|
|
|
|
|
|
|
|
|
|
$ |
33,548 |
|
|
$ |
20,486 |
|
|
|
|
|
|
|
|
|
|
19. |
Supplemental Schedule of Non-Cash Investing and Financing
Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Capital leases issued for equipment
|
|
$ |
10,334 |
|
|
$ |
10,472 |
|
|
$ |
10,782 |
|
Preferred stock dividend
|
|
$ |
|
|
|
$ |
|
|
|
$ |
1,525 |
|
Preferred stock issued to pay
accrued dividends
|
|
$ |
|
|
|
$ |
|
|
|
$ |
902 |
|
Accretion of preferred stock
discount
|
|
$ |
|
|
|
$ |
|
|
|
$ |
3,424 |
|
Common stock issued for FESCO
acquisition
|
|
$ |
|
|
|
$ |
|
|
|
$ |
18,827 |
|
Common stock issued for preferred
stock
|
|
$ |
|
|
|
$ |
|
|
|
$ |
17,029 |
|
Vehicle rebate accrual
|
|
$ |
|
|
|
$ |
709 |
|
|
$ |
|
|
Asset retirement obligation
additions
|
|
$ |
74 |
|
|
$ |
21 |
|
|
$ |
|
|
F1-34
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
20. |
Quarterly Financial Data (Unaudited) |
The following table summarizes results for each of the four
quarters in the years ended December 31, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First | |
|
Second | |
|
Third | |
|
Fourth | |
|
|
|
|
Quarter | |
|
Quarter | |
|
Quarter | |
|
Quarter | |
|
Year | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
Year ended December 31,
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$ |
93,813 |
|
|
$ |
109,818 |
|
|
$ |
120,771 |
|
|
$ |
135,350 |
|
|
$ |
459,752 |
|
|
|
Segment profits
|
|
$ |
33,416 |
|
|
$ |
42,238 |
|
|
$ |
45,791 |
|
|
$ |
55,464 |
|
|
$ |
176,909 |
|
|
|
Income from continuing operations
|
|
$ |
5,801 |
|
|
$ |
10,747 |
|
|
$ |
12,335 |
|
|
$ |
15,898 |
|
|
$ |
44,781 |
|
|
|
Net income available to common
stockholders
|
|
$ |
5,801 |
|
|
$ |
10,747 |
|
|
$ |
12,335 |
|
|
$ |
15,898 |
|
|
$ |
44,781 |
|
|
Basic earnings per share of common
stock(a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$ |
0.21 |
|
|
$ |
0.38 |
|
|
$ |
0.44 |
|
|
$ |
0.54 |
|
|
$ |
1.57 |
|
|
|
Net income available to common
stockholders
|
|
$ |
0.21 |
|
|
$ |
0.38 |
|
|
$ |
0.44 |
|
|
$ |
0.54 |
|
|
$ |
1.57 |
|
|
Diluted earnings per share of
common stock(a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$ |
0.18 |
|
|
$ |
0.33 |
|
|
$ |
0.38 |
|
|
$ |
0.46 |
|
|
$ |
1.35 |
|
|
|
Net income available to common
stockholders
|
|
$ |
0.18 |
|
|
$ |
0.33 |
|
|
$ |
0.38 |
|
|
$ |
0.46 |
|
|
$ |
1.35 |
|
|
Weighted average common shares
outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
28,186 |
|
|
|
28,328 |
|
|
|
28,318 |
|
|
|
29,481 |
|
|
|
28,581 |
|
|
|
Diluted
|
|
|
32,157 |
|
|
|
32,783 |
|
|
|
32,802 |
|
|
|
34,436 |
|
|
|
33,168 |
|
Year ended December 31,
2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$ |
67,603 |
|
|
$ |
74,262 |
|
|
$ |
83,714 |
|
|
$ |
85,923 |
|
|
$ |
311,502 |
|
|
|
Segment profits
|
|
$ |
21,548 |
|
|
$ |
23,717 |
|
|
$ |
26,605 |
|
|
$ |
27,472 |
|
|
$ |
99,342 |
|
|
|
Income from continuing operations
|
|
$ |
2,633 |
|
|
$ |
3,369 |
|
|
$ |
3,800 |
|
|
$ |
3,130 |
|
|
$ |
12,932 |
|
|
|
Net income available to common
stockholders
|
|
$ |
2,685 |
|
|
$ |
3,405 |
|
|
$ |
3,641 |
|
|
$ |
3,130 |
|
|
$ |
12,861 |
|
|
Basic earnings per share of common
stock(a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$ |
0.09 |
|
|
$ |
0.12 |
|
|
$ |
0.14 |
|
|
$ |
0.11 |
|
|
$ |
0.46 |
|
|
|
Net income available to common
stockholders
|
|
$ |
0.10 |
|
|
$ |
0.12 |
|
|
$ |
0.13 |
|
|
$ |
0.11 |
|
|
$ |
0.46 |
|
|
Diluted earnings per share of
common stock(a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$ |
0.09 |
|
|
$ |
0.11 |
|
|
$ |
0.12 |
|
|
$ |
0.10 |
|
|
$ |
0.42 |
|
|
|
Net income (loss) available to
common stockholders
|
|
$ |
0.09 |
|
|
$ |
0.11 |
|
|
$ |
0.12 |
|
|
$ |
0.10 |
|
|
$ |
0.42 |
|
|
Weighted average common shares
outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
28,094 |
|
|
|
28,094 |
|
|
|
28,094 |
|
|
|
28,094 |
|
|
|
28,094 |
|
|
|
Diluted
|
|
|
30,391 |
|
|
|
31,270 |
|
|
|
31,493 |
|
|
|
31,789 |
|
|
|
30,655 |
|
|
|
|
(a) |
|
The sum of individual quarterly net income per share may not
agree to the total for the year to due each periods
computation based on the weighted average number of common
shares outstanding during each period. |
F1-35
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
On January 31, 2006, Basic acquired all of the outstanding
capital stock of LeBus Oil Field Service Co. for an acquisition
price of $26 million, subject to adjustments. The
acquisition will operate in Basics fluid services line of
business in the Ark-La-Tex division.
On February 28, 2006, Basic acquired substantially all of
the operating assets of G&L Tool, Ltd. for total
consideration of $58 million cash. This acquisition will
operate in Basics drilling and completion line of
business. The purchase agreement also contained an earn-out
agreement based on annual EBITDA targets.
F1-36
BASIC ENERGY SERVICES, INC.
December 31, 2005, 2004, and 2003
Schedule II Valuation and Qualifying Accounts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions | |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
Balance at | |
|
Charged to | |
|
Charged to | |
|
|
|
Balance at | |
|
|
Beginning of | |
|
Costs and | |
|
Other | |
|
Deductions | |
|
End of | |
|
|
Period | |
|
Expenses(a) | |
|
Accounts(b) | |
|
(c) | |
|
Period | |
Description |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Year Ended December 31,
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Bad Debt
|
|
$ |
3,108 |
|
|
$ |
1,651 |
|
|
$ |
|
|
|
$ |
(1,984 |
) |
|
$ |
2,775 |
|
Year Ended December 31,
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Bad Debt
|
|
$ |
1,958 |
|
|
$ |
1,200 |
|
|
$ |
|
|
|
$ |
(50 |
) |
|
$ |
3,108 |
|
Year Ended December 31,
2003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Bad Debt
|
|
$ |
501 |
|
|
$ |
1,279 |
|
|
$ |
375 |
|
|
$ |
(197 |
) |
|
$ |
1,958 |
|
|
|
|
(a) |
|
Charges relate to provisions for doubtful accounts |
|
(b) |
|
Reflects the impact of acquisitions |
|
(c) |
|
Deductions relate to the write-off of accounts receivable deemed
uncollectible |
F1-37
Basic Energy Services, Inc.
Consolidated Balance Sheet
(In thousands, except share data)
|
|
|
|
|
|
|
|
|
March 31, | |
|
|
2006 | |
|
|
| |
|
|
(Unaudited) | |
ASSETS |
Current assets:
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
19,953 |
|
|
Trade accounts receivable, net of
allowance of $2,984
|
|
|
101,241 |
|
|
Accounts receivable
related parties
|
|
|
92 |
|
|
Inventories
|
|
|
1,851 |
|
|
Prepaid expenses
|
|
|
3,790 |
|
|
Other current assets
|
|
|
2,744 |
|
|
Deferred tax assets
|
|
|
6,700 |
|
|
|
|
|
|
|
Total current assets
|
|
|
136,371 |
|
|
|
|
|
Property and equipment, net
|
|
|
399,865 |
|
Deferred debt costs, net of
amortization
|
|
|
4,583 |
|
Goodwill
|
|
|
73,201 |
|
Other assets
|
|
|
2,767 |
|
|
|
|
|
|
|
$ |
616,787 |
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS EQUITY |
Current liabilities:
|
|
|
|
|
|
Accounts payable
|
|
$ |
11,376 |
|
|
Accrued expenses
|
|
|
39,711 |
|
|
Income taxes payable
|
|
|
13,124 |
|
|
Current portion of long-term debt
|
|
|
8,559 |
|
|
Other current liabilities
|
|
|
1,328 |
|
|
|
|
|
|
|
Total current liabilities
|
|
|
74,098 |
|
|
|
|
|
Long-term debt
|
|
|
201,488 |
|
Deferred income
|
|
|
11 |
|
Deferred tax liabilities
|
|
|
59,956 |
|
Other long-term liabilities
|
|
|
2,993 |
|
Commitments and contingencies
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
Common stock; $.01 par value;
80,000,000 shares authorized; 33,931,935 shares
issued; 33,787,305 shares outstanding
|
|
|
339 |
|
|
Additional paid-in capital
|
|
|
235,264 |
|
|
Deferred compensation
|
|
|
|
|
|
Retained earnings
|
|
|
46,174 |
|
|
Treasury stock,
144,630 shares, at cost
|
|
|
(3,618 |
) |
|
Accumulated other comprehensive
income
|
|
|
82 |
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
278,241 |
|
|
|
|
|
|
|
$ |
616,787 |
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F2-1
Basic Energy Services, Inc.
Consolidated Statements of Operations and Comprehensive
Income
(Dollars in thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months | |
|
|
Ended March 31, | |
|
|
| |
|
|
2006 | |
|
2005 | |
|
|
| |
|
| |
|
|
(Unaudited) | |
Revenues:
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
$ |
73,465 |
|
|
$ |
44,798 |
|
|
Fluid services
|
|
|
43,121 |
|
|
|
29,303 |
|
|
Drilling and completion services
|
|
|
27,455 |
|
|
|
10,764 |
|
|
Well site construction services
|
|
|
10,265 |
|
|
|
8,948 |
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
154,306 |
|
|
|
93,813 |
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
Well servicing
|
|
|
41,610 |
|
|
|
28,191 |
|
|
Fluid services
|
|
|
26,305 |
|
|
|
19,238 |
|
|
Drilling and completion services
|
|
|
13,854 |
|
|
|
5,860 |
|
|
Well site construction services
|
|
|
7,643 |
|
|
|
7,108 |
|
|
General and administrative,
including stock-based compensation of $758 and $591 in 2006 and
2005, respectively
|
|
|
18,005 |
|
|
|
13,091 |
|
|
Depreciation and amortization
|
|
|
12,837 |
|
|
|
8,047 |
|
|
(Gain) loss on disposal of assets
|
|
|
(200 |
) |
|
|
102 |
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
120,054 |
|
|
|
81,637 |
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
34,252 |
|
|
|
12,176 |
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(3,138 |
) |
|
|
(3,061 |
) |
|
Interest income
|
|
|
359 |
|
|
|
101 |
|
|
Other income
|
|
|
27 |
|
|
|
75 |
|
|
|
|
|
|
|
|
Income from continuing operations
before income taxes
|
|
|
31,500 |
|
|
|
9,291 |
|
Income tax expense
|
|
|
(11,819 |
) |
|
|
(3,490 |
) |
|
|
|
|
|
|
|
Net income
|
|
$ |
19,681 |
|
|
$ |
5,801 |
|
|
|
|
|
|
|
|
Earnings per share of common stock:
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
0.59 |
|
|
$ |
0.21 |
|
|
|
|
|
|
|
|
|
Diluted
|
|
$ |
0.53 |
|
|
$ |
0.18 |
|
|
|
|
|
|
|
|
Comprehensive Income:
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
19,681 |
|
|
$ |
5,801 |
|
|
Unrealized gains (loss) on hedging
activities
|
|
|
(154 |
) |
|
|
314 |
|
|
|
|
|
|
|
|
Comprehensive Income
|
|
$ |
19,527 |
|
|
$ |
6,115 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F2-2
Basic Energy Services, Inc.
Consolidated Statements of Stockholders Equity
(In thousands, except share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated | |
|
|
|
|
Common Stock | |
|
Additional | |
|
|
|
|
|
|
|
Other | |
|
Total | |
|
|
| |
|
Paid-In | |
|
Deferred | |
|
Treasury | |
|
Retained | |
|
Comprehensive | |
|
Stockholders | |
|
|
Shares | |
|
Amount | |
|
Capital | |
|
Compensation | |
|
Stock | |
|
Earnings | |
|
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 new accounting standard
|
|
|
|
|
|
|
|
|
|
|
(7,341 |
) |
|
|
7,341 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of deferred
compensation
|
|
|
|
|
|
|
|
|
|
|
758 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
758 |
|
Unrealized loss on interest rate
swap agreement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(154 |
) |
|
|
(154 |
) |
Offering costs
|
|
|
|
|
|
|
|
|
|
|
(161 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(161 |
) |
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,248 |
) |
|
|
|
|
|
|
|
|
|
|
(3,248 |
) |
Exercise of stock options
|
|
|
|
|
|
|
|
|
|
|
2,790 |
|
|
|
|
|
|
|
2,161 |
|
|
|
(2,161 |
) |
|
|
|
|
|
|
2,790 |
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,681 |
|
|
|
|
|
|
|
19,681 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance March 31,
2006 (Unaudited)
|
|
|
33,931,935 |
|
|
$ |
339 |
|
|
$ |
235,264 |
|
|
$ |
|
|
|
$ |
(3,618 |
) |
|
$ |
46,174 |
|
|
$ |
82 |
|
|
$ |
278,241 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F2-3
Basic Energy Services, Inc.
Consolidated Statements of Cash Flows
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended | |
|
|
March 31, | |
|
|
| |
|
|
2006 | |
|
2005 | |
|
|
| |
|
| |
|
|
(Unaudited) | |
Cash flows from operating
activities:
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
19,681 |
|
|
$ |
5,801 |
|
|
|
Adjustments to reconcile net income
to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
12,837 |
|
|
|
8,047 |
|
|
|
|
Accretion on asset retirement
obligation
|
|
|
19 |
|
|
|
9 |
|
|
|
|
Change in allowance for doubtful
accounts
|
|
|
209 |
|
|
|
450 |
|
|
|
|
Non-cash interest expense
|
|
|
310 |
|
|
|
263 |
|
|
|
|
Non-cash compensation
|
|
|
758 |
|
|
|
591 |
|
|
|
|
(Gain) loss on disposal of assets
|
|
|
(200 |
) |
|
|
102 |
|
|
|
|
Deferred income taxes
|
|
|
(2,873 |
) |
|
|
3,490 |
|
|
|
Changes in operating assets and
liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(10,708 |
) |
|
|
(2,763 |
) |
|
|
|
Inventories
|
|
|
(18 |
) |
|
|
(171 |
) |
|
|
|
Prepaid expenses and other current
assets
|
|
|
(1,442 |
) |
|
|
(317 |
) |
|
|
|
Other assets
|
|
|
(319 |
) |
|
|
(53 |
) |
|
|
|
Accounts payable
|
|
|
(3,169 |
) |
|
|
(1,344 |
) |
|
|
|
Excess tax benefits from exercise
of employee stock options
|
|
|
(2,790 |
) |
|
|
|
|
|
|
|
Income tax payable
|
|
|
7,449 |
|
|
|
|
|
|
|
|
Deferred income and other
liabilities
|
|
|
342 |
|
|
|
(122 |
) |
|
|
|
Accrued expenses
|
|
|
5,829 |
|
|
|
2,751 |
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
|
25,915 |
|
|
|
16,734 |
|
|
|
|
|
|
|
|
|
|
Cash flows from investing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of property and equipment
|
|
|
(24,812 |
) |
|
|
(16,083 |
) |
|
|
|
Proceeds from sale of assets
|
|
|
1,141 |
|
|
|
95 |
|
|
|
|
Payments for other long-term assets
|
|
|
(393 |
) |
|
|
(49 |
) |
|
|
|
Payments for businesses, net of
cash acquired
|
|
|
(87,520 |
) |
|
|
(3,909 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing
activities
|
|
|
(111,584 |
) |
|
|
(19,946 |
) |
|
|
|
|
|
|
|
|
|
Cash flows from financing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from debt
|
|
|
80,000 |
|
|
|
129 |
|
|
|
|
Payments of debt
|
|
|
(6,544 |
) |
|
|
(2,938 |
) |
|
|
|
Offering costs related to initial
public offering
|
|
|
(161 |
) |
|
|
|
|
|
|
|
Purchase of treasury stock
|
|
|
(1,258 |
) |
|
|
|
|
|
|
|
Excess tax benefits from exercise
of employee stock options
|
|
|
2,790 |
|
|
|
|
|
|
|
|
Exercise of employee stock options
|
|
|
(1,990 |
) |
|
|
|
|
|
|
|
Deferred loan costs and other
financing activities
|
|
|
(60 |
) |
|
|
(8 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in)
financing activities
|
|
|
72,777 |
|
|
|
(2,817 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and
equivalents
|
|
|
(12,892 |
) |
|
|
(6,029 |
) |
|
|
Cash and cash
equivalents beginning of period
|
|
|
32,845 |
|
|
|
20,147 |
|
|
|
|
|
|
|
|
|
|
Cash and cash
equivalents end of period
|
|
$ |
19,953 |
|
|
$ |
14,118 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F2-4
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
March 31, 2006
|
|
1. |
Basis of Presentation and Nature of Operations |
Basis of Presentation
The accompanying unaudited consolidated financial statements of
Basic Energy Services, Inc. and subsidiaries (Basic
or the Company) have been prepared in accordance
with accounting principles generally accepted in the United
States for interim financial reporting. Accordingly, they do not
include all of the information and footnotes required by
accounting principles generally accepted in the United States
for complete financial statements. In the opinion of management,
all adjustments considered necessary for a fair presentation
have been made in the accompanying unaudited financial
statements.
Nature of Operations
Basic provides a range of well site services to oil and gas
drilling and producing companies, including well servicing,
fluid services, drilling and completion services and well site
construction services. These services are primarily provided by
Basics fleet of equipment. Basics operations are
concentrated in the major United States onshore oil and gas
producing regions in Texas, New Mexico, Oklahoma and Louisiana,
and the Rocky Mountain states.
|
|
2. |
Summary of Significant Accounting Policies |
Principles of Consolidation
|
|
|
The accompanying consolidated financial statements include the
accounts of Basic and its wholly-owned subsidiaries. Basic has
no interest in any other organization, entity, partnership, or
contract that could require any evaluation under FASB
Interpretation No. 46R or Accounting Research
Bulletin No. 51. All inter-company transactions and
balances have been eliminated. |
Revenue Recognition
Well Servicing Well servicing consists
primarily of maintenance services, workover services, completion
services and plugging and abandonment services. Basic recognizes
revenue when services are performed, collection of the relevant
receivables is probable, persuasive evidence of an arrangement
exists and the price is fixed or determinable. Basic prices well
servicing by the hour of service performed.
Fluid Services Fluid services consists
primarily of the sale, transportation, storage and disposal of
fluids used in drilling, production and maintenance of oil and
natural gas wells. Basic recognizes revenue when services are
performed, collection of the relevant receivables is probable,
persuasive evidence of an arrangement exists and the price is
fixed or determinable. Basic prices fluid services by the job,
by the hour or by the quantities sold, disposed of or hauled.
Drilling and Completion Services Basic
recognizes revenue when services are performed, collection of
the relevant receivables is probable, persuasive evidence of an
arrangement exists and the price is fixed or determinable. Basic
prices drilling and completion services by the hour, day, or
project depending on the type of service performed. When Basic
provides multiple services to a customer, revenue is allocated
to the services performed based on the fair values of the
services.
Well Site Construction Services Basic
recognizes revenue when services are performed, collection of
the relevant receivables is probable, persuasive evidence of an
arrangement exists
F2-5
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
and the price is fixed or determinable. Basic prices well site
construction services by the hour, day, or project depending on
the type of service performed.
Impairments
In accordance with Statement of Financial Accounting Standards
No. 144,Accounting for the Impairment or Disposal of
Long-Lived Assets (SFAS No. 144),
long-lived assets, such as property, plant, and equipment, and
purchased intangibles subject to amortization, are reviewed for
impairment at a minimum annually, or whenever, in
managements judgment events or changes in circumstances
indicate that the carrying amount of such assets may not be
recoverable. Recoverability of assets to be held and used is
measured by a comparison of the carrying amount of such assets
to estimated undiscounted future cash flows expected to be
generated by the assets. Expected future cash flows and carrying
values are aggregated at their lowest identifiable level. If the
carrying amount of such assets exceeds its estimated future cash
flows, an impairment charge is recognized by the amount by which
the carrying amount of such assets exceeds the fair value of the
assets. Assets to be disposed of would be separately presented
in the consolidated balance sheet and reported at the lower of
the carrying amount or fair value less costs to sell, and are no
longer depreciated. The assets and liabilities, if material, of
a disposed group classified as held for sale would be presented
separately in the appropriate asset and liability sections of
the consolidated balance sheet.
Goodwill and intangible assets not subject to amortization are
tested annually for impairment, and are tested for impairment
more frequently if events and circumstances indicate that the
asset might be impaired. An impairment loss is recognized to the
extent that the carrying amount exceeds the assets fair
value.
Basic had no impairment expense in the three months ended
March 31, 2006 and 2005, respectively.
Deferred Debt Costs
Basic capitalizes certain costs in connection with obtaining its
borrowings, such as lenders fees and related
attorneys fees. These costs are being amortized to
interest expense using the straight line method, which
approximates the effective interest method over the terms of the
related debt.
Deferred debt costs of approximately $7.1 million at
March 31, 2006 and $7.0 million at December 31,
2005, respectively, represent debt issuance costs and are
recorded net of accumulated amortization of $2.5 million,
and $2.2 million at March 31, 2006 and
December 31, 2005, respectively. Amortization of deferred
debt costs totaled approximately $311,000 and $263,000 for the
three months ended March 31, 2006 and 2005, respectively.
Goodwill
Statement of Financial Accounting Standards No. 142,
Goodwill and Other Intangible Assets
(SFAS No. 142) eliminates the
amortization of goodwill and other intangible assets with
indefinite lives. Intangible assets with lives restricted by
contractual, legal, or other means will continue to be amortized
over their useful lives. Goodwill and other intangible assets
not subject to amortization are tested for impairment annually
or more frequently if events or changes in circumstances
indicate that the asset might be impaired.
SFAS No. 142 requires a two-step process for testing
impairment. First, the fair value of each reporting unit is
compared to its carrying value to determine whether an
indication of impairment exists. If impairment is indicated,
F2-6
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
then the fair value of the reporting units goodwill is
determined by allocating the units fair value to its
assets and liabilities (including any unrecognized intangible
assets) as if the reporting unit had been acquired in a business
combination. The amount of impairment for goodwill is measured
as the excess of its carrying value over its fair value. Basic
completed its assessment of goodwill impairment as of the date
of adoption and completed a subsequent annual impairment
assessment as of December 31 each year thereafter. The
assessments did not result in any indications of goodwill
impairment.
Basic has identified its reporting units to be well servicing,
fluid services, drilling and completion services and well site
construction services. The goodwill allocated to such reporting
units as of March 31, 2006 is $9.9 million,
$30.7 million, $28.9 million and $3.7 million,
respectively. The change in the carrying amount of goodwill for
the three months ended March 31, 2006 of $25.0 million
relates to goodwill from acquisitions and payments pursuant to
contingent earn-out agreements, with approximately
$10.1 million and $14.9 million of goodwill additions
relating to the fluid services and drilling and completion
units, respectively.
Stock-Based Compensation
On January 1, 2006, Basic adopted Statement of Financial
Accounting Standards No. 123 (revised 2004)
Share-Based Payment
(SFAS No. 123R). Prior to January 1,
2006, the Company accounted for share-based payments under the
recognition and measurement provisions of Accounting Principles
Board Opinion No. 25, Accounting for Stock issued
to Employees (APB No. 25) which was
permitted by Statement of Financial Accounting Standards
No. 123, Accounting for Stock-Based
Compensation (SFAS No. 123).
Basic adopted FAS No. 123R using both the modified
prospective method and the prospective method as applicable to
the specific awards granted. The modified prospective method was
applied to awards granted subsequent to the Company becoming a
public company. Awards granted prior to the Company becoming
public and which were accounted for under APB No. 25 were
adopted by using the prospective method. The results of prior
periods have not been restated. Compensation expense cost of the
unvested portion of awards granted as a private company and
outstanding as of January 1, 2006 will continue to be based
upon the intrinsic value method calculated under APB No. 25.
Under SFAS No. 123R, entities using the minimum value
method and the prospective application are not permitted to
provide the pro forma disclosures (as was required under
Statement of Financial Accounting Standard
No. 123,Accounting for Stock-Based
Compensation (SFAS No. 123))
subsequent to adoption of SFAS 123R since they do not have
the fair value information required by SFAS No. 123R.
Therefore, in accordance with 123R, Basic will no longer include
pro forma disclosures that were required by SFAS 123.
Asset Retirement Obligations
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
F2-7
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
closure. The following table reflects the changes in the
liability during the three months ended March 31, 2006 (in
thousands):
|
|
|
|
|
Balance, December 31, 2005
|
|
$ |
569 |
|
Additional asset retirement
obligations recognized through acquisitions
|
|
|
118 |
|
Accretion Expense
|
|
|
19 |
|
Increase in asset retirement
obligations due to change in estimate
|
|
|
295 |
|
|
|
|
|
Balance, March 31, 2006
(unaudited)
|
|
$ |
1,001 |
|
|
|
|
|
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 6).
Recent Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board
issued SFAS No. 123R. As discussed under this
Note 2, Stock-Based Compensation, Basic adopted
the provisions of SFAS No. 123R on January 1,
2006.
F2-8
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
In 2006 and 2005, 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) | |
|
|
| |
|
| |
R & R Hot Oil Service
|
|
|
January 5, 2005 |
|
|
$ |
1,702 |
|
Premier Vacuum Service,
Inc.
|
|
|
January 28, 2005 |
|
|
|
1,009 |
|
Spencers Coating Specialist
|
|
|
February 9, 2005 |
|
|
|
619 |
|
Marks Well Service
|
|
|
February 25, 2005 |
|
|
|
579 |
|
Max-Line, Inc.
|
|
|
April 28, 2005 |
|
|
|
1,498 |
|
MD Well Service, Inc.
|
|
|
May 17, 2005 |
|
|
|
4,478 |
|
179 Disposal, Inc.
|
|
|
August 4, 2005 |
|
|
|
1,729 |
|
Oilwell Fracturing Services,
Inc.
|
|
|
October 11, 2005 |
|
|
|
13,764 |
|
|
|
|
|
|
|
|
Total 2005
|
|
|
|
|
|
$ |
25,378 |
|
|
|
|
|
|
|
|
LeBus Oil Field Services
Co.
|
|
|
January 31, 2006 |
|
|
$ |
24,508 |
|
G&L Tool, Ltd.
|
|
|
February 28, 2006 |
|
|
|
58,000 |
|
Arkla Cementing, Inc.
|
|
|
March 27, 2006 |
|
|
|
5,012 |
|
|
|
|
|
|
|
|
Total 2006
|
|
|
|
|
|
$ |
87,520 |
|
|
|
|
|
|
|
|
Contingent Earn-out Arrangements and Final Purchase Price
Allocations
Contingent earn-out arrangements are generally arrangements
entered in certain acquisitions to encourage the owner/manager
to continue operating and building the business after the
purchase transaction. The contingent earn-out arrangements of
the related acquisitions are generally linked to certain
financial measures and performance of the assets acquired in the
various acquisitions. All amounts paid or reasonably accrued for
related to the contingent earn-out payments are reflected as
increases to the goodwill associated with the acquisition.
On February 28, 2006, Basic acquired substantially all of
the assets of G&L Tool for $58.0 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 earned by Basic 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 fishing and rental tool
market operations. The cost of the G&L acquisition was
allocated $43.3 million to property and equipment,
$14.6 million to goodwill, and $51,000 to non-compete
agreements. The allocations of the purchase price are based upon
preliminary estimates and assumptions. Accordingly, the
allocations are subject to revision when the Company receives
final information, including appraisals and other analyses.
Revisions to the fair values, which may be significant, will be
recorded by the Company as further adjustments to the purchase
price allocations.
F2-9
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
The following unaudited pro-forma results of operations have
been prepared as though the G&L Tool acquisition had
been completed on January 1, 2005. Pro forma amounts are
based on the preliminary 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).
|
|
|
|
|
|
|
|
|
|
|
Three Months | |
|
|
Ended March 31, | |
|
|
| |
|
|
2006 | |
|
2005 | |
|
|
| |
|
| |
|
|
(Unaudited) | |
Revenues
|
|
$ |
163,799 |
|
|
$ |
101,482 |
|
Net income
|
|
$ |
22,145 |
|
|
$ |
7,296 |
|
Earnings per common
share basic
|
|
$ |
0.67 |
|
|
$ |
0.26 |
|
Earnings per common
share diluted
|
|
$ |
0.60 |
|
|
$ |
0.23 |
|
Basic does not believe the pro-forma effect of the remainder of
the acquisitions completed in 2005 or 2006 is material, either
individually or when aggregated, to the reported results of
operations.
|
|
4. |
Property and Equipment |
Property and equipment consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31, | |
|
December 31, | |
|
|
2006 | |
|
2005 | |
|
|
| |
|
| |
|
|
(Unaudited) | |
|
|
Land
|
|
$ |
2,108 |
|
|
$ |
1,902 |
|
Buildings and improvements
|
|
|
10,418 |
|
|
|
8,634 |
|
Well service units and equipment
|
|
|
217,086 |
|
|
|
199,070 |
|
Fluid services equipment
|
|
|
72,797 |
|
|
|
59,104 |
|
Brine and fresh water stations
|
|
|
7,773 |
|
|
|
7,746 |
|
Frac/test tanks
|
|
|
43,425 |
|
|
|
31,475 |
|
Pressure pumping equipment
|
|
|
38,479 |
|
|
|
31,101 |
|
Construction equipment
|
|
|
25,013 |
|
|
|
24,224 |
|
Disposal facilities
|
|
|
21,685 |
|
|
|
16,828 |
|
Vehicles
|
|
|
25,382 |
|
|
|
23,329 |
|
Rental equipment
|
|
|
47,906 |
|
|
|
6,519 |
|
Aircraft
|
|
|
3,236 |
|
|
|
3,236 |
|
Other
|
|
|
8,473 |
|
|
|
8,602 |
|
|
|
|
|
|
|
|
|
|
|
523,781 |
|
|
|
421,770 |
|
Less accumulated depreciation and
amortization
|
|
|
123,916 |
|
|
|
112,695 |
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
$ |
399,865 |
|
|
$ |
309,075 |
|
|
|
|
|
|
|
|
F2-10
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
Basic is obligated under various capital leases for certain
vehicles and equipment that expire at various dates during the
next five years. The gross amount of property and equipment and
related accumulated amortization recorded under capital leases
and included above consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31, | |
|
December 31, | |
|
|
2006 | |
|
2005 | |
|
|
| |
|
| |
|
|
(Unaudited) | |
|
|
Light vehicles
|
|
$ |
19,564 |
|
|
$ |
17,912 |
|
Fluid services equipment
|
|
|
14,662 |
|
|
|
14,011 |
|
Construction equipment
|
|
|
3,156 |
|
|
|
1,300 |
|
|
|
|
|
|
|
|
|
|
|
37,382 |
|
|
|
33,223 |
|
Less accumulated amortization
|
|
|
9,535 |
|
|
|
8,474 |
|
|
|
|
|
|
|
|
|
|
$ |
27,847 |
|
|
$ |
24,749 |
|
|
|
|
|
|
|
|
Amortization of assets held under capital leases of
approximately $1,060,000 and $253,000 for the three months ended
March 31, 2006 and 2005, respectively, is included in
depreciation and amortization expense in the consolidated
statements of operations.
Long-term debt consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
March 31, | |
|
December 31, | |
|
|
2006 | |
|
2005 | |
|
|
| |
|
| |
|
|
(Unaudited) | |
|
|
Credit Facilities:
|
|
|
|
|
|
|
|
|
|
Term B Loan
|
|
$ |
89,750 |
|
|
$ |
90,000 |
|
|
Revolver
|
|
|
96,000 |
|
|
|
16,000 |
|
Capital leases and other notes
|
|
|
24,297 |
|
|
|
20,887 |
|
|
|
|
|
|
|
|
|
|
|
210,047 |
|
|
|
126,887 |
|
Less current portion
|
|
|
8,559 |
|
|
|
7,646 |
|
|
|
|
|
|
|
|
|
|
$ |
201,488 |
|
|
$ |
119,241 |
|
|
|
|
|
|
|
|
2005 Credit Facility
|
|
|
On December 15, 2005, Basic entered into a
$240 million Third Amended and Restated Credit Agreement
with a syndicate of lenders (2005 Credit Facility),
which refinanced all of its then existing credit facilities. The
2005 Credit Facility, as amended effective March 28, 2006,
provides for a $90 million Term B Loan (2005 Term B
Loan) and a $150 million revolving line of credit
(Revolver). The commitment under the Revolver allows
for (a) the borrowing of funds (b) issuance of up to
$30 million of letters of credit and
(c) $2.5 million of swing-line loans (next day
borrowing). The amounts outstanding under the 2005 Term B Loan
require quarterly amortization at various amounts during each
quarter with all amounts outstanding on December 15, 2011
being due and payable in full. All the outstanding amounts under
the Revolver are due and payable on December 15, 2010. The
2005 Credit Facility is secured by substantially all of
Basics tangible and intangible assets. Basic incurred
approximately $1.8 million in debt issuance costs in
obtaining the 2005 Credit Facility. |
F2-11
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
At Basics option, borrowings under the 2005 Term B
Loan bear interest at either the (a) Alternative Base
Rate (i.e. the higher of the banks prime rate
or the federal funds rate plus .5% per annum) plus 1% or
(b) the LIBOR rate plus 2.0%. At March 31, 2006 and
December 31, 2005, Basics weighted average interest
rate on its Term B Loan was 7.1% and 6.4%.
At Basics option, borrowings under the 2005 Revolver bear
interest at either the (a) Alternative Base
Rate (i.e. the higher of the banks prime rate or the
federal funds rate plus .5% per annum) plus a margin
ranging from .50% to 1.25% or (b) the LIBOR rate plus a
margin ranging from 1.5% to 2.25%. The margins vary depending on
Basics leverage ratio. At March 31, 2006,
Basics margin on Alternative Base Rates and LIBOR tranches
was .75% and 1.75%, respectively. Fees on the letters of credit
are due quarterly on the outstanding amount of the letters of
credit at a rate ranging from 1.5% to 2.25% for participation
fees and .125% for fronting fees. A commitment fee is due
quarterly on the available borrowings under the Revolver at
rates ranging from .375% to .5%.
At March 31, 2006 Basic, under its Revolver, had
outstanding $96 million of borrowings and $9.6 million
of letters of credit and no amounts outstanding in swing-line
loans. At March 31, 2006 and December 31, 2005 Basic
had availability under its Revolver of $44.4 million and
$124.4 million, respectively.
Pursuant to the 2005 Credit Facility, Basic must apply proceeds
to reduce principal outstanding under the 2005 Term B
Revolver from (a) individual assets sales greater than
$2 million or $7.5 million in the aggregate on an
annual basis, and (b) 50% of the proceeds from any equity
offering. The 2005 Credit Facility required Basic to enter into
an interest rate hedge, through May 28, 2006 on at least
$65 million of Basics then outstanding indebtedness.
The March 28, 2006 amendment deletes this requirement upon
payoff of the Term B Loans. Paydowns on the 2005 Term
B Loan may not be reborrowed.
The 2005 Credit Facility contains various restrictive covenants
and compliance requirements, which include (a) limiting of
the incurrence of additional indebtedness, (b) restrictions
on mergers, sales or transfers of assets without the
lenders consent, (c) limitation on dividends and
distributions and (d) various financial covenants,
including (1) a maximum leverage ratio of
3.5 to 1.0 reducing over time to 3.25 to 1.0,
(2) a minimum interest coverage ratio of
3.0 to 1.0 and (e) limitations on capital
expenditures in any period of four consecutive quarters in
excess of 20% of Consolidated Net Worth unless certain criteria
are met. At March 31, 2006 and December 31, 2005,
Basic was in compliance with its covenants.
F2-12
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
Other Debt
|
|
|
Basic has a variety of other capital leases and notes payable
outstanding that are generally customary in its business. None
of these debt instruments are material individually or in the
aggregate. Basics interest expense consisted of the
following (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
Three Months | |
|
|
Ended March 31, | |
|
|
| |
|
|
2006 | |
|
2005 | |
|
|
| |
|
| |
|
|
(Unaudited) | |
Cash payments for interest
|
|
$ |
1,942 |
|
|
$ |
2,723 |
|
Commitment and other fees paid
|
|
|
148 |
|
|
|
|
|
Amortization of debt issuance costs
|
|
|
311 |
|
|
|
263 |
|
Other
|
|
|
737 |
|
|
|
75 |
|
|
|
|
|
|
|
|
|
|
$ |
3,138 |
|
|
$ |
3,061 |
|
|
|
|
|
|
|
|
|
|
6. |
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. |
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 |
F2-13
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
|
compensation and medical and dental coverage of $150,000 and
$125,000, respectively. Basic has lower deductibles per
occurrence for automobile liability and general liability. Basic
maintains accruals in the accompanying consolidated balance
sheets related to self-insurance retentions by using third-party
data and historical claims history. |
At March 31, 2006 and December 31, 2005, self-insured
risk accruals, net of related recoveries/receivables totaled
approximately $11.4 million and $9.5 million,
respectively.
Common Stock
|
|
|
In February 2002, a group of related investors purchased a total
of 3,000,000 shares of Basics common stock at a
purchase price of $4 per share, for a total purchase price
of $12 million. As part of the purchase, 600,000 common
stock warrants were issued in connection with this transaction,
the fair value of which was approximately $1.2 million
(calculated using an option valuation model). The warrants allow
the holder to purchase 600,000 shares of Basics
common stock at $4 per share. The warrants are exercisable
in whole or in part after June 30, 2002 and prior to
February 13, 2007. |
In February 2004, Basic granted certain officers and directors
837,500 restricted shares of common stock. The shares vest
25% per year for four years from the award date and are
subject to other vesting and forfeiture provisions. The
estimated fair value of the restricted shares was
$5.8 million at the date of the grant and was recorded as
deferred compensation, a component of stockholders equity.
This amount is being charged to expense over the respective
vesting period and totaled approximately $379,000 and $409,000
for the three months ended March 31, 2006 and 2005,
respectively.
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.
In March 2006, Basic issued 148,720 shares of common stock
from treasury stock for the exercise of stock options.
In May 2003, Basics board of directors and stockholders
approved the Basic 2003 Incentive Plan (as amended effective
April 22, 2005), (the Plan) which provides for
granting of incentive awards in the form of stock options,
restricted stock, performance awards, bonus shares, phantom
shares, cash awards and other stock-based awards to officers,
employees, directors and consultants of Basic. The Plan assumed
awards of the plans of Basics successors that were awarded
and remained outstanding prior to adoption of the Plan. The Plan
provides for the issuance of 5,000,000 shares. The Plan is
administered by the Plan committee, and in the absence of a Plan
committee, by the Board of Directors, which determines the
awards, and the associated terms of the awards and interprets
its provisions and adopts policies for implementing the Plan.
The number of shares authorized under the Plan and the number of
shares subject to an award under the Plan will be adjusted for
stock splits, stock dividends, recapitalizations, mergers and
other changes affecting the capital stock of Basic.
On March 15, 2006, the board of directors granted various
employees options to purchase 418,000 shares,
respectively, of common stock of Basic at exercise prices of
$26.84 per share, respectively. All of the 418,000 options
granted in 2006 vest over a five-year
F2-14
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
period and expire 10 years from the date they were granted.
Option awards are generally granted with an exercise price equal
to the market price of the Companys stock at the date of
grant.
The fair value of each option award is estimated on the date of
grant using the Black-Scholes-Merton option-pricing model that
uses the subjective assumptions noted in the following table.
Since the Company has only been public since December 2005,
expected volatilities are based upon a peer group. When the
Company has sufficient historical data to calculate expected
volatility, the Company will use its own historical data
to calculate expected volatility. The expected term of options
granted represents the period of time that options granted are
expected to be outstanding. The risk-free rate for periods
within the contractual life of the options is based on the
U.S. Treasury yield curve in effect at the time of grant.
The estimates involve inherent uncertainties and the application
of management judgment. In addition, we are required to estimate
the expected forfeiture rate and only recognize expense for
those options expected to vest. Compensation expense related to
share-based arrangements was approximately $758,000 and $591,000
during the three months ended March 31, 2006 and 2005,
respectively.
The fair value of each option award accounted for under
FAS 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:
|
|
|
|
|
|
|
Three Months | |
|
|
Ended March 31, | |
|
|
2006 | |
|
|
| |
Risk-free interest rate
|
|
|
4.7 |
% |
Expected term
|
|
|
6.65 |
|
Expected volatility
|
|
|
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 for the three months ended March 31, 2006 and
the changes during the three months then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted | |
|
Aggregate | |
|
|
Number of | |
|
Average | |
|
Intrinsic | |
|
|
Options | |
|
Exercise | |
|
Value | |
|
|
Granted | |
|
Price | |
|
(000s) | |
|
|
| |
|
| |
|
| |
Non-statutory stock options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding beginning of period
|
|
|
2,445,800 |
|
|
$ |
5.44 |
|
|
|
|
|
|
Options granted
|
|
|
418,000 |
|
|
$ |
26.84 |
|
|
|
|
|
|
Options forfeited
|
|
|
(10,000 |
) |
|
$ |
6.98 |
|
|
|
|
|
|
Options exercised
|
|
|
(148,720 |
) |
|
$ |
4.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period
|
|
|
2,705,080 |
|
|
$ |
8.82 |
|
|
$ |
52,866 |
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, end of period
|
|
|
1,277,913 |
|
|
$ |
4.16 |
|
|
$ |
32,769 |
|
|
|
|
|
|
|
|
|
|
|
|
Expected to vest, end of period
|
|
|
1,391,469 |
|
|
$ |
12.64 |
|
|
$ |
23,883 |
|
|
|
|
|
|
|
|
|
|
|
F2-15
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
The following table summarizes information about Basics
stock options outstanding and options exercisable at
March 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding | |
|
Options Exercisable | |
|
|
| |
|
| |
|
|
Number of | |
|
|
|
Number of | |
|
|
|
|
Options | |
|
Weighted | |
|
Weighted | |
|
Options | |
|
Weighted | |
|
Weighted | |
|
|
Outstanding at | |
|
Average | |
|
Average | |
|
Outstanding at | |
|
Average | |
|
Average | |
Range of |
|
March 31, | |
|
Remaining | |
|
Exercise | |
|
March 31, | |
|
Remaining | |
|
Exercise | |
Exercise Prices |
|
2006 | |
|
Contractual Life | |
|
Price | |
|
2006 | |
|
Contractual Life | |
|
Price | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
$ 4.00
|
|
|
1,104,580 |
|
|
|
6.20 |
|
|
$ |
4.00 |
|
|
|
1,104,580 |
|
|
|
6.20 |
|
|
$ |
4.00 |
|
$ 5.16
|
|
|
310,000 |
|
|
|
8.23 |
|
|
$ |
5.16 |
|
|
|
173,333 |
|
|
|
8.12 |
|
|
$ |
5.16 |
|
$ 6.98
|
|
|
835,000 |
|
|
|
8.92 |
|
|
$ |
6.98 |
|
|
|
|
|
|
|
|
|
|
$ |
|
|
$21.01
|
|
|
37,500 |
|
|
|
9.71 |
|
|
$ |
21.01 |
|
|
|
|
|
|
|
|
|
|
$ |
|
|
$26.84
|
|
|
418,000 |
|
|
|
9.96 |
|
|
$ |
26.84 |
|
|
|
|
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,705,080 |
|
|
|
|
|
|
|
|
|
|
|
1,277,913 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted-average grant date fair value of share options
granted during the three months ended March 31, 2006 and
2005 was $14.47 and $8.10, respectively. The total intrinsic
value of share options exercised during the three months ended
March 31, 2006 and 2005 was approximately $3.4 million
and $0, respectively.
A summary of the status of the Companys non-vested share
grants at March 31, 2006 and changes during the three
months ended March 31, 2006 is presented in the following
table:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average | |
|
|
Number of | |
|
Grant Date Fair | |
Nonvested Shares |
|
Shares | |
|
Value Per Share | |
|
|
| |
|
| |
Nonvested at beginning of period
|
|
|
591,875 |
|
|
$ |
6.98 |
|
Granted during period
|
|
|
|
|
|
|
|
|
Vested during period
|
|
|
(230,625 |
) |
|
|
6.98 |
|
Forfeited during period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested at end of period
|
|
|
361,250 |
|
|
$ |
6.98 |
|
|
|
|
|
|
|
|
As of March 31, 2006, there was $12.2 million of total
unrecognized compensation related to non-vested share-based
compensation arrangements granted under the Plan. That cost is
expected to be recognized over a weighted-average period of
3.78 years. The total fair value of shares vested during
the three months ended March 31, 2006 and 2005 was
approximately $15.4 million and $6.2 million,
respectively.
Cash received from share option exercises under the incentive
plan was $0 for the three months ended March 31, 2006 and
2005, respectively. The actual tax benefit realized for the tax
deductions from option exercise is $2.8 million and $0,
respectively, for the three months ended March 31, 2006 and
2005.
|
|
9. |
Related Party Transactions |
Basic had receivables from employees of approximately $92,000
and $65,000 as of March 31, 2006 and December 31,
2005, respectively.
F2-16
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:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended | |
|
|
March 31, | |
|
|
| |
|
|
2006 | |
|
2005 | |
|
|
| |
|
| |
|
|
(Unaudited) | |
Numerator (both basic and
diluted):
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
19,681 |
|
|
$ |
5,801 |
|
Denominator:
|
|
|
|
|
|
|
|
|
|
Denominator for basic earnings per
share
|
|
|
33,261,539 |
|
|
|
28,186,147 |
|
|
Stock options
|
|
|
1,093,089 |
|
|
|
571,182 |
|
|
Unvested restricted stock
|
|
|
256,238 |
|
|
|
603,125 |
|
|
Common stock warrants
|
|
|
2,291,362 |
|
|
|
2,796,706 |
|
|
|
|
|
|
|
|
|
Denominator for diluted earnings
per share
|
|
|
36,902,228 |
|
|
|
32,157,160 |
|
|
|
|
|
|
|
|
|
Basic earnings per common share
|
|
$ |
.59 |
|
|
$ |
.21 |
|
|
|
|
|
|
|
|
|
Diluted earnings per common share
|
|
$ |
.53 |
|
|
$ |
.18 |
|
|
|
|
|
|
|
|
|
|
11. |
Business Segment Information |
Basics reportable business segments are well servicing,
fluid services, drilling and completion services and well site
construction services. The following is a description of the
segments:
Well Servicing: This business segment encompasses
a full range of services performed with a mobile well servicing
rig, including the installation and removal of downhole
equipment and elimination of obstructions in the well bore to
facilitate the flow of oil and gas. These services are performed
to establish, maintain and improve production throughout the
productive life of an oil and gas well and to plug and abandon a
well at the end of its productive life. Basic well servicing
equipment and capabilities are essential to facilitate most
other services performed on a well.
Fluid Services: This segment utilizes a fleet of
trucks and related assets, including specialized tank trucks,
storage tanks, water wells, disposal facilities and related
equipment. Basic employs these assets to provide, transport,
store and dispose of a variety of fluids. These services are
required in most workover, drilling and completion projects as
well as part of daily producing well operations.
Drilling and Completion Services: This segment
focuses on a variety of services designed to stimulate oil and
gas production or to enable cement slurry to be placed in or
circulated within a well. These services are carried out in
niche markets for jobs requiring a single truck and lower
horsepower.
F2-17
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
Well Site Construction Services: This segment
utilizes a fleet of power units, dozers, trenchers, motor
graders, backhoes and other heavy equipment. Basic employs these
assets to provide services for the construction and maintenance
of oil and gas production infrastructure, such as preparing and
maintaining access roads and well locations, installation of
small diameter gathering lines and pipelines and construction of
temporary foundations to support drilling rigs.
Basics management evaluates the performance of its
operating segments based on operating revenues and segment
profits. Corporate expenses include general corporate expenses
associated with managing all reportable operating segments.
Corporate assets consist principally of working capital and debt
financing costs. The following table sets forth certain
financial information with respect to Basics reportable
segments (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and | |
|
Well Site | |
|
|
|
|
|
|
Well | |
|
Fluid | |
|
Completion | |
|
Construction | |
|
Corporate | |
|
|
|
|
Servicing | |
|
Services | |
|
Services | |
|
Services | |
|
and Other | |
|
Total | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Three Months Ended
March 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$ |
73,465 |
|
|
$ |
43,121 |
|
|
$ |
27,455 |
|
|
$ |
10,265 |
|
|
$ |
|
|
|
$ |
154,306 |
|
Direct operating costs
|
|
|
(41,610 |
) |
|
|
(26,305 |
) |
|
|
(13,854 |
) |
|
|
(7,643 |
) |
|
|
|
|
|
|
(89,412 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profits
|
|
$ |
31,855 |
|
|
$ |
16,816 |
|
|
$ |
13,601 |
|
|
$ |
2,622 |
|
|
$ |
|
|
|
$ |
64,894 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$ |
5,694 |
|
|
$ |
3,520 |
|
|
$ |
2,321 |
|
|
$ |
830 |
|
|
$ |
472 |
|
|
$ |
12,837 |
|
Capital expenditures, (excluding
acquisitions)
|
|
$ |
11,005 |
|
|
$ |
6,804 |
|
|
$ |
4,485 |
|
|
$ |
1,604 |
|
|
$ |
914 |
|
|
$ |
24,812 |
|
Identifiable assets
|
|
$ |
185,390 |
|
|
$ |
138,969 |
|
|
$ |
106,264 |
|
|
$ |
29,747 |
|
|
$ |
156,417 |
|
|
$ |
616,787 |
|
Three Months Ended
March 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$ |
44,798 |
|
|
$ |
29,303 |
|
|
$ |
10,764 |
|
|
$ |
8,948 |
|
|
$ |
|
|
|
$ |
93,813 |
|
Direct operating costs
|
|
|
(28,191 |
) |
|
|
(19,238 |
) |
|
|
(5,860 |
) |
|
|
(7,108 |
) |
|
|
|
|
|
|
(60,397 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profits
|
|
$ |
16,607 |
|
|
$ |
10,065 |
|
|
$ |
4,904 |
|
|
$ |
1,840 |
|
|
$ |
|
|
|
$ |
33,416 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$ |
4,094 |
|
|
$ |
2,332 |
|
|
$ |
531 |
|
|
$ |
653 |
|
|
$ |
437 |
|
|
$ |
8,047 |
|
Capital expenditures, (excluding
acquisitions)
|
|
$ |
8,182 |
|
|
$ |
4,660 |
|
|
$ |
1,061 |
|
|
$ |
1,306 |
|
|
$ |
874 |
|
|
$ |
16,083 |
|
Identifiable assets
|
|
$ |
134,569 |
|
|
$ |
90,003 |
|
|
$ |
25,400 |
|
|
$ |
24,213 |
|
|
$ |
104,283 |
|
|
$ |
378,468 |
|
The following table reconciles the segment profits reported
above to the operating income as reported in the consolidated
statements of operations (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months | |
|
|
Ended March 31, | |
|
|
| |
|
|
2006 | |
|
2005 | |
|
|
| |
|
| |
Segment profits
|
|
$ |
64,894 |
|
|
$ |
33,416 |
|
General and administrative expenses
|
|
|
(18,005 |
) |
|
|
(13,091 |
) |
Depreciation and amortization
|
|
|
(12,837 |
) |
|
|
(8,047 |
) |
Gain (loss) on disposal of assets
|
|
|
200 |
|
|
|
(102 |
) |
|
|
|
|
|
|
|
Operating income
|
|
$ |
34,252 |
|
|
$ |
12,176 |
|
|
|
|
|
|
|
|
F2-18
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
12. |
Supplemental Schedule of Cash Flow Information: |
The following table reflects non-cash financing and investing
activity during:
|
|
|
|
|
|
|
|
|
|
|
Three Months | |
|
|
Ended March 31, | |
|
|
| |
|
|
2006 | |
|
2005 | |
|
|
| |
|
| |
|
|
(In thousands) | |
Capital leases issued for equipment
|
|
$ |
5,203 |
|
|
$ |
1,032 |
|
Asset retirement obligation
additions
|
|
$ |
413 |
|
|
$ |
|
|
Basic paid income taxes of approximately $6.9 million and
$0 during the three months ended March 31, 2006 and 2005,
respectively.
|
|
|
In April 2006, the Company completed a private offering for
$225,000,000 aggregate principal amount of 7.125% Senior
Notes due April 15, 2016. The net proceeds from the
offering were used to retire the outstanding Term B Loan
balance and to repay current borrowings under the revolving
credit facility. Any remaining proceeds will be used for general
corporate purposes. |
In connection with the retirement of the Term B Loan on
April 13, 2006, we will expense remaining unamortized
deferred debt issuance costs which amounted to approximately
$2.7 million, net.
F2-19
APPENDIX A
GLOSSARY OF TERMS
Acidizing: The process of pumping solvent into the
well as a means of dissolving unwanted material.
Brine water: Water that is heavily saturated with
salt used in various well completion and workover activities.
Cased-hole: A wellbore lined with a string of
casing or liner (generally metal casing placed and cemented) to
protect the open hole from fluids, pressures, wellbore stability
problems or a combination of these. Although the term can apply
to any hole section, it is often used to describe techniques and
practices applied after a casing or liner has been set across
the reservoir zone, such as cased-hole logging or cased-hole
testing.
Casing: Steel pipe placed in an oil or gas well as
drilling progresses to prevent the wall of the hole from caving
in, to prevent seepage of fluids, and to provide a means of
extracting petroleum if the well is productive.
Drilling mud: The fluid pumped down the drilling
string and up the well bore to bring debris from the drilling
and workover operators to the surface. Drilling muds also cool
and lubricate the bit, protect against blowouts by holding back
underground pressures and, in new well drilling, deposit a mud
cake on the wall of the borehole to minimize loss of fluid to
the formation.
Electric wireline: Wireline that contains an
electrical conduit, thereby enabling the use of downhole
electrical sensors to measure pressures and temperatures.
Fishing: The process of recovering lost or stuck
equipment in the wellbore.
Frac job or fracturing operations: A procedure to
stimulate production of oil or gas from a well by pumping fluids
from the surface under high pressure into the wellbore to induce
fractures in the formation.
Frac tank: A steel tank used to store fluids at
the well location to facilitate completion and workover
operations. The largest demand is related to the storage of
fluid used in fracturing operations.
Hot oil truck: A truck mounted pump, tank and
heating element used to melt paraffin accumulated in the well
bore by pumping heated oil or water through the well.
Newbuild: A newly built rig, as compared to a
refurbished rig that may contain substantially all new
components or new derrick but utilizes an older frame.
Plugging and abandonment activities: Activities to
remove production equipment and seal off a well at the end of a
wells economic life.
Slickline. A form of wireline that lacks an
electrical conduit and is used only to perform mechanical tasks
such as setting or retrieving various tools.
Stimulation: The general process of improving well
productivity through fracturing or acidizing operations.
Swab rig: Truck mounted equipment consisting of a
hoist and mast used to remove, or swab, wellbore
fluids by alternatively lowering and raising tools in a
wells tubing or casing.
Underbalanced drilling: A technique that involves
maintaining the pressure in a well at or slightly below that of
the surrounding formation using air, nitrogen, mist, foam or
lightweight drilling fluids instead of conventional drilling
fluid.
Water cut: The volume of water produced by a well
as a percentage of all fluids produced.
A-1
Wellbore: The drilled hole of a well, which may
include open hole or uncased portions, and which may also refer
to the rock face that bounds the inside diameter of the wall of
the drilled hole.
Well completion: The activities and procedures
necessary to prepare a well for the production of oil and gas
after the well has been drilled to its targeted depth. Well
completions establish a flow path for hydrocarbons between the
reservoir and the surface.
Well servicing: The maintenance work performed on
an oil or gas well to improve or maintain the production from a
formation already producing. It usually involves repairs to the
downhole pump, rods, tubing, and so forth or removal of sand,
paraffin or other debris which is preventing or restricting
production of oil or gas.
Well workover: Refers to a broad category of
procedures preformed on an existing well to correct a major
downhole problem, such as collapsed casing, or to establish
production from a formation not previously produced, including
deepening the well from its originally completed depth.
Wireline: A general term used to describe
well-intervention operations conducted using single-strand or
multistrand wire or cable for intervention in oil or gas wells.
Although applied inconsistently, the term is used commonly in
association with electric logging and cables incorporating
electrical conductors See slickline and
electric wireline for specific types of wireline
services.
A-2
No dealer, salesperson or other person is authorized to give
any information or to represent anything not contained in this
prospectus. You must not rely on any unauthorized information or
representations. This prospectus is an offer to sell only the
shares of common stock offered hereby, but only under
circumstances and in jurisdictions where it is lawful to do so.
The information contained in this prospectus is current only as
of its date.
2,101,641 Shares
Basic Energy Services, Inc.
Common Stock
PROSPECTUS
August 7, 2006