e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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(MARK ONE)
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þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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FOR THE FISCAL YEAR ENDED
DECEMBER 31,
2010
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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Commission File
No. 1-32858
Complete Production Services,
Inc.
(Exact name of registrant as
specified in its charter)
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Delaware
(State or Other Jurisdiction
of
Incorporation or Organization)
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72-1503959
(I.R.S. Employer
Identification No.)
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11700 Katy Freeway, Suite 300
Houston, Texas
(Address of principal
executive offices)
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77079
(Zip
Code)
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Registrants telephone number, including area code:
(281) 372-2300
Securities registered pursuant to Section 12(b) of the
Act:
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Name of each exchange on
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Title of each class
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which registered
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Common stock, $0.01 par value
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the
Act:
None
Indicate by check mark whether the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Website, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§ 232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
(§ 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrants
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this
Form 10-K
or any amendment to this
Form 10-K. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Rule
12b-2 of the
Exchange Act. (Check one):
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Large
accelerated
filer þ
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Accelerated
filer o
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Non-accelerated
filer o
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Smaller
reporting
company o
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(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
As of June 30, 2010, the aggregate market value of the
registrants common stock held by non-affiliates of the
registrant was $935,388,997 based upon the closing price on the
New York Stock Exchange on that date.
Number of shares of the Common Stock of the registrant
outstanding as of February 14, 2011: 78,592,455
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of the registrants proxy statement to be
furnished to the stockholders in connection with its 2011 Annual
Meeting of Stockholders are incorporated by reference in
Part III,
Items 10-14
of this Annual Report on
Form 10-K
for the fiscal year ending December 31, 2010 (this
Annual Report).
Complete
Production Services, Inc.
TABLE OF
CONTENTS
2
PART I
Unless otherwise indicated, all references to we,
us, our, our company, or
Complete include Complete Production Services, Inc.
and its consolidated subsidiaries.
Our
Company
Complete Production Services, Inc., formerly named Integrated
Production Services, Inc., is a Delaware corporation formed on
May 22, 2001. We focus on providing specialized completion
and production services and products that help oil and gas
companies develop hydrocarbon reserves, reduce costs and enhance
production. We operate in basins within North America that we
believe have attractive long-term potential for growth, and we
deliver targeted, value-added services and products required by
our customers within each specific basin. We believe our range
of services and products positions us to meet many needs of our
customers at the wellsite, from drilling and completion through
production and eventual abandonment. We seek to differentiate
ourselves from our competitors through our local leadership, our
basin-level expertise and the innovative application of
proprietary and other technologies. We deliver solutions to our
customers that we believe lower their costs and increase their
production in a safe and environmentally friendly manner.
Virtually all of our operations are located in basins within
North America, where we manage our operations from regional
field service facilities located throughout the U.S. Rocky
Mountain region, Texas, Oklahoma, Louisiana, Arkansas,
Pennsylvania, western Canada and Mexico. We also have operations
in Southeast Asia.
Company
History
On September 12, 2005, Integrated Production Services, Inc.
(IPS), Complete Energy Services, Inc. and I.E.
Miller Services, Inc. were combined and became Complete
Production Services, Inc. in a transaction in which IPS served
as the acquirer.
In April 2006, we completed our initial public offering and
became subject to the reporting requirements of the Securities
Exchange Act of 1934, as amended (the Exchange Act).
Our
Operating Segments
Our business is comprised of three segments:
Completion and Production Services. Through
our completion and production services segment, we establish,
maintain and enhance the flow of oil and gas throughout the life
of a well. This segment is divided into the following primary
service lines:
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Intervention Services. Well intervention
requires the use of specialized equipment to perform an array of
wellbore services. Our fleet of intervention service equipment
includes coiled tubing units, pressure pumping units, nitrogen
units, well service rigs, snubbing units and a variety of
support equipment. Our intervention services provide customers
with innovative solutions to complete oil and gas wells and
increase production.
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Downhole and Wellsite Services. Our downhole
and wellsite services include electric-line, slickline,
production optimization, production testing, rental and fishing
services.
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Fluid Handling. We provide a variety of
services to help our customers obtain, move, store and dispose
of fluids that are involved in the development and production of
their reservoirs. Through our fleet of specialized trucks, frac
tanks and other assets, we provide fluid transportation,
heating, pumping and disposal services for our customers.
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Drilling Services. Through our drilling
services segment, we provide contract drilling and specialized
rig relocation and logistics services.
Product Sales. We provide oilfield service
equipment and refurbishment of used equipment through our
Southeast Asian business, and we provide repair work and
fabrication services for our customers at a business located in
Gainesville, Texas.
3
Our
Industry
Our business depends on the level of exploration, development
and production expenditures made by our customers. These
expenditures are driven by the current and expected future
prices for oil and gas, and the perceived stability and
sustainability of those prices, as well as production depletion
rates and the resultant levels of cash flows generated and
allocated by our customers to their drilling and workover
budgets. Our business is primarily driven by oil, natural gas
and associated natural gas liquids-directed drilling activity in
North America.
As illustrated in the table below, natural gas and oil commodity
prices had risen in recent years but then began to decline in
late 2008. While the price of oil rebounded somewhat in 2009 and
continued to rise throughout 2010, the price of natural gas
remained relatively low in 2010. The WTI Cushing spot price of a
barrel of crude oil reached an all-time high of $145.31 per
barrel in July 2008 and then dropped sharply by the end of the
year, falling as low as $30.28 per barrel on December 23,
2008 before trending upwards again in late 2009 and reaching a
high of $91.48 towards the end of 2010. The number of drilling
rigs under contract in the United States and Canada and the
number of active well service rigs decreased in 2009 but
rebounded in 2010, according to Baker Hughes Incorporated
(BHI) and the Cameron International
Corporation/Guiberson/AESC Service Rig Count for Active
Rigs. The table below sets forth average daily closing
prices for the WTI Cushing spot oil price and the average daily
closing prices for the Henry Hub price for natural gas since
2001:
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Average Daily Closing
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Average Daily Closing
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Henry Hub Spot Natural
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WTI Cushing Spot Oil
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Period
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Gas Prices ($/mcf)
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Price ($/bbl)
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1/1/01 12/31/01
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$
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3.99
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$
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25.96
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1/1/02 12/31/02
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3.37
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26.17
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1/1/03 12/31/03
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5.49
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31.06
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1/1/04 12/31/04
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5.90
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41.51
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1/1/05 12/31/05
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8.89
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56.56
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1/1/06 12/31/06
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6.73
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66.09
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1/1/07 12/31/07
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6.97
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72.23
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1/1/08 12/31/08
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8.89
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99.92
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1/1/09 12/31/09
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3.94
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61.99
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1/1/10 12/31/10
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4.38
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79.48
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Source: Bloomberg NYMEX prices.
The closing spot price of a barrel of WTI Cushing oil at
December 31, 2010 was $91.38, and the closing spot price
for Henry Hub natural gas ($/mcf) was $4.41. At
February 14, 2011, the closing spot price of a barrel of
WTI Cushing oil was $84.81 and the closing spot price for Henry
Hub natural gas was $3.92.
Trends which we believe are affecting, and will continue to
affect, our industry include:
Trend toward drilling and developing unconventional North
American hydrocarbon resources. Due to the
maturity of conventional North American oil and gas reservoirs
and the relative abundance of undeveloped unconventional
resources, an increasing proportion of future North American oil
and gas will come from unconventional resources, which include
tight sands, shales and coalbed methane. Development of
unconventional resources typically require more wells to be
drilled and maintained on tighter acreage spacing and often
employ horizontal drilling and completion techniques, which are
more service intensive. The appropriate technology to recover
unconventional gas resources varies from region to region;
therefore, knowledge of local conditions and operating
procedures, and selection of the right technologies, is key to
providing customers with appropriate solutions.
The advent of the resource play. A
resource play is a term used to describe an
accumulation of hydrocarbons known to exist over a large area
which, when compared to a conventional play, has lower
commercial development risks and a higher average decline rate.
Once identified, resource plays have the potential to make a
material impact because of their size and long reserve life. The
application of appropriate technology and program execution are
important to obtain value from resource plays. Resource play
4
developments occur over long periods of time, well by well, in
large-scale developments that repeat common tasks in an
assembly-line fashion and capture economies of scale to drive
down costs.
Complex technologies, techniques and
equipment. The development of unconventional oil
and gas resources is driving the need for complex, new
technologies, completion techniques and equipment to help
increase recovery rates, lower production costs and accelerate
field development.
Increased Service Intensity. Advances in
horizontal drilling and completion technologies and techniques
have made the development of many unconventional resources such
as oil and natural gas shale formations economically attractive.
The North American horizontal rig count has risen from 335 at
the beginning of 2007 to 947 at the end of December 2010,
according to Baker Hughes, Inc. Additionally, the length of well
laterals has increased and the intervals between stages has
decreased over the past several years. The longer laterals and
increasing number of stages has enhanced recoveries and lowered
field development costs while causing the number of completion
stages to grow at a faster rate than the horizontal rig count,
creating an increased demand for completion related services.
Enhanced Economics in Oil- and Liquids-Rich
Formations. While the majority of
U.S. drilling rigs are currently drilling in natural gas
formations, there is increasing horizontal drilling and
completion related activity in oil- and liquid-rich formations
such as the Eagle Ford, Bakken and Niobrara Shales and various
other plays in Texas and Oklahoma, including the Granite Wash.
We believe that the oil and natural gas liquids content in these
plays significantly enhance the returns for our customers
relative to opportunities in dry gas basins due to the
significant disparity between oil and natural gas prices on a
Btu basis. We believe the price disparity will continue over the
near to mid-term resulting in increasing demand for services in
oil- and liquid-rich basins.
Our
Business Strategy
Our goal is to build the leading oilfield services company
focused on the completion and production phases in the life of
an oil and gas well. We intend to capitalize on the emerging
trends in the North American marketplace through the execution
of a growth strategy that consists of the following components:
Focus on execution and performance. We have
established and intend to develop further a culture of
performance and accountability. Senior management spends a
significant portion of its time ensuring that our customers
receive the highest levels of service quality and execution at
the well site by focusing on the following:
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clear business direction;
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thorough planning process;
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clearly defined targets and accountabilities;
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close performance monitoring;
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safety objectives;
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performance incentives for management and employees; and
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effective communication.
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Expand and capitalize on local leadership and basin-level
expertise. A key component of our strategy is to
build upon our base of strong local leadership and basin-level
expertise. We have a significant presence in most of the key
onshore continental U.S. and Canadian resource plays that
we believe have the potential for long-term growth. Our position
in these basins capitalizes on our local leadership as these
employees have accumulated a valuable knowledge base and strong
customer relationships. We intend to leverage our existing
market presence, expertise and customer relationships to expand
our business within these resource plays. We also intend to
replicate this approach in new regions by building and acquiring
new businesses that have strong regional management with
extensive local knowledge.
5
Develop and deploy technical and operational
solutions. We are focused on developing and
deploying technical services, equipment and expertise that lower
our customers costs.
Capitalize on organic and acquisition-related growth
opportunities. We believe there are numerous
opportunities to expand our service offerings in our current
geographic areas and to sell our current services and products
to customers in new geographic areas. We have a proven track
record of organic growth and successful acquisitions, and we
intend to continue using capital investments and acquisitions to
strategically expand our business over the long-term. In 2009,
we significantly reduced our capital expenditures and did not
complete any cash acquisitions primarily due to difficult market
conditions. In 2010, we increased our capital investment
significantly compared to the prior year and we acquired three
small strategic businesses. We continue to evaluate additional
business acquisition opportunities.
Our
Competitive Strengths
We believe that we are well positioned to execute our strategy
and capitalize on opportunities in the North American oil and
gas market based on the following competitive strengths:
Strong local leadership and basin-level
expertise. We operate our business with a focus
on each regional basin complemented by our local reputations. We
believe our local and regional businesses, some of which have
been operating for more than 50 years, provide us with a
significant advantage over many of our competitors. Our
managers, sales engineers and field operators have extensive
expertise in their local geological basins and understand the
regional challenges our customers face. We support our local
operations personnel through corporate teams that provide
service specific technical support and executive level contacts.
We have long-term relationships with many customers, and most of
the services and products we offer are sold or contracted at a
local level, allowing our operations personnel to leverage all
of our expertise to establish ourselves as the preferred
provider of our services in the basins in which we operate.
Significant presence in major North American
basins. We operate in major oil and gas producing
regions of the U.S. Rocky Mountains, Texas, Louisiana,
Arkansas, Pennsylvania, Oklahoma, western Canada and Mexico,
with concentrations in key resource play and
unconventional basins. Resource plays are expected to continue
to increase in importance in future North American oil and gas
production as more conventional resources enter later stages of
the exploration and development cycle. We believe we have an
excellent position in highly active markets such as the Bakken
Shale area of North Dakota, the Niobrara Shale of northeast
Colorado and southeast Wyoming, the Granite Wash of northern
Texas and western Oklahoma, the Marcellus Shale of Pennsylvania,
the Barnett Shale of north Texas, the Haynesville Shale area of
east Texas and northern Louisiana and the Eagle Ford shale in
south Texas. Each of these markets is among the most active
areas for exploration and development of onshore oil and gas.
Accelerating production and driving down development and
production costs are key goals for oil and gas operators in
these areas, resulting in higher demand for our services and
products. In addition, our presence in these regions allows us
to build solid customer relationships and take advantage of
cross-selling opportunities.
Focus on complementary production and field development
services. Our breadth of service and product
offerings positions us well relative to our competitors. Our
services encompass the entire lifecycle of a well from drilling
and completion, through production and eventual abandonment. We
deliver complementary services and products, which we may
provide in tandem or sequentially over the life of the well.
This suite of services and products gives us the opportunity to
cross-sell to our customer base throughout our geographic
regions. Leveraging our local leadership and basin-level
expertise, we are able to offer expanded services and products
to existing customers or current services and products to new
customers.
Innovative approach to technical and operational
solutions. We develop and deploy services and
products that enable our customers to increase production rates,
stem production declines and reduce the costs of drilling,
completion and production. The significant expertise we have
developed in our areas of operation offers our customers
customized operational solutions to meet their particular needs.
Our ability to develop these technical and operational solutions
is possible due to our understanding of applicable technology,
our basin-level expertise and our close local relationships with
customers.
6
Modern and active asset base. We have a modern
and well-maintained fleet of coiled tubing units, pressure
pumping equipment, wireline units, well service rigs, snubbing
units, fluid transports, frac tanks and other specialized
equipment. We believe our ongoing investment in our equipment
allows us to better serve the diverse and increasingly
challenging needs of our customer base. New equipment is
generally less costly to maintain and operate on an annual basis
and is more efficient for our customers. Modern equipment
reduces downtime, including associated costs and expenditures,
and enables increased utilization of our assets. We believe our
future expenditures will be used to capitalize on growth
opportunities within the areas we currently operate and to build
out platforms in new regions.
Experienced management team with proven track
record. Each member of our operating management
team has extensive experience in the oilfield services industry.
We believe that their considerable knowledge of and experience
in our industry enhances our ability to operate effectively
throughout industry cycles. Our management also has substantial
experience in identifying, completing and integrating
acquisitions. In addition, our management supports local
leadership by developing corporate strategy, overseeing
corporate governance procedures and administering a company-wide
safety program.
Overview
of Our Segments
We manage our business through three segments: completion and
production services, drilling services and product sales. Within
each of these segments, we perform services and deliver
products, as detailed in the table below. We constantly monitor
the North American market for opportunities to expand our
business by building our presence in existing regions and
expanding our services and products into attractive, new regions.
See Note 15 of the notes to the consolidated financial
statements included elsewhere in this Annual Report for
financial information about our operating segments and about
geographic areas.
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North
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Western
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Louisiana/
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Central &
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Eastern
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Western
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North
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Canadian
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North
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South
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East
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Western
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Oklahoma &
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Basin
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Slope
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Rockies
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Appalachia
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Sedimentary
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Product/Service Offering
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Texas
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Texas
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Texas
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Oklahoma
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Arkansas
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(CO)
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(CO & UT)
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Wyoming
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(MT & ND)
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(PA)
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Basin
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Mexico
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Completion and Production Services:
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Coiled Tubing
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Pressure Pumping
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Well Servicing
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Fluid Handling
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Snubbing
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Electric-line
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Slickline
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Production Optimization
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Production Testing
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Pressure Testing
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Drilling Services:
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Contract Drilling
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Drilling Logistics
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Fabrication and repair
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denotes a service or product currently offered by us in this
area.
Completion
and Production Services (87% of Revenue for the Year Ended
December 31, 2010)
Through our completion and production services segment, we
establish, maintain and enhance the flow of oil and gas
throughout the life of a well. This segment is divided into
intervention services, downhole and wellsite services and fluid
handling.
7
Intervention
Services
We use our intervention assets, which include coiled tubing
units, pressure pumping equipment, nitrogen units, well service
rigs and snubbing units to perform three major types of services
for our customers:
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Completion Services. As newly drilled oil and
gas wells are prepared for production, our operations may
include selectively perforating the well casing to access
producing zones, stimulating and testing these zones and
installing downhole equipment. We provide intervention services
and products to assist in the performance of these services. The
completion process typically lasts from a few days to several
weeks, depending on the nature and type of the completion. Oil
and gas producers use our intervention services to complete
their wells because we have well-maintained equipment,
well-trained employees, the experience necessary to perform such
services and a strong record for safety and reliability.
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Workover Services. Producing oil and gas wells
occasionally require major repairs or modifications, called
workovers. These services include extensions of
existing wells to drain new formations either through deepening
wellbores to new zones or by drilling horizontal lateral
wellbores to improve reservoir drainage patterns. In less
extensive workovers, we provide services and products to seal
off depleted zones in existing wellbores and access previously
bypassed productive zones. Other workover services which we
provide include: major subsurface repairs, such as casing repair
or replacement; recovery of tubing and removal of foreign
objects in the wellbore; repairing downhole equipment failures;
plugging back the bottom of a well to reduce the amount of water
being produced; cleaning out and recompleting a well if
production has declined; and repairing leaks in the tubing and
casing.
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Maintenance Services. Maintenance services are
required throughout the life of most producing oil and gas wells
to ensure efficient and continuous operation. We provide
services that include mechanical repairs necessary to maintain
production from the well, such as repairing inoperable pumping
equipment or replacing defective tubing, and removing debris
from the well. Other services include pulling rods, tubing,
pumps and other downhole equipment out of the wellbore to
identify and repair a production problem.
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The key intervention assets we use to perform intervention
services are as follows:
Coiled
Tubing Units and Nitrogen Units
We are one of the leading providers of coiled tubing services in
North America. We operate a fleet of coiled tubing units, as
well as nitrogen units. We use these assets to perform a variety
of wellbore applications, including plug drilling, foam washing,
acidizing, displacing, cementing, gravel packing, fishing and
jetting. Coiled tubing is a key segment of the well service
industry today, which allows operators to continue production
during service operations without shutting in the well, thereby
reducing the risk of formation damage. The growth in deep well
and horizontal drilling has increased the market for coiled
tubing. We provide coiled tubing services primarily in Oklahoma,
Texas, Louisiana, Arkansas, Pennsylvania, Wyoming, North Dakota
and Mexico.
Pressure
Pumping Services
We operate fleets of pressure pumping equipment in the Barnett
Shale of north Texas, in the Bakken Shale of North Dakota, in
the Marcellus Shale of Pennsylvania and in the Eagle Ford shale
of south Texas through which we provide stimulation and
cementing services principally to oil and gas production
companies.
Stimulation services primarily consist of hydraulic fracturing
of hydrocarbon bearing formations which lack permeability to
permit the natural flow. The fracturing process consists of
pumping fluids into a well at pressures that are sufficient
enough to fracture the formation. Materials such as sand and
synthetic proppants are pumped into the fracture to prop open
the fracture, permitting the hydrocarbons in the formation to
flow into the wellbore and ultimately to the surface. Various
pieces of specialized equipment are used in the process,
including a blender, which is used to blend the proppant into
the fluid, multiple high pressure pumping units capable of
pumping significant volumes at high pressures, and real-time
monitoring equipment where the progress of the process is
controlled. Our fracturing units are capable of pumping slurries
at pressures up to 10,000 pounds per square inch.
8
Cementing services consist of blending special cement with water
and various solid and liquid additives to form a cement slurry
that can be pumped into a well between the casing and the
wellbore. Cementing services are principally performed in
connection with primary cementing, where the casing used to line
a wellbore after a well has been drilled is cemented into place.
The purpose of primary cementing is to isolate fluids behind the
casing between productive formations and non-productive
formations that could damage the productivity of the well or
damage the quality of freshwater acquifers, seal the casing from
corrosive formation fluids and to provide structural support for
the casing string.
Well
Service Rigs
We own and operate a large fleet of well service rigs, of which
a significant number were either recently constructed or have
been recently rebuilt. We believe we have leading market
positions in the Barnett Shale region of north Texas, the
Haynesville Shale of east Texas and northern Louisiana and in
some of the most active basins of the U.S. Rocky Mountain
region. We also operate swabbing units, some of which are highly
customized hydraulic units which we use to diagnose and
remediate gas well production problems. We provide well service
rig operations in Wyoming, Colorado, Utah, Montana, North
Dakota, Pennsylvania, Louisiana, Oklahoma and Texas. These rigs
are used to perform a variety of completion, workover and
maintenance services, such as installations, completions,
assisting with perforating, removing defective equipment and
sidetracking wells.
Snubbing
Units
We operate a fleet of snubbing units, several of which are rig
assist units. Snubbing services use specialized hydraulic well
service units that permit an operator to repair damaged casing,
production tubing and downhole production equipment in
high-pressure, live-well environments. A snubbing
unit makes it possible to remove and replace downhole equipment
while maintaining pressure in the well. Applications for
snubbing units include live-well completions and
workovers, underground blowout control, underbalanced
completions, underbalanced drilling and the snubbing of tubing,
casing or drillpipe into or out of the wellbore. Our snubbing
units operate primarily in Texas, Wyoming and Pennsylvania.
Downhole
and Wellsite Services
We provide an array of complementary downhole and wellsite
services that we classify into four groups: wireline services;
production optimization services; production testing services;
and rental, fishing and pressure testing services.
Wireline Services. We own and operate a fleet
of wireline units in North America and provide both
electric-line and slickline services. Wireline services are used
to evaluate downhole well conditions, to initiate production
from a formation by perforating a wells casing, and to
provide mechanical services such as setting equipment in the
well, or fishing lost equipment out of a well. We provide
wireline services in the western Canadian Sedimentary Basin,
Wyoming, Colorado, North Dakota, Pennsylvania, Oklahoma and
Texas.
With our fleet of wireline equipment we provide the following
services:
Electric-Line Services:
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Perforating Services. Perforating involves
positioning a perforating gun that contains explosive jet
charges down the wellbore next to a productive zone. A detonator
is fired and primer cord is ignited, which then detonates the
jet charges. The resulting explosion burns a hole through the
wellbore casing and cement and into the formation, thus allowing
access to the formation. The perforating gun may be deployed in
a number of ways. The gun can be conveyed by a conventional
wireline cable if the wellbore geometry allows, it may be
conveyed on coiled tubing, it may be conveyed on conventional
tubing or the gun may be pumped-down to the correct
depth in the wellbore.
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Logging Services. Logging requires the use of
a single or multi-conductor, braided steel cable
(electric-line), mounted on a hydraulically operated drum, and a
specialized logging truck. Electronic instruments are attached
to the end of the cable and lowered to the bottom of the well
and the line is slowly pulled out of the well, transmitting
wellbore data up the cable to the surface where the
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information is processed by a surface computer system and
displayed on a graph in a logging format. This information is
used by customers to analyze different downhole formation
structures, to detect the presence of oil, gas and water and to
check the integrity of the casing or the cement behind the pipe.
Logs are also used to detect gas or fluid migration between
zones or to the surface.
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Slickline Services. Slickline services are
used primarily for well maintenance. The line used for this
application is generally a small single steel line. Typical
applications of this service would include bottom hole pressure
surveys, running temperature gradients, setting tubing plugs,
opening and closing sliding sleeves, fishing operations, plunger
lift installations, gas lift installations and other maintenance
services that a well might require during its lifecycle.
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Production Optimization Services. Our
production optimization services provide customers with
technical solutions to stem declining production that results
from liquid loading, reduced bottom-hole pressures or improper
wellsite designs. We assist in identifying candidates, designing
solutions, executing
on-site and
following up to ensure continued performance. We have developed
proprietary technologies that allow us to enhance recovery for
our customers and provide on-going service. We offer production
optimization services to customers across the United States and
in Canada. Specific services we provide include:
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Plunger Lift Services and Products. We provide
plunger lift candidate selection, installation and maintenance
services which may incorporate the use of our patented Pacemaker
Plunger Lift System. Plunger lift systems facilitate the removal
of fluids that restrict the production of natural gas wells.
Removing fluids that accumulate in wells increases production
and, in many cases, slows decline rates. The proprietary design
of our Pacemaker Plunger Lift System incorporates a large bypass
area which allows it to make more trips per day and remove more
wellbore fluids, versus other plunger lift designs, in wells
with certain characteristics.
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Gas Lift Services and Products. We provide gas
lift candidate selection, installation and maintenance services.
Gas lift systems facilitate the removal of fluids that restrict
the production of natural gas wells. Evacuating fluids that
accumulate in wells increases production and, in many cases,
slows decline rates. Gas is injected down the tubing-casing
annular and enters the tubing string through a valve to aerate
liquids above an entrance point to reduce hydrostatic pressure.
Valves are set at varying depths and pressures throughout the
tubing string to aerate the fluid column. This practice reduces
bottom hole pressure, resulting in an increase in production.
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Acoustic Pressure Surveys. We provide acoustic
pressure surveys, an analytical technique that assists our
customers in determining static reservoir pressure and the
existence of near wellbore formation damage.
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Dynamometer Analysis. Our dynamometer analysis
services include the analysis of reciprocating rod pumping
systems (pumpjacks) to determine pump performance and provide
our customers with critical information for well performance
used to optimize the production and recovery of oil and gas.
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Fluid Level Analysis. We provide fluid
level analysis services which record an acoustic pulse as it
travels down the wellbore in order to determine the fluid depth.
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Production Testing Services. Production
testing is a service required by exploration and production
companies to evaluate and clean out new and existing wells. We
provide production testing services in Wyoming, Utah, Colorado,
Texas and Mexico.
Production testing has the following primary applications:
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Well
clean-ups or
flowbacks are done shortly after completing or stimulating a
well and are designed to remove damaging drilling fluids,
completion fluids, sand and other debris. This
clean-up
prevents damage to the permanent production facilities and
flowlines, thereby improving production. Our
clean-up
offering includes our Green Flowback services, which permit the
flow of gas to our customers while performing drill-outs and
flowback operations, increasing production, accelerating time to
production and eliminating the need to flare gas.
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Exploration well testing measures how a reservoir
performs under various flow conditions. These measurements allow
reservoir and production engineers and geologists to understand
well or reservoir production capabilities. Exploration testing
jobs can last from a few days to several months.
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In-line production testing measures well flow rates, oil,
gas and water composition, pressure and temperature. These
measurements are used by engineers to identify and solve well
and reservoir problems. In-line production testing is performed
after a well has been completed and is already producing.
In-line tests can run from several hours to more than several
months.
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Rental Equipment, Fishing and Pressure Testing
Services. Oil and gas producers and drilling
contractors often need specialized tools, drillpipe, pressure
testing equipment and other equipment and need qualified
personnel to operate this equipment. In response to this need,
we provide the following services and products:
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Rental Equipment and Services. We rent
specialized tools, equipment and tubular goods for the drilling,
completion and workover of oil and gas wells. Items rented
include pressure control equipment, drill string equipment, pipe
handling equipment, fishing and downhole tools, as well as other
equipment such as stabilizers, power swivels and bottom-hole
assemblies.
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Fishing Services. We provide highly-skilled
downhole services, including fishing, milling and cutting
services, which consist of removing or otherwise eliminating
fish or junk (a piece of equipment, a
tool, a part of the drill string or debris) in a well that is
causing an obstruction. We also install whipstocks to sidetrack
wells, provide plugging and abandonment services, as well as
pipe and wireline recovery services, foam services and casing
patch installation.
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Pressure Testing Services. We provide
specialized pressure testing services which involve the use of
truck-mounted equipment designed to carry small fluid volumes
with high pressure pumps and hydraulic torque equipment. This
equipment is primarily used to perform pressure tests on flow
line, pressure vessels, lubricators, well heads and casings and
tubing strings. The units are also used to assemble and
disassemble blowout preventors (BOPs) for the
drilling and work over sector. We have developed specialized,
multi-service pressure testing units that enable one or two
employees to complete multiple services simultaneously. We have
multi-service pressure testing units that we operate in
Colorado, North Dakota, Utah, Wyoming and Mexico.
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Fluid
Handling
Oil and gas operations use and produce significant quantities of
fluids. We provide a variety of services to assist our customers
to obtain, move, store and dispose of fluids that are involved
in the development and production of their reservoirs. We
provide fluid handling services in Texas, Oklahoma, Louisiana,
Colorado, Wyoming, Arkansas, North Dakota and Montana.
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Fluid Transportation. We operate specialized
transport trucks to deliver, transport and dispose of fluids
safely and efficiently. We transport fresh water, completion
fluids, produced water, drilling mud and other fluids to and
from our customers wellsites. Our assets include
U.S. Department of Transportation certified equipment for
transportation of hazardous waste.
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Frac Tank Rental. We operate a fleet of frac
tanks that are often used during hydraulic fracturing
operations. We use our fleet of fluid transport assets to fill
and empty these tanks and we deliver and remove these tanks from
the wellsite with our fleet of winch trucks.
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Fluid Disposal. We own salt water disposal
wells in Oklahoma, Texas, Colorado and Arkansas and one
evaporation facility in Wyoming. These facilities are used to
dispose of water from fracturing operations and from fluids
produced during the routine production of oil and gas.
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Other Services. We own and operate a fleet of
hot oilers and superheaters, which are assets capable of heating
high volumes of fluids. We also sell fluids used during well
completions, such as fresh water and potassium chloride, and
drilling mud, which we move to our customers wellsites
using our fluid transportation services.
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Drilling
Services (11% of Revenue for the Year Ended December 31,
2010)
Through our drilling services segment, we deliver services that
initiate oil and gas production by providing land drilling and
specialized rig logistics.
Contract
Drilling
We provide contract drilling services to major oil companies and
independent oil and gas producers in and around the Barnett
Shale region of north Texas and the Permian Basin in west Texas.
Contract drilling services are primarily provided under a
standard day rate, and, to a lesser extent, footage or turnkey
contracts. Drilling rigs vary in size and capability and may
include specialized equipment. The majority of our drilling rig
fleet is equipped with mechanical power systems and has depth
ratings ranging from approximately 8,000 to 15,000 feet.
Drilling
Logistics
Through our owned and operated fleet of specialized trucks, we
provide drilling rig mobilization services primarily in
Louisiana, Texas, North Dakota, Colorado and Arkansas. Our
capabilities allow us to move the largest rigs in the United
States. Our operations are strategically located in regions
where approximately 50% of the land drilling rigs in the United
States are located. We believe our highly skilled personnel
position us as one of the leading rig moving companies in the
industry.
Product
Sales (2% of Revenue for the Year Ended December 31,
2010)
Through our product sales segment, we provide a variety of
equipment used by oil and gas companies throughout the lifecycle
of their wells. We assemble and refurbish equipment at our
fabrication shop in north Texas. In addition, we operate an
oilfield sales, service and rental business based in Singapore.
This business sells new and reconditioned equipment used in the
construction and upgrade of offshore drilling rigs; rents mud
coolers, tubular handling equipment, BOPs and other service
tools; and provides machining and repair services.
Sales and
Marketing
Most sales and marketing activities are performed through our
local operations in each geographical region. We believe our
local field sales personnel have an excellent understanding of
basin-specific issues and customer operating procedures and,
therefore, can effectively target marketing activities. We
supplement our field sales efforts with corporate teams that
provide service specific technical support and executive level
contacts.
Customers
Our customers consist of large
multi-national
and independent oil and gas producers, as well as smaller
independent producers and the major
land-based
drilling contractors in North America. Our top ten customers
accounted for approximately 52%, 49% and 45% of our revenue for
the years ended December 31, 2010, 2009 and 2008,
respectively. Our top two customers provided 12.2% and 10.7% of
our total annual revenue in 2010, and the same two customers
provided 9.9% and 9.7% of our total annual revenue in 2009. No
customer represented more than 10% of our total annual revenue
in 2008. We believe we have a broad customer base and wide
geographic coverage of operations, which somewhat insulates us
from regional or customer specific circumstances.
12
Our top ten customers for the year ended December 31, 2010
were as following (in alphabetical order):
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Anadarko Petroleum Corporation
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Chesapeake Energy Corporation
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Chief Oil & Gas, LLC
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Continental Resources, Inc.
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Devon Energy Corporation
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EOG Resources, Inc.
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Exxon Mobil Corporation
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Noble Energy, Inc.
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Petroleos Mexicanos (Pemex)
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The Williams Companies, Inc.
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Seasonality
Our completion and production services business generally
experiences a decline in sales for our Canadian operations
during the second quarter of each year due to seasonality, as
weather conditions make oil and gas operations in this region
difficult during this period. Our Canadian operations accounted
for approximately 5% of total revenues from continuing
operations for each of the years ended December 31, 2010,
2009 and 2008. To a lesser extent, seasonality can affect our
operations in the Appalachian region and certain parts of the
Rocky Mountain and Mid-continent regions, which may be subject
to periods of reduced activity due to inclement weather
conditions, road restrictions and environmental stipulations.
Operating
Risk and Insurance
Our operations are subject to hazards inherent in the oil and
gas industry, such as accidents, blowouts, explosions, fires and
oil spills that can cause:
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personal injury or loss of life;
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damage or destruction of property, equipment and the
environment; and
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suspension of operations.
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In addition, claims for loss of oil and gas production and
damage to formations can occur in the well services industry. If
a serious accident were to occur at a location where our
equipment and services are being used, it could result in our
being named as a defendant in lawsuits asserting large claims.
Because our business involves the transportation of heavy
equipment and materials, we may also experience traffic
accidents which may result in spills, property damage and
personal injury.
Despite our efforts to maintain high safety standards, we have
suffered accidents in the past and anticipate that we will
experience accidents in the future. In addition to the property
and personal losses from these accidents, the frequency and
severity of these incidents affect our operating costs and
insurability and our relationships with customers, employees and
regulatory agencies. Any significant increase in the frequency
or severity of these incidents, or the general level of
compensation awards, could adversely affect the cost of, or our
ability to obtain, workers compensation and other forms of
insurance, and could have other material adverse effects on our
financial condition and results of operations.
Although we maintain insurance coverage of types and amounts
that we believe to be customary in the industry, we are not
fully insured against all risks, either because insurance is not
available or because of the high premium costs. We do maintain
commercial general liability, workers compensation,
business auto, excess auto liability, commercial property, rig
physical damage and contractors equipment, motor truck
cargo, umbrella liability and excess liability, non-owned
aircraft liability, directors and officers, employment practices
liability, fiduciary and commercial crime insurance policies.
However, any insurance obtained by us may not be adequate to
cover any losses or liabilities and this insurance may not
continue to be available or available on terms which are
13
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. See Item 1A.
Risk Factors.
Competition
The markets in which we operate are highly competitive. To be
successful, a company must provide services and products that
meet the specific needs of oil and gas exploration and
production companies and drilling services contractors at
competitive prices.
We provide our services and products across North America, and
we compete against different companies in each service and
product line we offer. Our competition includes many large and
small oilfield service companies, including the largest
integrated oilfield services companies.
Our major competitors for our completion and production services
segment include Schlumberger Ltd., Baker Hughes Incorporated,
Halliburton Company, Weatherford International Ltd., Key Energy
Services, Inc., Basic Energy Services, Inc., Nabors Industries
Ltd., RPC Inc. and a significant number of locally-oriented
businesses. In our drilling services segment, our primary
competitors include Nabors Industries Ltd., Patterson-UTI
Energy, Inc., Unit Corporation, Helmerich & Payne and
Precision Drilling Corporation. Our principal competitors in our
product sales segment include National Oilwell Varco, Inc. and
various smaller providers of equipment. We believe that the
principal competitive factors in the market areas that we serve
are quality of service and products, reputation for safety and
technical proficiency, availability and price. While we must be
competitive in our pricing, we believe our customers select our
services and products based on local leadership and
basin-expertise that our personnel use to deliver quality
services and products.
Government
Regulation
We operate under the jurisdiction of a number of regulatory
bodies that regulate worker safety standards, the handling of
hazardous materials, the transportation of explosives, the
protection of the environment and driving standards of
operation. Regulations concerning equipment certification create
an ongoing need for regular maintenance which is incorporated
into our daily operating procedures. The oil and gas industry is
subject to environmental regulation pursuant to local, state and
federal legislation.
Among the services we provide, we operate as a motor carrier and
therefore are subject to regulation by the U.S. Department
of Transportation and by various state agencies. These
regulatory authorities exercise broad powers, governing
activities such as the authorization to engage in motor carrier
operations and regulatory safety, financial reporting and
certain mergers, consolidations and acquisitions. There are
additional regulations specifically relating to the trucking
industry, including testing and specification of equipment and
product handling requirements. The trucking industry is subject
to possible regulatory and legislative changes that may affect
the economics of the industry by requiring changes in operating
practices or by changing the demand for common or contract
carrier services or the cost of providing truckload services.
Some of these possible changes include increasingly stringent
environmental regulations, changes in the hours of service
regulations which govern the amount of time a driver may drive
in any specific period, onboard black box recorder devices or
limits on vehicle weight and size.
Interstate motor carrier operations are subject to safety
requirements prescribed by the U.S. Department of
Transportation. To a large degree, intrastate motor carrier
operations are subject to safety regulations that mirror federal
regulations. Such matters as weight and dimension of equipment
are also subject to federal and state regulations. Department of
Transportation regulations mandate drug testing of drivers.
From time to time, various legislative proposals are introduced,
including proposals to increase federal, state, or local taxes,
including taxes on motor fuels, which may increase our costs or
adversely impact the recruitment of drivers. We cannot predict
whether, or in what form, any increase in such taxes applicable
to us will be enacted.
Environmental
Matters
Our operations are subject to numerous federal, state, local and
foreign environmental laws and regulations governing the release
and/or
discharge of materials into the environment or otherwise
relating to environmental
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protection. Numerous governmental agencies issue regulations to
implement and enforce these laws, for which compliance is often
costly and difficult. The violation of these laws and
regulations may result in the denial or revocation of permits,
issuance of corrective action orders, assessment of
administrative and civil penalties, and even criminal
prosecution. We believe that we are in substantial compliance
with applicable environmental laws and regulations. Further, we
do not anticipate that compliance with existing environmental
laws and regulations will have a material effect on our
consolidated financial statements. However, it is possible that
substantial costs for compliance or penalties for non-compliance
may be incurred in the future. Moreover, it is possible that
other developments, such as the adoption of stricter
environmental laws, regulations, and enforcement policies, could
result in additional costs or liabilities that we cannot
currently quantify.
We generate wastes, including hazardous wastes, which are
subject to the federal Resource Conservation and Recovery Act,
or RCRA, and comparable state statutes. The
U.S. Environmental Protection Agency, or EPA, the Nuclear
Regulatory Commission, and state agencies have limited the
approved methods of disposal for some types of hazardous and
nonhazardous wastes. Some wastes handled by us in our field
service activities that currently are exempt from treatment as
hazardous wastes may in the future be designated as
hazardous wastes under RCRA or other applicable
statutes. If this were to occur, we would become subject to more
rigorous and costly operating and disposal requirements.
The federal Comprehensive Environmental Response, Compensation,
and Liability Act, CERCLA or the Superfund law, and
comparable state statutes impose liability, without regard to
fault or legality of the original conduct, on classes of persons
that are considered to have contributed to the release of a
hazardous substance into the environment. Such classes of
persons include the current and past owners or operators of
sites where a hazardous substance was released, and companies
that disposed of or arranged for the disposal of hazardous
substances at offsite locations such as landfills. Under CERCLA,
these persons may be subject to joint and several liability for
the costs of cleaning up the hazardous substances that have been
released into the environment and for damages to natural
resources, and it is not uncommon for neighboring landowners and
other third parties to file claims for personal injury and
property damage allegedly caused by the hazardous substances
released into the environment. We currently own, lease, or
operate numerous properties and facilities that for many years
have been used for industrial activities, including oil and gas
production operations. Hazardous substances, wastes, or
hydrocarbons may have been released on or under the properties
owned or leased by us, or on or under other locations where such
substances have been taken for disposal. In addition, some of
these properties have been operated by third parties or by
previous owners whose treatment and disposal or release of
hazardous substances, wastes, or hydrocarbons, was not under our
control. These properties and the substances disposed or
released on them may be subject to CERCLA, RCRA and analogous
state laws. Under such laws, we could be required to remove
previously disposed substances and wastes (including substances
disposed of or released by prior owners or operators), remediate
contaminated property (including groundwater contamination,
whether from prior owners or operators or other historic
activities or spills), or perform remedial plugging of disposal
wells or pit closure operations to prevent future contamination.
These laws and regulations may also expose us to liability for
our acts that were in compliance with applicable laws at the
time the acts were performed.
In the course of our operations, some of our equipment may be
exposed to naturally occurring radiation associated with oil and
gas deposits, and this exposure may result in the generation of
wastes containing naturally occurring radioactive materials or
NORM. NORM wastes exhibiting trace levels of
naturally occurring radiation in excess of established state
standards are subject to special handling and disposal
requirements, and any storage vessels, piping, and work area
affected by NORM may be subject to remediation or restoration
requirements. Because many of the properties presently or
previously owned, operated, or occupied by us have been used for
oil and gas production operations for many years, it is possible
that we may incur costs or liabilities associated with elevated
levels of NORM.
The Federal Water Pollution Control Act, also known as the Clean
Water Act, and applicable state laws impose restrictions and
strict controls regarding the discharge of pollutants into state
waters or waters of the United States. The discharge of
pollutants into jurisdictional waters is prohibited unless the
discharge is permitted by the EPA or applicable state agencies.
Many of our properties and operations require permits for
discharges of wastewater
and/or
stormwater, and we have a system for securing and maintaining
these permits. In addition, the Oil Pollution Act of 1990
imposes a variety of requirements on responsible parties related
to the prevention of oil spills and
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liability for damages, including natural resource damages,
resulting from such spills in waters of the United States. A
responsible party includes the owner or operator of a facility.
The Federal Water Pollution Control Act and analogous state laws
provide for administrative, civil and criminal penalties for
unauthorized discharges and, together with the Oil Pollution
Act, impose rigorous requirements for spill prevention and
response planning, as well as substantial potential liability
for the costs of removal, remediation, and damages in connection
with any unauthorized discharges.
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. State
regulations require us to obtain a permit from the applicable
regulatory agencies to operate our underground injection wells.
We believe that we have obtained the necessary permits from
these agencies for our underground injection wells and that we
are in substantial compliance with permit conditions and state
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.
Some of our operations also result in emissions of regulated air
pollutants. The federal Clean Air Act and analogous state laws
require permits for facilities that have the potential to emit
substances into the atmosphere that could adversely affect
environmental quality. Failure to obtain a permit or to comply
with permit requirements could result in the imposition of
substantial administrative, civil and even criminal penalties.
The U.S. Congress is considering legislation to reduce
emissions of greenhouse gases. President Obama has expressed
support for legislation to restrict or regulate emissions of
greenhouse gases. In addition, more than one-third of the
states, either individually or through multi-state regional
initiatives, have already begun implementing legal measures to
reduce emissions of greenhouse gases, primarily through the
planned development of emission inventories or regional
greenhouse gas cap and trade programs. Depending on the
particular program, our customers could be required to purchase
and surrender allowances for greenhouse gas emissions resulting
from their operations. This requirement could increase our
customers operational and compliance costs and result in
reduced demand for their products, which would have a material
adverse effect on the demand for our services and our business.
Also, as a result of the United States Supreme Courts
decision on April 2, 2007 in Massachusetts, et
al. v. EPA, the EPA may regulate greenhouse gas
emissions from mobile sources such as cars and trucks even if
Congress does not adopt new legislation specifically addressing
emissions of greenhouse gases. The Courts holding in
Massachusetts that greenhouse gases, including carbon
dioxide, fall under the federal Clean Air Acts definition
of air pollutant may also result in future
regulation of carbon dioxide and other greenhouse gas emissions
from stationary sources. In July 2008, the EPA released an
Advance Notice of Proposed Rulemaking regarding
possible future regulation of greenhouse gas emissions under the
Clean Air Act, in response to the Supreme Courts decision
in Massachusetts. In the notice, the EPA evaluated the potential
regulation of greenhouse gases under the Clean Air Act and other
potential methods of regulating greenhouse gases. Although the
notice did not propose any specific, new regulatory requirements
for greenhouse gases, it indicates that federal regulation of
greenhouse gas emissions could occur in the near future even if
Congress does not adopt new legislation specifically addressing
emissions of greenhouse gases. Although it is not possible at
this time to predict how legislation or new regulations that may
be adopted to address greenhouse gas emissions would impact our
business, any new federal, regional or state
16
restrictions on emissions of carbon dioxide or other greenhouse
gases that may be imposed in areas in which we conduct business
could result in increased compliance costs or additional
operating restrictions on our customers. Such legislation could
potentially make our customers products more expensive and thus
reduce demand for them, which could have a material adverse
effect on the demand for our services and our business.
Many foreign nations, including Canada, have agreed to limit
emissions of greenhouse gases pursuant to the United Nations
Framework Convention on Climate Change, also known as the
Kyoto Protocol. In December 2002, Canada ratified
the Kyoto Protocol. The Kyoto Protocol requires Canada to reduce
its emissions of greenhouse gases to 6% below 1990 levels by
2012. The implementation of the Kyoto Protocol in Canada is
expected to affect the operation of all industries in Canada,
including the well service industry and its customers in the oil
and natural gas industry. On April 26, 2007, the Government
of Canada released its Action Plan to Reduce Greenhouse Gases
and Air Pollution (the Action Plan) also known as ecoACTION,
which includes the regulatory framework for air emissions. This
Action Plan covers not only large industry, but regulates the
fuel efficiency of vehicles and strengthens energy standards for
a number of products. On March 10, 2008, the Government of
Canada released details of the Action Plans regulatory
framework, which includes a requirement that all covered
industrial sectors, including upstream oil and gas facilities
meeting certain threshold requirements, reduce their emissions
from 2006 levels by 18% by 2010. The Government of Canada is in
the process of developing regulations to implement the Action
Plan. As precise details of the implementation of the Action
Plan have not yet been finalized, the exact effect on our
operations in Canada cannot be determined at this time. It is
possible that already stringent air emissions regulations
applicable to our operations and the operations of our customers
in Canada will be replaced with even stricter requirements prior
to 2012. These requirements could increase the cost of doing
business for us and our customers, reduce the demand for the oil
and gas our customers produce, and thus have an adverse effect
on the demand for our products and services.
We are also subject to the requirements of the federal
Occupational Safety and Health Act (OSHA) and
comparable state statutes that regulate the protection of the
health and safety of workers. In addition, the OSHA hazard
communication standard requires that information be maintained
about hazardous materials used or produced in operations and
that this information be provided to employees, state and local
government authorities and the public. We believe that our
operations are in substantial compliance with the OSHA
requirements, including general industry standards, record
keeping requirements, and monitoring of occupational exposure to
regulated substances.
Employees
As of December 31, 2010, we had 6,572 employees. Of
our total employees, 5,890 were in the United States, 301 were
in Canada, 298 were in Mexico and 83 were in Singapore and other
locations in Southeast Asia. We are a party to certain
collective bargaining agreements in Mexico. Other than these
agreements in Mexico, we are not a party to any collective
bargaining agreements, and we consider our relations with our
employees to be satisfactory.
Website
Access to Our Periodic SEC Reports
We periodically file or furnish documents to the Securities and
Exchange Commission (SEC), including our Annual
Report on
Form 10-K,
Quarterly Reports on
Form 10-Q,
Current Reports on
Form 8-K
and other reports as required. These reports are linked to and
available from our corporate website free of charge, as soon as
reasonably practicable after we file such material, or furnish
it to the SEC. Our primary internet address is:
http://www.completeproduction.com.
Our website also includes certain corporate governance
documentation such as our business ethics policy. As permitted
by the SEC rules, we may occasionally provide important
disclosures to investors by posting them in the investor
relations section of our website. However, the information
contained on our website is not incorporated by reference into
this Annual Report and should not be considered part of this
report.
The information we file with the SEC may also be read and copied
at the SECs Public Reference Room at 100F Street, N.E.,
Washington, D.C. 20549. In addition, the SEC maintains a
website at:
http://www.sec.gov
which contains reports, proxy and other documents regarding our
company which are filed electronically with the SEC.
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Forward-looking
Statements
Certain statements and information in this Annual Report on
Form 10-K
may constitute forward-looking statements within the
meaning of the Private Securities Litigation Act of 1995. These
forward-looking statements are based on our current
expectations, assumptions, estimates and projections about us
and the oil and gas industry. While management believes that
these forward-looking statements are reasonable as and when
made, there can be no assurance that future developments
affecting us will be those that we anticipate. These
forward-looking statements involve risks and uncertainties that
may be outside of our control and could cause actual results to
differ materially from those in the forward-looking statements.
Factors that could cause or contribute to such differences
include, but are not limited to: market prices for oil and gas,
the level of oil and gas drilling, economic and competitive
conditions, capital expenditures, regulatory changes and other
uncertainties. Other factors that could cause our actual results
to differ from our projected results are described in:
Item 1A. Risk Factors. See Item 1A.
Risk Factors and Item 7.
Managements Discussion and Analysis of Financial
Condition and Results of Operations Overview
for a discussion of trends and factors affecting us and our
industry. Also see Item 8. Financial Statements and
Supplementary Data, Note 15 Segment
Reporting for financial information about each of our
business segments.
Although we believe that the forward-looking statements
contained in this Annual Report are based upon reasonable
assumptions, the forward-looking events and circumstances
discussed in this document 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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general economic and market conditions;
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our access to current or future financing arrangements;
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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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our ability to replace or add workers at economic rates;
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environmental and other governmental regulations including
climate change related legislation; and
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the effects of severe weather on our services, centers or
equipment.
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In light of these risks, uncertainties and assumptions, the
forward-looking events discussed in this Annual Report may not
occur, and therefore, our forward-looking statements speak only
as of the date of this Annual Report. Unless otherwise required
by law, we undertake no obligation and do not intend to update
publicly any forward-looking statements, even if new information
becomes available or other events occur in the future. These
cautionary statements qualify all such forward-looking
statements attributable to us or persons acting on our behalf.
An investment in our common stock involves a degree of risk. You
should carefully consider the following risk factors, together
with the other information contained in this Annual Report and
other public filings with the SEC, before deciding to invest in
our common stock. Additional risks and uncertainties not
currently known to us or that we currently view as immaterial
may also impair our business. If any of these risks develop into
actual events, our business, financial condition, results of
operations or cash flows could be materially adversely affected,
and you could lose all or part of your investment.
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Risks
Related to Our Business and Our Industry
Our
business depends on the oil and gas industry and particularly on
the level of activity for North American oil and gas. Our
markets 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 for, develop and produce oil
and gas in North America. If these expenditures decline, our
business may suffer. Our customers willingness to explore,
develop and produce depends largely upon prevailing industry
conditions that are influenced by numerous factors over which
management has no control, such as:
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the supply of and demand for oil and gas, including current
natural gas storage capacity and usage;
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the level of prices, and expectations about future prices, of
oil and gas;
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the cost of exploring for, developing, producing and delivering
oil and gas;
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the expected rates of declining current production;
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the discovery rates of new oil and gas reserves;
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available pipeline and other transportation capacity;
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weather conditions, including hurricanes that can affect oil and
gas operations over a wide area;
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domestic and worldwide economic conditions;
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political instability in oil and gas producing countries;
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technical advances affecting energy consumption;
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the price and availability of alternative fuels;
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the access to and cost of capital for oil and gas
producers; and
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merger and divestiture activity among oil and gas producers.
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The level of activity in the North American oil and gas
exploration and production industry is volatile. Expected trends
in oil and gas production activities may not continue and demand
for the services provided by us may not reflect the level of
activity in the industry. Oil and natural gas prices and rotary
rig counts declined sharply in the fourth quarter of 2008 and
remained relatively low throughout 2009 compared to the levels
in mid-2008. Although activity began to recover at the end of
2009 and improved throughout 2010, an unexpected material
decline in oil and gas prices or North American activity levels
could occur again and have a material adverse effect on our
business, financial condition, results of operations and cash
flows. In addition, a decrease in the development rate of oil
and gas reserves in our market areas may also have an adverse
impact on our business, even in an environment of stronger oil
and gas prices.
Because
the oil and gas industry is cyclical, our operating results may
fluctuate.
Oil and gas prices are volatile. WTI oil commodity prices
reached historic highs in 2008 then declined substantially by
year end and remained at depressed levels through much of 2009.
Oil prices rebounded in 2010, reaching a high of $91.48 towards
the end of the year. Henry Hub natural gas prices averaged $8.89
per mcf in 2008, but exceeded $12.00 per mcf in June of 2008,
before falling below $6.00 per mcf at the end of 2008. Natural
gas prices did not exceed $6.11 per mcf in 2009 and averaged
$3.94 per mcf during that year. Prices for natural gas rebounded
somewhat in 2010, although the average was only $4.38 per mcf.
Declines in oil and gas prices result in a decrease in the
expenditure levels of oil and gas companies and drilling
contractors which in turn adversely affects us. We have
experienced in the past, and may experience in the future,
significant fluctuations in operating results as a result of the
reactions of our customers to actual and anticipated changes in
oil and gas prices. We reported income from continuing
operations in 2010 of $84.2 million, a loss from continuing
operations of $181.7 million in 2009 which included a goodwill
impairment loss of $97.6 million and fixed asset and other
intangible impairment losses totaling $38.6 million, and a
loss from continuing operations of $84.7 million in 2008 which
included a goodwill impairment loss of $272.0 million.
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With the exception of our pressure pumping operations,
substantially all of the service and rental revenue we earn is
based upon a charge for a relatively short period of time (an
hour, a day, a week) for the actual period of time the service
or rental is provided to our customer. By contracting services
on a short-term basis, we are exposed to the risks of a rapid
reduction in market price and utilization and volatility in our
revenues. Product sales are recorded when the actual sale
occurs, title or ownership passes to the customer and the
product is shipped or delivered to the customer.
Our
business depends upon our ability to obtain key materials and
specialized equipment from suppliers. Shortages of these
materials or equipment or an increase in the cost of these items
which are used in our operations or an increase in the cost to
manufacture this equipment could adversely affect our operations
in the future.
We do not have long-term contracts with the third party
suppliers of many of the products that we use in large volumes
in our operations, including many parts we use in the
manufacture of our fracturing units and pumps, coiled tubing
pipe, some of the chemicals and sand we use in fracturing fluids
and the fuel we use in our equipment and vehicles. During
periods in which certain of our services are in high demand, the
availability of the key products used in our industry decreases
and the price of such products increases. Our industry has
faced sporadic proppant shortages associated with pressure
pumping operations requiring work stoppages which adversely
impacted the operating results of several competitors and, in
the fourth quarter of 2010, we experienced logistical
constraints in North Dakota adversely impacting our results. In
addition, rising diesel fuel prices have had a significant
impact on our expenses, and adversely impacted our earnings in
some periods. We are dependent on a small number of suppliers
for certain parts that are in high demand in our industry. Our
reliance on a small number of suppliers could increase the
difficulty of obtaining such parts in the event of a shortage of
those parts in our industry. Should our current suppliers be
unable to provide the necessary raw materials (proppant,
chemicals, cement or explosives) or finished products (such as
workover rigs or fluid-handling equipment) or otherwise fail to
deliver the products timely and in the quantities required, any
resulting delays in the provision of services could have a
material adverse effect on our business, financial condition,
results of operations and cash flows.
We rely on certain related parties (e.g., companies
majority-owned by certain of our directors or current or former
officers or employees) for the purchase and manufacture of a
significant amount of the equipment, including pressure pumping
units, used in our operations. Concentrating our equipment
supply needs on one or more related parties could adversely
impact our results of operations if any of the related parties
experience shortages or other interruptions to their
businesses. See Note 19, Related party transactions
in our notes to consolidated financial statements included
elsewhere in this Annual Report.
There
is potential for excess capacity in our industry.
Because oil and gas prices and drilling activity are at high
levels and service companies are seeing increasing demand for
services and attractive returns on investments, oilfield service
companies are ordering new equipment to expand their services. A
growing supply of equipment may result in an increasingly
competitive environment for oilfield service companies, which
may lead to lower prices and utilization for our services which
would adversely affect our business.
We are
subject to federal, state and local laws and regulations
regarding issues of health, safety and protection of the
environment, including climate change. Under these laws and
regulations, we may become liable for penalties, damages or
costs of remediation or other corrective measures. Any changes
in laws or government regulations could increase our costs of
doing business.
Our operations are subject to stringent federal, state and local
laws and regulations relating to, among other things, protection
of natural resources, wetlands, endangered species, the
environment, health and safety, waste management, waste
disposal, and transportation of waste and other materials. Such
laws and regulations include the Resource Recovery and
Conservation Act, the Comprehensive Environmental Response,
Compensation, and Liability Act, the Clean Water Act, the Safe
Drinking Water Act and analogous state laws. Our operations pose
risks of environmental liability, including leakage from our
operations to surface or subsurface soils, surface water or
groundwater. Some environmental laws and regulations may impose
strict, joint and several liability. Therefore in
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some situations we could be exposed to liability as a result of
our conduct that was lawful at the time it occurred or the
conduct of, or conditions caused by, third parties. Actions
arising under these laws and regulations could result in the
shutdown of our operations, fines and penalties, expenditures
for remediation or other corrective measures, and claims for
liability for property damage, exposure to hazardous materials
or hazardous waste, or personal injuries. Sanctions for
noncompliance with applicable environmental laws and regulations
also may include the assessment of administrative, civil or
criminal penalties, revocation of permits, temporary or
permanent cessation of operations in a particular location and
issuance of corrective action orders. Such claims or sanctions
and related costs could cause us to incur substantial costs or
losses and could have a material adverse effect on our business,
financial condition and results of operations. An increase in
regulatory requirements on oil and gas exploration and
completion activities could significantly delay or interrupt our
operations.
If we do not perform in accordance with government, industry or
our own safety standards, we could lose business from certain
customers, many of whom have an increased focus on safety issues
as a result of recent incidents, such as the Macondo Well event
in the Gulf of Mexico, and governmental initiatives on safety
and environmental issues related to E&P activities.
On June 9, 2009, companion bills entitled the Fracturing
Responsibility and Awareness of Chemicals (FRAC) Act of 2009
were introduced in the United States Senate (S. 1215) and
House of Representatives (H.R. 2766). Currently, unless the
fracturing fluid used in the hydraulic fracturing process
contains diesel, hydraulic fracturing operations are exempt from
regulation under the federal Safe Drinking Water Act. The FRAC
Act would remove the permit exemption and require the United
States Environmental Protection Agency (the EPA), to
promulgate regulations on hydraulic fracturing. Further, states
with delegated authority to implement the Safe Drinking Water
Act would have to modify their programs to remain consistent
with any new federal regulations. The FRAC Act would also
require persons conducting hydraulic fracturing, such as us, to
disclose the chemical constituents of their fracturing fluids to
a regulatory agency. This Act would make the information public
via the internet, which could make it easier for third parties
opposed to the hydraulic fracturing process to initiate legal
proceedings based on allegations that specific chemicals used in
the fracturing process could adversely affect the environment,
including groundwater, soil or surface water. If this or similar
legislation becomes law, the legislation could establish an
additional level of regulation at the federal level that could
lead to operational delays or increased operating costs, making
it more difficult to perform hydraulic fracturing and increasing
our costs of compliance and doing business. Currently, neither
S. 1215 nor H.R. 2766 is scheduled for consideration by the
Senate or the House, and it is not clear whether the
111th Congress will act on either bill. Compliance or the
consequences of any failure to comply by us could have a
material adverse effect on our business, financial condition and
operational results.
Another bill has been introduced in Congress in 2010 that would
require disclosure of chemicals used in hydraulic fracturing
operations. The Clean Energy Jobs and Oil Company Accountability
Act of 2010 (S. 3663) remains on the Senate Legislative
Calendar under General Orders, and would amend the Emergency
Planning and Community
Right-to-Know
Act by requiring any person using hydraulic fracturing for an
oil or natural gas well to submit to the state, or make publicly
available, the list of chemicals used in each hydraulic
fracturing process (identified by well location and number),
including the chemical constituents of mixtures, Chemical
Abstracts Service registry numbers, and material safety data
sheets. S. 3663 would not, however, require public disclosure of
proprietary chemical formulas.
Several states have considered, or are considering, legislation
or regulations similar to the federal legislation described
above or are taking action to restrict hydraulic fracturing in
certain jurisdictions. In June 2010, the Wyoming Oil and Gas
Conservation Commission passed a rule requiring disclosure of
hydraulic fracturing fluid content. In October 2010, the
Governor of Pennsylvania issued a moratorium on new natural gas
development on state forest lands. In November 2010, the
Pennsylvania Environmental Quality Board proposed regulations
that would require reporting of the chemicals used in fracturing
fluids. At this time, it is not possible to estimate the
potential impact on our business of these state actions or the
enactment of additional federal or state legislation or
regulations affecting hydraulic fracturing.
On February 18, 2010, the Energy and Commerce Committee of
the United States House of Representatives requested that we and
other companies provide information concerning the chemicals
used in hydraulic fracturing. Subsequently, we received
follow-up
requests from the Committee for additional information and
documentation.
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We have worked with the Committees staff to provide
information concerning such chemicals while at the same time
acting to protect our proprietary interests and to fulfill our
contractually imposed confidentiality obligations to certain
customers.
Also, the EPA is reviewing the scope of its existing regulatory
authority and evaluating whether and how it can regulate
hydraulic fracturing. The EPA recently requested additional
information from us and several other service companies
concerning hydraulic fracturing. In addition, in March 2010, the
EPA announced its intention to conduct a comprehensive research
study, ordered by Congress, on the potential adverse impacts
that hydraulic fracturing may have on water quality and public
health. As part of this study, the EPA is conducting public
hearings across the country. Even if the FRAC Act or similar
legislation is not adopted, the EPA study, depending on its
results, could spur further initiatives to regulate hydraulic
fracturing under the Safe Drinking Water Act or otherwise. The
EPA has announced that the energy extraction sector is one of
the sectors designated for increased enforcement over the next
three to five years.
Additionally, the EPAs Tier IV regulations apply to
certain off-road diesel engines that are used by us to power
equipment in the field. Under these regulations, we are limited
in the number of non-compliant off-road diesel engines we can
purchase. Until
Tier IV-compliant
engines that meet our needs are available, these regulations
could limit our ability to acquire a sufficient number of diesel
engines to expand our fleet and to replace existing engines as
they are taken out of service.
Laws protecting the environment generally have become more
stringent over time and we expect them to continue to do so,
which could lead to material increases in our costs for future
environmental compliance and remediation. The effect of
environmental laws and regulations on our business is discussed
in greater detail in Item 1, Business
Environmental Matters of this Annual Report.
We may
be exposed to certain regulatory and financial risks related to
climate change.
Current and future regulatory initiatives directed at climate
change may increase our operating costs and may, in the future,
reduce the demand for hydrocarbons that our customers produce.
In 2009 and 2010, the United States Congress considered a
variety of legislation on climate change. These bills or new
legislation may be considered by the current Congress. In
substance, most legislative proposals contain a cap and
trade approach to greenhouse gas regulation. Under such an
approach, companies would be required to hold sufficient
emission allowances to cover their greenhouse gas emissions.
Over time, the total number of allowances would be reduced or
expire, thereby relying on market-based incentives to allocate
investment in emission reductions across the economy. As the
number of available allowances declines, the cost would
presumably increase. In addition to the prospect of federal
legislation, several states have adopted or are in the process
of adopting greenhouse gas reporting or
cap-and-trade
programs. Therefore, while the outcome of the federal and state
legislative processes is currently uncertain, if such an
approach were adopted (either by domestic legislation,
international treaty obligation or domestic regulation), our
operating costs could increase as could the operating costs of
our customers, as they buy additional allowances or embark on
emission reduction programs. Such legislation could have both a
direct and indirect effect on our business.
Even without further federal legislation, the EPA has begun to
regulate greenhouse gas emissions. In December 2009, the EPA
released an Endangerment and Cause or Contribute Findings for
Greenhouse Gases, which became effective in January 2010. This
regulatory finding sets the foundation for future EPA greenhouse
gas regulation under the Clean Air Act. The EPA also promulgated
a new greenhouse gas reporting rule, which became effective in
December 2009, and which requires facilities that emit more than
25,000 tons per year of carbon dioxide-equivalent emissions to
prepare and file certain emission reports. On May 12, 2010,
the EPA issued a new tailoring rule, which proposed
and imposes additional permitting requirements on certain
stationary sources emitting over 75,000 tons per year of carbon
dioxide equivalent emissions. The EPA is considering additional
rulemaking to apply these requirements to broader classes of
emission sources by 2012, which may apply to some of our
facilities. Finally, on November 8, 2010, the EPA adopted
rules expanding the industries subject to greenhouse gas
reporting to include certain petroleum and natural gas
facilities. These rules require data collection beginning in
2011 and reporting beginning in 2012. Many of our
customers facilities are subject to these rules. As a
result of these regulatory initiatives, our operating costs may
increase in compliance with these programs, although we are
22
not situated differently in this respect from our competitors in
the industry. Our customers operating costs may also
increase, thereby having a potential indirect effect on our
business.
Future
growth in our business could strain our resources, causing us to
lose customers and increase our operating
expenses.
The expansion of our business through organic growth can impact
us. We have experienced
short-term
logistical constraints in positioning assets during 2010, and
expect that we might incur such constraints in the future. In
addition, as we expand into new geographic regions and service
lines and add new equipment, we could incur delays and will
incur costs to attract, train and retain staff to crew the
equipment as well as costs to adequately train these new
employees. Our inability to manage our growth effectively or to
maintain the quality of our services, products and personnel
could have a material adverse effect on our business, financial
condition or results of operations.
Changes
in trucking regulations may increase our costs and negatively
impact our results of operations.
We operate trucks and other heavy equipment associated with many
of our service offerings. We therefore are subject to regulation
as a motor carrier by the United States Department of
Transportation and by various state agencies, whose regulations
include certain permit requirements of state highway and safety
authorities. These regulatory authorities exercise broad powers
over our trucking operations, generally governing such matters
as the authorization to engage in motor carrier operations,
safety, equipment testing and specifications and insurance
requirements. The trucking industry is subject to possible
regulatory and legislative changes that may impact our
operations by requiring changes in fuel emissions limits, the
hours of service regulations that govern the amount of time a
driver may drive or work in any specific period, limits on
vehicle weight and size and other matters, including safety
requirements. On May 21, 2010 the Obama Administration
announced proposed regulations that would set mileage
requirements and emissions limits for medium- and heavy-duty
trucks. A final rule is expected by July 30, 2011 effective
for the 2014 model year. Associated with this ruling, we may
experience an increase in costs related to truck purchases or
maintenance. Proposals to increase federal, state, or local
taxes, including taxes on motor fuels, are also made from time
to time, and any such increase would increase our operating
costs. We cannot predict whether, or in what form, any
legislative or regulatory changes applicable to our trucking
operations will be enacted.
Our
indebtedness could restrict our operations and make us more
vulnerable to adverse economic conditions.
As of December 31, 2010, our long-term debt, including
current maturities, was $650 million. Our level of
indebtedness may adversely affect operations and limit our
growth, and we may have difficulty making debt service payments
on our indebtedness as such payments become due. Our level of
indebtedness may affect our operations in several ways,
including the following:
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our vulnerability to general adverse economic and industry
conditions;
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the covenants that are contained in the agreements that govern
our indebtedness limit our ability to borrow funds, dispose of
assets, pay dividends and make certain investments;
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any failure to comply with the financial or other covenants of
our debt could result in an event of default, which could result
in some or all of our indebtedness becoming immediately due and
payable; and
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our level of debt may impair our ability to obtain additional
financing in the future for working capital, capital
expenditures, acquisitions or other general corporate purposes.
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We may
not be able to provide services that meet the specific needs of
oil and gas exploration and production companies at competitive
prices.
The markets in which we operate are highly competitive and have
relatively few barriers to entry. The principal competitive
factors in our markets are product and service quality and
availability, responsiveness, experience, technology, equipment
quality, reputation for safety and price. We compete with large
national and multi-national companies that have longer operating
histories, greater financial, technical and other resources and
greater name recognition than we do. Several of our competitors
provide a broader array of services and have a stronger presence
23
in more geographic markets. In addition, we compete with several
smaller companies capable of competing effectively on a regional
or local basis. Our competitors may be able to respond more
quickly to new or emerging technologies and services and changes
in customer requirements. Some contracts are awarded on a bid
basis, which further increases competition based on price. As a
result of competition, we may lose market share or be unable to
maintain or increase prices for our present services or to
participate in additional business opportunities, which could
have a material adverse effect on our business, financial
condition, results of operations and cash flows. In addition,
competition among oilfield service and equipment providers is
affected by each providers reputation for safety and
quality. Although we believe that our reputation for safety and
quality service is good, we cannot assure that we will be able
to maintain our competitive position.
Our
executive officers and certain key personnel are critical to our
business and these officers and key personnel may not remain
with us in the future.
Our future success depends upon the continued service of our
executive officers and other key personnel. If we lose the
services of one or more of our executive officers or key
employees, our business, operating results and financial
condition could be harmed.
Our
inability to control the inherent risks of acquiring and
integrating businesses could adversely affect our
operations.
Acquisitions have been, and our management believes acquisitions
will continue to be, a key element of our business strategy. We
may not be able to identify and acquire acceptable acquisition
candidates on favorable terms in the future. We may be required
to incur substantial indebtedness to finance future acquisitions
and also may issue equity securities in connection with such
acquisitions. We may not be able to secure additional capital to
fund acquisitions. If we are able to obtain financing, such
additional debt service requirements may impose a significant
burden on our results of operations and financial condition. The
issuance of additional equity securities could result in
significant dilution to stockholders. Acquisitions may not
perform as expected when the acquisition was made and may be
dilutive to our overall operating results. Additional risks we
will face include:
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retaining and attracting key employees;
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retaining and attracting new customers;
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increased administrative burden;
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developing our sales and marketing capabilities;
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managing our growth effectively;
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integrating operations;
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operating a new line of business; and
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increased logistical problems common to large, expansive
operations.
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If we fail to manage these risks successfully, our business
could be harmed.
Our
customer base is concentrated within the oil and gas production
industry and loss of a significant customer could cause our
revenue to decline substantially.
Our top five customers accounted for approximately 39%, 33% and
28% of our revenue for the years ended December 31, 2010,
2009 and 2008, respectively. Our top ten customers represented
approximately 52%, 49% and 45% of our revenue for the years then
ended. Our top two customers provided 12.2% and 10.7% of our
total annual revenue in 2010, and these same two customers
provided 9.9% and 9.7% of our total annual revenue in 2009. It
is likely that we will continue to derive a significant portion
of our revenue from a relatively small number of customers in
the future. If a major customer decided not to continue to use
our services, revenue would decline and our operating results
and financial condition could be harmed. For a list of our top
ten customers, see Item 1. Business
Customers.
24
We may
be unable to attract and retain a sufficient number of skilled
and qualified workers.
The delivery of our services and products requires personnel
with specialized skills and experience who can perform
physically demanding work. As a result of the volatility of the
oilfield service industry and the demanding nature of the work,
workers may choose to pursue employment in fields that offer a
more desirable work environment. Our ability to be productive
and profitable will depend upon our ability to employ and retain
skilled workers. In addition, our ability to expand our
operations depends in part on our ability to increase the size
of our skilled labor force. The demand for skilled workers is
high, and the supply is limited, particularly in the
U.S. Rocky Mountain region, which is one of our key
regions. In addition, although our employees in the United
States are not covered by a collective bargaining agreement,
some of our employees have in the past been targeted by labor
unions in an effort to organize such employees. A significant
increase in the wages paid by competing employers or the
unionization of groups of our employees could result in a
reduction of our skilled labor force, increases in the wage
rates that we must pay, or both. If either of these events were
to occur, our capacity and profitability could be diminished and
our growth potential could be impaired.
Our
operations are subject to hazards inherent in the oil and gas
industry.
Risks inherent to our industry, such as equipment defects,
vehicle accidents, explosions and uncontrollable flows of gas or
well fluids, can cause personal injury, loss of life, suspension
of operations, damage to formations, damage to facilities,
business interruption and damage to or destruction of property,
equipment and the environment. These risks could expose us to
substantial liability for personal injury, wrongful death,
property damage, loss of oil and gas production, pollution and
other environmental damages. The frequency and severity of such
incidents will affect operating costs, insurability and
relationships with customers, employees and regulators. In
particular, our customers may elect not to purchase our services
if they view our safety record as unacceptable, which could
cause us to lose customers and substantial revenues. In
addition, these risks may be greater for us because we sometimes
acquire companies that have not allocated significant resources
and management focus to safety and have a poor safety record.
Our operations have experienced fatalities. Many of the claims
filed against us arise from vehicle-related accidents that have
in certain specific instances resulted in the loss of life or
serious bodily injury. Our safety procedures may not always
prevent such damages. Our insurance coverage may be inadequate
to cover our liabilities. In addition, we may not be able to
maintain adequate insurance in the future at rates we consider
reasonable and commercially justifiable and insurance may not
continue to be available on terms as favorable as our current
arrangements. The occurrence of a significant uninsured claim, a
claim in excess of the insurance coverage limits maintained by
us or a claim at a time when we are not able to obtain liability
insurance could have a material adverse effect on our ability to
conduct normal business operations and on our financial
condition, results of operations and cash flows. Although our
senior management is committed to improving our overall safety
record, they may not be successful in doing so.
If we
are not able to implement commercially competitive services and
access commercially competitive products in a timely manner in
response to changes in technology, our business and revenue
could be materially and adversely affected.
The market for our services and products is characterized by
continual technological developments to provide better and more
reliable performance and services. If we are not able to
implement commercially competitive services and access
commercially competitive products in a timely manner in response
to changes in technology, our business and revenue could be
materially and adversely affected. Likewise, if our proprietary
technologies, equipment and facilities, or work processes become
obsolete, we may no longer be competitive, and our business and
revenue could be materially and adversely affected.
We are
self-insured for certain health care benefits for our
employees.
We are self-insured for claims arising from healthcare benefits
provided to certain of our employees in the United States. Under
this self-insurance program, we use the services of an insurance
company, the former provider of full insurance coverage prior to
the inception of the program in 2007, to administer the program
on a
fee-per-participant
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basis, and we have purchased a stop-loss policy with this
provider to insure for individual claims which exceed a
designated ceiling. Pursuant to this program, we accrue expense
based upon expected claims, and make periodic claim payments to
the administrator, who then facilitates claim payments to the
medical care providers. With the passage of time and as our
business expands and more employees enroll in our healthcare
benefit plan, we may choose or be required to maintain higher
self-insured retention levels. There is a risk that our actual
claims incurred may exceed the projected claims, and we may
incur more expense than expected for health insurance coverage.
There is also a risk that we may not adequately accrue for
claims that are incurred but not reported. Either of these
events could have a material adverse effect on our financial
position, results of operations or cash flows.
If we
become subject to product liability claims, it could be
time-consuming and costly to defend.
Since our customers use our products, or third party products
that we sell or rent, errors, defects or other performance
problems could result in financial or other damages to us. Our
customers could seek damages from us for losses associated with
these errors, defects or other performance problems. If
successful, these claims could have a material adverse effect on
our business, operating results or financial condition. Our
existing product liability insurance may not be enough to cover
the full amount of any loss we might suffer. A product liability
claim brought against us, even if unsuccessful, could be
time-consuming and costly to defend and could harm our
reputation.
Impairment
of Long-term Assets
We evaluate our long-term assets including property, plant and
equipment, identifiable intangible assets and goodwill in
accordance with generally accepted accounting principles in the
U.S. In performing this assessment, we project future cash
flows on a discounted basis for goodwill, and on an undiscounted
basis for other long-term assets, and compare these cash flows
to the carrying amount of the related net assets. The cash flow
projections are based on our current operating plan, estimates
and judgmental assessments. We perform this assessment of
potential impairment at least annually, but also whenever facts
and circumstances indicate that the carrying value of the net
assets may not be recoverable due to various external or
internal factors, termed a triggering event. We have
recorded goodwill impairment charges of $97.6 million and
$272.0 million for the years ended December 31, 2009
and 2008, respectively, with no goodwill impairment charges for
the year ended December 31, 2010. In 2009, management
performed additional analysis and determined that further
write-downs were necessary, which resulted in a fixed asset
impairment in our drilling services segment of
$36.2 million recorded in September 2009, and an intangible
asset impairment in our completion and production services
segment totaling $2.5 million recorded in December 2009.
Based on our annual impairment test results in 2010, we did not
record any significant impairment losses for the year ended
December 31, 2010. While we did not incur impairment
charges in 2010, if we determine that our estimates of future
cash flows were inaccurate or our actual results for 2011 are
materially different than expected, we could record additional
impairment charges at interim periods during 2011 or in future
years, which could have a material adverse effect on our
financial position and results of operations.
Many
of our customers activity levels, spending for our
products and services, and payment patterns may be impacted by
deterioration in the credit markets.
Many of our customers finance their activities through cash flow
from operations, the incurrence of debt or the issuance of
equity. In late 2008 and throughout 2009, there was a
significant decline in the credit markets and the availability
of credit. Additionally, many of our customers equity
values substantially declined. The combination of a reduction of
cash flow resulting from declines in commodity prices, a
reduction in borrowing bases under reserve-based credit
facilities and the lack of availability of debt or equity
financing may result in a significant reduction in our
customers spending for our products and services. A
prolonged reduction in spending could have a material adverse
effect on our operations.
In addition, while historically our customer base has not
presented significant credit risks, the same factors that may
lead to a reduction in our customers spending also may
increase our exposure to the risks of nonpayment and
nonperformance by our customers. A significant reduction in our
customers liquidity may result in a decrease in their
ability to pay or otherwise perform on their obligations to us.
Any increase in the nonpayment of and nonperformance by our
counterparties, either as a result of recent changes in
financial and economic conditions or otherwise, could have an
adverse impact on our operating results and could adversely
affect our liquidity.
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We
participate in a capital intensive business. We may not be able
to finance future growth of our operations or future
acquisitions.
Historically, we have funded the growth of our operations and
our acquisitions from bank debt, private placement of shares,
our initial public offering in April 2006, a private placement
of debt in December 2006, as well as cash generated by our
business. In the future, we may not be able to continue to
obtain sufficient bank debt at competitive rates or complete
equity and other debt financings. If we do not generate
sufficient cash from our business to fund operations, our growth
could be limited unless we are able to obtain additional capital
through equity or debt financings. Our inability to grow as
planned may reduce our chances of maintaining and improving
profitability.
If we
fail to maintain an effective system of internal controls, we
may not be able to accurately report our financial results or
prevent fraud.
Effective internal controls are necessary for us to provide
reliable financial reports and effectively prevent fraud. If we
cannot provide reliable financial reports or prevent fraud, our
reputation and operating results would be harmed. Our efforts to
maintain internal controls may not be successful, and we may be
unable to maintain adequate controls over our financial
processes and reporting in the future, including compliance with
the obligations under Section 404 of the Sarbanes-Oxley Act
of 2002. Any failure to maintain effective controls or to make
effective improvements to our internal controls could harm our
operating results.
In 2010, our management approved a plan to implement new
accounting software which will replace our existing accounting
systems at several of our operating divisions in a phased
approach. Two divisions converted during the fourth quarter of
2010 and two divisions will convert during 2011. In addition, we
implemented a new chart of accounts which is being adopted as
these divisions convert to the new software. Although we believe
the new software, once implemented, will enhance our internal
control over financial reporting and we believe that we have
taken the necessary steps to maintain appropriate internal
control over financial reporting during this period of system
change, we will continuously monitor controls through and around
the system to provide reasonable assurance that controls are
effective during and after each step of this implementation
process.
Conservation
measures and technological advances could reduce demand for oil
and gas.
Fuel conservation measures, alternative fuel requirements,
increasing consumer demand for alternatives to oil and gas,
technological advances in fuel economy and energy generation
devices could reduce demand for oil and gas. Management cannot
predict the impact of the changing demand for oil and gas
services and products, and any major changes may have a material
adverse effect on our business, financial condition, results of
operations and cash flows.
Fluctuations
in currency exchange rates in Canada could adversely affect our
business.
We have operations in Canada. As a result, fluctuations in
currency exchange rates in Canada could materially and adversely
affect our business. For each of the years ended
December 31, 2010, 2009 and 2008, our Canadian operations
represented approximately 5% of our revenue from continuing
operations. Our Canadian operations recorded income from
continuing operations before taxes of $1.3 million for the
year ended December 31, 2010 and recorded losses of
$11.1 million and $26.7 million for the years ended
December 31, 2009 and 2008, respectively. The loss in 2008
primarily resulted from a goodwill impairment charge.
Our
operations in Mexico are subject to specific risks, including
dependence on Petróleos Mexicanos (PEMEX) as
the primary customer, exposure to fluctuation in the Mexican
peso and workforce unionization.
The majority of our business in Mexico is performed for PEMEX
pursuant to multi-year contracts. These contracts are generally
two years in duration, specify an authorized spending amount and
are subject to competitive bid for renewal. Any failure by us to
renew or extend our existing contracts, or win award of
contracts that replace expiring contracts, could have an adverse
effect on our financial condition, results of operations and
cash flows. Additionally, PEMEX is experiencing budget
limitations that may affect its ability to make timely payments
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to us under our existing contracts. Recent regulatory and
financial uncertainty regarding PEMEXs drilling programs
and development budget could adversely impact PEMEXs
ability to fulfill certain of its payment obligations under
these contracts in a timely manner. A failure of PEMEX to make
required payments to us would adversely affect our Mexico-based
financial performance.
The PEMEX contracts provide that 70% to 80% of the value of our
billings under the contracts is charged to PEMEX in
U.S. dollars with the remainder billed in Mexican pesos.
The portion billed in U.S. dollars to PEMEX is converted to
pesos on the date of payment. Invoices are paid approximately
45 days after the invoice date. As such, we are exposed to
fluctuations in the value of the peso. A material decrease in
the value of the Mexican peso relative to the U.S. dollar
could negatively impact our revenues, cash flows and net income.
Our operations in Mexico are party to a collective labor
contract most recently modified on and effective as of October
2008 between Servicios Petrotec S.A. DE C.V., one of our
subsidiaries, and Unión Sindical de Trabajadores de la
Industria Metálica y Similares, the metal and similar
industry workers labor union. We have not experienced work
stoppages in the past but cannot guarantee that we will not
experience work stoppages in the future. A prolonged work
stoppage could negatively impact our revenues, cash flows and
net income.
Mexico
has experienced a period of increasing criminal violence and
such activities could affect our Mexico-based operations and
financial performance.
Recently, Mexico has experienced a period of increasing criminal
violence, primarily due to the activities of drug cartels and
related organized crime. Although the Mexican government has
implemented various security measures and strengthened its
military and police forces, drug-related crime continues to
exist in Mexico and has impacted our ability to safely conduct
business in certain areas of the country. Our inability to
conduct business in certain areas of Mexico, and the safety
risks in the areas of Mexico where we do conduct business, could
have a negative impact on our Mexico-based financial performance.
We
could be adversely affected by violations of the U.S. Foreign
Corrupt Practices Act and similar worldwide anti-bribery
laws.
We are subject to the U.S. Foreign Corrupt Practices Act
(the FCPA), which generally prohibits companies and
their intermediaries from making payments to
non-U.S. government
officials for the purpose of obtaining or retaining business or
securing any other improper advantage. We are also subject to
anti-bribery laws in the jurisdictions in which we operate.
Although we have policies and procedures designed to ensure that
we, our employees and our agents comply with the FCPA and other
anti-bribery laws, there is no assurance that such policies or
procedures will protect us against liability under the FCPA or
other laws for actions taken by our agents, employees and
intermediaries with respect to our business or any businesses
that we acquire. We do business in countries in which FCPA
violations have recently been enforced. Failure to comply with
the FCPA, other anti-bribery laws or other laws governing the
conduct of business with foreign government entities, including
local laws, could disrupt our business and lead to severe
criminal and civil penalties, including imprisonment, criminal
and civil fines, loss of our export licenses and suspension of
our ability to do business with the federal government. Other
remedial measures could include further changes or enhancements
to our procedures, policies, and controls and potential
personnel changes
and/or
disciplinary actions, any of which could have a material adverse
affect on our business, financial condition, results of
operations and liquidity. We could also be adversely affected by
any allegation that we violated such laws.
Severe
weather conditions may affect our operations.
Our business may be materially affected by severe weather
conditions in areas where we operate. This may entail the
evacuation of personnel and stoppage of services which could
adversely affect our financial condition, results of operations
and cash flows. Hurricanes and the threat of hurricanes during
this period will often result in the shut-down of oil and gas
operations in the Gulf of Mexico as well as land operations
within the hurricane path. During a shut-down period, we are
unable to access wellsites and our services are also shut down.
This situation can therefore create unpredictability in activity
and utilization rates, which can have a material adverse impact
on our business, financial conditions, results of operations and
cash flows. In addition, the extreme winter weather
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conditions in the first quarter of 2011 have adversely affected
our operations in North Dakota, Oklahoma and North Texas.
Our operations are directly affected by seasonal differences in
weather in Canada. The level of activity in the Canadian
oilfield services industry declines significantly in the second
calendar quarter, when the ground thaws and many secondary roads
are temporarily rendered incapable of supporting the weight of
heavy equipment. The duration of this period is referred to as
spring breakup and has a direct impact on our
activity levels in Canada. The timing and duration of
spring breakup depend on weather patterns but
generally spring breakup occurs in April and May.
Additionally, if an unseasonably warm winter prevents sufficient
freezing, we may not be able to access wellsites and our
operating results and financial condition may, therefore, be
adversely affected. The demand for our services may also be
affected by the severity of the Canadian winters. In addition,
during excessively rainy periods, equipment moves may be
delayed, thereby adversely affecting operating results. The
volatility in weather and temperature in the Canadian oilfield
can therefore create unpredictability in activity and
utilization rates. As a result, full-year results are not likely
to be a direct multiple of any particular quarter or combination
of quarters.
When
rig counts are low, our rig relocation customers may not have a
need for our services.
Many of the major U.S. onshore drilling services
contractors have capabilities to move their own drilling rigs
and related oilfield equipment and to erect rigs. When regional
rig counts are high, drilling services contractors exceed their
own capabilities and contract for additional oilfield equipment
hauling and rig erection capacity. Our rig relocation business
activity is highly correlated to the rig count; however, the
correlation varies over the rig count range. As rig count drops,
some drilling services contractors reach a point where all of
their oilfield equipment hauling and rig erection needs can be
met by their own fleets. If one or more of our rig relocation
customers reaches this tipping point, our revenues
attributable to rig relocation will decline much faster than the
corresponding overall decline in the rig count. This non-linear
relationship between our rig relocation business activity and
the rig count in the areas in which we have rig relocation
operations can significantly increase our earnings volatility
with respect to rig relocation.
Covenants
in our debt agreements restrict our business in many
ways.
The indenture governing our senior notes contains various
covenants that limit our ability
and/or our
restricted subsidiaries ability to, among other things:
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incur or assume liens or additional debt or provide guarantees
in respect of obligations of other persons;
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issue redeemable stock and certain preferred stock;
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pay dividends or distributions or redeem or repurchase capital
stock;
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prepay, redeem or repurchase subordinated debt;
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make loans and investments;
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enter into agreements that restrict distributions from our
subsidiaries;
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sell assets and capital stock of our subsidiaries;
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enter into certain transactions with affiliates;
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consolidate or merge with or into, or sell substantially all of
our assets to, another person; and
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enter into new lines of business.
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In addition, our amended revolving credit facility contains
restrictive covenants and requires us to maintain a fixed charge
coverage ratio based on borrowing base limitations and satisfy
other financial condition tests. Our ability to meet those
financial requirements can be affected by adverse industry
conditions and other events beyond our control, and we cannot
assure you that we will meet those requirements. A breach of any
of these covenants could result in a default under our amended
revolving credit facility
and/or the
notes. Upon the occurrence of an event of default under our
amended revolving credit facility, the lenders could elect to
declare all amounts outstanding to be immediately due and
payable and terminate all commitments to extend further credit.
We had no
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borrowings outstanding under our amended credit facility at
December 31, 2010. However, if we borrowed under this
facility and if we were unable to repay those amounts, the
lenders under our amended revolving credit facility could
proceed against the collateral granted to them to secure that
indebtedness. We have pledged a significant portion of our
assets as collateral under our amended revolving credit
facility. If the lenders under our amended revolving credit
facility accelerate the repayment of borrowings, we cannot
assure you that we will have sufficient assets to repay
indebtedness under our amended revolving credit facility and our
other indebtedness, including our senior notes.
Borrowings under our amended revolving credit facility would
bear interest at variable rates and could expose us to interest
rate risk. If interest rates increase, our debt service
obligations on the variable rate indebtedness would increase
even though the amount borrowed remained the same, and our net
income would decrease.
|
|
Item 1B.
|
Unresolved
Staff Comments.
|
None.
As of December 31, 2010, we owned 57 offices, facilities
and yards, of which 15 were in Texas, 18 were in Oklahoma, one
was in Arkansas, three were in North Dakota, one was in Montana,
one was in Wyoming, 10 were in Colorado, one was in Louisiana,
three were in Pennsylvania, two were in Alberta, Canada, one was
in Poza Rica, Mexico and one was in Singapore.
As of December 31, 2010, we owned or operated 64 saltwater
disposal wells, of which 29 were in Texas, 32 were in Oklahoma,
two were in Colorado, and one was in Arkansas. In addition, we
owned one and leased two drilling mud disposal facilities in
Oklahoma and one produced water evaporation facility in Wyoming.
In addition, as of December 31, 2010, we leased 209
offices, facilities and yards, of which 74 were in Texas, 25
were in Oklahoma, 18 were in Wyoming, 25 were in Colorado, 22
were in Pennsylvania, three were in North Dakota, 10 were
in Louisiana, three were in Arkansas, two were in Utah, 14 were
in Alberta, Canada, one was in British Columbia, Canada, six
were in Mexico and six were in Singapore.
We lease our corporate headquarters in Houston, Texas, as well
as administrative offices in Gainesville, Texas; Enid, Oklahoma;
Fredrick, Colorado; Eunice, Louisiana; Shelocta, Pennsylvania;
Calgary, Alberta, Canada; and additional office space in
Houston, Texas.
|
|
Item 3.
|
Legal
Proceedings.
|
In the normal course of our business, we are a party to various
pending or threatened claims, lawsuits and administrative
proceedings seeking damages or other remedies concerning our
commercial operations, products, employees and other matters,
including warranty and product liability claims and occasional
claims by individuals alleging exposure to hazardous materials,
on the job injuries and fatalities as a result of our products
or operations. Many of the claims filed against us relate to
motor vehicle accidents which can result in the loss of life or
serious bodily injury. Some of these claims relate to matters
occurring prior to our acquisition of businesses. In certain
cases, we are entitled to indemnification from the sellers of
such businesses.
Although we cannot know or predict with certainty the outcome of
any claim or proceeding or the effect such outcomes may have on
us, we believe that any liability resulting from the resolution
of any of these matters, to the extent not otherwise provided
for or covered by insurance, will not have a material adverse
effect on our financial position, results of operations or
liquidity.
We have historically incurred additional insurance premium
related to a cost-sharing provision of our general liability
insurance policy, and we cannot be certain that we will not
incur additional costs until either existing claims become
further developed or until the limitation periods expire for
each respective policy year. Any such additional premiums should
not have a material adverse effect on our financial position,
results of operations or liquidity.
|
|
Item 4.
|
(Removed
and Reserved)
|
30
PART II
|
|
Item 5.
|
Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities.
|
At February 14, 2011, we had 78,592,455 shares of
common stock outstanding, of which 1,353,996 shares were
non-vested restricted stock subject to forfeiture restrictions.
The common shares outstanding at February 14, 2011 were
held by 57 record holders, excluding stockholders for whom
shares are held in nominee or street
name. We had 5,000,000 authorized shares of $0.01 par value
preferred stock, of which none was issued and outstanding at
December 31, 2010 or February 14, 2011.
On April 21, 2006, our common stock began trading on the
New York Stock Exchange under the symbol CPX. On
April 26, 2006, we completed our initial public offering.
The following table presents the high and low sales prices of
our common stock reported on the New York Stock Exchange for
each of the calendar quarters in 2009 and 2010:
|
|
|
|
|
|
|
|
|
|
|
CPX Stock Price
|
Period
|
|
High
|
|
Low
|
|
Quarter ended March 31, 2009
|
|
$
|
10.10
|
|
|
$
|
2.32
|
|
Quarter ended June 30, 2009
|
|
$
|
8.31
|
|
|
$
|
3.27
|
|
Quarter ended September 30, 2009
|
|
$
|
11.72
|
|
|
$
|
6.78
|
|
Quarter ended December 31, 2009
|
|
$
|
13.48
|
|
|
$
|
9.11
|
|
Quarter ended March 31, 2010
|
|
$
|
16.06
|
|
|
$
|
10.83
|
|
Quarter ended June 30, 2010
|
|
$
|
15.97
|
|
|
$
|
11.33
|
|
Quarter ended September 30, 2010
|
|
$
|
21.69
|
|
|
$
|
13.68
|
|
Quarter ended December 31, 2010
|
|
$
|
32.72
|
|
|
$
|
20.52
|
|
The year-end closing sales price of our common stock was $13.00
on December 31, 2009, the last trading day of 2009, and
$29.55 on December 31, 2010, the last trading day of 2010.
Issuer
Purchases of Equity Securities:
In accordance with the provisions of the 2008 Incentive Award
Plan, holders of unvested restricted stock were given the option
to either remit to us the required withholding taxes associated
with the vesting of restricted stock, or to authorize us to
repurchase shares equivalent to the cost of the withholding tax
and to remit the withholding taxes on behalf of the holder. We
made no repurchases of our common stock during the year ended
December 31, 2008. However, pursuant to this provision, we
repurchased 18,743 shares in 2009 and 113,330 shares
in 2010, of which the following shares were purchased during the
quarter ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(d)
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum
|
|
|
|
|
|
|
|
|
|
(c)
|
|
|
Number (or
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
Approximate
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Dollar Value) of
|
|
|
|
(a)
|
|
|
|
|
|
Shares Purchased
|
|
|
Shares that May
|
|
|
|
Total
|
|
|
(b)
|
|
|
as Part of Publicly
|
|
|
Yet Be Purchased
|
|
|
|
Number of
|
|
|
Average Price
|
|
|
Announced Plans
|
|
|
Under the Plans or
|
|
Period
|
|
Shares Purchased
|
|
|
Paid per Share
|
|
|
or Programs
|
|
|
Programs
|
|
|
October 1 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
November 1 30, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
December 1 31, 2010
|
|
|
436
|
|
|
|
29.00
|
|
|
|
436
|
|
|
|
|
*
|
|
|
|
* |
|
We do not have a publicly announced stock repurchase program. We
had 1,672,854 shares of non-vested restricted stock
outstanding at December 31, 2010. The holders of these
shares have the option to either remit taxes due related to the
vesting of these shares or to authorize us to purchase the
shares at the current market value in a sufficient amount to
settle the related tax withholding. The amount purchased will
depend on the market value at the time and whether or not the
holders choose to surrender shares in settlement of the related
tax withholding. |
31
Equity
Compensation Plans:
The information relating to our equity compensation plans
required by Item 5 is incorporated by reference to such
information as set forth in Item 12. Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters contained herein.
Dividends:
We paid no dividends on our outstanding $0.01 par value
common stock for the years ended December 31, 2010, 2009 or
2008. We currently do not intend to pay dividends in the
foreseeable future, but rather plan to reinvest such funds in
our business. Furthermore, our credit facility and the indenture
governing our senior notes contain covenants which restrict us
from paying future dividends on our common stock.
32
Performance
Graph:
The information in this section of the Annual Report
pertaining to our performance relative to our peers is being
furnished but not filed with the SEC, and as such, the
information is neither subject to Regulation 14A or 14C or
to the liabilities of Section 18 of the Exchange Act of
1934.
The following chart presents a comparative analysis of the stock
performance of our common stock (CPX) relative to an
industry index, the Philadelphia Oil Service Sector Index
(OSX), and a broader market index,
Standard & Poors 500 Index
(S&P). This analysis assumes a $100 investment
in the underlying common stock of CPX, OSX and S&P on
April 21, 2006, the date of our initial public offering,
through December 31, 2010. This analysis does not purport
to be a representation of the actual market performance of our
stock or these indexes. This chart has been provided for
informational purposes to assist the reader in evaluating the
market performance of our common stock compared to other market
participants.
Notwithstanding anything to the contrary set forth in our
previous filings under the Securities Act of 1933, as amended,
or the Securities Exchange Act of 1934, as amended, which might
incorporate future filings made by us under those statutes, the
following Stock Performance Graph will not be deemed
incorporated by reference into any future filings made by us
under those statutes.
COMPARISON
OF 56 MONTH CUMULATIVE TOTAL RETURN*
Among
Complete Production Services, Inc, the S&P 500 Index
And The PHLX Oil Service Sector Index
|
|
* |
$100 invested on 4/21/06 in stock or 3/31/06 in index, including
reinvestment of dividends. Fiscal year ending December 31.
|
Copyright
©
2011 S&P, a division of The McGraw-Hill Companies Inc. All
rights reserved.
33
|
|
Item 6.
|
Selected
Financial Data.
|
The following table presents selected historical consolidated
financial and operating data for the periods shown. The selected
consolidated financial data as of December 31, 2006, 2007,
2008, 2009 and 2010 and for each of the years then ended have
been derived from our audited consolidated financial statements
for those dates and periods, adjusted for discontinued
operations, as indicated. The following information should be
read in conjunction with Managements Discussion and
Analysis of Financial Condition and Results of Operations
and our financial statements and related notes included
elsewhere in this Annual Report.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2006
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
(In thousands)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Completion and production services
|
|
$
|
860,508
|
|
|
$
|
1,238,126
|
|
|
$
|
1,541,709
|
|
|
$
|
897,584
|
|
|
$
|
1,354,797
|
|
Drilling services
|
|
|
194,517
|
|
|
|
212,272
|
|
|
|
234,104
|
|
|
|
114,729
|
|
|
|
172,821
|
|
Products sales
|
|
|
29,586
|
|
|
|
40,857
|
|
|
|
59,102
|
|
|
|
44,081
|
|
|
|
33,775
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,084,611
|
|
|
|
1,491,255
|
|
|
|
1,834,915
|
|
|
|
1,056,394
|
|
|
|
1,561,393
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service and product expenses(1)
|
|
|
630,195
|
|
|
|
875,570
|
|
|
|
1,136,488
|
|
|
|
725,365
|
|
|
|
1,011,040
|
|
Selling, general and administrative
|
|
|
144,503
|
|
|
|
179,508
|
|
|
|
198,200
|
|
|
|
181,420
|
|
|
|
175,445
|
|
Depreciation and amortization
|
|
|
75,902
|
|
|
|
131,399
|
|
|
|
181,197
|
|
|
|
200,732
|
|
|
|
181,823
|
|
Fixed asset and other intangibles impairment loss(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38,646
|
|
|
|
|
|
Goodwill impairment loss(2)
|
|
|
|
|
|
|
13,094
|
|
|
|
272,006
|
|
|
|
97,643
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income from continuing operations before interest,
taxes and non-controlling interest
|
|
|
234,011
|
|
|
|
291,684
|
|
|
|
47,024
|
|
|
|
(187,412
|
)
|
|
|
193,085
|
|
Write-off of deferred financing fees
|
|
|
170
|
|
|
|
|
|
|
|
|
|
|
|
528
|
|
|
|
|
|
Interest expense
|
|
|
40,645
|
|
|
|
61,328
|
|
|
|
59,729
|
|
|
|
56,895
|
|
|
|
57,669
|
|
Interest income
|
|
|
(1,387
|
)
|
|
|
(325
|
)
|
|
|
(301
|
)
|
|
|
(79
|
)
|
|
|
(322
|
)
|
Taxes
|
|
|
70,184
|
|
|
|
84,833
|
|
|
|
72,305
|
|
|
|
(63,088
|
)
|
|
|
51,580
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before non-controlling
interest
|
|
|
124,399
|
|
|
|
145,848
|
|
|
|
(84,709
|
)
|
|
|
(181,668
|
)
|
|
|
84,158
|
|
Non-controlling interest
|
|
|
(49
|
)
|
|
|
(569
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
|
124,448
|
|
|
|
146,417
|
|
|
|
(84,709
|
)
|
|
|
(181,668
|
)
|
|
|
84,158
|
|
Income (loss) from discontinued operations (net of tax expense
of $9,359, $6,890, $3,865, $0 and $0, respectively)(3)
|
|
|
14,050
|
|
|
|
11,443
|
|
|
|
(4,859
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
138,498
|
|
|
$
|
157,860
|
|
|
$
|
(89,568
|
)
|
|
$
|
(181,668
|
)
|
|
$
|
84,158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations per diluted share
|
|
$
|
1.83
|
|
|
$
|
2.00
|
|
|
$
|
(1.15
|
)
|
|
$
|
(2.42
|
)
|
|
$
|
1.08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Service and product expenses is the aggregate of service
expenses and product expenses. |
|
(2) |
|
For the year ended December 31, 2009, we recorded a fixed
asset impairment in our drilling services segment of $36,158 and
an intangible asset impairment in our completion and production
services segment totaling $2,488. We also recorded a goodwill
impairment charge of $97,643 associated with several of our
reportable units at December 31, 2009. We recorded an
impairment loss of $272,006 associated with goodwill for various
reporting units as of December 31, 2008. For the year ended
December 31, 2007, we recorded an impairment |
34
|
|
|
|
|
loss of $13,094 associated with our Canadian reporting unit. For
a further discussion, see Item 7. Managements
Discussion and Analysis of Financial Condition and Results of
Operations included elsewhere in this Annual Report. |
|
(3) |
|
In May 2008, our Board of Directors authorized and committed to
a plan to sell certain operations in the Barnett Shale region of
north Texas, consisting primarily of our supply store business,
as well as certain non-strategic drilling logistics assets and
other completion and production services assets. On May 19,
2008, we sold these operations to a company owned by a former
officer of one of our subsidiaries. In August 2006, our Board of
Directors authorized and committed to a plan to sell certain
manufacturing and production enhancement product sales
operations of a subsidiary located in Alberta, Canada, which
includes certain assets located in south Texas. This sale was
completed on October 31, 2006. We revised our financial
statements and reclassified the assets and liabilities of these
disposal groups as held for sale as of the date of each balance
sheet presented and removed the results of operations of the
disposal group from net income from continuing operations, and
presented these separately as income (loss) from discontinued
operations, net of tax, for each of the accompanying statements
of operations. We ceased depreciating the assets when each
disposal group was reclassified as held for sale, and we
adjusted the net assets to the lower of carrying value or fair
value less selling costs. For a further discussion, see
Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations included
elsewhere in this Annual Report. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2006
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
(In thousands)
|
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA(4)
|
|
$
|
309,743
|
|
|
$
|
436,177
|
|
|
$
|
500,227
|
|
|
$
|
149,081
|
|
|
$
|
374,908
|
|
Cash flows from operating activities
|
|
|
187,635
|
|
|
|
338,415
|
|
|
|
350,409
|
|
|
|
285,204
|
|
|
|
216,158
|
|
Cash flows from financing activities
|
|
|
471,376
|
|
|
|
66,643
|
|
|
|
27,990
|
|
|
|
(207,991
|
)
|
|
|
(174,088
|
)
|
Cash flows from investing activities
|
|
|
(650,863
|
)
|
|
|
(409,189
|
)
|
|
|
(374,098
|
)
|
|
|
(18,128
|
)
|
|
|
6,817
|
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions, net of cash acquired(5)
|
|
|
369,606
|
|
|
|
50,406
|
|
|
|
180,154
|
|
|
|
|
|
|
|
33,721
|
|
Property, plant and equipment
|
|
|
303,922
|
|
|
|
368,053
|
|
|
|
253,776
|
|
|
|
38,487
|
|
|
|
169,919
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2006
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
(In thousands)
|
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
19,766
|
|
|
$
|
13,034
|
|
|
$
|
18,500
|
|
|
$
|
77,360
|
|
|
$
|
126,681
|
|
Net property, plant and equipment
|
|
|
752,648
|
|
|
|
1,013,539
|
|
|
|
1,166,686
|
|
|
|
941,133
|
|
|
|
956,028
|
|
Goodwill
|
|
|
541,313
|
|
|
|
549,130
|
|
|
|
341,592
|
|
|
|
243,823
|
|
|
|
250,533
|
|
Total assets
|
|
|
1,739,198
|
|
|
|
2,050,633
|
|
|
|
1,987,353
|
|
|
|
1,588,854
|
|
|
|
1,800,576
|
|
Long-term debt, excluding current portion
|
|
|
750,311
|
|
|
|
825,985
|
|
|
|
843,842
|
|
|
|
650,002
|
|
|
|
650,000
|
|
Total stockholders equity
|
|
|
734,633
|
|
|
|
926,031
|
|
|
|
860,711
|
|
|
|
698,890
|
|
|
|
805,834
|
|
|
|
|
(4) |
|
Adjusted EBITDA consists of net income (loss) from continuing
operations before net interest expense, taxes, depreciation and
amortization, non-controlling interest and impairment loss.
Adjusted EBITDA is a non-GAAP measure of performance. We use
Adjusted EBITDA as the primary internal management measure for
evaluating performance and allocating additional resources. The
calculation of Adjusted EBITDA is different from the calculation
of EBITDA, as defined and used in our credit
facilities. For a discussion of the calculation of
EBITDA as defined under our existing credit
facilities, as recently amended, see Note 11, |
35
|
|
|
|
|
Long-term debt in the Notes to Consolidated
Financial Statements. Adjusted EBITDA is included in this Annual
Report on
Form 10-K
because our management considers it an important supplemental
measure of our performance and believes that it is frequently
used by securities analysts, investors and other interested
parties in the evaluation of companies in our industry, some of
which present EBITDA when reporting their results. We regularly
evaluate our performance as compared to other companies in our
industry that have different financing and capital structures
and/or tax rates by using Adjusted EBITDA. In addition, we use
Adjusted EBITDA in evaluating acquisition targets. Management
also believes that Adjusted EBITDA is a useful tool for
measuring our ability to meet our future debt service, capital
expenditures and working capital requirements, and Adjusted
EBITDA is commonly used by us and our investors to measure our
ability to service indebtedness. Adjusted EBITDA is not a
substitute for the GAAP measures of earnings or cash flow and is
not necessarily a measure of our ability to fund our cash needs.
In addition, it should be noted that companies calculate EBITDA
differently and, therefore, EBITDA has material limitations as a
performance measure because it excludes interest expense, taxes,
depreciation and amortization and non-controlling interest. The
following table reconciles Adjusted EBITDA with our net income
(loss). |
|
(5) |
|
Acquisitions, net of cash acquired, consists only of the cash
component of acquisitions. It does not include common stock and
notes issued for acquisitions, nor does it include other
non-cash assets issued for acquisitions. |
Reconciliation
of Adjusted EBITDA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
|
|
|
2006
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Net income (loss)
|
|
$
|
138,498
|
|
|
$
|
157,860
|
|
|
$
|
(89,568
|
)
|
|
$
|
(181,668
|
)
|
|
$
|
84,158
|
|
|
|
|
|
Plus: interest expense, net
|
|
|
39,258
|
|
|
|
61,003
|
|
|
|
59,428
|
|
|
|
56,816
|
|
|
|
57,347
|
|
|
|
|
|
Plus: tax expense (benefit)
|
|
|
70,184
|
|
|
|
84,833
|
|
|
|
72,305
|
|
|
|
(63,088
|
)
|
|
|
51,580
|
|
|
|
|
|
Plus: depreciation and amortization
|
|
|
75,902
|
|
|
|
131,399
|
|
|
|
181,197
|
|
|
|
200,732
|
|
|
|
181,823
|
|
|
|
|
|
Plus: non-controlling interest
|
|
|
(49
|
)
|
|
|
(569
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plus: impairment loss
|
|
|
|
|
|
|
13,094
|
|
|
|
272,006
|
|
|
|
136,289
|
|
|
|
|
|
|
|
|
|
Minus: income (loss) from discontinued operations (net of tax
expense of $9,359, $6,890, $3,865, $0 and $0, respectively)
|
|
|
14,050
|
|
|
|
11,443
|
|
|
|
(4,859
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
309,743
|
|
|
$
|
436,177
|
|
|
$
|
500,227
|
|
|
$
|
149,081
|
|
|
$
|
374,908
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
The following discussion and analysis should be read in
conjunction with our consolidated financial statements and
related notes included within this Annual Report. This
discussion contains forward-looking statements based on our
current expectations, assumptions, estimates and projections
about us and the oil and gas industry. See Forward-Looking
Statement contained in Item 1. Business.
These forward-looking statements involve risks and uncertainties
that may be outside of our control and could cause actual
results to differ materially from those in the forward-looking
statements. For examples of those risks and uncertainties, see
the cautionary statements contained in Item 1A. Risk
Factors. Factors that could cause or contribute to such
differences include, but are not limited to: market prices for
oil and gas, the level of oil and gas drilling, economic and
competitive conditions, capital expenditures, regulatory changes
and other uncertainties. In light of these risks, uncertainties
and assumptions, the forward-looking events discussed below may
not occur. Unless otherwise required by law, we undertake no
obligation to publicly update any forward-looking statements,
even if new information becomes available or other events occur
in the future.
36
The words believe, may,
will, estimate, continue,
anticipate, intend, plan,
expect and similar expressions are intended to
identify forward-looking statements. All statements other than
statements of current or historical fact contained in this
Annual Report are forward-looking statements.
Overview
We are a leading provider of specialized completion and
production services and products focused on helping oil and gas
companies develop hydrocarbon reserves, reduce operating costs
and enhance production. We focus on basins within North America
that we believe have attractive long-term potential for growth,
and we deliver targeted, value-added services and products
required by our customers within each specific basin. We believe
our range of services and products positions us to meet the many
needs of our customers at the wellsite, from drilling and
completion through production and eventual abandonment. We
manage our operations from regional field service facilities
located throughout the U.S. Rocky Mountain region, Texas,
Oklahoma, Louisiana, Arkansas, Pennsylvania, western Canada,
Mexico and Southeast Asia.
We operate in three business segments:
Completion and Production Services. Through
our completion and production services segment, we establish,
maintain and enhance the flow of oil and gas throughout the life
of a well. This segment is divided into the following primary
service lines:
|
|
|
|
|
Intervention Services. Well intervention
requires the use of specialized equipment to perform an array of
wellbore services. Our fleet of intervention service equipment
includes coiled tubing units, pressure pumping units, nitrogen
units, well service rigs, snubbing units and a variety of
support equipment. Our intervention services provide customers
with innovative solutions to increase production of oil and gas.
|
|
|
|
Downhole and Wellsite Services. Our downhole
and wellsite services include electric-line, slickline,
production optimization, production testing, rental and fishing
services.
|
|
|
|
Fluid Handling. We provide a variety of
services to help our customers obtain, move, store and dispose
of fluids that are involved in the development and production of
their reservoirs. Through our fleet of specialized trucks, frac
tanks and other assets, we provide fluid transportation,
heating, pumping and disposal services for our customers.
|
Drilling Services. Through our drilling
services segment, we provide services and equipment that
initiate or stimulate oil and gas production by providing land
drilling and specialized rig logistics services.
Product Sales. We provide oilfield service
equipment and refurbishment of used equipment through our
Southeast Asian business, and we provide repair work and
fabrication services for our customers at a business located in
Gainesville, Texas.
Substantially all service and rental revenue we earn is based
upon a charge for a period of time (an hour, a day, a week) for
the actual period of time the service or rental is provided to
our customer, on a fixed per-stage-completed fee or pursuant to
a long-term contract which may include
take-or-pay
provisions. Product sales are recorded when the actual sale
occurs and title or ownership passes to the customer.
Our customers include large multi-national and independent oil
and gas producers, as well as smaller independent producers and
the major land-based drilling contractors in North America (see
Customers in Item 1 of this Annual Report on
Form 10-K).
The primary factors influencing demand for our services and
products are the level of drilling and workover activity of our
customers and the complexity of such activity, which in turn,
depends on current and anticipated future oil and gas prices,
production depletion rates and the resultant levels of cash
flows generated and allocated by our customers to their drilling
and workover budgets. As a result, demand for our services and
products is cyclical, substantially depends on activity levels
in the North American oil and gas industry and is highly
sensitive to current and expected oil and natural gas prices.
The following tables summarize average North American drilling
and well service rig activity, as measured by Baker Hughes
Incorporated (BHI) and the
37
Cameron International Corporation/Guiberson/AESC Service Rig
Count for Active Rigs, respectively, and historical
commodity prices as provided by Bloomberg:
AVERAGE
RIG COUNTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
12/31/06
|
|
|
12/31/07
|
|
|
12/31/08
|
|
|
12/31/09
|
|
|
12/31/10
|
|
|
BHI Rotary Rig Count:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Land
|
|
|
1,559
|
|
|
|
1,695
|
|
|
|
1,814
|
|
|
|
1,046
|
|
|
|
1,514
|
|
U.S. Offshore
|
|
|
90
|
|
|
|
73
|
|
|
|
65
|
|
|
|
44
|
|
|
|
31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S.
|
|
|
1,649
|
|
|
|
1,768
|
|
|
|
1,879
|
|
|
|
1,090
|
|
|
|
1,545
|
|
Canada
|
|
|
471
|
|
|
|
343
|
|
|
|
382
|
|
|
|
222
|
|
|
|
348
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North America
|
|
|
2,120
|
|
|
|
2,111
|
|
|
|
2,261
|
|
|
|
1,312
|
|
|
|
1,893
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Source: BHI (www.BakerHughes.com)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
12/31/06
|
|
|
12/31/07
|
|
|
12/31/08
|
|
|
12/31/09
|
|
|
12/31/10
|
|
|
Cameron International Corporation/Guiberson/AESC Well Service
Rig Count (Active Rigs):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
2,364
|
|
|
|
2,388
|
|
|
|
2,515
|
|
|
|
1,722
|
|
|
|
1,854
|
|
Canada
|
|
|
779
|
|
|
|
596
|
|
|
|
686
|
|
|
|
457
|
|
|
|
534
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S. and Canada
|
|
|
3,143
|
|
|
|
2,984
|
|
|
|
3,201
|
|
|
|
2,179
|
|
|
|
2,388
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Source: Cameron International Corporation/Guiberson/AESC Well
Service Rig Count for Active Rigs.
Service rig counts for active rigs for December 2010 was 2,682
according to the Cameron International
Corporation/Guiberson/AESC Well Service Rig Count for
Active Rigs and was 2,713 as of January 31,
2011.
AVERAGE
OIL AND GAS PRICES
|
|
|
|
|
|
|
|
|
|
|
Average Daily Closing
|
|
Average Daily Closing
|
|
|
Henry Hub Spot Natural
|
|
WTI Cushing Spot Oil
|
Period
|
|
Gas Prices ($/mcf)
|
|
Price ($/bbl)
|
|
1/1/01 12/31/01
|
|
$
|
3.99
|
|
|
$
|
25.96
|
|
1/1/02 12/31/02
|
|
|
3.37
|
|
|
|
26.17
|
|
1/1/03 12/31/03
|
|
|
5.49
|
|
|
|
31.06
|
|
1/1/04 12/31/04
|
|
|
5.90
|
|
|
|
41.51
|
|
1/1/05 12/31/05
|
|
|
8.89
|
|
|
|
56.56
|
|
1/1/06 12/31/06
|
|
|
6.73
|
|
|
|
66.09
|
|
1/1/07 12/31/07
|
|
|
6.97
|
|
|
|
72.23
|
|
1/1/08 12/31/08
|
|
|
8.89
|
|
|
|
99.92
|
|
1/1/09 12/31/09
|
|
|
3.94
|
|
|
|
61.99
|
|
1/1/10 12/31/10
|
|
|
4.38
|
|
|
|
79.48
|
|
Source: Bloomberg NYMEX prices.
The closing spot price of a barrel of WTI Cushing oil at
December 31, 2010 was $91.38 and the closing spot price for
Henry Hub natural gas ($/mcf) was $4.41. At February 14,
2011, the closing spot price of a barrel of WTI Cushing oil was
$84.81 and the closing spot price for Henry Hub natural gas was
$3.92.
38
We consider the drilling and well service rig counts to be an
indication of spending by our customers in the oil and gas
industry for exploration and development of new and existing
hydrocarbon reserves. These spending levels are a primary driver
of our business, and we believe that our customers tend to
invest more in these activities when oil and gas prices are at
higher levels or are increasing. The utilization of our assets
and the performance of our business can be impacted by these and
other external and internal factors. See Item 1A.
Risk Factors.
We generally charge for our services either on a dayrate or
per-stage-completed basis. Depending on the specific service,
charges may include one or more of these components: (1) a
set-up
charge, (2) an hourly service rate based on equipment and
labor, (3) a stage-completed charge, (4) an equipment
rental charge, (5) a consumables charge, and (6) a
mileage and fuel charge. We generally determine the rates
charged through a competitive process on a
job-by-job
basis. Typically, work is performed on a call out
basis, whereby the customer requests services on a job-specific
basis, but does not guarantee work levels beyond the specific
job bid. For contract drilling services, fees are charged based
on standard dayrates or, to a lesser extent, as negotiated by
footage contracts. Product sales generated through our Southeast
Asian business are typically based on a pre-determined price
book.
We have entered into long-term take or pay contracts on the
majority of our pressure pumping capacity. These agreements are
typically for three-year terms and require our customers to pay
us a minimum daily rate for not less than five days per week and
provide for an option to operate seven days per week. We are
typically paid within 30 60 days for
services provided during the previous month. The contracts
typically provide incentives to compensate us for better
efficiencies and services provided at higher pressures, extended
pump times and flow rates. We are also able to pass-through
increases in costs associated with certain consumables used in
pressure pumping operations. Our customers would be required to
pay us substantial fees for the early termination of the
contracts.
Outlook
Our growth strategy is focused on internal growth in the basins
in which we currently operate, maximizing equipment utilization,
adding additional like-kind equipment and expanding our service
and product offerings. We seek new basins in which to replicate
this approach and augment our internal growth with strategic
acquisitions. Our business is impacted by changes in the oil and
gas cycle. Oil and gas commodity prices rose steadily throughout
the decade culminating in 2008, then declined sharply in late
2008 and the early part of 2009, primarily due to the global
financial crisis. Oil prices recovered through the remainder of
2009 and continued a gradual improvement during the course of
2010 along with the global economy. The price of natural gas in
North America has remained subdued as a result of storage levels
remaining above historical averages caused primarily by
increasing gas production from unconventional resource plays. As
a result, exploration and production companies are shifting a
greater portion of their activities into emerging oil and
liquid-rich plays and our business has shifted from a
predominantly gas-oriented business, to a majority oil and
liquids-oriented business.
In 2010, we remained disciplined with our financial investments
in capital expenditures, targeted specific acquisitions, which
were additive to our business objectives and responded to our
customers needs for quality services in the emerging oil
and liquid-rich plays. We redeployed equipment and personnel
into the emerging basins while continuing to maintain a strong
presence in our historical markets.
|
|
|
|
|
Internal Capital Investment. Our internal
expansion activities have generally consisted of adding
equipment and qualified personnel in locations where we have
established a presence. We have grown our operations in many of
these locations by expanding services to current customers,
attracting new customers and hiring local personnel with local
basin-level expertise and leadership recognition. Depending on
customer demand, we will consider adding equipment to further
increase the capacity of services currently being provided
and/or add
equipment to expand the services we provide. We invested
$462.2 million in equipment additions over the three-year
period ended December 31, 2010, which included
$399.4 million for the completion and production services
segment, $51.9 million for the drilling services segment,
$6.8 million for the product sales segment and
$4.1 million related to general corporate operations. For
the year ended December 31, 2010, we invested
$169.9 million in capital expenditures.
|
|
|
|
External Growth. We use strategic acquisitions
as an integral part of our growth strategy. We consider
acquisitions that will add to our service offerings in a current
operating area or that will expand our geographical footprint
into a targeted basin. We have completed several acquisitions in
recent years. These
|
39
|
|
|
|
|
acquisitions affect our operating performance from period to
period. Accordingly, revenue and operating results in different
periods are not necessarily comparable and should not be relied
upon as indications of future performance. We invested an
aggregate of $213.9 million in acquisitions over the
three-year period ended December 31, 2010. Of this amount,
we invested an aggregate of $33.7 million to acquire 3
businesses during 2010, including a well servicing platform
acquisition in the Eagle Ford Shale of south Texas, and
$180.2 million to acquire 4 businesses during 2008. We did
not complete any business acquisitions during the year ended
December 31, 2009. See Significant
Transactions.
|
For 2011, we anticipate that activity levels will remain strong
and a greater percentage of activity will be directed at
increasingly more service intensive, multi-stage, horizontal
wells. Current oil prices are encouraging increased investments
in oil plays and in gas fields that have meaningful natural gas
liquids content. Additionally, drilling and completion activity
required to retain leases and service capacity shortages, which
have led to a backlog of wells to be completed, should support
activity in dry gas basins through the first half of the year.
As a result of our positive outlook for North America in 2011 we
have expanded our capital expenditure program which includes:
(1) roughly 170,000 hydraulic horse power of pressure
pumping equipment; (2) five larger-diameter coiled tubing
units with extended reach capabilities; and (3) meaningful
investments in fluid handling and well servicing assets.
Additionally, we continue to seek strategic acquisitions to
enhance service offerings and extend our presence in new service
areas.
We, and many of our competitors, are investing in new equipment,
some of which requires long lead-times to manufacture. As more
of this equipment is available to be placed into service there
could be additional excess capacity in the industry, which may
negatively impact utilization rates and pricing and put
inflationary pressure on labor costs. To improve efficiencies
for us and our customers and due to the concern associated with
excess capacity we have entered into long-term
take-or-pay
contracts on the majority of our pressure pumping capacity.
Additionally, we continue to monitor our equipment utilization
and poll our customers to assess demand levels. As equipment
enters the marketplace or competition for existing customers
increases, we believe our customers will rely upon service
providers who provide quality services and have positioned
themselves to be responsive to customers needs which we
believe we have and which constitutes a fundamental aspect of
our growth strategy.
Our business continues to be impacted by seasonality and
inclement weather, including the effects of harsh winter weather
conditions which occurred during the past few months in North
Dakota, Oklahoma and north Texas, the normal second quarter
Canadian
break-up,
as well as the impact of Gulf of Mexico tropical weather systems.
We believe our customers will continue to rely upon service
providers with local knowledge and a proven ability to
effectively execute complex services on more service intensive,
longer-lateral horizontal wells, particularly in oil and
liquid-rich basins. We believe we are well positioned in
high-growth basins and our core services, which include pressure
pumping, coiled tubing, well servicing and fluid handling, will
benefit from these secular trends.
Significant
Transactions
During 2010, we acquired substantially all the assets or all of
the equity interests in three oilfield service companies, for
$33.7 million in cash, resulting in goodwill of
approximately $6.9 million.
|
|
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On May 11, 2010, we acquired certain assets of a provider
of gas lift services based in Oklahoma City, Oklahoma. The total
purchase price for the assets was $1.4 million in cash. We
recorded goodwill totaling $1.0 million in conjunction with
this acquisition which has been allocated entirely to the
completion and production services business segment. We believe
this acquisition supplements our plunger lift service offering
for the completion and production services business segment.
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On September 3, 2010, we purchased the assets of a well
service and fluid handling service provider based in Carrizo
Springs, Texas. The total purchase price for the assets was
$20.8 million and included goodwill of $4.9 million,
all of which was allocated to the completion and production
services business segment. We believe this acquisition enhances
our position in the Eagle Ford Shale in south Texas.
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40
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On December 1, 2010, we acquired all of the outstanding
common stock of a disposal well operator located in Colorado for
$12.6 million in cash, subject to an additional
$0.5 million holdback. We recorded goodwill totaling
$1.5 million in conjunction with this acquisition which has
been allocated entirely to the completion and production
services business segment. We believe this acquisition will
enhance our position in the Denver-Julesburg Basin in Colorado.
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During 2008, we acquired substantially all the assets or all of
the equity interests in four oilfield service companies, for
$180.2 million in cash, resulting in goodwill of
approximately $71.2 million.
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On February 29, 2008, we acquired substantially all of the
assets of KR Fishing & Rental, Inc. for
$9.5 million in cash, resulting in goodwill of
$6.4 million. KR Fishing & Rental, Inc. is a
provider of fishing, rental and foam unit services in the
Piceance Basin and the Raton Basin, and is located in Rangely,
Colorado. We believe this acquisition complemented our
completion and production services business in the Rocky
Mountain region.
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On April 15, 2008, we acquired all the outstanding common
stock of Frac Source Services, Inc., a provider of pressure
pumping services to customers in the Barnett Shale of north
Texas, for $62.4 million in cash, net of cash acquired,
which includes a working capital adjustment of
$1.6 million, and recorded goodwill of $15.4 million.
Upon closing this transaction, we entered into a contract with
one of our major customers to provide pressure pumping services
in the Barnett Shale utilizing three frac fleets under a
contract with a term that extends up to three years from the
date each fleet is placed into service. We spent an additional
$20.0 million in 2008 on capital equipment related to these
contracted frac fleets. Thus, our total investment in this
operation was approximately $82.4 million. We believe this
acquisition expanded our pressure pumping business in north
Texas and that the related contract provided a stable revenue
stream from which to expand our pressure pumping business
outside of this region.
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On October 3, 2008, we acquired all of the membership
interests of TSWS Well Services, LLC, a limited liability
corporation which held substantially all of the well servicing
and heavy haul assets of TSWS, Inc., a company based in
Magnolia, Arkansas, which provides well servicing and heavy haul
services to customers in northern Louisiana, east Texas and
southern Arkansas. As consideration, we paid $57.2 million
in cash and prepaid an additional $1.0 million related to
an employee retention bonus pool. We also recorded goodwill
totaling $21.9 million. We believe this acquisition
extended our geographic reach into the Haynesville Shale area.
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On October 4, 2008, we acquired substantially all of the
assets of Appalachian Well Services, Inc. and its wholly-owned
subsidiary, each of which is based in Shelocta, Pennsylvania.
This business provides pressure pumping,
e-line and
coiled tubing services in the Appalachian region, and includes a
service area which extends through portions of Pennsylvania,
West Virginia, Ohio and New York. As consideration for the
purchase, we paid $50.1 million in cash and issued 588,292
unregistered shares of our common stock, valued at $15.04 per
share. We invested an additional $6.5 million to complete a
frac fleet at this location and have an option to purchase real
property for approximately $0.6 million. In addition, we
entered into an agreement that could have required us to pay up
to an additional $5.0 million in cash consideration during
the earn-out period. This earn-out period ended in 2010 with no
additional consideration paid. We recorded goodwill of
approximately $27.5 million associated with this
acquisition, however, this goodwill was deemed impaired in 2009
and expensed as of December 31, 2009. This acquisition
created a platform for future growth for our pressure pumping
and other completion and production service lines in the
Marcellus Shale.
|
We have accounted for our acquisitions using the purchase method
of accounting, whereby the purchase price is allocated to the
fair value of net assets acquired, including intangibles and
property, plant and equipment at depreciated replacement costs
with the excess to goodwill. Results of operations related to
each of the acquired companies have been included in our
accounts and results of operations as of the date of acquisition.
In March 2009, our Canadian subsidiary exchanged certain
non-monetary assets with a net book value of $9.3 million
related to our production testing business for certain
e-line
assets of a competitor. We recorded a non-cash loss on the
transaction of $4.9 million, which represented the
difference between the carrying value and the fair
41
market value of the assets surrendered. We believe the
e-line
assets will generate incremental future cash flows compared to
the production testing assets exchanged.
In May 2008, our Board of Directors authorized and committed to
a plan to sell certain operations in the Barnett Shale region of
north Texas, consisting primarily of our supply store business,
as well as certain non-strategic drilling logistics assets and
other completion and production services assets. On May 19,
2008, we sold these operations to Select Energy Services,
L.L.C., a company owned by a former officer of one of our
subsidiaries, for which we received proceeds of
$50.2 million in cash and assets with a fair market value
of $8.0 million. The carrying value of the net assets sold
was approximately $51.4 million, excluding
$11.1 million of allocated goodwill associated with the
combination that formed Complete Production Services, Inc. in
September 2005. We recorded a loss on the sale of this disposal
group totaling approximately $6.9 million, which included
$2.6 million related to income taxes. In accordance with
the sales agreement, we sublet office space to Select Energy
Services, L.L.C. and provided certain administrative services
for an initial term of one year, at an
agreed-upon
rate.
On October 31, 2006, we completed the sale of a disposal
group which included certain manufacturing and production
enhancement operations of a subsidiary located in Alberta,
Canada, as well as operations in south Texas. We sold this
disposal group to an oilfield service company located in
Calgary, Alberta, Canada. In conjunction with this asset
disposal, the buyer issued a note to us for $2.0 million
denominated in Canadian dollars. During the second quarter of
2010, we were notified that the seller was in default on a term
loan and security agreement which was senior to our note.
Therefore, management recorded a provision of $1.9 million
for bad debt associated with this note as of June 30, 2010,
but we will continue to pursue our interest in this note to the
extent a portion may be recoverable in a future period.
Market
Environment
We operate in a highly competitive industry. Our competition
includes many large and small oilfield service companies. As
such, we price our services and products to remain competitive
in the markets in which we operate, adjusting our rates to
reflect current market conditions as necessary. We examine the
rate of utilization of our equipment as one measure of our
ability to compete in the current market environment.
Critical
Accounting Policies and Estimates
The preparation of our consolidated financial statements in
conformity with Generally Accepted Accounting Principles
(GAAP) requires the use of estimates and assumptions
that affect the reported amount of assets, liabilities, revenues
and expenses, and related disclosure of contingent assets and
liabilities. We base our estimates on historical experience and
on various other assumptions that we believe are reasonable
under the circumstances, and provide a basis for making
judgments about the carrying value of assets and liabilities
that are not readily available through open market quotes.
Estimates and assumptions are reviewed periodically, and actual
results may differ from those estimates under different
assumptions or conditions. We must use our judgment related to
uncertainties in order to make these estimates and assumptions.
In the selection of our critical accounting policies, the
objective is to properly reflect our financial position and
results of operations for each reporting period in a consistent
manner that can be understood by the reader of our financial
statements. Our accounting policies and procedures are explained
in Note 2, Significant accounting policies, in
our notes to consolidated financial statements included
elsewhere in this Annual Report. We consider an estimate to be
critical if it is subjective and if changes in the estimate
using different assumptions would result in a material impact on
our financial position or results of operations.
We have identified the following as the most critical accounting
policies and estimates, and have provided: (1) a
description, (2) information about variability and
(3) our historical experience, including a sensitivity
analysis, if applicable.
Revenue
Recognition
We recognize service revenue as services are performed and when
realized or earned. Revenue is deemed to be realized or earned
when we determine that the following criteria are met:
(1) persuasive evidence of an arrangement
42
exists; (2) delivery has occurred or services have been
rendered; (3) the fee is fixed or determinable; and
(4) collectibility is reasonably assured. These services
are generally provided over a relatively short period of time
pursuant to short-term contracts at pre-determined dayrate fees,
or on a
day-to-day
basis. Revenue and costs related to drilling contracts are
recognized as work progresses. Progress is measured as revenue
is recognized based upon dayrate charges. For certain contracts,
we may receive lump-sum payments from our customers related to
the mobilization of rigs and other drilling equipment. Under
these arrangements, we defer revenues and the related cost of
services and recognize them over the term of the drilling
contract. Costs incurred to relocate rigs and other drilling
equipment to areas in which a contract has not been secured are
expensed as incurred. Revenues associated with product sales are
recorded when product title is transferred to the customer.
Under current GAAP, revenue is to be recognized when it is
realized or realizable and earned. The SECs rules and
regulations provide additional guidance for revenue recognition
under specific circumstances, including bill and hold
transactions. There is a risk that our results of operations
could be misstated if we do not record revenue in the proper
accounting period.
The nature of our business has been such that we generally bill
for services over a relatively short period of time or bill for
services on a stage-completed basis under a longer-term contract
with
take-or-pay
provisions and record revenues as products are sold. We did not
record material adjustments resulting from revenue recognition
issues for the years ended December 31, 2010, 2009 and 2008.
Impairment
of Long-Lived Assets
Based on guidance from the Financial Accounting Standards Board
(FASB) regarding accounting for the impairment or
disposal of long-lived assets, we evaluate potential impairment
of long-lived assets and intangibles, excluding goodwill and
other intangible assets without defined service lives, when
indicators of impairment are present. If such indicators are
present, we project the fair value of the assets by estimating
the undiscounted future cash in-flows to be derived from the
long-lived assets over their remaining estimated useful lives,
as well as any salvage value. Then, we compare this fair value
estimate to the carrying value of the assets and determine
whether the assets are deemed to be impaired. For goodwill and
other intangible assets without defined service lives, we
perform an annual impairment test, whereby we estimate the fair
value of the asset by discounting future cash flows at a
projected cost of capital rate. If the fair value estimate is
less than the carrying value of the asset, an additional test is
required whereby we apply a purchase price analysis similar to a
purchase price allocation for a business combination. If
impairment is still indicated, we would record an impairment
loss in the current reporting period for the amount by which the
carrying value of the intangible asset exceeds its projected
fair value.
Our industry is highly cyclical and the estimate of future cash
flows requires the use of assumptions and our judgment. Periods
of prolonged down cycles in the industry could have a
significant impact on the carrying value of these assets and may
result in impairment charges. If our estimates do not
approximate actual performance or if the rates we used to
discount cash flows vary significantly from actual discount
rates, we could overstate our assets and an impairment loss may
not be timely identified.
We tested goodwill for impairment for each of the years ended
December 31, 2010, 2009 and 2008. Management prepared a
discounted cash flow analysis to determine the fair market value
of the reportable units as of the annual testing date. Projected
cash flows were based on certain management assumptions related
to expected growth, capital investment and terminal value,
discounted at a market-participant weighted average cost of
capital, refined to reflect our current and anticipated capital
structure. Based on this analysis, management determined that
goodwill was not impaired as of our annual testing date in 2010,
but was impaired in 2009 and 2008. In accordance with the
FASBs guidance for goodwill, management performed a
step-two analysis to calculate the amount by which the carrying
value of the reporting units exceeded the projected fair market
value of such units as of the respective annual testing dates.
We performed our impairment calculations as of December 31,
2008, incorporating our assumptions of future earnings and cash
flows. Based on this testing, we determined that the goodwill
associated with most of our reporting units had been impaired.
We recorded an impairment charge of $272.0 million at
December 31, 2008. In calculating this impairment charge,
management made assumptions about future earnings by reportable
unit, which may differ from actual future earnings for these
operations. In 2009, management performed additional analysis
and determined that further write-downs were necessary. We
recorded a
43
goodwill impairment charge of $97.6 million associated with
several of our reportable units at December 31, 2009. In
addition, pursuant to an undiscounted cash flow analysis, we
recorded a fixed asset impairment in our drilling services
segment of $36.2 million and an intangible asset impairment
in our completion and production services segment totaling
$2.5 million during 2009. A significant decline in expected
future cash flow, a further erosion of market conditions or a
lower-than-expected
recovery of the oil and gas industry activity levels in future
years, could result in an additional impairment charge.
Stock
Options and Other Stock-Based Compensation
We have issued stock-based compensation to certain employees,
officers and directors in the form of stock options and
restricted stock. In accordance with U.S. GAAP, we account
for grants made prior to September 30, 2005, the date of
our initial filing with the SEC, using the minimum value method,
whereby no compensation expense is recognized for stock-based
compensation grants that have an exercise price equal to the
fair value of the stock on the date of grant. For grants of
stock-based compensation between October 1, 2005 and
December 31, 2005, we utilized the modified prospective
transition method to record expense associated with these
options, whereby we did not record compensation expense
associated with these grants during the period October 1,
2005 through December 31, 2005 but provided pro forma
disclosure of this expense, and, then began recognizing
compensation expense related to these grants over the remaining
vesting period after December 31, 2005 based upon a
calculated fair value. These grants were fully vested as of
December 31, 2009. For grants of stock-based compensation
on or after January 1, 2006, we recognize expense
associated with new awards of stock-based compensation, as
determined using a Black-Scholes pricing model over the expected
term of the award. In addition, we record compensation expense
associated with restricted stock which has been granted to
certain of our directors, officers and employees. In accordance
with current U.S. GAAP, we calculate compensation expense
on the date of grant (number of options granted multiplied by
the fair value of our common stock on the date of grant) and
recognize this expense, adjusted for forfeitures, ratably over
the applicable vesting period.
U.S. GAAP permits the use of various models to determine
the fair value of stock options and the variables used for the
model are highly subjective. For purposes of determining
compensation expense associated with stock options granted after
January 1, 2006, we are required to determine the fair
value of the stock options by applying a pricing model which
includes assumptions for expected term, discount rate, stock
volatility, expected forfeitures and a dividend rate. The use of
different assumptions or a different model may have a material
impact on our financial disclosures.
For the years ended December 31, 2010, 2009 and 2008, we
applied a Black-Scholes model with similar assumptions for
expected term (based on a probability analysis and ranging from
2.2 to 5.1 years), risk free rate (based upon published
rates for U.S. Treasury notes), zero dividend rate and
stock volatility, which we determined based on our historical
common stock volatility for grants after June 2008 and estimated
based on the historical volatility rates of several peer
companies prior to that time. In addition, we estimated a
forfeiture rate based upon our historical experience. We have
recorded compensation expense associated with stock option and
restricted stock grants totaling $11.6 million,
$12.2 million and $12.4 million for the years ended
December 31, 2010, 2009 and 2008, respectively.
Allowance
for Bad Debts and Inventory Obsolescence
We record trade accounts receivable at billed amounts, less an
allowance for bad debts. Inventory is recorded at cost, less an
allowance for obsolescence. To estimate these allowances,
management reviews the underlying details of these assets as
well as known trends in the marketplace, and applies historical
factors as a basis for recording these allowances. If market
conditions are less favorable than those projected by
management, or if our historical experience is materially
different from future experience, additional allowances may be
required.
There is a risk that management may not detect uncollectible
accounts or unsalvageable inventory in the correct accounting
period.
Bad debt expense (recovery) has been less than 1% of sales for
the years ended December 31, 2010, 2009 and 2008. If bad
debt expense had increased by 1% of sales, net income would have
decreased by $9.7 million for the year ended
December 31, 2010 and net loss would have increased by
$7.8 million and $11.9 million for the years
44
ended December 2009 and 2008, respectively. Our obsolescence and
other inventory reserves were approximately 7%, 2% and 2% of our
inventory balances at December 31, 2010, 2009 and 2008,
respectively. A 1% increase in inventory reserves, from 7% to
8%, at December 31, 2010 would have decreased net income by
$0.2 million for the year then ended.
Property,
Plant and Equipment
We record property, plant and equipment at cost less accumulated
depreciation. Major betterments to existing assets are
capitalized, while repairs and maintenance costs that do not
extend the service lives of our equipment are expensed. We
determine the useful lives of our depreciable assets based upon
historical experience and the judgment of our operating
personnel. We generally depreciate the historical cost of
assets, less an estimate of the applicable salvage value, on the
straight-line basis over the applicable useful lives. Upon
disposition or retirement of an asset, we record a gain or loss
if the proceeds from the transaction differ from the net book
value of the asset at the time of the disposition or retirement.
U.S. GAAP permits various depreciation methods to recognize
the use of assets. Use of a different depreciation method or
different depreciable lives could result in materially different
results. If our depreciation estimates are not correct, we could
over- or understate our results of operations, such as recording
a disproportionate amount of gains or losses upon disposition of
assets. There is also a risk that the useful lives we apply for
our depreciation calculation will not approximate the actual
useful life of the asset. We believe our estimates of useful
lives are materially correct and that these estimates are
consistent with industry averages.
We evaluate property, plant and equipment for impairment when
there are indicators of impairment. We did not record any
significant impairment charges related to our long-term assets
for the year ended December 31, 2010. During September
2009, we evaluated the fair market value of assets in our
contract drilling business with the assistance of a third-party
appraiser and determined that the carrying value of certain of
these drilling rigs exceeded the fair market value estimates. We
projected the undiscounted cash flows associated with these
rigs, including an estimate of salvage value, and compared these
expected future cash flows to the carrying amount of the rigs.
If the undiscounted cash flows exceeded the carrying amount, no
further testing was performed and the rig was deemed to not be
impaired. If the undiscounted cash flows did not exceed the
carrying value, we estimated the fair market value of the
equipment based on management estimates and general market data
obtained by the third-party appraiser using the sales comparison
market approach, which included the analysis of recent sales and
offering prices of similar equipment to arrive at an indication
of the most probable net sales proceeds for the equipment. The
result of this analysis was a calculated fixed asset impairment
of $36.2 million, which was recorded as an impairment loss
in September 30, 2009. This impairment charge was allocated
entirely to the drilling services business segment. This
impairment was deemed necessary due to an overall decline in oil
and gas exploration and production activity in late 2008 which
extended throughout 2009, as well as managements
expectation of future operating results for this business
segment. There were no significant impairment charges related to
our long-term assets during the year ended December 31,
2008. Depreciation and amortization expense for the years ended
December 31, 2010 and 2009 represented 19% of the average
depreciable asset base for each year. An increase in
depreciation expense relative to the depreciable base of 1%,
from 19% to 20%, would have reduced net income by approximately
$5.9 million for the year ended December 31, 2010.
Self
Insurance
On January 1, 2007, we began a self-insurance program to
pay claims associated with health care benefits provided to
certain of our employees in the United States. Pursuant to this
program, we have purchased a stop-loss insurance policy from an
insurance company. Our accounting policy for this self-insurance
program is to accrue expense based upon the number of employees
enrolled in the plan at pre-determined rates. As claims are
processed and paid, we compare our claims history to our
expected claims in order to estimate incurred but not reported
claims. If our estimate of claims incurred but not reported
exceeds our current accrual, we record additional expense during
the current period. There is a risk that we may not estimate our
incurred but not reported claims correctly or that our stop-loss
provision may not be adequate to insure us against losses in the
future. At December 31, 2010, we accrued $4.7 million
pursuant to this self-insurance program. A 10% increase in this
self-insurance accrual would reduce our net income for the year
ended December 31, 2010 by $0.4 million.
45
Deferred
Income Taxes
Our income tax expense includes income taxes related to the
United States, Canada and other foreign countries, including
local, state and provincial income taxes. We account for tax
ramifications pursuant to U.S. GAAP for income taxes and
record deferred income tax assets and liabilities based upon
temporary differences between the carrying amount and tax basis
of our assets and liabilities and measure tax expense using
enacted tax rates and laws that will be in effect when the
differences are expected to reverse. The effect of a change in
tax rates is recognized in income in the period of the change.
Furthermore, we record a valuation allowance for any deferred
income tax assets which we believe are likely to not be used
through future operations. As of December 31, 2010, 2009
and 2008, we recorded a valuation allowance of less than
$1.0 million related to certain deferred tax assets in
Canada. If our estimates and assumptions related to our deferred
tax position change in the future, we may be required to record
additional valuation allowances against our deferred tax assets
and our effective tax rate may increase, which could adversely
affect our financial results. As of December 31, 2010, we
did not provide deferred U.S. income taxes on approximately
$28.6 million of undistributed earnings of our foreign
subsidiaries in which we intend to indefinitely reinvest. Upon
distribution of these earnings in the form of dividends or
otherwise, we may be subject to U.S. income taxes and
foreign withholding taxes. On January 1, 2007, we adopted
the FASB interpretation that provides guidance to account for
uncertain tax positions. Annually, we perform an evaluation of
our tax positions. We have evaluated our tax positions at
December 31, 2010 and believe these positions are deemed
appropriate for all significant matters.
There is a risk that estimates related to the use of loss carry
forwards and the realizability of deferred tax accounts may be
incorrect, and that the result could materially impact our
financial position and results of operations. In addition,
future changes in tax laws or GAAP requirements could result in
additional valuation allowances or the recognition of additional
tax liabilities.
Historically, we have utilized net operating loss carry forwards
to partially offset current tax expense, and we have recorded a
valuation allowance to the extent we expect that our deferred
tax assets will not be utilized through future operations.
Deferred income tax assets totaled $30.5 million at
December 31, 2010, against which we recorded a valuation
allowance of $0.3 million, leaving a net deferred tax asset
of $30.2 million deemed realizable. Changes in our
valuation allowance would affect our net income on a dollar for
dollar basis.
Discontinued
Operations
We account for discontinued operations in accordance with the
FASB guidance on accounting for the impairment or disposal of
long-lived assets. U.S. GAAP requires that we classify the
assets and liabilities of a disposal group as held for sale if
the following criteria are met: (1) management, with
appropriate authority, commits to a plan to sell a disposal
group; (2) the asset is available for immediate sale in its
current condition; (3) an active program to locate a buyer
and other actions to complete the sale have been initiated;
(4) the sale is probable; (5) the disposal group is
being actively marketed for sale at a reasonable price; and
(6) actions required to complete the plan of sale indicate
it is unlikely that significant changes to the plan of sale will
occur or that the plan will be withdrawn. Once deemed held for
sale, we no longer depreciate the assets of the disposal group.
Upon sale, we calculate the gain or loss associated with the
disposition by comparing the carrying value of the assets less
direct costs of the sale with the proceeds received. In
conjunction with the sale, we settle inter-company balances
between us and the disposal group and allocate interest expense
to the disposal group for the period the assets were held for
sale. In the statement of operations, we present discontinued
operations, net of tax effect, as a separate caption below net
income from continuing operations.
46
Results
of Operations for the Years Ended December 31, 2010 and
2009
The following tables set forth our results of continuing
operations, including amounts expressed as a percentage of total
revenue, for the periods indicated (in thousands, except
percentages).
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent
|
|
|
|
Year
|
|
|
Year
|
|
|
Change
|
|
|
Change
|
|
|
|
Ended
|
|
|
Ended
|
|
|
2010/
|
|
|
2010/
|
|
|
|
12/31/10
|
|
|
12/31/09
|
|
|
2009
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Completion and production services
|
|
$
|
1,354,797
|
|
|
$
|
897,584
|
|
|
$
|
457,213
|
|
|
|
51
|
%
|
Drilling services
|
|
|
172,821
|
|
|
|
114,729
|
|
|
|
58,092
|
|
|
|
51
|
%
|
Product sales
|
|
|
33,775
|
|
|
|
44,081
|
|
|
|
(10,306
|
)
|
|
|
(23
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,561,393
|
|
|
$
|
1,056,394
|
|
|
$
|
504,999
|
|
|
|
48
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Completion and production services
|
|
$
|
369,826
|
|
|
$
|
165,787
|
|
|
$
|
204,039
|
|
|
|
123
|
%
|
Drilling services
|
|
|
38,973
|
|
|
|
9,641
|
|
|
|
29,332
|
|
|
|
304
|
%
|
Product sales
|
|
|
5,197
|
|
|
|
7,966
|
|
|
|
(2,769
|
)
|
|
|
(35
|
)%
|
Corporate
|
|
|
(39,088
|
)
|
|
|
(34,313
|
)
|
|
|
(4,775
|
)
|
|
|
(14
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
374,908
|
|
|
$
|
149,081
|
|
|
$
|
225,827
|
|
|
|
151
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate includes amounts related to corporate
personnel costs, other general expenses and stock-based
compensation charges.
Adjusted EBITDA consists of net income (loss) from
continuing operations before net interest expense, taxes,
depreciation and amortization, non-controlling interest and
impairment loss. Adjusted EBITDA is a non-GAAP measure of
performance. We use Adjusted EBITDA as the primary internal
management measure for evaluating performance and allocating
additional resources. The following table reconciles Adjusted
EBITDA for the years ended December 31, 2010 and 2009 to
the most comparable U.S. GAAP measure, operating income
(loss). The calculation of Adjusted EBITDA is different from the
calculation of EBITDA, as defined and used in our
credit facilities. For a discussion of the calculation of
EBITDA as defined under our existing credit
facilities, as recently amended, see Note 11,
Long-term debt in our notes to consolidated
financial statements included elsewhere in this Annual Report.
Reconciliation
of Adjusted EBITDA to Most Comparable
GAAP Measure Operating Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Completion and
|
|
|
Drilling
|
|
|
Product
|
|
|
|
|
|
|
|
Year Ended December 31, 2010
|
|
Production Services
|
|
|
Services
|
|
|
Sales
|
|
|
Corporate
|
|
|
Total
|
|
|
Adjusted EBITDA, as defined
|
|
$
|
369,826
|
|
|
$
|
38,973
|
|
|
$
|
5,197
|
|
|
$
|
(39,088
|
)
|
|
$
|
374,908
|
|
Depreciation and amortization
|
|
$
|
159,110
|
|
|
$
|
18,480
|
|
|
$
|
2,211
|
|
|
$
|
2,022
|
|
|
$
|
181,823
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
210,716
|
|
|
$
|
20,493
|
|
|
$
|
2,986
|
|
|
$
|
(41,110
|
)
|
|
$
|
193,085
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA, as defined
|
|
$
|
165,787
|
|
|
$
|
9,641
|
|
|
$
|
7,966
|
|
|
$
|
(34,313
|
)
|
|
$
|
149,081
|
|
Depreciation and amortization
|
|
$
|
174,929
|
|
|
$
|
21,067
|
|
|
$
|
2,460
|
|
|
$
|
2,276
|
|
|
$
|
200,732
|
|
Write-off of deferred financing fees
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(528
|
)
|
|
$
|
(528
|
)
|
Fixed asset and other intangible impairment loss
|
|
$
|
2,488
|
|
|
$
|
36,158
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
38,646
|
|
Goodwill impairment loss
|
|
$
|
97,643
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
97,643
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
(109,273
|
)
|
|
$
|
(47,584
|
)
|
|
$
|
5,506
|
|
|
$
|
(36,061
|
)
|
|
$
|
(187,412
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
47
Reconciliation
of Net Income (Loss) to Adjusted EBITDA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Net income (loss)
|
|
$
|
84,158
|
|
|
$
|
(181,668
|
)
|
|
$
|
(89,568
|
)
|
Plus: interest expense, net
|
|
|
57,347
|
|
|
|
56,816
|
|
|
|
59,428
|
|
Plus: tax expense (benefit)
|
|
|
51,580
|
|
|
|
(63,088
|
)
|
|
|
72,305
|
|
Plus: depreciation and amortization
|
|
|
181,823
|
|
|
|
200,732
|
|
|
|
181,197
|
|
Plus: impairment loss
|
|
|
|
|
|
|
136,289
|
|
|
|
272,006
|
|
Minus: income (loss) from discontinued operations (net of tax
expense of $0, $0 and $3,865, respectively)
|
|
|
|
|
|
|
|
|
|
|
(4,859
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
374,908
|
|
|
$
|
149,081
|
|
|
$
|
500,227
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Below is a detailed discussion of our operating results by
segment for these periods.
Year
Ended December 31, 2010 Compared to the Year ended
December 31, 2009
Revenue
Revenue from continuing operations for the year ended
December 31, 2010 increased by $505.0 million, or 48%,
to $1,561.4 million from $1,056.4 million for the year
ended December 31, 2009. This increase by segment was as
follows:
|
|
|
|
|
Completion and Production Services. Segment
revenue increased $457.2 million, or 51%, primarily due to
an increase in demand for our services and an overall increase
in activity levels for the oil and gas industry during 2010
compared to 2009, resulting in higher utilization of our
equipment. Activity levels and pricing in some service lines and
select geographic areas began to improve during the latter part
of the fourth quarter of 2009 and continued improving throughout
2010. The segment continued to benefit from increased horizontal
drilling and completion related activity within resource plays,
particularly for our pressure pumping, fluid handling and
U.S. coiled tubing businesses, Our pressure pumping
business also benefitted from the deployment of approximately
43,000 hydraulic horse power of new pressure pumping equipment
into the Eagle Ford and Bakken shales during the latter part of
2010.
|
|
|
|
Drilling Services. Segment revenue increased
$58.1 million, or 51%, for the year, primarily due to
improved utilization and pricing in our rig relocation and
contract drilling businesses. The rig relocation business also
benefitted from long rig moves as customers reactivated and
repositioned assets from dry gas basins into emerging oil and
liquid-rich markets such as the Bakken, Niobrara and Eagle Ford
shales.
|
|
|
|
Product Sales. Segment revenue decreased
$10.3 million, or 23%, for the year, primarily due to lower
third-party sales at our repair and fabrication shop in north
Texas as several large projects were completed during the first
quarter of 2009, while results for our Southeast Asian business
remained relatively constant for the years ended
December 31, 2010 and 2009.
|
Service
and Product Expenses
Service and product expenses include labor costs associated with
the execution and support of our services, materials used in the
performance of those services and other costs directly related
to the support and maintenance of equipment. These expenses
increased $285.7 million, or 39%, to $1,011.0 million
for the year ended December 31, 2010 from
$725.4 million for the year ended December 31, 2009.
The increase in service and product expenses was consistent with
an overall increase in revenues resulting from improvements in
oilfield activity in the
48
U.S. and Canada in 2010. The following table summarizes
service and product expenses as a percentage of revenues for the
years ended December 31, 2010 and 2009:
Service
and Product Expenses as a Percentage of Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
Segment:
|
|
12/31/10
|
|
12/31/09
|
|
Change
|
|
Completion and Production services
|
|
|
64
|
%
|
|
|
68
|
%
|
|
|
(4
|
)%
|
Drilling services
|
|
|
70
|
%
|
|
|
75
|
%
|
|
|
(5
|
)%
|
Product sales
|
|
|
77
|
%
|
|
|
75
|
%
|
|
|
2
|
%
|
Total
|
|
|
65
|
%
|
|
|
69
|
%
|
|
|
(4
|
)%
|
Service and product expenses as a percentage of revenue improved
to 65% for the year ended December 31, 2010 compared to 69%
for the year ended December 31, 2009. Margins by business
segment were impacted primarily by utilization and pricing.
|
|
|
|
|
Completion and Production Services. Service
and product expenses as a percentage of revenue for this
business segment decreased when comparing the year ended
December 31, 2010 to the same period in 2009. The
year-over-year
favorable margin improvement was attributable to an increase in
overall oilfield activity, improved pricing and service mix,
with an increase in sales for historically higher-margin
offerings, partially offset by some increases in labor costs and
other inflationary factors. We enacted certain cost-saving
measures in 2009, including headcount reductions and payroll
concessions which were substantially reinstated during 2010.
|
|
|
|
Drilling Services. The decrease in service and
product expenses as a percentage of revenue for this business
segment was primarily due to increased asset utilization and
improved pricing.
|
|
|
|
Product Sales. The increase in service and
product expenses as a percentage of revenue for the products
segments was primarily due to the mix of products sold for the
relative periods. Additionally, on a
year-over-year
basis, a larger proportion of the revenues and related costs for
the product sales segment for the year ended December 31,
2010 were provided by our Southeast Asian business, for which
sales tend to be project specific and are subject to
fluctuations in activity levels in the region.
|
Selling,
General and Administrative Expenses
Selling, general and administrative expenses include salaries
and other related expenses for our selling, administrative,
finance, information technology and human resource functions.
Selling, general and administrative expenses decreased
$6.0 million, or 3%, to $175.4 million for the year
ended December 31, 2010 from $181.4 million for the
year ended December 31, 2009. The results for 2009 included
incremental bad debt charges associated with
specifically-identified uncollectible accounts of $10.9 million,
incremental losses on the retirement of fixed assets of $12.8
million and certain insignificant inventory adjustments. In
addition, we recorded a loss on the non-monetary exchange of
certain assets in Canada during the first quarter of 2009 which
totaled $4.9 million. The overall decrease in selling,
general and administrative expense in 2010 was partially offset
by higher incentive compensation based on earnings, increased
payroll costs, higher insurance costs and the write-off of a
$1.9 million note receivable in Canada. Excluding the
impact of the non-monetary asset exchange in Canada, the
incremental charges to bad debt expense and losses on the
retirement of fixed assets, as a percentage of revenues,
selling, general and administrative expense was 11% and 14% for
the years ended December 31, 2010 and 2009, respectively.
Depreciation
and Amortization
Depreciation and amortization expense decreased
$18.9 million, or 9%, to $181.8 million for the year
ended December 31, 2010 from $200.7 million for the
year ended December 31, 2009. The decrease in depreciation
and amortization expense was attributable to the normal run-off
of depreciation associated with existing assets, asset
retirements in 2009, a $36.2 million impairment of our
drilling rigs as of September 30, 2009, sale-leaseback
transactions associated with our small vehicle fleet as well as
a facility in Wyoming and an impairment charge in
49
late 2009 related to certain intangible assets acquired in 2008.
Although we increased our capital expenditures in 2010 compared
to 2009, approximately half of those additions were incurred
during the second half of the year, resulting in overall lower
depreciation and amortization expense year-over-year. As a
percentage of revenue, depreciation and amortization expense
decreased to 12% from 19% for the years ended December 31,
2010 and 2009, respectively.
Fixed
Asset and Other Intangible Impairment Loss
We did not record any impairment charges in 2010. For the year
ended December 31, 2009, we recorded a fixed asset and
other intangible impairment loss of $38.6 million. We
recorded a charge of $36.2 million related to our contract
drilling business in the third quarter of 2009 after determining
that the carrying value of certain of these drilling rigs
exceeded the undiscounted cash flows associated with these
assets and the fair market value estimates for these assets. In
the fourth quarter of 2009, we recorded an impairment of
intangible assets of $2.5 million related to our completion
and production business.
Goodwill
Impairment Loss
We did not record any goodwill impairment in 2010. For the year
ended December 31, 2009, we recorded a goodwill impairment loss
of $97.6 million. The write-downs of goodwill was
associated with several of our reporting units and was based
upon several valuation techniques including a discounted cash
flow analysis of expected future earnings associated with these
businesses. Our analysis of future cash flows was impacted
significantly by the overall decline in oilfield activity in
late 2008 which continued throughout 2009.
Taxes
Tax expense (benefit) is comprised of current income taxes and
deferred income taxes. The current and deferred taxes added
together provide an indication of an effective rate of income
tax.
We recorded a tax provision of $51.6 million, at an
effective rate of 38%, for the year ended December 31, 2010
compared to a tax benefit of $63.1 million for the year
ended December 31, 2009 at an effective rate of
approximately 25.8%. The lower effective tax rate in 2009 was
primarily due to the impairment of goodwill with limited tax
basis. Excluding the impact of the goodwill impairment charges,
our effective tax rate for the year ended December 31, 2009
would have been 33.9%.
50
Results
of Operations for the Years Ended December 31, 2009 and
2008
The following tables set forth our results of continuing
operations, including amounts expressed as a percentage of total
revenue, for the periods indicated (in thousands, except
percentages).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent
|
|
|
|
Year
|
|
|
Year
|
|
|
Change
|
|
|
Change
|
|
|
|
Ended
|
|
|
Ended
|
|
|
2009/
|
|
|
2009/
|
|
|
|
12/31/09
|
|
|
12/31/08
|
|
|
2008
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Completion and production services
|
|
$
|
897,584
|
|
|
$
|
1,541,709
|
|
|
$
|
(644,125
|
)
|
|
|
(42
|
)%
|
Drilling services
|
|
|
114,729
|
|
|
|
234,104
|
|
|
|
(119,375
|
)
|
|
|
(51
|
)%
|
Product sales
|
|
|
44,081
|
|
|
|
59,102
|
|
|
|
(15,021
|
)
|
|
|
(25
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,056,394
|
|
|
$
|
1,834,915
|
|
|
$
|
(778,521
|
)
|
|
|
(42
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Completion and production services
|
|
$
|
165,787
|
|
|
$
|
467,100
|
|
|
$
|
(301,313
|
)
|
|
|
(65
|
)%
|
Drilling services
|
|
|
9,641
|
|
|
|
58,743
|
|
|
|
(49,102
|
)
|
|
|
(84
|
)%
|
Product sales
|
|
|
7,966
|
|
|
|
12,677
|
|
|
|
(4,711
|
)
|
|
|
(37
|
)%
|
Corporate
|
|
|
(34,313
|
)
|
|
|
(38,293
|
)
|
|
|
3,980
|
|
|
|
10
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
149,081
|
|
|
$
|
500,227
|
|
|
$
|
(351,146
|
)
|
|
|
(70
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate includes amounts related to corporate
personnel costs, other general expenses and stock-based
compensation charges.
Adjusted EBITDA consists of net income (loss) from
continuing operations before net interest expense, taxes,
depreciation and amortization, non-controlling interest and
impairment loss. Adjusted EBITDA is a non-GAAP measure of
performance. We use Adjusted EBITDA as the primary internal
management measure for evaluating performance and allocating
additional resources. The following table reconciles Adjusted
EBITDA for the years ended December 31, 2009 and 2008 to
the most comparable U.S. GAAP measure, operating income
(loss). The calculation of Adjusted EBITDA is different from the
calculation of EBITDA, as defined and used in our
credit facilities. For a discussion of the calculation of
EBITDA as defined under our existing credit
facilities, as
51
recently amended, see Note 11, Long-term debt,
in our notes to consolidated financial statements included
elsewhere in this Annual Report.
Reconciliation
of Adjusted EBITDA to Most Comparable
GAAP Measure Operating Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Completion and
|
|
|
Drilling
|
|
|
Product
|
|
|
|
|
|
|
|
|
|
Production Services
|
|
|
Services
|
|
|
Sales
|
|
|
Corporate
|
|
|
Total
|
|
|
Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA, as defined
|
|
$
|
165,787
|
|
|
$
|
9,641
|
|
|
$
|
7,966
|
|
|
$
|
(34,313
|
)
|
|
$
|
149,081
|
|
Depreciation and amortization
|
|
$
|
174,929
|
|
|
$
|
21,067
|
|
|
$
|
2,460
|
|
|
$
|
2,276
|
|
|
$
|
200,732
|
|
Write-off of deferred financing fees
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(528
|
)
|
|
$
|
(528
|
)
|
Fixed asset and other intangible impairment losses
|
|
$
|
2,488
|
|
|
$
|
36,158
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
38,646
|
|
Goodwill impairment loss
|
|
$
|
97,643
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
97,643
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
(109,273
|
)
|
|
$
|
(47,584
|
)
|
|
$
|
5,506
|
|
|
$
|
(36,061
|
)
|
|
$
|
(187,412
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA, as defined
|
|
$
|
467,100
|
|
|
$
|
58,743
|
|
|
$
|
12,677
|
|
|
$
|
(38,293
|
)
|
|
$
|
500,227
|
|
Depreciation and amortization
|
|
$
|
156,298
|
|
|
$
|
19,961
|
|
|
$
|
2,537
|
|
|
$
|
2,401
|
|
|
$
|
181,197
|
|
Goodwill impairment losses
|
|
$
|
243,203
|
|
|
$
|
27,410
|
|
|
$
|
1,393
|
|
|
$
|
|
|
|
$
|
272,006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
67,599
|
|
|
$
|
11,372
|
|
|
$
|
8,747
|
|
|
$
|
(40,694
|
)
|
|
$
|
47,024
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Below is a detailed discussion of our operating results by
segment for these periods.
Year
Ended December 31, 2009 Compared to the Year ended
December 31, 2008
Revenue
Revenue from continuing operations for the year ended
December 31, 2009 decreased by $778.5 million, or 42%,
to $1,056.4 million from $1,834.9 million for the year
ended December 31, 2008. This decrease by segment was as
follows:
|
|
|
|
|
Completion and Production Services. Segment
revenue decreased $644.1 million, or 42%, primarily due to
an overall decline in investment by our customers in oil and gas
exploration and development activities resulting from lower oil
and gas commodity prices and concerns over the availability of
capital for such investment. We experienced lower utilization
and pricing for each of our service offerings on a
year-over-year
basis, except for our coiled tubing business in Mexico which
provided a positive contribution to 2009 results. In the fourth
quarter of 2009, we experienced an increase in revenues and
margins compared to the third quarter of 2009 as market
conditions showed signs of improvement.
|
|
|
|
Drilling Services. Segment revenue decreased
$119.4 million, or 51%, for the year, primarily due to the
overall decline in oilfield service activities throughout the
year compared to 2008. Lower utilization rates and pricing
pressure impacted our rig logistics and drilling businesses,
however revenues were up slightly in the fourth quarter of 2009
compared to the third quarter of 2009 as we experienced a slight
increase in customer activity.
|
|
|
|
Product Sales. Segment revenue decreased
$15.0 million, or 25%, for the year, primarily due to a
decline in our Southeast Asian business resulting from a change
in the sales mix and the timing of product sales and equipment
refurbishment, which tends to be project-specific. Partially
offsetting this decrease were the consistent revenues earned at
our fabrication business in north Texas
year-over-year,
which included a work-over rig project completed in the first
quarter of 2009 and sales of low margin equipment to
third-parties.
|
52
Service
and Product Expenses
Service and product expenses include labor costs associated with
the execution and support of our services, materials used in the
performance of those services and other costs directly related
to the support and maintenance of equipment. These expenses
decreased $411.1 million, or 36%, to $725.4 million
for the year ended December 31, 2009 from
$1,136.5 million for the year ended December 31, 2008.
The decline in service and product expenses was primarily due to
significantly lower activity levels and cost-saving measures we
began implementing in late 2008, including headcount reductions,
payroll concessions and reduced product and service costs from
outside vendors. The following table summarizes service and
product expenses as a percentage of revenues for the years ended
December 31, 2009 and 2008:
Service
and Product Expenses as a Percentage of Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
Segment:
|
|
12/31/09
|
|
12/31/08
|
|
Change
|
|
Completion and Production services
|
|
|
68
|
%
|
|
|
61
|
%
|
|
|
7
|
%
|
Drilling services
|
|
|
75
|
%
|
|
|
67
|
%
|
|
|
8
|
%
|
Product sales
|
|
|
75
|
%
|
|
|
71
|
%
|
|
|
4
|
%
|
Total
|
|
|
69
|
%
|
|
|
62
|
%
|
|
|
7
|
%
|
Service and product expenses as a percentage of revenue
increased to 69% for the year ended December 31, 2009
compared to 62% for the year ended December 31, 2008.
Margins by business segment were impacted primarily by pricing
and utilization.
|
|
|
|
|
Completion and Production Services. Service
and product expenses as a percentage of revenue for this
business segment increased when comparing the year ended
December 31, 2009 to the same period in 2008. The overall
decline in activity levels in the oil and gas industry, which
began in late 2008 and continued throughout most of the year in
2009, resulted in lower utilization of our equipment and
services, and pricing pressure from competitors. Partially
defraying the impact of this overall decline in activity levels
were cost-saving measures we began implementing in late 2008.
|
|
|
|
Drilling Services. The increase in service and
product expenses as a percentage of revenue for this business
segment was primarily due to lower utilization of our equipment
due to significantly reduced activity levels by our customers,
and lower pricing on a
year-over-year
basis, partially offset by cost-saving measures.
|
|
|
|
Product Sales. The increase in service and
product expenses as a percentage of revenue for the products
segments was primarily due to the mix of products sold for the
relative periods, as the 2008 results included several higher
margin projects associated with our Southeast Asian operations
when compared to the year ended December 31, 2009.
Additionally, on a
year-over-year
basis, a larger proportion of the revenues and related costs for
the product sales segment for the year ended December 31,
2009 were provided by our repair and fabrication facility in
north Texas at lower margins relative to our Southeast Asian
business, including the sale of a large inventory item.
|
Selling,
General and Administrative Expenses
Selling, general and administrative expenses include salaries
and other related expenses for our selling, administrative,
finance, information technology and human resource functions.
Selling, general and administrative expenses decreased
$16.8 million, or 8%, for the year ended December 31,
2009 to $181.4 million from $198.2 million during the
year ended December 31, 2008. Several cost saving measures
were implemented during 2009 including headcount reductions,
other payroll concessions and lower outside service costs. These
expense reductions were offset by: (1) the loss on the
exchange of certain non-monetary assets in Canada during the
first quarter of 2009 which totaled $4.9 million;
(2) higher bad debt expense, particularly in our drilling
services segment and (3) higher losses from the disposal of
fixed assets. Excluding the impact of the non-monetary asset
exchange in Canada, as a percentage of revenues, selling,
general and administrative expense was 17% and 11% for the years
ended December 31, 2009 and 2008, respectively.
53
Depreciation
and Amortization
Depreciation and amortization expense increased
$19.5 million, or 11%, to $200.7 million for the year
ended December 31, 2009 from $181.2 million for the
year ended December 31, 2008. The increase in depreciation
and amortization expense was the result of the following:
(1) depreciation of equipment placed into service
throughout 2008, as well as additional equipment purchased in
2009; (2) depreciation and amortization expense related to
assets associated with businesses acquired in 2008, some of
which did not contribute depreciation expense for the full year
ended December 31, 2008 due to the timing of the
acquisitions; and (3) an increase in amortization expense
associated with intangible assets acquired in business
combinations in 2008. As a percentage of revenue, depreciation
and amortization expense increased to 19% from 10% for the years
ended December 31, 2009 and 2008, respectively. We expected
depreciation and amortization expense as a percentage of revenue
to remain higher than in recent periods due to the significant
investment in capital expenditures made throughout the last
three years and the overall decline in activity levels that
began in late 2008.
Fixed
Asset and Other Intangible Impairment Loss
For the year ended December 31, 2009, we recorded a fixed
asset and other intangible impairment loss of
$38.6 million. We recorded a charge of $36.2 million
related to our contract drilling business in the third quarter
of 2009 after determining that the carrying value of certain of
these drilling rigs exceeded the undiscounted cash flows
associated with these assets and the fair market value estimates
for these assets. In the fourth quarter of 2009, we recorded an
impairment of intangible assets of $2.5 million related to
our completion and production business. We recorded no such
impairment charges in 2008.
Goodwill
Impairment Loss
We recorded a goodwill impairment loss of $97.6 million for
the year ended December 31, 2009 compared to
$272.0 million recorded in 2008. These write-downs of
goodwill in both 2008 and 2009 were associated with several of
our reporting units and were based upon several valuation
techniques including a discounted cash flow analysis of expected
future earnings associated with these businesses. Our analysis
of future cash flows was impacted significantly by the overall
decline in oilfield activity in late 2008 which continued
throughout 2009.
Interest
Expense
Interest expense was $56.9 million and $59.7 million
for the years ended December 31, 2009 and 2008,
respectively. This 5% decrease in interest expense was
attributable primarily to a decrease in the average amount of
debt outstanding during the year ended December 31, 2009
and lower interest rates in 2009 compared to 2008 on our
outstanding borrowings under revolving credit facilities, which
were fully repaid as of June 30, 2009. The weighted-average
interest rate of borrowings outstanding at December 31,
2009 and 2008 was approximately 8.0% and 7.0%, respectively.
Taxes
Tax expense (benefit) is comprised of current income taxes and
deferred income taxes. The current and deferred taxes added
together provide an indication of an effective rate of income
tax.
We recorded a tax benefit of $63.1 million for the year
ended December 31, 2009 at an effective rate of
approximately 25.8% compared to a tax expense of
$72.3 million for the year ended December 31, 2008.
The lower effective tax rate in 2009 was due to the impairment
of goodwill with limited tax basis. Our tax rate for the year
ended December 31, 2008 was impacted significantly by a
$272.0 million impairment of goodwill which had a limited
tax basis, as the majority of the goodwill arose through stock
purchase transactions with little or no tax basis. Excluding the
impact of the goodwill impairment charges, our effective tax
rates for the years ended December 31, 2009 and 2008 would
have been 33.9% and 35.5%.
54
Liquidity
and Capital Resources
As of December 31, 2010, we had working capital, net of
cash, of $276.8 million and cash and cash equivalents of
$126.7 million, compared to working capital, net of cash,
of $200.8 million and cash and cash equivalents of
$77.4 million at December 31, 2009. This increase in
working capital was primarily due to an increase in accounts
receivable, partially offset by an increase in accounts payable,
associated with favorable operating results, and an increase in
accrued expenses due to higher earnings-based incentive
compensation accruals. We also received net tax refunds of
approximately $31.1 million during 2010.
Our primary liquidity needs are to fund capital expenditures and
general working capital. In addition, we have historically
obtained capital to fund strategic business acquisitions. Our
primary sources of funds have been cash flow from operations,
proceeds from borrowings under bank credit facilities and a
private placement of debt that was subsequently exchanged for
publicly registered debt.
We anticipate that our cash generated from operations and our
current cash balance will be sufficient to fund the majority of
our cash requirements for the next twelve months, however
borrowings under our amended revolving credit facility, future
debt offerings
and/or
future public equity offerings may also be used to fund future
acquisitions or to satisfy our other liquidity needs. We believe
that funds from these sources will be sufficient to meet both
our short-term working capital requirements and our long-term
capital requirements. If our plans or assumptions change, or are
inaccurate, or if we make further acquisitions, we may have to
raise additional capital. Our ability to fund planned capital
expenditures and to make acquisitions will depend upon our
future operating performance, and more broadly, on the
availability of equity and debt financing, which will be
affected by prevailing economic conditions in our industry, and
general financial, business and other factors, some of which are
beyond our control. In addition, new debt obtained could include
service requirements based on higher interest paid and shorter
maturities and could impose a significant burden on our results
of operations and financial condition. The issuance of
additional equity securities could result in significant
dilution to stockholders.
On October 13, 2009, we completed an amendment to our
existing revolving credit facilities (the Third
Amendment) which modified the structure of the credit
facility to an asset-based facility subject to borrowing base
restrictions. This amendment provided us with less restrictive
financial debt covenants and reduced borrowing capacity under
the facility.
The following table summarizes cash flows by type for the
periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2010
|
|
2009
|
|
2008
|
|
Cash flows provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
216,158
|
|
|
$
|
285,204
|
|
|
$
|
350,409
|
|
Investing activities
|
|
|
(174,088
|
)
|
|
|
(18,128
|
)
|
|
|
(374,098
|
)
|
Financing activities
|
|
|
6,817
|
|
|
|
(207,991
|
)
|
|
|
27,990
|
|
Net cash provided by operating activities decreased
$69.0 million for the year ended December 31, 2010
compared to the year ended December 31, 2009, and decreased
$65.2 million for the year ended December 31, 2009
compared to the year ended December 31, 2008. The decrease
in operating cash flows for the year ended December 31,
2010 compared to the year ended December 31, 2009 was
primarily due to an increase in trade receivables resulting from
a favorable increase in oilfield activity partially offset by an
increase in payables and the collection of a large income tax
receivable. During 2010, cash receipts activity remained
favorable, but with an increase in sales there was an increase
in outstanding receivables. The decrease in operating cash flows
for 2009 compared to 2008 reflects the overall decline in
oilfield activity in late 2008 and throughout 2009.
Net cash used in investing activities increased
$156.0 million for the year ended December 31, 2010
compared to the year ended December 31, 2009 and decreased
$356.0 million for the year ended December 31, 2009
compared to the year ended December 31, 2008. Of this
increase in 2010, $145.0 million was due to an increase in
capital expenditures, which was only $37.4 million for the
year ended December 31, 2009. We decreased our overall
capital expenditures in 2009 in response to the decline in
commodity prices and lower activity levels. In addition, we
invested $33.7 million in business acquisitions in 2010,
with no corresponding business acquisitions in 2009. The
55
decrease in 2009 compared to 2008 was due to investment in
capital expenditures of $253.8 million and acquisitions of
$180.2 million in 2008.
Net cash provided by financing activities was $6.8 million
for the year ended December 31, 2010 compared to
$208.0 million of cash used for financing activities for
the year ended December 31, 2009, and compared to cash
provided by financing activities of $28.0 million for the
year ended December 31, 2008. In 2009, we focused on
eliminating obligations under our credit facility and building
cash. We repaid long-term borrowings under our debt facilities
totaling $200.6 million and only borrowed $3.2 million
during 2009. The primary source of these funds in 2009 was cash
flow from operations. Our long-term debt balances, including
current maturities, were $650.0 and $650.2 million as of
December 31, 2010 and 2009, respectively.
In 2010, we invested significantly more on capital expenditures
and acquisitions than we did during 2009. We will continue to
evaluate acquisitions of complementary companies. We believe
that our operating cash flows and borrowing capacity will be
sufficient to fund our operations and capital expenditures for
the next 12 months.
Dividends
We did not pay dividends on our $0.01 par value common
stock during the years ended December 31, 2010, 2009 and
2008. We do not intend to pay dividends in the foreseeable
future, but rather plan to reinvest such funds in our business.
Furthermore, our credit facility contains restrictive debt
covenants which preclude us from paying future dividends on our
common stock.
Description
of Our Indebtedness
Senior
Notes.
On December 6, 2006, we issued 8.0% senior notes with
a face value of $650.0 million through a private placement
of debt. These notes mature in 10 years, on
December 15, 2016, and require semi-annual interest
payments, paid in arrears and calculated based on an annual rate
of 8.0%, on June 15 and December 15, of each year, which
commenced on June 15, 2007. There was no discount or
premium associated with the issuance of these notes. The senior
notes are guaranteed by all of our current domestic
subsidiaries. The senior notes have covenants which, among other
things: (1) limit the amount of additional indebtedness we
can incur; (2) limit restricted payments such as a
dividend; (3) limit our ability to incur liens or
encumbrances; (4) limit our ability to purchase, transfer
or dispose of significant assets; (5) limit our ability to
purchase or redeem stock or subordinated debt; (6) limit
our ability to enter into transactions with affiliates;
(7) limit our ability to merge with or into other companies
or transfer all or substantially all of our assets; and
(8) limit our ability to enter into sale and leaseback
transactions. We have the option to redeem all or part of these
notes on or after December 15, 2011. Additionally, we may
redeem some or all of the notes prior to December 15, 2011
at a price equal to 100% of the principal amount of the notes
plus a make-whole premium.
Pursuant to a registration rights agreement with the holders of
our 8.0% senior notes, on June 1, 2007, we filed a
registration statement on
Form S-4
with the SEC which enabled these holders to exchange their notes
for publicly registered notes with substantially identical
terms. These holders exchanged 100% of the notes for publicly
traded notes on July 25, 2007. On August 28, 2007, we
entered into a supplement to the indenture governing the
8.0% senior notes, whereby additional domestic subsidiaries
became guarantors under the indenture. Effective April 1,
2009, we entered into a second supplement to this indenture
whereby additional domestic subsidiaries became guarantors under
the indenture.
Credit
Facility.
We maintain a senior secured facility (the Credit
Agreement) with Wells Fargo Bank, National Association, as
U.S. Administrative Agent, HSBC Bank Canada, as Canadian
Administrative Agent, and certain other financial institutions.
On October 13, 2009, we entered into the Third Amendment
(the Credit Agreement after giving effect to the Third
Amendment, the Amended Credit Agreement) and
modified the structure of our existing credit facility to an
asset-based facility subject to borrowing base restrictions. In
connection with the Third Amendment, Wells Fargo Capital
Finance, LLC (formerly known as Wells Fargo Foothill,
LLC) replaced Wells Fargo Bank,
56
National Association, as U.S. Administrative Agent and also
serves as U.S. Issuing Lender and U.S. Swingline
Lender under the Amended Credit Agreement. The Amended Credit
Agreement provides for a U.S. revolving credit facility of
up to $225 million that matures in December 2011 and a
Canadian revolving credit facility of up to $15 million
(with Integrated Production Services Ltd., one of our
wholly-owned subsidiaries, as the borrower thereof
(Canadian Borrower)) that matures in December 2011.
The Amended Credit Agreement includes a provision for a
commitment increase, as defined therein, which
permits us to effect up to two separate increases in the
aggregate commitments under the Amended Credit Agreement by
designating one or more existing lenders or other banks or
financial institutions, subject to the banks sole
discretion as to participation, to provide additional aggregate
financing up to $75 million, with each committed increase
equal to at least $25 million in the U.S., or
$5 million in Canada, and in accordance with other
provisions as stipulated in the Amended Credit Agreement.
Certain portions of the credit facilities are available to be
borrowed in U.S. dollars, Canadian dollars and other
currencies approved by the lenders.
Our U.S. borrowing base is limited to: (1) 85% of
U.S. eligible billed accounts receivable, less dilution, if
any, plus (2) the lesser of 55% of the amount of
U.S. eligible unbilled accounts receivable or
$10.0 million, plus (3) the lesser of the
equipment reserve amount and 80% times the most
recently determined net liquidation percentage, as
defined in the Amended Credit Agreement, times the value of our
and the U.S. subsidiary guarantors equipment,
provided that at no time shall the amount determined under this
clause exceed 50% of the U.S. borrowing base, minus
(4) the aggregate sum of reserves established by the
U.S. Administrative Agent, if any. The equipment
reserve amount means $50.0 million upon the effective
date of the Third Amendment, less $0.6 million for each
subsequent month, not to be reduced below zero in the aggregate.
The Canadian borrowing based is limited to: (1) 80% of
Canadian eligible billed accounts receivable, plus (2) if
the Canadian Borrower has requested credit for equipment under
the Canadian borrowing base, the lesser of
(a) $15.0 million, and (b) 80% times the
most recently determined net liquidation percentage,
as defined in the Amended Credit Agreement, times the value
(calculated on a basis consistent with our historical accounting
practices) of our and the US subsidiary guarantors
equipment, minus (3) the aggregate amount of reserves
established by our Canadian Administrative Agent, if any.
Subject to certain limitations set forth in the Amended Credit
Agreement, we have the ability to elect how interest under the
Amended Credit Agreement will be computed. Interest under the
Amended Credit Agreement may be determined by reference to
(1) the London Inter-bank Offered Rate, or LIBOR, plus an
applicable margin between 3.75% and 4.25% per annum (with the
applicable margin depending upon our excess availability
amount, as defined in the Amended Credit Agreement) or
(2) the Base Rate (which means the higher of
the Prime Rate, Federal Funds Rate plus 0.50%,
3-month
LIBOR plus 1.00% and 3.50%), plus the applicable margin, as
described above. For the period from the effective date of the
Third Amendment until the six month anniversary of the effective
date of the Third Amendment, interest was computed with an
applicable margin rate of 4.00%. If an event of default exists
or continues under the Amended Credit Agreement, advances will
bear interest as described above with an applicable margin rate
of 4.25% plus 2.00%. Additionally, if an event of default exists
under the Amended Credit Agreement, as defined therein, the
lenders could accelerate the maturity of the obligations
outstanding thereunder and exercise other rights and remedies.
Interest is payable monthly.
Under the Amended Credit Agreement, we are permitted to prepay
our borrowings and we have the right to terminate, in whole or
in part, the unused portion of the U.S. commitments in
$1.0 million increments upon written notice to the
U.S. Administrative Agent. If all of the U.S. facility
is terminated, the Canadian facility must also be terminated.
All of the obligations under the U.S. portion of the
Amended Credit Agreement are secured by first priority liens on
substantially all of our assets and the assets of our
U.S. subsidiaries as well as a pledge of approximately 66%
of the stock of our first-tier foreign subsidiaries.
Additionally, all of the obligations under the U.S. portion
of the Amended Credit Agreement are guaranteed by substantially
all of our U.S. subsidiaries. The obligations under the
Canadian portion of the Amended Credit Agreement are secured by
first priority liens on substantially all of our assets and the
assets of our subsidiaries (other than our Mexican subsidiary).
Additionally, all of the obligations under the Canadian portion
of the Amended Credit Agreement are guaranteed by us as well as
certain of our subsidiaries.
57
The Amended Credit Agreement also contains various covenants
that limit our and our subsidiaries ability to:
(1) grant certain liens; (2) incur additional
indebtedness; (3) make certain loans and investments;
(4) make capital expenditures; (5) make distributions;
(6) make acquisitions; (7) enter into hedging
transactions; (8) merge or consolidate; or (9) engage
in certain asset dispositions. The Amended Credit Agreement
contains one financial maintenance covenant which requires us
and our subsidiaries, on a consolidated basis, to maintain a
fixed charge coverage ratio, as defined in the
Amended Credit Agreement, of not less than 1.10 to 1.00. This
covenant is only tested if our excess availability
amount, as defined under the Amended Credit Agreement,
plus certain qualified cash and cash equivalents (collectively
Liquidity) is less than $50.0 million for a
period of 5 consecutive days and continues only until such time
as our Liquidity has been greater than or equal to
$50.0 million for a period of 90 consecutive days or
greater than or equal to $75.0 million for a period of 45
consecutive days.
Our fixed charge coverage ratio covenant is calculated, for
fiscal quarters ending after September 30, 2009, as the
ratio of EBITDA calculated for the four fiscal
quarter period ended after September 30, 2009 minus capital
expenditures made with cash (to the extent not already incurred
in a prior period) or incurred during such four quarter period,
compared to fixed charges, calculated for the four
quarters then ended. EBITDA is defined in the
Amended Credit Agreement as consolidated net income for the
period plus, to the extent deducted in determining our
consolidated net income, interest expense, taxes, depreciation,
amortization and other non-cash charges for such period,
provided that EBITDA shall be subject to pro forma adjustments
for acquisitions and non-ordinary course asset sales assuming
that such transactions occurred on the first day of the
determination period, which adjustments shall be made in
accordance with the guidelines for pro forma presentations set
forth by the Securities and Exchange Commission. Fixed
charges, as defined in the Amended Credit Agreement,
include interest expense, among other things, reduced by the
amortization of transaction fees associated with the Third
Amendment.
We were not subject to the fixed charge coverage ratio covenant
in the Amended Credit Agreement as of December 31, 2010
since the Excess Availability Amount plus Qualified Cash Amount
(each as defined in the Amended Credit Agreement) exceeded
$50 million. If we were subject to the fixed charge
coverage ratio covenant, we would have been in compliance as of
December 31, 2010.
There were no revolving borrowings outstanding under our
U.S. or Canadian revolving credit facilities as of
December 31, 2010. The weighted average interest rate for
our revolving credit facilities during the twelve months ended
December 31, 2010 was 8.0%. There were letters of credit
outstanding under the U.S. revolving portion of the
facility totaling $26.4 million, which reduced the
available borrowing capacity as of December 31, 2010. We
incurred fees related to our letters of credit as of
December 31, 2010 at 3.75% per annum. For the twelve months
ended December 31, 2010, fees related to our letters of
credit were calculated using a
360-day
provision, at 4.0% per annum. The net excess availability under
our borrowing base calculations for the U.S. and Canadian
revolving facilities at December 31, 2010 was
$187.4 million and $8.4 million, respectively.
Outstanding
Debt and Operating Lease Commitments
The following table summarizes our known contractual obligations
as of December 31, 2010 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
Contractual Obligations
|
|
Total
|
|
|
2011
|
|
|
2012-2013
|
|
|
2014-2015
|
|
|
Thereafter
|
|
|
Long-term debt, including capital (finance) lease obligations
|
|
$
|
650,000
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
650,000
|
|
Interest on 8% senior notes issued December 6, 2006
|
|
|
307,667
|
|
|
|
52,000
|
|
|
|
104,000
|
|
|
|
104,000
|
|
|
|
47,667
|
|
Purchase obligations(1)
|
|
|
45,376
|
|
|
|
45,376
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating lease obligations
|
|
|
92,945
|
|
|
|
27,287
|
|
|
|
39,162
|
|
|
|
15,441
|
|
|
|
11,055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual obligations
|
|
$
|
1,095,988
|
|
|
$
|
124,663
|
|
|
$
|
143,162
|
|
|
$
|
119,441
|
|
|
$
|
708,722
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Purchase obligations were pursuant to non-cancelable equipment
purchase orders outstanding as of December 31, 2010. We
have no significant purchase orders which extend beyond one year. |
58
We have entered into agreements to purchase certain equipment
for use in our business, which are included as purchase
obligations in the table above to the extent that these
obligations represent firm non-cancelable commitments. The
manufacture of this equipment requires lead-time and we
generally are committed to accept this equipment at the time of
delivery, unless arrangements have been made to cancel delivery
in accordance with the purchase agreement terms. We spent
$169.9 million for equipment purchases and other capital
expenditures during the year ended December 31, 2010.
We expect to continue to acquire complementary companies and
evaluate potential acquisition targets. We may use cash from
operations, proceeds from future debt or equity offerings and
borrowings under our amended revolving credit facility for this
purpose.
Off-Balance
Sheet Arrangements
We have entered into operating lease arrangements for our light
vehicle fleet, certain of our specialized equipment and for our
office and field operating locations in the normal course of
business. The terms of the facility leases range from monthly to
five years. The terms of the light vehicle leases range from
three to four years. The terms of the specialized equipment
leases range from two to six years. Annual payments pursuant to
these leases are included above in the table under
Outstanding Debt and Operating Lease
Commitments.
Recent
Accounting Pronouncements and Authoritative Literature
The FASB has addressed the issue of business combinations during
recent years. In December 2007, the FASB issued guidance
regarding business combinations that substantially replaced
previously existing guidance, while maintaining the precepts
prescribed therein, and further requiring that all assets and
liabilities and non-controlling interests of an acquired
business be measured at their fair value, with limited
exceptions, including the recognition of acquisition-related
costs and anticipated restructuring costs separate from the
acquired net assets. In addition, entities must recognize
pre-acquisition contingencies, as well as assets and liabilities
assumed arising from contractual contingencies as of the
acquisition date, measured at acquisition-date fair values, and
must recognize all other contractual contingencies as of the
acquisition date, measured at their acquisition-date fair values
only if it is more likely than not that these contingencies meet
the definition of an asset or liability. In addition, this
standard provides guidance for measuring goodwill and recording
a bargain purchase, defined as a business combination in which
total acquisition-date fair value of the identifiable net assets
acquired exceeds the fair value of the consideration transferred
plus any non-controlling interest in the acquiree, and states
that the acquiring entity must recognize that excess in earnings
as a gain attributable to the acquirer. The FASB amended this
guidance in April 2009 as it relates to accounting for assets
and liabilities assumed in a business combination which arise
from contingencies. This amendment requires that contingent
assets acquired and liabilities assumed in a business
combination to be recognized at fair value on the acquisition
date if fair value can be reasonably estimated during the
measurement period. If fair value cannot be reasonably estimated
during the measurement period, the contingent asset or liability
would be recognized as a contingency, in accordance with
existing U.S. GAAP, with reasonable estimation of the
amount of loss, if any. This amendment also eliminated the
specific subsequent accounting guidance for contingent assets
and liabilities, without significantly revising the original
guidance. However, contingent consideration arrangements of an
acquiree assumed by the acquirer in a business combination would
still be initially and subsequently measured at fair value. We
originally adopted the revised guidance for business
combinations when it became effective on January 1, 2009,
and the amendment thereto, subsequently in 2009. In December
2010, the FASB updated this guidance to require each public
entity that presents comparative financial statements to
disclose the revenue and earnings of the combined entity as if
the business combination that occurred during the current year
had occurred as of the beginning of the comparable prior annual
reporting period only. In addition, this amendment expands the
supplemental pro forma disclosures related to such a business
combination to include a description of the nature and amount of
material, nonrecurring pro forma adjustments directly
attributable to the business combination included in the
reported pro forma revenue and earnings. This most recent
amendment should be accounted for prospectively for business
combinations for which the acquisition date is on or after
January 1, 2011, for calendar-year reporting entities.
Early adoption is permitted. Although we did not early adopt
this standard, we do not expect this guidance to have a material
impact on our financial position, results of
59
operations or cash flows. We will comply with this update for
business combinations that have a material impact on our
financial results.
In May 2009, the FASB issued a standard regarding subsequent
events that provides guidance as to when an entity should
recognize events or transactions occurring after a balance sheet
date in its financial statements and the necessary disclosures
related to these events. Specifically, the entity should
recognize subsequent events that provide evidence about
conditions that existed at the balance sheet date, including
significant estimates used to prepare financial statements.
Originally, this standard required entities to disclose the date
through which subsequent events had been evaluated and whether
that date was the date the financial statements were issued or
the date the financial statements were available to be issued.
We adopted this accounting standard effective June 30, 2009
and applied its provisions prospectively. In February 2010, the
FASB modified this standard to eliminate the requirement for
publicly-traded entities to disclose the date through which
subsequent events have been evaluated.
In January 2010, the FASB issued Fair Value Measurements
and Disclosure (Topic 820) which clarified the disclosure
requirements of existing U.S. GAAP related to fair value
measurements. This standard requires additional disclosures
about recurring and non-recurring fair value measurements as
follows: (1) for transfers in and out of Level 1 and
Level 2 fair value measurements, as those terms are
currently defined in existing authoritative literature, a
reporting entity is required to disclose the amount of the
movement between levels and an explanation for the movement;
(2) for activity at Level 3, primarily fair value
measurements based on unobservable inputs, a reporting entity is
required to present separately information about purchases,
sales, issuances and settlements, as opposed to presenting such
transactions on a net basis; (3) in the event of a
disaggregation, a reporting entity is required to provide fair
value measurement disclosure for each class of assets and
liabilities; and (4) a reporting entity is required to
provide disclosures about the valuation techniques and inputs
used to measure fair value for both recurring and non-recurring
fair value measurements for items that fall in either
Level 2 or Level 3. These disclosure requirements are
effective for interim and annual reporting periods beginning
after December 15, 2009, except for disclosures about
purchases, sales, issuances and settlements in the roll forward
of activity in Level 3 fair value measurements for which
disclosure becomes effective for fiscal years beginning after
December 15, 2010, and for interim periods within those
fiscal years.
On March 30, 2010, the President of the United States
signed the Health Care and Education Reconciliation Act of 2010,
which is a reconciliation bill that amends the Patient
Protection and Affordable Care Act that was signed by the
President on March 23, 2010. Certain provisions of this law
became effective during 2010. We have reviewed our health
insurance plan provisions with third-party consultants and
continue to evaluate our position relative to the changes in the
law. We do not believe that the provisions which have taken
effect will have a significant impact on the operation of our
existing health insurance plan. However, future provisions under
the law which become effective in subsequent periods may impact
our health insurance plan and our overall financial position. We
are evaluating these provisions as they become effective and
continue to seek guidance from the FASB and SEC related to the
implications of this new legislation on accounting and
disclosure requirements. We expect that this legislation will
have an impact on our financial position, results of operations
and cash flows, but we cannot determine the extent of the impact
at this time.
In December 2010, the FASB issued additional guidance related to
accounting for intangible assets and goodwill. The amendments in
this update modify Step 1 of the goodwill impairment test for
reporting units with zero or negative carrying amounts. For
those reporting units, an entity is required to perform Step 2
of the goodwill impairment test if it is more likely than not
that a goodwill impairment exists. In determining whether it is
more likely than not that a goodwill impairment exists, an
entity should consider whether there are any adverse qualitative
factors indicating that an impairment may exist. The qualitative
factors are consistent with the existing guidance and examples,
which require that goodwill of a reporting unit be tested for
impairment between annual test dates if an event occurs or
circumstances change that would more likely than not reduce the
fair value of a reporting unit below its carrying amount. This
update is effective for public entities with fiscal years
beginning after December 15, 2010 and interim periods
within those years. Early adoption is not permitted. We are
currently evaluating the effect this proposed guidance may have
on our financial position, results of operations and cash flows.
60
|
|
Item 7A.
|
Quantitative
and Qualitative Disclosures About Market Risk.
|
The demand, pricing and terms for oil and gas services provided
by us are largely dependent upon the level of activity for the
U.S. and Canadian gas industry. Industry conditions are
influenced by numerous factors over which we have no control,
including, but not limited to: the supply of and demand for oil
and gas; the level of prices, and expectations about future
prices, of oil and gas; the cost of exploring for, developing,
producing and delivering oil and gas; the expected rates of
declining current production; the discovery rates of new oil and
gas reserves; available pipeline and other transportation
capacity; weather conditions; domestic and worldwide economic
conditions; political instability in oil-producing countries;
technical advances affecting energy consumption; the price and
availability of alternative fuels; the ability of oil and gas
producers to raise equity capital and debt financing; and merger
and divestiture activity among oil and gas producers.
The level of activity in the U.S. and Canadian oil and gas
exploration and production industry is volatile. No assurance
can be given that our expectations of trends in oil and gas
production activities will reflect actual future activity levels
or that demand for our services will be consistent with the
general activity level of the industry. Any prolonged
substantial reduction in oil and gas prices would likely affect
oil and gas exploration and development efforts and therefore
affect demand for our services. A material decline in oil and
gas prices or U.S. and Canadian activity levels could have
a material adverse effect on our business, financial condition,
results of operations and cash flows.
For the years ended December 31, 2010 and 2009,
approximately 5% of our revenues from continuing operations and
4% of our total assets were denominated in Canadian dollars, our
functional currency in Canada. As a result, a material decrease
in the value of the Canadian dollar relative to the
U.S. dollar may negatively impact our revenues, cash flows
and net income. Each one percentage point change in the value of
the Canadian dollar would have impacted our revenues for the
year ended December 31, 2010 by approximately
$0.8 million, or $0.5 million net of tax. We do not
currently use hedges or forward contracts to offset this risk.
Our Mexican operation uses the U.S. dollar as its
functional currency, and as a result, all transactions and
translation gains and losses are recorded currently in the
financial statements. The balance sheet amounts are translated
into U.S. dollars at the exchange rate at the end of the
month and the income statement amounts are translated at the
average exchange rate for the month. We estimate that a
hypothetical one percentage point change in the value of the
Mexican peso relative to the U.S. dollar would have
impacted our revenues for the year ended December 31, 2010
by approximately $0.5 million, or $0.3 million, net of
tax. Currently, we conduct a portion of our business in Mexico
in the local currency, the Mexican peso.
|
|
Item 8.
|
Financial
Statements and Supplementary Data.
|
61
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Complete Production Services, Inc.
We have audited the accompanying consolidated balance sheets of
Complete Production Services, Inc. as of December 31, 2010
and 2009, and the related consolidated statements of operations,
comprehensive income (loss), stockholders equity, and cash
flows for each of the three years in the period ended
December 31, 2010. These financial statements are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements 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 Complete Production Services, Inc. as of
December 31, 2010 and 2009, and the results of their
operations and their cash flows for each of the three years in
the period ended December 31, 2010, in conformity with
accounting principles generally accepted in the United States of
America.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States),
Complete Production Services, Inc.s internal control over
financial reporting as of December 31, 2010, based on
criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO) and our report
dated February 18, 2011, expressed an unqualified opinion
that Complete Production Services, Inc. maintained, in all
material respects, effective internal control over financial
reporting.
Houston, Texas
February 18, 2011
62
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Complete Production Services, Inc.
We have audited Complete Production Services, Inc.s
internal control over financial reporting as of
December 31, 2010, based on criteria established in
Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). Complete Production Services, Inc.s
management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting,
included in the accompanying Managements Report on
Internal Control over Financial Reporting. Our responsibility is
to express an opinion on Complete Production Services,
Inc.s internal control over financial reporting based on
our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk
that a material weakness exists, testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk, and performing such other procedures as we
considered necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of
management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, Complete Production Services, Inc. maintained,
in all material respects, effective internal control over
financial reporting as of December 31, 2010, based on
criteria established in Internal Control
Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of Complete Production Services,
Inc. as of December 31, 2010 and 2009, and the related
consolidated statements of operations, comprehensive income
(loss), stockholders equity, and cash flows for each of
the three years in the period ended December 31, 2010, and
our report dated February 18, 2011 expressed an unqualified
opinion on those consolidated financial statements.
Houston, Texas
February 18, 2011
63
COMPLETE
PRODUCTION SERVICES, INC.
Consolidated Balance Sheets
December 31, 2010 and 2009
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands, except share data)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
126,681
|
|
|
$
|
77,360
|
|
Accounts receivable, net of allowance for doubtful accounts of
$4,160 and $12,564, respectively
|
|
|
345,648
|
|
|
|
171,284
|
|
Inventory, net of obsolescence reserve of $2,453 and $888,
respectively
|
|
|
33,536
|
|
|
|
37,464
|
|
Prepaid expenses
|
|
|
18,700
|
|
|
|
17,943
|
|
Income tax receivable
|
|
|
23,462
|
|
|
|
57,606
|
|
Current deferred tax assets
|
|
|
2,499
|
|
|
|
8,158
|
|
Other current assets
|
|
|
1,384
|
|
|
|
111
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
551,910
|
|
|
|
369,926
|
|
Property, plant and equipment, net
|
|
|
956,028
|
|
|
|
941,133
|
|
Intangible assets, net of accumulated amortization of $21,293
and $15,476, respectively
|
|
|
9,209
|
|
|
|
13,243
|
|
Deferred financing costs, net of accumulated amortization of
$9,316 and $6,266, respectively
|
|
|
9,694
|
|
|
|
12,744
|
|
Goodwill
|
|
|
250,533
|
|
|
|
243,823
|
|
Restricted cash
|
|
|
17,000
|
|
|
|
|
|
Other long-term assets
|
|
|
6,202
|
|
|
|
7,985
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,800,576
|
|
|
$
|
1,588,854
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
$
|
|
|
|
$
|
228
|
|
Accounts payable
|
|
|
75,099
|
|
|
|
31,745
|
|
Accrued liabilities
|
|
|
44,291
|
|
|
|
41,102
|
|
Accrued payroll and payroll burdens
|
|
|
26,568
|
|
|
|
13,559
|
|
Accrued interest
|
|
|
2,446
|
|
|
|
3,206
|
|
Notes payable
|
|
|
|
|
|
|
1,069
|
|
Income taxes payable
|
|
|
|
|
|
|
813
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
148,404
|
|
|
|
91,722
|
|
Long-term debt
|
|
|
650,000
|
|
|
|
650,002
|
|
Deferred income taxes
|
|
|
190,422
|
|
|
|
148,240
|
|
Other long-term liabilities
|
|
|
5,916
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
994,742
|
|
|
|
889,964
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Common stock, $0.01 par value per share,
200,000,000 shares authorized, 76,443,926 (2009
75,278,406) issued
|
|
|
764
|
|
|
|
752
|
|
Preferred stock, $0.01 par value per share,
5,000,000 shares authorized, no shares issued and
outstanding
|
|
|
|
|
|
|
|
|
Additional paid-in capital
|
|
|
657,993
|
|
|
|
636,904
|
|
Retained earnings
|
|
|
126,165
|
|
|
|
42,007
|
|
Treasury stock, 167,643 (2009 54,313) shares at cost
|
|
|
(1,765
|
)
|
|
|
(334
|
)
|
Accumulated other comprehensive income
|
|
|
22,677
|
|
|
|
19,561
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
805,834
|
|
|
|
698,890
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
1,800,576
|
|
|
$
|
1,588,854
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
64
COMPLETE
PRODUCTION SERVICES, INC.
Consolidated Statements of Operations
Years Ended December 31, 2010, 2009 and
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except per share data)
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
|
|
$
|
1,527,618
|
|
|
$
|
1,012,313
|
|
|
$
|
1,775,813
|
|
Product
|
|
|
33,775
|
|
|
|
44,081
|
|
|
|
59,102
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,561,393
|
|
|
|
1,056,394
|
|
|
|
1,834,915
|
|
Service expenses
|
|
|
985,093
|
|
|
|
692,164
|
|
|
|
1,094,574
|
|
Product expenses
|
|
|
25,947
|
|
|
|
33,201
|
|
|
|
41,914
|
|
Selling, general and administrative expenses
|
|
|
175,445
|
|
|
|
181,420
|
|
|
|
198,200
|
|
Depreciation and amortization
|
|
|
181,823
|
|
|
|
200,732
|
|
|
|
181,197
|
|
Fixed asset and other intangibles impairment loss
|
|
|
|
|
|
|
38,646
|
|
|
|
|
|
Goodwill impairment loss
|
|
|
|
|
|
|
97,643
|
|
|
|
272,006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before interest and
taxes
|
|
|
193,085
|
|
|
|
(187,412
|
)
|
|
|
47,024
|
|
Interest expense
|
|
|
57,669
|
|
|
|
56,895
|
|
|
|
59,729
|
|
Interest income
|
|
|
(322
|
)
|
|
|
(79
|
)
|
|
|
(301
|
)
|
Write-off of deferred financing costs
|
|
|
|
|
|
|
528
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before taxes
|
|
|
135,738
|
|
|
|
(244,756
|
)
|
|
|
(12,404
|
)
|
Taxes
|
|
|
51,580
|
|
|
|
(63,088
|
)
|
|
|
72,305
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
|
84,158
|
|
|
|
(181,668
|
)
|
|
|
(84,709
|
)
|
Loss from discontinued operations (net of tax expense of $0, $0,
and $3,865, respectively)
|
|
|
|
|
|
|
|
|
|
|
(4,859
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
84,158
|
|
|
$
|
(181,668
|
)
|
|
$
|
(89,568
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per share information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$
|
1.11
|
|
|
$
|
(2.42
|
)
|
|
$
|
(1.15
|
)
|
Discontinued operations
|
|
|
|
|
|
|
|
|
|
|
(0.07
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per share
|
|
$
|
1.11
|
|
|
$
|
(2.42
|
)
|
|
$
|
(1.22
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$
|
1.08
|
|
|
$
|
(2.42
|
)
|
|
$
|
(1.15
|
)
|
Discontinued operations
|
|
|
|
|
|
|
|
|
|
|
(0.07
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per share
|
|
$
|
1.08
|
|
|
$
|
(2.42
|
)
|
|
$
|
(1.22
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
76,048
|
|
|
|
75,095
|
|
|
|
73,600
|
|
Diluted
|
|
|
77,684
|
|
|
|
75,095
|
|
|
|
73,600
|
|
See accompanying notes to consolidated financial statements.
65
COMPLETE
PRODUCTION SERVICES, INC.
Consolidated Statements of Comprehensive Income (Loss)
Years Ended December 31, 2010, 2009 and
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Net income (loss)
|
|
$
|
84,158
|
|
|
$
|
(181,668
|
)
|
|
$
|
(89,568
|
)
|
Change in cumulative translation adjustment
|
|
|
3,116
|
|
|
|
7,059
|
|
|
|
(18,359
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
$
|
87,274
|
|
|
$
|
(174,609
|
)
|
|
$
|
(107,927
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
66
COMPLETE
PRODUCTION SERVICES, INC.
Consolidated Statement of Stockholders Equity
Years Ended December 31, 2010, 2009 and
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
Number
|
|
|
Common
|
|
|
Paid-in
|
|
|
Retained
|
|
|
Treasury
|
|
|
Comprehensive
|
|
|
|
|
|
|
of Shares
|
|
|
Stock
|
|
|
Capital
|
|
|
Earnings
|
|
|
Stock
|
|
|
Income
|
|
|
Total
|
|
|
|
(In thousands, except share data)
|
|
|
Balance at December 31, 2007
|
|
|
72,509,511
|
|
|
$
|
725
|
|
|
$
|
581,404
|
|
|
$
|
313,243
|
|
|
$
|
(202
|
)
|
|
$
|
30,861
|
|
|
$
|
926,031
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(89,568
|
)
|
|
|
|
|
|
|
|
|
|
|
(89,568
|
)
|
Change in cumulative translation adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(18,359
|
)
|
|
|
(18,359
|
)
|
Issuance of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of AWS
|
|
|
588,292
|
|
|
|
6
|
|
|
|
8,848
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,854
|
|
Acquisition Double Jack shares
|
|
|
7,234
|
|
|
|
|
|
|
|
225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
225
|
|
Exercise of stock options
|
|
|
1,238,819
|
|
|
|
13
|
|
|
|
12,001
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,014
|
|
Expense related to employee stock options
|
|
|
|
|
|
|
|
|
|
|
5,436
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,436
|
|
Excess tax benefit from share-based compensation
|
|
|
|
|
|
|
|
|
|
|
9,144
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,144
|
|
Vested restricted stock
|
|
|
422,461
|
|
|
|
4
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of non-vested restricted stock
|
|
|
|
|
|
|
|
|
|
|
6,934
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,934
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
74,766,317
|
|
|
$
|
748
|
|
|
$
|
623,988
|
|
|
$
|
223,675
|
|
|
$
|
(202
|
)
|
|
$
|
12,502
|
|
|
$
|
860,711
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(181,668
|
)
|
|
|
|
|
|
|
|
|
|
|
(181,668
|
)
|
Change in cumulative translation adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,059
|
|
|
|
7,059
|
|
Exercise of stock options
|
|
|
123,858
|
|
|
|
|
|
|
|
496
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
496
|
|
Expense related to employee stock options
|
|
|
|
|
|
|
|
|
|
|
3,987
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,987
|
|
Excess tax benefit from share-based compensation
|
|
|
|
|
|
|
|
|
|
|
215
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
215
|
|
Purchase of treasury shares
|
|
|
(18,743
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(132
|
)
|
|
|
|
|
|
|
(132
|
)
|
Vested restricted stock
|
|
|
406,974
|
|
|
|
4
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of non-vested restricted stock
|
|
|
|
|
|
|
|
|
|
|
8,222
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,222
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
75,278,406
|
|
|
$
|
752
|
|
|
$
|
636,904
|
|
|
$
|
42,007
|
|
|
$
|
(334
|
)
|
|
$
|
19,561
|
|
|
$
|
698,890
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
84,158
|
|
|
|
|
|
|
|
|
|
|
|
84,158
|
|
Change in cumulative translation adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,116
|
|
|
|
3,116
|
|
Exercise of stock options
|
|
|
599,035
|
|
|
|
6
|
|
|
|
8,076
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,082
|
|
Expense related to employee stock options
|
|
|
|
|
|
|
|
|
|
|
2,321
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,321
|
|
Excess tax benefit from share-based compensation
|
|
|
|
|
|
|
|
|
|
|
1,465
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,465
|
|
Purchase of treasury shares
|
|
|
(113,330
|
)
|
|
|
(1
|
)
|
|
|
1
|
|
|
|
|
|
|
|
(1,431
|
)
|
|
|
|
|
|
|
(1,431
|
)
|
Vested restricted stock
|
|
|
679,815
|
|
|
|
7
|
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of non-vested restricted stock
|
|
|
|
|
|
|
|
|
|
|
9,233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2010
|
|
|
76,443,926
|
|
|
$
|
764
|
|
|
$
|
657,993
|
|
|
$
|
126,165
|
|
|
$
|
(1,765
|
)
|
|
$
|
22,677
|
|
|
$
|
805,834
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
67
COMPLETE
PRODUCTION SERVICES, INC.
Consolidated Statements of Cash Flows
Years Ended December 31, 2010, 2009 and
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Cash provided by:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
84,158
|
|
|
$
|
(181,668
|
)
|
|
$
|
(89,568
|
)
|
Items not affecting cash:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
181,823
|
|
|
|
200,732
|
|
|
|
183,191
|
|
Deferred income taxes
|
|
|
47,841
|
|
|
|
(7,567
|
)
|
|
|
20,827
|
|
Fixed asset and other intangibles impairment loss
|
|
|
|
|
|
|
38,646
|
|
|
|
|
|
Goodwill impairment loss
|
|
|
|
|
|
|
97,643
|
|
|
|
272,006
|
|
Write-off of deferred financing fees
|
|
|
|
|
|
|
528
|
|
|
|
|
|
Loss on sale of discontinued operations
|
|
|
|
|
|
|
|
|
|
|
6,935
|
|
Excess tax benefit from share-based compensation
|
|
|
(1,465
|
)
|
|
|
(215
|
)
|
|
|
(9,144
|
)
|
Non-cash compensation expense
|
|
|
11,554
|
|
|
|
12,209
|
|
|
|
12,370
|
|
(Gain) loss on non-monetary asset exchange
|
|
|
(493
|
)
|
|
|
4,868
|
|
|
|
|
|
Provision for (recoveries of) bad debt expense
|
|
|
(159
|
)
|
|
|
10,770
|
|
|
|
4,344
|
|
Loss on retirement of fixed assets
|
|
|
839
|
|
|
|
10,284
|
|
|
|
3,778
|
|
Provision for write-off of note receivable
|
|
|
1,926
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
2,995
|
|
|
|
2,081
|
|
|
|
1,956
|
|
Changes in operating assets and liabilities, net of effect of
acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(173,328
|
)
|
|
|
155,303
|
|
|
|
(18,873
|
)
|
Inventory
|
|
|
3,585
|
|
|
|
4,339
|
|
|
|
(8,653
|
)
|
Prepaid expenses and other current assets
|
|
|
(1,095
|
)
|
|
|
11,292
|
|
|
|
8,118
|
|
Accounts payable
|
|
|
25,831
|
|
|
|
(24,544
|
)
|
|
|
(10,199
|
)
|
Income taxes
|
|
|
34,093
|
|
|
|
(30,892
|
)
|
|
|
(13,873
|
)
|
Restricted cash
|
|
|
(17,000
|
)
|
|
|
|
|
|
|
|
|
Accrued liabilities and other
|
|
|
15,053
|
|
|
|
(18,605
|
)
|
|
|
(12,806
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
216,158
|
|
|
|
285,204
|
|
|
|
350,409
|
|
Investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Business acquisitions, net of cash acquired
|
|
|
(33,721
|
)
|
|
|
|
|
|
|
(180,154
|
)
|
Additions to property, plant and equipment
|
|
|
(145,023
|
)
|
|
|
(37,431
|
)
|
|
|
(253,776
|
)
|
Proceeds from sale of fixed assets
|
|
|
5,482
|
|
|
|
20,800
|
|
|
|
7,666
|
|
Proceeds from sale of disposal group
|
|
|
|
|
|
|
|
|
|
|
50,150
|
|
Other
|
|
|
(826
|
)
|
|
|
(1,497
|
)
|
|
|
2,016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(174,088
|
)
|
|
|
(18,128
|
)
|
|
|
(374,098
|
)
|
Financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuances of long-term debt
|
|
|
|
|
|
|
3,194
|
|
|
|
350,115
|
|
Repayments of long-term debt
|
|
|
(230
|
)
|
|
|
(200,609
|
)
|
|
|
(329,282
|
)
|
Repayments of notes payable
|
|
|
(1,069
|
)
|
|
|
(8,244
|
)
|
|
|
(14,001
|
)
|
Proceeds from issuances of common stock
|
|
|
8,082
|
|
|
|
496
|
|
|
|
12,014
|
|
Deferred financing fees
|
|
|
|
|
|
|
(2,911
|
)
|
|
|
|
|
Treasury stock purchased
|
|
|
(1,431
|
)
|
|
|
(132
|
)
|
|
|
|
|
Excess tax benefit from share-based compensation
|
|
|
1,465
|
|
|
|
215
|
|
|
|
9,144
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by financing activities
|
|
|
6,817
|
|
|
|
(207,991
|
)
|
|
|
27,990
|
|
Effect of exchange rate changes on cash
|
|
|
434
|
|
|
|
(225
|
)
|
|
|
1,165
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cash and cash equivalents
|
|
|
49,321
|
|
|
|
58,860
|
|
|
|
5,466
|
|
Cash and cash equivalents, beginning of period
|
|
|
77,360
|
|
|
|
18,500
|
|
|
|
13,034
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
126,681
|
|
|
$
|
77,360
|
|
|
$
|
18,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental cash flow information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest, net of capitalized interest
|
|
$
|
54,301
|
|
|
$
|
52,686
|
|
|
$
|
58,812
|
|
Cash paid (refund received) for taxes
|
|
$
|
(31,067
|
)
|
|
$
|
(25,414
|
)
|
|
$
|
71,365
|
|
Significant non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash capital expenditures
|
|
$
|
25,952
|
|
|
$
|
1,056
|
|
|
$
|
|
|
Note issued to finance insurance premiums
|
|
$
|
|
|
|
$
|
7,960
|
|
|
$
|
|
|
Common stock issued for acquisitions
|
|
$
|
|
|
|
$
|
|
|
|
$
|
9,079
|
|
Assets received as proceeds from sale of disposal group
|
|
$
|
|
|
|
$
|
|
|
|
$
|
7,987
|
|
Debt acquired in acquisition
|
|
$
|
|
|
|
$
|
|
|
|
$
|
429
|
|
See accompanying notes to consolidated financial statements.
68
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial Statements
(In thousands, except share and per share data)
(a) Nature
of operations:
Complete Production Services, Inc. is a provider of specialized
services and products focused on developing hydrocarbon
reserves, reducing operating costs and enhancing production for
oil and gas companies. Complete Production Services, Inc.
focuses its operations on basins within North America and
manages its operations from regional field service facilities
located throughout the U.S. Rocky Mountain region, Texas,
Oklahoma, Louisiana, Arkansas, Pennsylvania, western Canada,
Mexico and Southeast Asia.
References to Complete, the Company,
we, our and similar phrases are used
throughout these financial statements and relate collectively to
Complete Production Services, Inc. and its consolidated
affiliates.
On April 20, 2006, we entered into an underwriting
agreement in connection with our initial public offering and
became subject to the reporting requirements of the Securities
Exchange Act of 1934. On April 21, 2006, our common stock
began trading on the New York Stock Exchange under the symbol
CPX. On April 26, 2006, we completed our
initial public offering. See Note 12,
Stockholders equity.
(b) Basis
of presentation:
Our consolidated financial statements are expressed in
U.S. dollars and have been prepared by us in accordance
with accounting principles generally accepted in the United
States (U.S. GAAP). In preparing financial
statements, we make informed judgments and estimates that affect
the reported amounts of assets and liabilities as of the date of
the financial statements and affect the reported amounts of
revenues and expenses during the reporting period. On an ongoing
basis, we review our estimates, including those related to
impairment of long-lived assets and goodwill, contingencies and
income taxes. Changes in facts and circumstances may result in
revised estimates and actual results may differ from these
estimates.
These audited consolidated financial statements reflect all
normal recurring adjustments that are, in the opinion of
management, necessary for a fair statement of the financial
position of Complete as of December 31, 2010 and 2009 and
the statements of operations, the statements of comprehensive
income (loss), the statements of stockholders equity and
the statements of cash flows for each of the three years in the
period ended December 31, 2010. We believe that these
financial statements contain all adjustments necessary so that
they are not misleading. Certain reclassifications have been
made in order to present results on a comparable basis with
amounts for 2009.
In May 2008, our Board of Directors authorized and committed to
a plan to sell certain operations in the Barnett Shale region of
north Texas, consisting primarily of our supply store business,
as well as certain non-strategic drilling logistics assets and
other completion and production services assets. On May 19,
2008, we sold these operations to a company owned by a former
officer of one of our subsidiaries, for which we received
proceeds of $50,150 and assets with a fair market value of
$7,987. Accordingly, we have revised our financial statements
for the year ended December 31, 2008 to classify the
related results of operations of this disposal group as
discontinued operations. See Note 14, Discontinued
operations.
|
|
2.
|
Significant
accounting policies:
|
(a) Basis
of preparation:
Our consolidated financial statements include the accounts of
the legal entities discussed above and their wholly owned
subsidiaries. All material inter-company balances and
transactions have been eliminated in consolidation.
69
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
(b) Foreign
currency translation:
Assets and liabilities of foreign subsidiaries, whose functional
currencies are the local currency, are translated from their
respective functional currencies to U.S. dollars at the
balance sheet date exchange rates. Income and expense items are
translated at the average rates of exchange prevailing during
the period. Foreign exchange gains and losses resulting from
translation of account balances are included in income or loss
in the year in which they occur. The adjustment resulting from
translating the financial statements of such foreign
subsidiaries into U.S. dollars is reflected as a separate
component of stockholders equity.
(c) Revenue
recognition:
We recognize service revenue when it is realized and earned. We
consider revenue to be realized and earned when the services
have been provided to the customer, the product has been
delivered, the sales price is fixed or determinable and
collectibility is reasonably assured. Generally, services are
provided over a relatively short time.
Revenue and costs on drilling contracts are recognized as work
progresses. Progress is measured and revenues recognized based
upon agreed day-rate charges. For certain contracts, we may
receive additional lump-sum payments for the mobilization of
rigs and other drilling equipment. Consistent with the drilling
contract day-rate revenues and charges, revenues and related
direct costs incurred for the mobilization are deferred and
recognized over the term of the related drilling contract. Costs
incurred to relocate rigs and other drilling equipment to areas
in which a contract has not been secured are expensed as
incurred.
We recognize revenue under service contracts as services are
performed. We had no significant unearned revenues associated
with long-term service contracts as of December 31, 2010
and 2009.
(d) Cash
and cash equivalents:
Short-term investments with maturities of less than three months
are considered to be cash equivalents and are recorded at cost,
which approximates fair market value. For purposes of the
consolidated statements of cash flows, we consider all
investments in highly liquid debt instruments with original
maturities of three months or less to be cash equivalents. We
invest excess cash in overnight investments which are accounted
for as cash. At December 31, 2010, our cash and cash
equivalents exceeded what is federally insured.
(e) Trade
accounts receivable:
Trade accounts receivable are recorded at the invoiced amount
and do not bear interest. The allowance for doubtful accounts is
our best estimate of the amount of probable credit losses
incurred in our existing accounts receivable. We determine the
allowance based on historical write-off experience, account
aging and our assumptions about the oil and gas industry
economic cycle. We review our allowance for doubtful accounts
monthly. Past due balances over 90 days and over a
specified amount are reviewed individually for collectibility.
All other balances are reviewed on a pooled basis. Account
balances are charged off against the allowance after all
appropriate means of collection have been exhausted and the
potential for recovery is considered remote. Considering our
customer base, we do not believe that we have any significant
concentrations of credit risk other than our concentration in
the oil and gas industry. We have no significant off
balance-sheet credit exposure related to our customers.
(f) Inventory:
Inventory, which consists of finished goods, materials and
supplies held for resale, work in process and bulk fuel, is
carried at the lower of cost or market. Market is defined as net
realizable value for finished goods and as replacement cost for
manufacturing parts and materials. Cost is determined on a
first-in,
first-out basis for refurbished parts and an average cost basis
for all other inventories and includes the cost of raw materials
and labor
70
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
for finished goods. We record a reserve for excess and obsolete
inventory based upon specific identification of items based on
periodic reviews of inventory on hand.
(g) Property,
plant and equipment:
Property, plant and equipment are carried at cost less
accumulated depreciation. Major betterments are capitalized.
Repairs and maintenance that do not extend the useful life of
equipment are expensed.
Depreciation is provided over the estimated useful life of each
asset as follows:
|
|
|
|
|
Asset
|
|
Basis
|
|
Rate
|
|
Buildings
|
|
straight-line
|
|
39 years
|
Field Equipment:
|
|
|
|
|
Wireline, optimization and coiled tubing equipment
|
|
straight-line
|
|
10 years
|
Production testing equipment
|
|
straight-line
|
|
15 years
|
Drilling rigs
|
|
straight-line
|
|
20 years
|
Well-servicing rigs
|
|
straight-line
|
|
10 to 25 years
|
Pressure pumping equipment
|
|
straight-line
|
|
10 years
|
Office furniture and computers
|
|
straight-line
|
|
3 to 7 years
|
Leasehold improvements
|
|
straight-line
|
|
Shorter of
5 years or the life
of the lease
|
Vehicles and other equipment
|
|
straight-line
|
|
3 to 10 years
|
(h) Intangible
assets:
Intangible assets, consisting of acquired customer
relationships, service marks, non-compete agreements, acquired
patents and technology, are carried at cost less accumulated
amortization, which is calculated on a straight-line basis over
a period of 2 to 10 years depending on the assets
estimated useful life. The weighted average amortization period
for these intangible assets was approximately 4 years as of
December 31, 2010.
(i) Impairment
of long-lived assets:
We review long-lived assets including property, plant and
equipment and intangible assets with definite lives for
impairment whenever events or changes in circumstances indicate
that the carrying amount of an asset may not be recoverable.
Recoverability of assets to be held and used is measured by a
comparison of the carrying amount of an asset to estimated
undiscounted future cash flows expected to be generated by the
asset. If the carrying amount of an asset exceeds its estimated
future cash flows, an impairment charge is recognized in the
amount by which the carrying amount of the asset exceeds the
fair value of the asset. When assets are determined to be held
for sale, they are separately presented in the appropriate asset
and liability sections of the balance sheet and reported at the
lower of the carrying amount or fair value less cost to sell,
and are no longer depreciated. We recorded a fixed asset and
other intangibles impairment loss of $38,646 for the year ended
December 31, 2009. See Note 6, Property, plant
and equipment.
(j) Asset
retirement obligations:
Asset retirement obligations are recorded at fair value as a
liability in the period in which a legal obligation is incurred
associated with the retirement of tangible long-lived assets
that result from the acquisition, construction, development,
and/or
normal use of the assets in accordance with U.S. GAAP.
Furthermore, a corresponding asset is recorded and depreciated
over the contractual term of the underlying asset. Subsequent to
the initial measurement of the asset retirement obligation, the
obligation is adjusted at the end of each period to reflect the
passage of time and
71
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
changes in the estimated future cash flows underlying the
obligation. We recorded asset retirement obligations of $5,022
as of December 31, 2010 related to the expected cost to
plug our saltwater disposal wells at the end of the service
lives of the assets, as well as other retirement commitments. We
did not have significant retirement obligations recorded at
December 31, 2009 and 2008.
(k) Deferred
financing costs:
Deferred financing costs associated with long-term debt under
our revolving credit facilities and senior notes are carried at
cost and are expensed over the term of the applicable long-term
debt facility or the term of the notes.
(l) Goodwill:
Goodwill represents the excess of costs over the fair value of
the assets and liabilities of businesses acquired.
U.S. GAAP requires an impairment test at least annually, or
more frequently if indicators of impairment are present, whereby
we estimate the fair value of the asset by discounting future
cash flows at a projected cost of capital rate. If the fair
value estimate is less than the carrying value of the asset, an
additional test is required whereby we apply a purchase price
allocation consistent with authoritative guidance pertaining to
business combinations. If impairment is still indicated, we
would record an impairment loss in the current reporting period
for the amount by which the carrying value of the intangible
asset exceeds its implied fair value. We did not record a
goodwill impairment for the year ended 2010. We recorded
goodwill impairment losses for each of the years ended
December 31, 2009 and 2008. See (t) Fair value
measurements and Note 15, Segment
information.
|
|
(m)
|
Deferred
income taxes:
|
We follow the liability method of accounting for income taxes.
Under this method, deferred income tax assets and liabilities
are determined based upon temporary differences between the
carrying amount and tax basis of our assets and liabilities and
measured using enacted tax rates and laws that will be in effect
when the differences are expected to reverse. The effect on
deferred tax assets and liabilities of a change in the tax rates
is recognized in income in the period in which the change
occurs. We record a valuation allowance when we believe that it
is more likely than not that a deferred tax asset will not be
realized.
In assessing the realizability of deferred income tax assets,
management considers whether it is more likely than not that
some portion or all of the deferred income tax assets will not
be realized. The ultimate realization of deferred income tax
assets is dependent upon the generation of future taxable income
during the periods in which those temporary differences become
deductible.
(n) Financial
instruments:
The financial instruments recognized in the balance sheet
consist of cash and cash equivalents, trade accounts receivable,
revolving credit facilities, accounts payable and accrued
liabilities, long-term debt and senior notes. The fair value of
our financial instruments approximate their carrying amounts due
to their current maturities or market rates of interest, except
the senior notes which were issued in December 2006 with a fixed
8% coupon rate. At December 31, 2010 and 2009, the fair
value of these notes was $669,500 and $641,875, respectively,
based on the published closing prices for the applicable day.
(o) Per
share amounts:
In accordance with U.S. GAAP, we use the treasury stock
method to calculate the dilutive effect of stock options and
non-vested restricted stock on our earnings per share
calculations. This method requires that we compare the presumed
proceeds from the exercise of options and other dilutive
instruments, including the expected tax benefit to us, to the
exercise price of the instrument, and assume that we used the
net proceeds to purchase shares of our common stock at the
average price during the period. These assumed shares are then
included in the
72
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
calculation of the diluted weighted average shares outstanding
for the period, if such instruments are not deemed to be
anti-dilutive.
(p) Stock-based
compensation:
We have stock-based compensation plans for our employees,
officers and directors to acquire common stock. For stock option
grants made prior to January 1, 2006, no compensation
expense was recorded if the stock options were issued at fair
value on the date of grant. Accordingly, we did not recognize
compensation expense associated with these stock option grants.
Subsequent to January 1, 2006, we measure the cost of
employee services received in exchange for an award of equity
instruments based on the grant-date fair value of the award,
with limited exceptions, by using an option pricing model to
determine fair value. We applied the modified-prospective
transition method to account for grants of stock options between
September 30, 2005, the date of our initial filing with the
Securities and Exchange Commission, and December 31, 2005.
For stock options granted on or after January 1, 2006, we
use the prospective transition method to account for these
grants and record compensation expense. See Note 12,
Stockholders equity.
(q) Research
and development:
Research and development costs are charged to income as period
costs when incurred.
(r) Contingencies:
Liabilities for loss contingencies, including environmental
remediation costs not within the scope of FASB guidance provided
with regard to asset retirement obligations and which arise from
claims, assessments, litigation, fines, and penalties and other
sources, are recorded when it is probable that a liability has
been incurred and the amount of the assessment
and/or
remediation can be reasonably estimated.
(s) Measurement
uncertainty:
Our consolidated financial statements are prepared in accordance
with U.S. GAAP. The preparation of the consolidated
financial statements in accordance with U.S. GAAP
necessarily requires us to make estimates and judgments that
affect the reported amounts of assets, liabilities, revenues and
expenses, and related disclosure of contingent assets and
liabilities. We evaluate our estimates including those related
to bad debts, inventory obsolescence, useful lives of property,
plant and equipment, goodwill, intangible assets, income taxes,
contingencies and litigation on an ongoing basis. We base our
estimates on historical experience and on various other
assumptions that we believe to be reasonable under the
circumstances. Under different assumptions or conditions, the
actual results could differ, possibly materially, from those
previously estimated. Many of the conditions impacting these
assumptions are estimates outside of our control.
(t) Fair
value measurement:
We evaluate fair value measurements in accordance with
U.S. GAAP, which requires us to base our estimates on
assumptions that a market participant might use to price an
asset or liability, and to establish a hierarchy that
prioritizes the information used to determine fair value,
whereby quoted market prices in active markets are given highest
priority with lowest priority given to data provided by the
reporting entity based on unobservable facts. U.S. GAAP
requires disclosure of significant fair value measurements by
level within the prescribed hierarchy.
We generally apply fair value valuation techniques on a
non-recurring basis associated with: (1) valuing assets and
liabilities acquired in connection with business combinations
and other transactions; (2) valuing potential impairment
loss related to long-lived assets; and (3) valuing
potential impairment loss related to goodwill and
indefinite-lived intangible assets. We generally do not hold a
significant investment in trading securities, and we
73
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
were not party to significant derivative contract arrangements
during the years ended December 31, 2010, 2009 or 2008.
Business
combinations and other transactions:
We acquired several businesses during the years ended
December 31, 2010 and 2008, but did not complete any such
business combinations during the year ended December 31,
2009. To determine the fair value of the assets acquired,
primarily fixed assets, we generally obtain assistance from an
independent appraiser to determine the fair value of the assets
acquired based upon the value of comparable assets in the market
as of the date of the acquisition. For one business acquired in
late 2010, the assets were recently constructed and cost was
deemed to approximate fair value at the date of acquisition. In
addition, we applied an income method approach to value
identifiable intangible assets associated with our acquisitions,
as applicable, including customer relationships, trade names and
non-compete agreements. For working capital items, including
receivables, payables and inventory, carrying value was deemed
to approximate fair value. During the year ended
December 31, 2010, we recorded an insignificant
non-monetary exchange of assets which resulted in a gain on the
transaction of $493. The fair value of the assets received in
the exchange was $914 and was more readily determinable based
upon the sellers price for such equipment received in the
exchange. For the year ended December 31, 2009, we acquired
certain property, plant and equipment at a subsidiary in Canada
through a non-monetary exchange of assets, as further described
in Note 6, Property, plant and equipment. We
determined that this transaction had economic substance and that
the assets received should be recorded at the fair value of the
assets surrendered in the exchange. To determine the fair value
of these assets, management obtained assistance from a
third-party appraiser and used the orderly-liquidation value of
the assets surrendered as an estimate of fair value. This
transaction resulted in a loss of $4,868 for the year ended
December 31, 2009.
Long-lived
assets:
We reviewed our tangible fixed assets and intangible assets with
definite lives at December 31, 2010 and noted no
significant indicators of impairment. Therefore, no impairment
losses related to long-lived assets were recorded for the year
ended December 31, 2010. In September 2009, we evaluated
the fair value of assets in our contract drilling business with
the assistance of a third-party appraiser and determined that
the carrying value of certain of these drilling rigs exceeded
the fair value estimates. We projected the undiscounted cash
flows associated with these rigs, including an estimate of
salvage value, and compared these expected future cash flows to
the carrying amount of the rigs. If the undiscounted cash flows
exceeded the carrying amount, no further testing was performed
and the rig was deemed to not be impaired. If the undiscounted
cash flows did not exceed the carrying value, we estimated the
fair market value of the equipment based on management estimates
and general market data obtained by the third-party appraiser
using the sales comparison market approach, which included the
analysis of recent sales and offering prices of similar
equipment to arrive at an indication of the most probable
selling price for the equipment. The result of this analysis was
a calculated fixed asset impairment of $36,158, which was
recorded as an impairment loss in the accompanying statement of
operations for the year ended December 31, 2009. This
impairment charge was allocated entirely to the Drilling
Services business segment. This impairment was deemed necessary
due to an overall decline in oil and gas exploration and
production activity in late 2008 which extended throughout 2009,
as well as managements expectation of future operating
results for this business segment for the foreseeable future. We
continue to evaluate the remaining useful lives of our drilling
rigs, and have considered our depreciation methodology and these
estimates of useful lives in our projected future cash flows
associated with these assets.
In addition, we evaluated certain long-term intangible assets
with definite lives in accordance with U.S. GAAP as of
December 31, 2009. Based on our review, we believe that
impairment was indicated at one of our businesses due to
lower-than-expected
results, revised expected future cash flows for the business and
changes in local management. Therefore, with the assistance of a
third-party appraiser, we determined that certain non-compete
agreements and customer relationship intangibles were impaired
at December 31, 2009. We recorded an
74
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
impairment charge related to these intangible assets totaling
$2,488 in the accompanying statement of operations for the year
ended December 31, 2009.
Goodwill:
We evaluated our goodwill and indefinite-lived intangible assets
in accordance with the recoverability tests prescribed by
U.S. GAAP as of our annual testing date in 2010. With the
assistance of a third-party valuation specialist, we prepared
several valuation models including a discounted cash flow
analysis, a market multiples approach and a review of precedent
transactions. We weighted these valuation methodologies, with
greatest weight given to our discounted cash flow projections,
which included assumptions related to organic growth, capital
investment, working capital needs, residual value and other
assumptions. Based on this analysis, we determined that our
goodwill and indefinite-lived intangible assets were not
impaired as of the annual testing date for the year ended
December 31, 2010. For the year ended December 31,
2009, we determined that goodwill associated with three of our
reporting units was impaired as of the testing date. For the
year ended December 31, 2008, we performed this test at the
annual testing date and impairment of goodwill was indicated for
most of our reporting units. Then, due to a significant decline
in the overall U.S. debt and equity markets which was
deemed a triggering event, we performed the test at
December 31, 2008 and impairment was indicated. We update
our assumptions used in the preparation of our discounted cash
flow analysis each year based largely upon unobservable inputs
from management, which represent our best estimates of actual
results over a long-term period, appropriately discounted as of
the test date. Although the assumptions used vary from
year-to-year
based upon our perception of market conditions, the valuation
methodology used to value goodwill was consistent for the years
ended December 31, 2010, 2009 and 2008.
For the years ended December 31, 2009 and 2008, we
performed step two of the goodwill impairment test as prescribed
by U.S. GAAP. In performing the two-step goodwill
impairment test, we compared the fair value of each of our
reportable units to its carrying value. We estimated the fair
value of our reportable units by considering both the income
approach and market approach. Under the market approach, the
fair value of the reportable unit is based on market multiple
and recent transaction values of peer companies. Under the
income approach, the fair value of the reportable unit is based
on the present value of estimated future cash flows using the
discounted cash flow method. The discounted cash flow method is
dependent on a number of unobservable inputs including
projections of the amounts and timing of future revenues and
cash flows, assumed discount rates and other assumptions. Based
upon this initial testing, we determined that goodwill
associated with several of our reporting units within our
completion and production services business segments were
impaired, which triggered step two. For step two, we calculated
the implied fair value of goodwill and compared it to the
carrying amount of that goodwill, by examining the fair value of
the tangible and intangible property of these reportable units.
The inputs for this model were largely unobservable estimates
from management based on historical performance. We retained the
assistance of a third-party appraiser to collect market data for
a sample of assets from each of these reporting units to assess
the market value of the property, plant and equipment of these
reportable units, and the results were extrapolated to the asset
population. Thus, the primary source for our assessment of value
was based on managements estimates and projections. The
result of this analysis was a calculated goodwill impairment of
$97,643 which is recorded in the accompanying statement of
operations at December 31, 2009. This impairment charge of
$97,643 was allocated to the completion and production services
business segment in 2009. These impairments were deemed
necessary due to an overall decline in oil and gas exploration
and production activity throughout 2009. For the year ended
December 31, 2008, goodwill with a carrying amount of
$613,876 was written down to its implied fair value of $341,592,
resulting in an impairment charge of $272,284, of which $272,006
was recorded as an impairment loss and $277 was recorded as a
charge to cumulative translation adjustment in the accompanying
balance sheet as of December 31, 2008. We continue to hold
an investment in each of these reportable units for which
impairment losses were recorded in 2009 and 2008.
75
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The following tabular presentation is presented for quantitative
presentation of our significant fair value measurements for the
years ended December 31, 2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted Prices in
|
|
|
Significant Other
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
Active Markets for
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
|
|
|
Balance at
|
|
|
Identical Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
Total Gains
|
|
Description
|
|
Year End
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
(Losses)
|
|
|
As of December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-monetary exchange
|
|
$
|
914
|
|
|
|
|
|
|
$
|
914
|
|
|
$
|
|
|
|
$
|
493
|
|
Goodwill
|
|
|
250,533
|
|
|
|
|
|
|
|
|
|
|
|
250,533
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
251,447
|
|
|
|
|
|
|
$
|
914
|
|
|
$
|
250,533
|
|
|
$
|
493
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-monetary exchange
|
|
$
|
4,487
|
|
|
|
|
|
|
$
|
4,487
|
|
|
$
|
|
|
|
$
|
(4,868
|
)
|
Property, plant and equipment
|
|
|
100,820
|
|
|
|
|
|
|
|
|
|
|
|
100,820
|
|
|
|
(36,158
|
)
|
Definite-lived intangible assets
|
|
|
187
|
|
|
|
|
|
|
|
|
|
|
|
187
|
|
|
|
(2,488
|
)
|
Goodwill
|
|
|
243,823
|
|
|
|
|
|
|
|
|
|
|
|
243,823
|
|
|
|
(97,643
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
349,317
|
|
|
|
|
|
|
$
|
4,487
|
|
|
$
|
344,830
|
|
|
$
|
(141,157
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
$
|
613,876
|
|
|
|
|
|
|
$
|
|
|
|
$
|
341,592
|
|
|
$
|
(272,284
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(u) Investment
in Unconsolidated Subsidiaries
We constructed a salt water disposal well for a customer during
2009 at a cost of $1,497. In exchange for this service, we
received a non-controlling interest in the company that owns and
operates the well. In accordance with U.S. GAAP, we account
for our interest in this company as an equity investment in an
unconsolidated subsidiary, whereby we have recorded our initial
investment as a long-term asset in the accompanying balance
sheet at December 31, 2009, and record our portion of
earnings or losses associated with this well as equity in
earnings of unconsolidated subsidiaries, a component of income
or expense in the current period. We have evaluated this
ownership interest and determined that it does not constitute a
variable interest entity, as that term is defined in current
U.S. GAAP guidance. This well did not begin operating until
late 2009, and we did not record any significant earnings or
loss associated with these operations during the years ended
December 31, 2009 or 2010.
|
|
3.
|
Business
combinations:
|
We did not acquire any businesses during the year ended
December 31, 2009. However, we did execute several business
acquisitions for the years ended December 31, 2010 and
2008, as described below, and expect to complete more
transactions in the future, depending on the circumstances and
the availability of financing.
(a) Acquisitions
During the Year Ended December 31, 2010:
During the year ended December 31, 2010, we acquired assets
or all of the equity interests in various service companies, for
$33,721 in cash, resulting in tax deductible goodwill of $6,710.
(i) On May 11, 2010, we acquired certain assets of a
provider of gas lift services based in Oklahoma City, Oklahoma.
The total purchase price for the assets was $1,440 in cash. We
recorded goodwill totaling $1,017 in conjunction with this
acquisition which has been allocated entirely to the completion
and production services business segment. We believe this
acquisition supplements our plunger lift service offering for
the completion and production services business segment.
76
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
(ii) On September 3, 2010, we completed the purchase
of a well service and fluid handling service provider based in
Carrizo Springs, Texas. The total purchase price for the assets
was $20,767 and included goodwill of $4,046, all of which was
allocated to the completion and production services business
segment. We believe this acquisition enhances our position in
the Eagle Ford Shale in south Texas.
(iii) On December 1, 2010, we completed the purchase
of all of the outstanding common stock of a disposal well
operator located in Colorado for $11,514 in cash, subject to an
additional $500 holdback. We recorded goodwill totaling $1,457
in conjunction with this acquisition which has been allocated to
the completion and production services business segment. We
believe this acquisition will enhance our position in the
Denver-Julesburg Basin in Colorado.
We accounted for these acquisitions using the purchase method of
accounting, whereby the purchase price was allocated to the fair
value of net assets acquired, including definite-lived
intangible assets and property, plant and equipment, with the
excess recorded as goodwill. Results for each of these
acquisitions were included in our accounts and results of
operations since the date of acquisition. The following table
summarizes the preliminary purchase price allocations for these
acquisitions as of December 31, 2010:
|
|
|
|
|
|
|
Totals
|
|
|
Net assets acquired:
|
|
|
|
|
Accounts receivable
|
|
$
|
209
|
|
Inventory and other current assets
|
|
|
428
|
|
Property, plant and equipment
|
|
|
23,960
|
|
Payables and accrued liabilities
|
|
|
(106
|
)
|
Intangible assets
|
|
|
2,520
|
|
Goodwill
|
|
|
6,710
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
33,721
|
|
|
|
|
|
|
Consideration:
|
|
|
|
|
Cash, net of cash and cash equivalents acquired
|
|
$
|
33,721
|
|
|
|
|
|
|
We determined the fair value of assets and liabilities acquired
through these business acquisitions as of the acquisition date
by retaining third-party consultants to perform valuation
techniques related to identifiable intangible assets and to
evaluate property, plant and equipment acquired based upon, at
minimum, the replacement cost of the assets, except for the two
saltwater disposal wells in Colorado which were newly
constructed just prior to acquisition. Working capital items
were deemed to have a fair market value equal to book value. Of
the total intangible assets acquired, $1,670 related to customer
relationship intangibles determined by applying an income
approach over the expected term, allowing for customer attrition
at an assumed rate.
|
|
(b)
|
Acquisitions
During the Year Ended December 31, 2008:
|
During the year ended December 31, 2008, we acquired
substantially all the assets or all of the equity interests in
four oilfield service companies, for $180,154 in cash, resulting
in goodwill of $71,209. Several of these acquisitions were
subject to final working capital adjustments.
(i) On February 29, 2008, we acquired substantially
all of the assets of KR Fishing & Rental, Inc.
(KR Fishing & Rental) for $9,464 in
cash, resulting in goodwill of $6,411. KR Fishing &
Rental, Inc. is a provider of fishing, rental and foam unit
services in the Piceance Basin and the Raton Basin, and is
located in Rangely, Colorado. We believe this acquisition
complements our completion and production services business in
the Rocky Mountain region.
77
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
(ii) On April 15, 2008, we acquired all the
outstanding common stock of Frac Source Services, Inc.
(Frac Source), a provider of pressure pumping
services to customers in the Barnett Shale of north Texas, for
$62,359 in cash, net of cash acquired, which includes a working
capital adjustment of $1,600 and recorded goodwill of $15,431.
Upon closing this transaction, we entered into a contract with
one of our major customers to provide pressure pumping services
in the Barnett Shale utilizing three frac fleets under a
contract with a term that extends up to three years from the
date each fleet is placed into service. We spent an additional
$20,000 in 2008 on capital equipment related to these contracted
frac fleets. Thus, our total investment in this operation was
approximately $82,400. This acquisition expanded our pressure
pumping business in north Texas and the related contract
provides a stable revenue stream from which to expand our
pressure pumping business outside of this region.
(iii) On October 3, 2008, we acquired all of the
membership interests of TSWS Well Services, LLC
(TSWS), a limited liability corporation which held
substantially all of the well servicing and heavy haul assets of
TSWS, Inc., a company based in Magnolia, Arkansas, which
provides well servicing and heavy haul services to customers in
northern Louisiana, east Texas and southern Arkansas. As
consideration, we paid $57,163 in cash and prepaid an additional
$1,000 related to an employee retention bonus pool. We also
recorded goodwill totaling $21,911. This acquisition extended
our geographic reach in the Haynesville Shale area.
(iv) On October 4, 2008, we acquired substantially all
of the assets of Appalachian Well Services, Inc. and its
wholly-owned subsidiary (AWS), each of which is
based in Shelocta, Pennsylvania. This business provides pressure
pumping,
e-line and
coiled tubing services in the Appalachian region, and includes a
service area which extends through portions of Pennsylvania,
West Virginia, Ohio and New York. As consideration for the
purchase, we paid $50,168 in cash and issued 588,292
unregistered shares of our common stock, valued at $15.04 per
share. We invested an additional $6,500 to complete a frac fleet
at this location and have an option to purchase real property
for approximately $600. In addition, we entered into an
agreement under which we might be required to pay up to an
additional $5,000 in cash consideration during the earn-out
period. The earn-out period expired in 2010 with no additional
consideration required. We recorded goodwill of approximately
$27,456 associated with this acquisition, however, this goodwill
was deemed impaired in 2009 and expensed as of December 31,
2009. We believe this acquisition created a platform for future
growth for our pressure pumping and other completion and
production service lines in the Marcellus Shale.
We accounted for these acquisitions using the purchase method of
accounting, whereby the purchase price was allocated to the fair
value of net assets acquired, including definite-lived
intangible assets and property, plant and equipment at
depreciated replacement costs, with the excess recorded as
goodwill. Results for each of these acquisitions were included
in our accounts and results of operations since the date of
acquisition, and goodwill associated with these acquisitions was
allocated entirely to the completion and production services
business
78
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
segment. The following table summarizes our purchase price
allocations for these acquisitions as of December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
KR Fishing
|
|
|
Frac
|
|
|
|
|
|
|
|
|
|
|
|
|
& Rental
|
|
|
Source
|
|
|
TSWS
|
|
|
AWS
|
|
|
Totals
|
|
|
Net assets acquired:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
|
$
|
2,673
|
|
|
$
|
41,172
|
|
|
$
|
28,852
|
|
|
$
|
24,140
|
|
|
$
|
96,837
|
|
Non-cash working capital
|
|
|
50
|
|
|
|
(2,085
|
)
|
|
|
1,000
|
|
|
|
3,226
|
|
|
|
2,191
|
|
Intangible assets
|
|
|
330
|
|
|
|
6,810
|
|
|
|
6,400
|
|
|
|
4,200
|
|
|
|
17,740
|
|
Deferred tax asset
|
|
|
|
|
|
|
1,031
|
|
|
|
|
|
|
|
|
|
|
|
1,031
|
|
Goodwill
|
|
|
6,411
|
|
|
|
15,431
|
|
|
|
21,911
|
|
|
|
27,456
|
|
|
|
71,209
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
9,464
|
|
|
$
|
62,359
|
|
|
$
|
58,163
|
|
|
$
|
59,022
|
|
|
$
|
189,008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consideration:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, net of cash and cash equivalents acquired
|
|
$
|
9,464
|
|
|
$
|
62,359
|
|
|
$
|
58,163
|
|
|
$
|
50,168
|
|
|
$
|
180,154
|
|
Stock issued for acquisition
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,854
|
|
|
|
8,854
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total consideration
|
|
$
|
9,464
|
|
|
$
|
62,359
|
|
|
$
|
58,163
|
|
|
$
|
59,022
|
|
|
$
|
189,008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Of the $71,209 of goodwill above, $55,718 is tax deductible.
The purchase price of each of the businesses that we acquire is
negotiated as an arms length transaction with the seller.
We generally evaluate acquisition targets based on an earnings
multiple approach, whereby we consider precedent transactions
which we have undertaken and those of others in our industry.
We determined the fair value of assets and liabilities acquired
through these business acquisitions as of the acquisition date
by retaining third-party consultants to perform valuation
techniques related to identifiable intangible assets and to
evaluate property, plant and equipment acquired based upon, at
minimum, the replacement cost of the assets. Working capital
items were deemed to have a fair market value equal to book
value. Of the total intangible assets acquired, $14,010 related
to customer relationship intangibles determined by applying an
income approach over the expected term, allowing for customer
attrition at an assumed rate. We considered these factors when
determining the goodwill impairment recorded at
December 31, 2008. Of the businesses acquired in 2008, an
insignificant portion of the goodwill associated with the
acquisitions of TSWS and AWS was deemed impaired at
December 31, 2008. As of December 31, 2009, the
remaining goodwill associated with AWS, and other intangibles
totaling $2,488, were deemed impaired and expensed.
(c) Pro
Forma Results
Our acquisitions during the year ended December 31, 2010
were not deemed to be significant to our overall results for the
year. Therefore, no pro forma disclosure of the impact of these
acquisitions has been provided for 2010.
We calculated the pro forma impact of the businesses we acquired
on our operating results for the year ended December 31,
2008. The following pro forma results give effect to each of
these acquisitions, assuming that each occurred on
January 1, 2008.
We derived the pro forma results of these acquisitions based
upon historical financial information obtained from the sellers
and certain management assumptions. In addition, we assumed debt
service costs related to these acquisitions based upon the
actual cash investments, calculated at a rate of 7% per annum,
less an assumed tax benefit calculated at our statutory rate of
35%. Each of these acquisitions related to our continuing
operations, and, thus, had no pro forma impact on discontinued
operations presented on the accompanying statement of operations
for the year ended December 31, 2008.
79
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The following pro forma results do not purport to be indicative
of the results that would have been obtained had the
transactions described above been completed on the indicated
dates or that may be obtained in the future.
|
|
|
|
|
|
|
Pro Forma Results
|
|
|
|
For the Year Ended
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
|
(Unaudited)
|
|
|
Revenue
|
|
$
|
1,901,879
|
|
Loss before taxes
|
|
$
|
(2,132
|
)
|
Net loss from continuing operations
|
|
$
|
(78,203
|
)
|
Net loss
|
|
$
|
(83,062
|
)
|
Loss per share:
|
|
|
|
|
Basic
|
|
$
|
(1.13
|
)
|
|
|
|
|
|
Diluted
|
|
$
|
(1.13
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
Trade accounts receivable
|
|
$
|
253,662
|
|
|
$
|
155,871
|
|
Related party receivables(a)
|
|
|
51,046
|
|
|
|
6,593
|
|
Unbilled revenue
|
|
|
42,747
|
|
|
|
19,409
|
|
Notes and other receivables
|
|
|
2,353
|
|
|
|
1,975
|
|
|
|
|
|
|
|
|
|
|
|
|
|
349,808
|
|
|
|
183,848
|
|
Allowance for doubtful accounts
|
|
|
4,160
|
|
|
|
12,564
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
345,648
|
|
|
$
|
171,284
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
See Note 19, Related party transactions. |
The following table summarizes the change in our allowance for
doubtful accounts for the years ended December 31, 2010,
2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at
|
|
Additions
|
|
Write-offs
|
|
Balance at
|
|
|
Beginning
|
|
Charged
|
|
or
|
|
End of
|
Year Ended
|
|
of Period
|
|
to Expense
|
|
Adjustments
|
|
Period
|
|
2010
|
|
$
|
12,564
|
|
|
$
|
(159
|
)
|
|
$
|
(8,245
|
)
|
|
$
|
4,160
|
|
2009
|
|
$
|
5,976
|
|
|
$
|
10,770
|
|
|
$
|
(4,182
|
)
|
|
$
|
12,564
|
|
2008
|
|
$
|
5,487
|
|
|
$
|
4,344
|
|
|
$
|
(3,855
|
)
|
|
$
|
5,976
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
Finished goods
|
|
$
|
18,644
|
|
|
$
|
23,435
|
|
Manufacturing parts, materials and fuel
|
|
|
16,063
|
|
|
|
14,486
|
|
Work in process
|
|
|
1,282
|
|
|
|
431
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35,989
|
|
|
|
38,352
|
|
Inventory reserves
|
|
|
2,453
|
|
|
|
888
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
33,536
|
|
|
$
|
37,464
|
|
|
|
|
|
|
|
|
|
|
80
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
6.
|
Property,
plant and equipment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
Net Book
|
|
December 31, 2010
|
|
Cost
|
|
|
Depreciation
|
|
|
Value
|
|
|
Land
|
|
$
|
16,153
|
|
|
$
|
|
|
|
$
|
16,153
|
|
Building
|
|
|
32,083
|
|
|
|
4,456
|
|
|
|
27,627
|
|
Field equipment
|
|
|
1,434,986
|
|
|
|
642,302
|
|
|
|
792,684
|
|
Vehicles
|
|
|
128,381
|
|
|
|
58,110
|
|
|
|
70,271
|
|
Office furniture and computers
|
|
|
18,259
|
|
|
|
11,970
|
|
|
|
6,289
|
|
Leasehold improvements
|
|
|
26,644
|
|
|
|
7,538
|
|
|
|
19,106
|
|
Construction in progress
|
|
|
23,898
|
|
|
|
|
|
|
|
23,898
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,680,404
|
|
|
$
|
724,376
|
|
|
$
|
956,028
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
Net Book
|
|
December 31, 2009
|
|
Cost
|
|
|
Depreciation
|
|
|
Value
|
|
|
Land
|
|
$
|
8,884
|
|
|
$
|
|
|
|
$
|
8,884
|
|
Building
|
|
|
30,200
|
|
|
|
3,168
|
|
|
|
27,032
|
|
Field equipment
|
|
|
1,293,292
|
|
|
|
497,632
|
|
|
|
795,660
|
|
Vehicles
|
|
|
126,256
|
|
|
|
55,035
|
|
|
|
71,221
|
|
Office furniture and computers
|
|
|
17,087
|
|
|
|
9,108
|
|
|
|
7,979
|
|
Leasehold improvements
|
|
|
25,006
|
|
|
|
4,771
|
|
|
|
20,235
|
|
Construction in progress
|
|
|
10,122
|
|
|
|
|
|
|
|
10,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,510,847
|
|
|
$
|
569,714
|
|
|
$
|
941,133
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Construction in progress at December 31, 2010 and 2009
primarily included progress payments to vendors for equipment to
be delivered in future periods and component parts to be used in
final assembly of operating equipment, which in all cases were
not yet placed into service at the time. For the years ended
December 31, 2010, 2009 and 2008, we recorded capitalized
interest of $1,250, $878 and $4,458, respectively, related to
assets that we are constructing for internal use and amounts
paid to vendors under progress payments for assets that are
being constructed on our behalf.
Effective March 1, 2009, our Canadian subsidiary
transferred certain property, plant and equipment used in our
production testing business to Enseco, a competitor, in exchange
for certain electric line
(e-line)
equipment. This exchange was determined to have commercial
substance for us and therefore we recorded the new assets
acquired at the fair market value of the assets surrendered
which had a carrying value of $9,284. We incurred costs to sell
totaling approximately $71. We determined the fair value of the
assets with the assistance of a third-party appraiser, assuming
an orderly liquidation methodology, to be $4,487, resulting in a
loss on the exchange of $4,868. Of the total value assigned to
the new assets, $4,209 was included in property, plant and
equipment and $279 was included in inventory in the accompanying
balance sheet as of December 31, 2009. The fair market
value of the assets received was determined to be $5,497, using
the same methodology applied to the assets surrendered. We
believe that these
e-line
assets will generate cash flows in excess of the cash flows that
would have been received from the production testing assets due
to relatively higher demand from our customers for
e-line
services.
Effective March 31, 2009, we entered into a sale-leaseback
transaction with Agua Dulce, LLC, through which we sold a
facility and approximately 50 acres of real property
located near Rock Springs, Wyoming for $3,827. The sales price
approximated the net book value of the facility, which is
currently under construction, and the land, resulting in an
insignificant gain on the transaction which has been included as
a component of selling, general and administrative expense in
the accompanying statement of operations for the year ended
December 31, 2009. In
81
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
addition, the buyer agreed to fund the completion of the
construction of the facility. Effective April 1, 2009, we
became party to the lease agreement which requires monthly
operating lease payments for a term of 10 years, with an
option to extend the lease term for an additional 10 years.
The rental rate adjusts for construction draws to date divided
ratably over the remaining lease term. The lease term began on
April 1, 2009 and the first monthly rental was $35. We will
also incur additional lease costs related to certain operating
costs, taxes and insurance for the facility over the term of the
lease.
Effective July 30, 2009, we entered into a sale-leaseback
agreement with Enterprise Leasing Company of Houston to sell
over 550 light-vehicles with a net book value of approximately
$10,362 as of July 30, 2009. During the third quarter of
2009, we received proceeds from the sale which totaled $10,551.
In August 2009, pursuant to this lease agreement, we began
making monthly rental payments of approximately $306. The lease
terms range from 24 to 36 months.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2010
|
|
|
As of December 31, 2009
|
|
|
|
|
|
|
Historical
|
|
|
Accumulated
|
|
|
Net Book
|
|
|
Historical
|
|
|
Accumulated
|
|
|
Net Book
|
|
Description
|
|
Term
|
|
|
Cost
|
|
|
Amortization
|
|
|
Value
|
|
|
Cost
|
|
|
Amortization
|
|
|
Value
|
|
|
|
(In months)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Patents and trademarks
|
|
|
60 to 120
|
|
|
$
|
5,215
|
|
|
$
|
3,353
|
|
|
$
|
1,862
|
|
|
$
|
5,942
|
|
|
$
|
2,421
|
|
|
$
|
3,521
|
|
Contractual agreements
|
|
|
24 to 120
|
|
|
|
11,985
|
|
|
|
8,660
|
|
|
|
3,325
|
|
|
|
9,455
|
|
|
|
6,644
|
|
|
|
2,811
|
|
Customer lists and other
|
|
|
36 to 60
|
|
|
|
13,302
|
|
|
|
9,280
|
|
|
|
4,022
|
|
|
|
13,322
|
|
|
|
6,411
|
|
|
|
6,911
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
|
|
|
$
|
30,502
|
|
|
$
|
21,293
|
|
|
$
|
9,209
|
|
|
$
|
28,719
|
|
|
$
|
15,476
|
|
|
$
|
13,243
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We recorded amortization expense associated with intangible
assets of continuing operations totaling $6,591, $7,769 and
$5,248 for the years ended December 31, 2010, 2009 and
2008, respectively. We expect to record amortization expense
associated with these intangible assets for the next five years
approximating: 2011 $4,645; 2012 $2,926;
2013 $1,341; 2014 $170 and
2015 $127.
|
|
8.
|
Deferred
financing costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
Net
|
|
|
|
Cost
|
|
|
Amortization
|
|
|
Book Value
|
|
|
December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred financing costs
|
|
$
|
19,010
|
|
|
$
|
9,316
|
|
|
$
|
9,694
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred financing costs
|
|
$
|
19,010
|
|
|
$
|
6,266
|
|
|
$
|
12,744
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We incurred deferred financing costs associated with our amended
credit facility as well as $13,414 related to the issuance of
our senior notes in December 2006. In October 2009, we amended
our senior secured credit facility and incurred additional
financing costs of $2,911 in the fourth quarter of 2009. In
October 2009, due to the decrease in borrowing capacity after
giving effect to the amendment, we expensed $528 of unamortized
fees related to our prior revolving credit facilities.
82
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Tax expense (benefit) from continuing operations consisted of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Domestic:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current income taxes
|
|
$
|
(105
|
)
|
|
$
|
(59,637
|
)
|
|
$
|
42,490
|
|
Deferred income taxes
|
|
|
48,468
|
|
|
|
(4,733
|
)
|
|
|
24,739
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
48,363
|
|
|
|
(64,370
|
)
|
|
|
67,229
|
|
Foreign:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current income taxes
|
|
|
3,844
|
|
|
|
4,116
|
|
|
|
8,988
|
|
Deferred income taxes
|
|
|
(627
|
)
|
|
|
(2,834
|
)
|
|
|
(3,912
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,217
|
|
|
|
1,282
|
|
|
|
5,076
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax expense (benefit) continuing operations
|
|
$
|
51,580
|
|
|
$
|
(63,088
|
)
|
|
$
|
72,305
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We operate in several tax jurisdictions. A reconciliation of the
U.S. federal income tax rate of 35% for the years ended
December 31, 2010, 2009 and 2008 to our effective income
tax rate follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Expected provision for taxes:
|
|
$
|
47,508
|
|
|
$
|
(85,665
|
)
|
|
$
|
(4,341
|
)
|
Increase (decrease) resulting from foreign tax rate differential
|
|
|
(528
|
)
|
|
|
(1,971
|
)
|
|
|
280
|
|
Change in foreign tax rates
|
|
|
|
|
|
|
68
|
|
|
|
746
|
|
Change in domestic tax rates
|
|
|
1,357
|
|
|
|
4,544
|
|
|
|
|
|
State taxes, net of federal benefit
|
|
|
978
|
|
|
|
(4,948
|
)
|
|
|
4,989
|
|
Non-deductible expenses
|
|
|
2,180
|
|
|
|
18,125
|
|
|
|
70,619
|
|
Other, net
|
|
|
85
|
|
|
|
6,759
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax expense (benefit) continuing operations
|
|
$
|
51,580
|
|
|
$
|
(63,088
|
)
|
|
$
|
72,305
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-deductible expenses for the years ended December 31,
2009 and 2008 relate primarily to impaired goodwill with limited
tax basis. There was no goodwill impairment for the year ended
December 31, 2010.
83
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The net deferred income tax liability was comprised of the tax
effect of the following temporary differences:
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
Deferred income tax assets:
|
|
|
|
|
|
|
|
|
Net operating loss
|
|
$
|
10,386
|
|
|
$
|
6,909
|
|
Goodwill and intangible assets
|
|
|
9,240
|
|
|
|
14,487
|
|
Accrued liabilities and other
|
|
|
6,789
|
|
|
|
4,853
|
|
Stock-based compensation costs
|
|
|
4,125
|
|
|
|
6,744
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30,540
|
|
|
|
32,993
|
|
Less valuation allowance
|
|
|
(253
|
)
|
|
|
(265
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
30,287
|
|
|
|
32,728
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax liabilities:
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
|
|
(213,589
|
)
|
|
|
(168,450
|
)
|
Other
|
|
|
(4,621
|
)
|
|
|
(4,360
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
(218,210
|
)
|
|
|
(172,810
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred income tax liability
|
|
$
|
(187,923
|
)
|
|
$
|
(140,082
|
)
|
|
|
|
|
|
|
|
|
|
The net deferred income tax liability consisted of:
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
Domestic
|
|
$
|
(187,988
|
)
|
|
$
|
(139,061
|
)
|
Foreign
|
|
|
65
|
|
|
|
(1,021
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(187,923
|
)
|
|
$
|
(140,082
|
)
|
|
|
|
|
|
|
|
|
|
Included in our deferred tax assets are state tax net operating
loss carry forwards of $9,279. We expect to generate future
state taxable income to fully utilize these loss carry forwards.
We had no U.S. federal loss carry forward at
December 31, 2010 and $3,592 of U.S. loss carry
forward at December 31, 2009. We have $1,107 of foreign
non-capital loss carry forward at December 31, 2010,
compared to $2,930 at December 31, 2009.
No deferred income taxes were provided on $28,584 of
undistributed earnings of foreign subsidiaries as of
December 31, 2010, as we intend to indefinitely reinvest
these funds. Upon distribution of these earnings in the form of
dividends or otherwise, we may be subject to U.S. income
taxes and foreign withholding taxes. It is not practical,
however, to estimate the amount of taxes that may be payable on
the eventual distribution of these earnings after consideration
of available foreign tax credits.
We adopted the FASB interpretation on accounting for uncertainty
in income taxes as of January 1, 2007. This guidance
clarifies the accounting for uncertain tax positions that may
have been taken by an entity. Specifically, it prescribes a
more-likely-than-not recognition threshold to measure a tax
position taken or expected to be taken in a tax return through a
two-step process: (1) determining whether it is more likely
than not that a tax position will be sustained upon examination
by taxing authorities, after all appeals, based upon the
technical merits of the position; and (2) measuring to
determine the amount of benefit/expense to recognize in the
financial statements, assuming taxing authorities have all
relevant information concerning the issue. The tax position is
measured at the largest amount of benefit/expense that is
greater than 50 percent likely of being realized upon
ultimate settlement. This pronouncement also specifies how to
present a liability for unrecognized tax benefits in a
classified balance sheet, but does not change the classification
requirements for deferred taxes. Under this guidance, if a tax
position previously failed the more-likely-than-not recognition
threshold, it should be recognized in the first subsequent
84
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
financial reporting period in which the threshold is met.
Similarly, a position that no longer meets this recognition
threshold should no longer be recognized in the first financial
reporting period in which the threshold is no longer met.
The FASB issued additional guidance on how an entity is to
determine whether a tax position has effectively settled for
purposes of recognizing previously unrecognized tax benefits.
Specifically, this guidance states that an entity would
recognize a benefit when a tax position is effectively settled
using the following criteria: (1) the taxing authority has
completed its examination including all appeals and
administrative reviews; (2) the entity does not plan to
appeal or litigate any aspect of the tax position; and
(3) it is remote that the taxing authority would examine or
reexamine any aspect of the tax position, assuming the taxing
authority has full knowledge of all relevant information
relative to making their assessment on the position.
We performed an examination of our tax positions and calculated
the cumulative amount of our estimated exposure by evaluating
each issue to determine whether the impact exceeded the
50 percent threshold of being realized upon ultimate
settlement with the taxing authorities. Based upon this
examination, we determined that the aggregate exposure did not
have a material impact on our financial statements during the
years ended December 31, 2010, 2009 and 2008. Therefore, we
have not recorded an adjustment to our financial statements
related to this interpretation. We will continue to evaluate our
tax positions, and recognize any future impact as a charge to
income in the applicable period in accordance with the standard.
Our tax filings for tax years 2006 to 2009 remain open for
examination by taxing authorities. We do not anticipate any
significant changes in our uncertain tax positions during the
next twelve months.
Our accounting policy related to income tax penalties and
interest assessments is to accrue for these costs and record a
charge to selling, general and administrative expense for tax
penalties and a charge to interest expense for interest
assessments during the period that we take an uncertain tax
position through resolution with the taxing authorities or the
expiration of the applicable statute of limitations. We did not
record any significant amounts related to penalties and interest
during the years ended December 31, 2010, 2009 and 2008.
We entered into a note arrangement to finance certain of our
annual insurance premiums for the policy term from
December 1, 2007 to April 30, 2009. Effective
May 1, 2009, we renewed our insurance policies and entered
into a similar financing arrangement for the twelve-month policy
term which extended through April 2010. Concurrently, we renewed
our workers compensation, general liability and auto
insurance policies through our insurance broker for the same
policy term. Our accounting policy has been to record a prepaid
asset associated with certain of these policies which is
amortized over the term and which takes into account actual
premium payments and deposits made to date, to record an accrued
liability for premiums which are contractually committed for the
policy term and to make monthly premium payments in accordance
with our premium commitments and monthly note payments for
amounts financed. Effective May 1, 2010, we renewed our
annual insurance premiums for the policy term May 1, 2010
through April 30, 2011, but chose to prepay our premiums
for certain insurance coverages which had been financed through
a note arrangement in prior renewals, and to continue to make
monthly premium payments through our broker for other insurance
coverages, including workers compensation, general
liability and auto insurance during this twelve-month policy
term. As a result, we recorded a prepaid asset of $4,267 in May
2010 associated with these renewals.
85
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The following table summarizes long-term debt as of
December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
U.S. revolving credit facility(a)
|
|
$
|
|
|
|
$
|
|
|
Canadian revolving credit facility(a)
|
|
|
|
|
|
|
|
|
8% senior notes(b)
|
|
|
650,000
|
|
|
|
650,000
|
|
Capital leases and other
|
|
|
|
|
|
|
230
|
|
|
|
|
|
|
|
|
|
|
|
|
|
650,000
|
|
|
|
650,230
|
|
Less: current maturities of long-term debt and capital leases
|
|
|
|
|
|
|
228
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
650,000
|
|
|
$
|
650,002
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
We maintain a senior secured facility (the Credit
Agreement) with Wells Fargo Bank, National Association, as
U.S. Administrative Agent, HSBC Bank Canada, as Canadian
Administrative Agent, and certain other financial institutions.
On October 13, 2009, we entered into the Third Amendment
(the Credit Agreement after giving effect to the Third
Amendment, the Amended Credit Agreement) and
modified the structure of our existing credit facility to an
asset-based facility subject to borrowing base restrictions. In
connection with the Third Amendment, Wells Fargo Capital
Finance, LLC (formerly known as Wells Fargo Foothill,
LLC) replaced Wells Fargo Bank, National Association, as
U.S. Administrative Agent and also serves as U.S. Issuing Lender
and U.S. Swingline Lender under the Amended Credit Agreement.
The Amended Credit Agreement provides for a U.S. revolving
credit facility of up to $225,000 that matures in December 2011
and a Canadian revolving credit facility of up to $15,000 (with
Integrated Production Services Ltd., one of our wholly-owned
subsidiaries, as the borrower thereof (Canadian
Borrower)) that matures in December 2011. The Amended
Credit Agreement includes a provision for a commitment
increase, as defined therein, which permits us to effect
up to two separate increases in the aggregate commitments under
the Amended Credit Agreement by designating one or more existing
lenders or other banks or financial institutions, subject to the
banks sole discretion as to participation, to provide
additional aggregate financing up to $75,000, with each
committed increase equal to at least $25,000 in the U.S., or
$5,000 in Canada, and in accordance with other provisions as
stipulated in the Amended Credit Agreement. Certain portions of
the credit facilities are available to be borrowed in U.S.
dollars, Canadian dollars and other currencies approved by the
lenders. |
|
|
|
Our U.S. borrowing base is limited to: (1) 85% of U.S.
eligible billed accounts receivable, less dilution, if any, plus
(2) the lesser of 55% of the amount of U.S. eligible
unbilled accounts receivable or $10.0 million, plus
(3) the lesser of the equipment reserve amount
and 80% times the most recently determined net liquidation
percentage, as defined in the Amended Credit Agreement,
times the value of our and the U.S. subsidiary guarantors
equipment, provided that at no time shall the amount determined
under this clause exceed 50% of the U.S. borrowing base, minus
(4) the aggregate sum of reserves established by the U.S.
Administrative Agent, if any. The equipment reserve
amount means $50.0 million upon the effective date of
the Third Amendment, less $0.6 million for each subsequent
month, not to be reduced below zero in the aggregate. |
|
|
|
The Canadian borrowing based is limited to: (1) 80% of
Canadian eligible billed accounts receivable, plus (2) if
the Canadian Borrower has requested credit for equipment under
the Canadian borrowing base, the lesser of
(a) $15.0 million, and (b) 80% times the most
recently determined net liquidation percentage, as
defined in the Amended Credit Agreement, times the value
(calculated on a basis consistent with our historical accounting
practices) of our and the US subsidiary guarantors
equipment, minus (3) the aggregate amount of reserves
established by our Canadian Administrative Agent, if any. |
|
|
|
Subject to certain limitations set forth in the Amended Credit
Agreement, we have the ability to elect how interest under the
Amended Credit Agreement will be computed. Interest under the
Amended Credit Agreement may be determined by reference to
(1) the London Inter-bank Offered Rate, or LIBOR, plus |
86
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
an applicable margin between 3.75% and 4.25% per annum (with the
applicable margin depending upon our excess availability
amount, as defined in the Amended Credit Agreement) or
(2) the Base Rate (which means the higher of
the Prime Rate, Federal Funds Rate plus 0.50%,
3-month
LIBOR plus 1.00% and 3.50%), plus the applicable margin, as
described above. For the period from the effective date of the
Third Amendment until the six month anniversary of the effective
date of the Third Amendment, interest was computed with an
applicable margin rate of 4.00%. If an event of default exists
or continues under the Amended Credit Agreement, advances will
bear interest as described above with an applicable margin rate
of 4.25% plus 2.00%. Additionally, if an event of default exists
under the Amended Credit Agreement, as defined therein, the
lenders could accelerate the maturity of the obligations
outstanding thereunder and exercise other rights and remedies.
Interest is payable monthly. |
|
|
|
Under the Amended Credit Agreement, we are permitted to prepay
our borrowings and we have the right to terminate, in whole or
in part, the unused portion of the U.S. commitments in
$1.0 million increments upon written notice to the U.S.
Administrative Agent. If all of the U.S. facility is terminated,
the Canadian facility must also be terminated. |
|
|
|
All of the obligations under the U.S. portion of the Amended
Credit Agreement are secured by first priority liens on
substantially all of our assets and the assets of our U.S.
subsidiaries as well as a pledge of approximately 66% of the
stock of our first-tier foreign subsidiaries. Additionally, all
of the obligations under the U.S. portion of the Amended Credit
Agreement are guaranteed by substantially all of our U.S.
subsidiaries. The obligations under the Canadian portion of the
Amended Credit Agreement are secured by first priority liens on
substantially all of our assets and the assets of our
subsidiaries (other than our Mexican subsidiary). Additionally,
all of the obligations under the Canadian portion of the Amended
Credit Agreement are guaranteed by us as well as certain of our
subsidiaries. |
|
|
|
The Amended Credit Agreement also contains various covenants
that limit our and our subsidiaries ability to:
(1) grant certain liens; (2) incur additional
indebtedness; (3) make certain loans and investments;
(4) make capital expenditures; (5) make distributions;
(6) make acquisitions; (7) enter into hedging
transactions; (8) merge or consolidate; or (9) engage
in certain asset dispositions. The Amended Credit Agreement
contains one financial maintenance covenant which requires us
and our subsidiaries, on a consolidated basis, to maintain a
fixed charge coverage ratio, as defined in the
Amended Credit Agreement, of not less than 1.10 to 1.00. This
covenant is only tested if our excess availability
amount, as defined under the Amended Credit Agreement,
plus certain qualified cash and cash equivalents (collectively
Liquidity) is less than $50.0 million for a
period of 5 consecutive days and continues only until such time
as our Liquidity has been greater than or equal to
$50.0 million for a period of 90 consecutive days or
greater than or equal to $75.0 million for a period of 45
consecutive days. |
|
|
|
Our fixed charge coverage ratio covenant is calculated, for
fiscal quarters ending after September 30, 2009, as the
ratio of EBITDA calculated for the four fiscal
quarter period ended after September 30, 2009 minus capital
expenditures made with cash (to the extent not already incurred
in a prior period) or incurred during such four quarter period,
compared to fixed charges, calculated for the four
quarters then ended. EBITDA is defined in the
Amended Credit Agreement as consolidated net income for the
period plus, to the extent deducted in determining our
consolidated net income, interest expense, taxes, depreciation,
amortization and other non-cash charges for such period,
provided that EBITDA shall be subject to pro forma adjustments
for acquisitions and non-ordinary course asset sales assuming
that such transactions occurred on the first day of the
determination period, which adjustments shall be made in
accordance with the guidelines for pro forma presentations set
forth by the Securities and Exchange Commission. Fixed
charges, as defined in the Amended Credit Agreement,
include interest expense, among other things, reduced by the
amortization of transaction fees associated with the Third
Amendment. |
|
|
|
We were not subject to the fixed charge coverage ratio covenant
in the Amended Credit Agreement as of December 31, 2010
since the Excess Availability Amount plus Qualified Cash Amount
(each as defined in the |
87
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
Amended Credit Agreement) exceeded $50,000. If we had been
subject to the fixed charge coverage ratio covenant at
December 31, 2010, we would have been in compliance. |
|
|
|
There were no borrowings outstanding under our U.S. or Canadian
revolving credit facilities as of December 31, 2010. There
were letters of credit outstanding under the U.S. revolving
portion of the facility totaling $26,370, which reduced the
available borrowing capacity as of December 31, 2010. We
incurred fees related to our letters of credit as of
December 31, 2010 at 3.75% per annum. For the twelve months
ended December 31, 2010, fees related to our letters of
credit were calculated using a
360-day
provision, at 4.0% per annum. The availability of the U.S. and
Canadian revolving credit facilities is determined by our
borrowing base less any borrowings and letters of credit
outstanding. The net excess availability under our borrowing
base calculations for the U.S. and Canadian revolving facilities
at December 31, 2010 was $187,380 and $8,405, respectively. |
|
|
|
The primary purpose of our letters of credit is to secure
potential future claim liability which may be incurred by our
insurance providers. During the quarter ended September 30,
2010, we negotiated a reduction in our letter of credit
requirements of $5,569. In addition, we placed $17,000 in escrow
as a compensating balance, effectively cash collateralizing a
portion of our letters of credit, in order to better utilize
excess cash and reduce interest expense. This compensating
balance has been recorded as a long-term asset called
Restricted cash on the accompanying consolidated
balance sheet at December 31, 2010. |
|
|
|
We incur unused commitment fees under the Amended Credit
Agreement ranging from 0.50% to 1.00% based on the average daily
balance of amounts outstanding. The unused commitment fees were
calculated at 1.00% as of December 31, 2010. |
|
(b) |
|
On December 6, 2006, we issued 8.0% senior notes with
a face value of $650,000 through a private placement of debt.
These notes mature in 10 years, on December 15, 2016,
and require semi-annual interest payments, paid in arrears and
calculated based on an annual rate of 8.0%, on June 15 and
December 15, of each year, which commenced on June 15,
2007. There was no discount or premium associated with the
issuance of these notes. The senior notes are guaranteed by all
of our current domestic subsidiaries. The senior notes have
covenants which, among other things: (1) limit the amount
of additional indebtedness we can incur; (2) limit
restricted payments such as a dividend; (3) limit our
ability to incur liens or encumbrances; (4) limit our
ability to purchase, transfer or dispose of significant assets;
(5) limit our ability to purchase or redeem stock or
subordinated debt; (6) limit our ability to enter into
transactions with affiliates; (7) limit our ability to
merge with or into other companies or transfer all or
substantially all of our assets; and (8) limit our ability
to enter into sale and leaseback transactions. We have the
option to redeem all or part of these notes on or after
December 15, 2011. Additionally, we may redeem some or all
of the notes prior to December 15, 2011 at a price equal to
100% of the principal amount of the notes plus a make-whole
premium. |
|
|
|
Pursuant to a registration rights agreement with the holders of
our 8.0% senior notes, on June 1, 2007, we filed a
registration statement on
Form S-4
with the SEC which enabled these holders to exchange their notes
for publicly registered notes with substantially identical
terms. These holders exchanged 100% of the notes for publicly
traded notes on July 25, 2007. On August 28, 2007, we
entered into a supplement to the indenture governing the
8.0% senior notes, whereby additional domestic subsidiaries
became guarantors under the indenture. Effective April 1,
2009, we entered into a second supplement to this indenture
whereby additional domestic subsidiaries became guarantors under
the indenture. |
|
|
12.
|
Stockholders
equity:
|
(a) Authorized
Share Capital:
On September 12, 2005, our authorized share capital was
increased to 200,000,000 shares of common stock from
24,000,000 shares of common stock with par value of $0.01
per share and to 5,000,000 shares of preferred stock from
1,000 shares of preferred stock with a par value of $0.01
per share.
88
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
(b) Initial
Public Offering:
On April 26, 2006, we sold 13,000,000 shares of our
common stock, $.01 par value per share, in our initial
public offering. These shares were offered to the public at
$24.00 per share, and we recorded proceeds of approximately
$292,500 after underwriter fees of $19,500. In addition, we
incurred transaction costs of $3,865 associated with the
issuance that were netted against the proceeds of the offering.
Our stock began trading on the New York Stock Exchange on
April 21, 2006.
(c) Stock-based
Compensation:
We maintain option plans under which we grant stock-based
compensation to employees, officers and directors to purchase
our common stock. The exercise price of each option is based on
the fair value of the issuing companys common stock at the
date of grant. Options may be exercised over a five or ten-year
period and generally a third of the options vest on each of the
first three anniversaries from the grant date. Upon exercise of
stock options, we issue our common stock.
For grants of stock-based compensation on or after
January 1, 2006, we apply the prospective transition method
prescribed by U.S. GAAP, whereby we recognize expense
associated with new awards of stock-based compensation ratably,
as determined using a Black-Scholes pricing model, over the
expected term of the award.
In November 2006, we assumed the stock option plan of Pumpco,
which included 145,000 outstanding employee stock options at an
exercise price of $5.00 per share. The exercise price of these
stock options was $5.00 per share, which was below market price
at the date of grant pursuant to the
agreed-upon
conversion rate negotiated as part of the acquisition. These
options vested ratably over the three-year term. Upon exercise
of these Pumpco stock options, we issue shares of our common
stock.
(i) Employee
Stock Options Granted Between October 1, 2005 and
December 31, 2005:
For grants of stock-based compensation between October 1,
2005 and December 31, 2005, we have utilized the modified
prospective transition method to record expense associated with
these stock-based compensation instruments. Under this
transition method, beginning January 1, 2006, we began to
recognize expense related to these option grants over the
applicable vesting period, with expense calculated by applying a
Black-Scholes pricing model with the following assumptions:
risk-free rate of 4.23% to 4.47%; expected term of
4.5 years and no dividend rate. The weighted average fair
value of these option grants was $2.05 per share.
For the year ended December 31, 2008, the compensation
expense recognized related to these stock options was $270,
which reduced net income by $174. There was no impact on basic
and diluted earnings per share from continuing operations as
reported for the year ended December 31, 2008 attributable
to the compensation expense recognized related to these stock
options. These awards were 100% vested at December 31, 2008.
(ii) Employee
Stock Options Granted On or After January 1,
2006:
For grants of stock-based compensation on or after
January 1, 2006, we apply the prospective transition method
prescribed by U.S. GAAP, whereby we recognize expense
associated with new awards of stock-based compensation ratably,
as determined using a Black-Scholes pricing model, over the
expected term of the award.
During the years ended December 31, 2010 and 2009, the
Compensation Committee of our Board of Directors authorized and
issued to our officers and employees 480,300 and
875,300 employee stock options, respectively, and 774,800
and 1,191,400 non-vested restricted shares, respectively. The
stock options granted on January 29, 2010 had an exercise
price of $12.53 per share. Stock option grants in 2009 had an
exercise price which ranged from $6.41 to $6.78 per share. The
exercise price represented the fair market value of the shares
on the date of grant. These stock option grants vest ratably
over a three-year term. In addition, our directors received
stock option grants during 2010 and 2009 of 30,000 and
40,000 shares, respectively, which vest ratably over a
three-year period. Furthermore, the directors received
89
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
34,296 shares of non-vested restricted stock in 2010 which
vests 100% on January 29, 2011 and received
109,608 shares of non-vested restricted stock in 2009 which
vested 100% on January 30, 2010. The fair value of the
stock option grants was determined by applying a Black-Scholes
option pricing model based on the following assumptions:
|
|
|
|
|
|
|
For the Year Ended December 31,
|
Assumptions:
|
|
2010
|
|
2009
|
|
Risk-free rate
|
|
1.38% to 2.34%
|
|
0.89% to 2.51%
|
Expected term (in years)
|
|
3.7 to 5.1
|
|
2.2 to 5.1
|
Volatility
|
|
50%
|
|
29% to 47%
|
Calculated fair value per option
|
|
$4.83 to $5.81
|
|
$1.14 to $3.01
|
The weighted average fair value of stock option grants for the
years ended December 31, 2010, 2009 and 2008 was $5.74,
$1.82 and $4.62, respectively.
For stock option grants made prior to the second quarter of
2008, we did not have sufficient historical market data in order
to determine the volatility of our common stock. In accordance
with U.S. GAAP, we analyzed the market data of peer
companies and calculated an average volatility factor based upon
changes in the closing price of these companies common
stock for a three-year period. This volatility factor was then
applied as a variable to determine the fair value of our stock
option grants. For stock options granted during or after the
second quarter of 2008, we calculated an average volatility
factor for our common stock for the period from April 21,
2006 through the respective quarter end, or for the three-year
period then ended. These volatility calculations were used to
compute the calculation of the fair market value of stock option
grants made subsequent to June 30, 2008.
We projected a rate of stock option forfeitures based upon
historical experience and management assumptions related to the
expected term of the options. After adjusting for these
forfeitures, we expect to recognize expense totaling $19,538
related to our stock option grants made after January 1,
2006. For the years ended December 31, 2010, 2009 and 2008,
we have recognized expense related to these stock option grants
totaling $2,321, $3,943 and $5,166, respectively, which
represents a reduction of net income before taxes. The impact on
net income (loss) was a reduction of $1,439, $2,926 and $3,332,
respectively. The unrecognized compensation costs related to the
non-vested portion of these awards was $2,418 as of
December 31, 2010 and will be recognized over the
applicable remaining vesting periods.
The non-vested restricted shares were granted at fair value on
the date of grant. If the restricted non-vested shares are not
forfeited, we will recognize compensation expense related to our
2010, 2009 and 2008 grants to officers and employees totaling
$9,781, $7,634 and $14,025, respectively, over the three-year
vesting period. We expect to recognize expense associated with
grants to our directors in 2010, 2009 and 2008 totaling $430,
$703 and $402, respectively, over a twelve-month vesting period.
90
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The following tables provide a roll forward of stock options
from December 31, 2007 to December 31, 2010 and a
summary of stock options outstanding by exercise price range at
December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Exercise
|
|
|
|
Number
|
|
|
Price
|
|
|
Balance at December 31, 2007
|
|
|
3,730,761
|
|
|
$
|
13.36
|
|
Granted
|
|
|
408,596
|
|
|
$
|
17.90
|
|
Exercised
|
|
|
(1,238,819
|
)
|
|
$
|
9.70
|
|
Cancelled
|
|
|
(154,026
|
)
|
|
$
|
20.11
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
2,746,512
|
|
|
$
|
15.33
|
|
Granted
|
|
|
915,300
|
|
|
$
|
6.41
|
|
Exercised
|
|
|
(123,858
|
)
|
|
$
|
4.01
|
|
Cancelled
|
|
|
(154,334
|
)
|
|
$
|
20.17
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
3,383,620
|
|
|
$
|
13.09
|
|
Granted
|
|
|
510,300
|
|
|
$
|
12.53
|
|
Exercised
|
|
|
(599,035
|
)
|
|
$
|
13.49
|
|
Cancelled
|
|
|
(153,305
|
)
|
|
$
|
18.16
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2010
|
|
|
3,141,580
|
|
|
$
|
12.68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
|
Options Exercisable
|
|
|
|
|
|
|
Weighted
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
Weighted
|
|
|
|
Outstanding at
|
|
|
Average
|
|
|
Average
|
|
|
Exercisable at
|
|
|
Average
|
|
|
Average
|
|
|
|
December 31,
|
|
|
Remaining
|
|
|
Exercise
|
|
|
December 31,
|
|
|
Remaining
|
|
|
Exercise
|
|
Range of Exercise Price
|
|
2010
|
|
|
Life (Months)
|
|
|
Price
|
|
|
2010
|
|
|
Life (months)
|
|
|
Price
|
|
|
$5.00
|
|
|
65,000
|
|
|
|
29
|
|
|
$
|
5.00
|
|
|
|
65,000
|
|
|
|
29
|
|
|
$
|
5.00
|
|
$6.69 - $8.16
|
|
|
1,386,031
|
|
|
|
77
|
|
|
$
|
6.54
|
|
|
|
793,276
|
|
|
|
63
|
|
|
$
|
6.63
|
|
$11.66 - $12.53
|
|
|
573,569
|
|
|
|
103
|
|
|
$
|
12.43
|
|
|
|
63,269
|
|
|
|
57
|
|
|
$
|
11.66
|
|
$15.90
|
|
|
275,400
|
|
|
|
85
|
|
|
$
|
15.90
|
|
|
|
176,644
|
|
|
|
73
|
|
|
$
|
15.90
|
|
$17.60 - $19.87
|
|
|
412,011
|
|
|
|
73
|
|
|
$
|
19.82
|
|
|
|
412,011
|
|
|
|
73
|
|
|
$
|
19.82
|
|
$22.55 - $24.07
|
|
|
333,069
|
|
|
|
64
|
|
|
$
|
23.97
|
|
|
|
333,069
|
|
|
|
64
|
|
|
$
|
23.97
|
|
$26.26 - $27.11
|
|
|
45,000
|
|
|
|
77
|
|
|
$
|
26.35
|
|
|
|
45,000
|
|
|
|
77
|
|
|
$
|
26.35
|
|
$29.88
|
|
|
40,000
|
|
|
|
89
|
|
|
$
|
29.88
|
|
|
|
26,667
|
|
|
|
89
|
|
|
$
|
29.88
|
|
$34.19
|
|
|
11,500
|
|
|
|
90
|
|
|
$
|
34.19
|
|
|
|
7,667
|
|
|
|
90
|
|
|
$
|
34.19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,141,580
|
|
|
|
80
|
|
|
$
|
12.68
|
|
|
|
1,922,603
|
|
|
|
66
|
|
|
$
|
14.32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The total intrinsic value of stock options exercised during the
years ended December 31, 2010 and 2009 was $7,888 and $568,
respectively. The total intrinsic value of all
in-the-money
vested outstanding stock options at December 31, 2010 was
$29,330. Assuming all stock options outstanding at
December 31, 2010 were vested, the total intrinsic value of
all
in-the-money
outstanding stock options would have been $53,394.
|
|
(d)
|
2008
Incentive Award Plan:
|
In March 2008, upon the recommendation of the Compensation
Committee and subject to approval by stockholders, our Board of
Directors approved the Complete Production Services, Inc. 2008
Incentive Award Plan, which was intended to succeed the prior
stock option plan, the Amended and Restated 2001 Stock Incentive
Plan,
91
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
pursuant to which, 2,500,000 shares of common stock were
authorized for future issuance to our directors, officers and
employees in conjunction with stock-based compensation
arrangements. On May 22, 2008, stockholders owning more
than a majority of the shares of our common stock adopted the
2008 Stock Incentive Plan. We subsequently filed a registration
statement on
Form S-8
and made grants to our directors, officers and employees. In
March 2009, upon the recommendation of the Compensation
Committee and as approved by our stockholders owning more than a
majority of the shares of our common stock on May 24, 2009,
we amended the 2008 Incentive Award Plan to increase the number
of shares authorized for future issuance to up to
6,400,000 shares. As amended, the aggregate number of
shares of common stock available for issuance under the 2008
Incentive Award Plan will be reduced by (i) 1.3 shares
for each share of common stock delivered in settlement of any
full value award, and (ii) 1.0 shares for each share
of common stock delivered in settlement of any option, stock
appreciation right or any other award that is not a full value
award. If all of the shares authorized by the amendment to the
2008 Incentive Award Plan were granted as full value awards,
then there would be 4,900,000 shares granted as full value
awards and no shares available for issuance as awards that were
not full value awards. For purposes of the 2008 Incentive Award
Plan, full value awards mean any award other than (i) an
option, (ii) a stock appreciation right or (iii) any
other award for which the holder pays the intrinsic value
existing as of the date of grant (whether directly or by
forgoing a right to receive a payment from us or any subsidiary
of ours). We subsequently filed a registration statement on
Form S-8
and made grants to our directors, officers and employees under
the 2008 Incentive Award Plan, as amended. The 2008 Stock
Incentive Plan provides that forfeitures under the Amended and
Restated 2001 Stock Incentive Plan will become available for
issuance under the 2008 Incentive Award Plan.
|
|
(e)
|
Non-vested
Restricted Stock:
|
We present the amortization of non-vested restricted stock as an
increase in additional paid-in capital. At December 31,
2010 and 2009, amounts not yet recognized related to non-vested
stock totaled $9,704 and $9,727, respectively, which represented
the unamortized expense associated with awards of non-vested
stock granted to employees, officers and directors under our
compensation plans. Compensation expense associated with these
grants of non-vested stock is determined as the fair value of
the shares on the date of grant, and recognized ratably over the
applicable vesting periods. We recognized compensation expense
associated with non-vested restricted stock totaling $9,233,
$8,222 and $6,934 for the years ended December 31, 2010,
2009 and 2008, respectively.
92
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
The following table summarizes the change in non-vested
restricted stock from December 31, 2007 to
December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
Non-vested
|
|
|
|
Restricted Stock
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
Number
|
|
|
Grant Price
|
|
|
Balance at December 31, 2007
|
|
|
625,871
|
|
|
$
|
9.46
|
|
Granted
|
|
|
618,632
|
|
|
$
|
23.32
|
|
Vested
|
|
|
(422,461
|
)
|
|
$
|
9.94
|
|
Forfeited
|
|
|
(32,851
|
)
|
|
$
|
12.47
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
789,191
|
|
|
$
|
19.95
|
|
Granted
|
|
|
1,301,008
|
|
|
$
|
6.41
|
|
Vested
|
|
|
(406,880
|
)
|
|
$
|
16.75
|
|
Forfeited
|
|
|
(47,754
|
)
|
|
$
|
9.85
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
1,635,565
|
|
|
$
|
10.27
|
|
Granted
|
|
|
809,096
|
|
|
$
|
12.62
|
|
Vested
|
|
|
(679,815
|
)
|
|
$
|
10.89
|
|
Forfeited
|
|
|
(91,992
|
)
|
|
$
|
10.89
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2010
|
|
|
1,672,854
|
|
|
$
|
11.12
|
|
|
|
|
|
|
|
|
|
|
(f) Common
Shares Issued for Acquisitions:
On October 4, 2008, we issued 588,292 unregistered shares
of our $0.01 par value common stock as a portion of the
purchase consideration for Appalachian Well Service, Inc. and
its wholly owned subsidiary. See Note 3, Business
combinations. In connection with this issuance, we
recorded common stock and additional paid-in capital totaling
$8,854, based on an issuance price of $15.04 per share, based on
an average of the closing and opening price of our common stock
on the business day proceeding and following the acquisition
date. The number of shares issued was calculated based upon the
agreed-upon
purchase price negotiated with the seller.
(g) Treasury
shares:
In accordance with the provisions of the 2008 Incentive Award
Plan, holders of unvested restricted stock were given the option
to either remit to us the required withholding taxes associated
with the vesting of restricted stock, or to authorize us to
repurchase shares equivalent to the cost of the withholding tax
and to remit the withholding taxes
93
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
on behalf of the holder. Pursuant to this provision, we
repurchased the following shares during the year ended
December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
Average Price
|
|
|
Extended
|
|
Period
|
|
Purchased
|
|
|
Paid per Share
|
|
|
Amount
|
|
|
January 1 31, 2010
|
|
|
109,360
|
|
|
$
|
12.53
|
|
|
$
|
1,370
|
|
March 1 31, 2010
|
|
|
902
|
|
|
|
14.06
|
|
|
|
13
|
|
April 1 30, 2010
|
|
|
426
|
|
|
|
11.84
|
|
|
|
5
|
|
May 1 31, 2010
|
|
|
1,260
|
|
|
|
14.48
|
|
|
|
18
|
|
June 1 30, 2010
|
|
|
355
|
|
|
|
14.83
|
|
|
|
4
|
|
July 1 31, 2010
|
|
|
591
|
|
|
|
14.38
|
|
|
|
8
|
|
December 1 31, 2010
|
|
|
436
|
|
|
|
29.00
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
113,330
|
|
|
|
|
|
|
$
|
1,431
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
These shares were included as treasury stock at cost in the
accompanying balance sheet as of December 31, 2010. We
expect to purchase additional shares in the future pursuant to
this plan provision.
We compute basic earnings per share by dividing net income by
the weighted average number of common shares outstanding during
the period. Diluted earnings per common and potential common
share includes the weighted average of additional shares
associated with the incremental effect of dilutive employee
stock options and non-vested restricted stock, as determined
using the treasury stock method prescribed by the FASB guidance
on earnings per share. The following table reconciles basic and
diluted weighted average shares used in the computation of
earnings per share for the years ended December 31, 2010,
2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Weighted average basic common shares outstanding
|
|
|
76,048
|
|
|
|
75,095
|
|
|
|
73,600
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee stock options
|
|
|
759
|
|
|
|
|
|
|
|
|
|
Non-vested restricted stock
|
|
|
877
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average diluted common and potential common shares
outstanding
|
|
|
77,684
|
|
|
|
75,095
|
|
|
|
73,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For each of the years ended December 31, 2009 and 2008, we
incurred a net loss and thus all potential common shares were
deemed to be anti-dilutive. We excluded the impact of
anti-dilutive potential common shares from the calculation of
diluted weighted average shares for the years ended
December 31, 2010, 2009 and 2008. If these potential common
shares were included, the impact would have been a decrease in
weighted average shares outstanding of 194,211 shares,
2,474,169 shares and 1,245,148 shares, respectively,
for the years ended December 31, 2010, 2009 and 2008.
|
|
14.
|
Discontinued
operations:
|
In May 2008, our Board of Directors authorized and committed to
a plan to sell certain business assets located primarily in
north Texas which included our product supply stores, certain
drilling logistics assets and other completion and production
services assets. Although this sale did not represent a material
disposition of assets relative to our total assets, the disposal
group did represent a significant portion of the assets and
operations which were attributable to our product sales business
segment for the periods presented, and therefore, was accounted
for
94
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
as a disposal group that is held for sale. We revised our
financial statements, in accordance with U.S. GAAP and
removed the results of operations of the disposal group from net
income from continuing operations, and presented these
separately as income from discontinued operations, net of tax,
for the accompanying statement of operations for the year ended
December 31, 2008. We ceased depreciating the assets of
this disposal group in May 2008 and adjusted the net assets to
the lower of carrying value or fair value less selling costs,
which resulted in a pre-tax charge of approximately $200. In
addition, we allocated $11,109 of goodwill associated with the
original formation of Complete Production Services, Inc. to this
business, and impaired this goodwill as of the date of the
transaction. Thus, this amount has been included in the
calculation of the loss on the sale of this disposal group.
On May 19, 2008, we completed the sale of the disposal
group for $50,150 in cash and we received assets with a fair
market value of $7,987. In addition, we retained the receivables
and payables associated with the operating results of these
entities as of the date of the sale. The carrying value of the
related net assets was approximately $51,353 on May 19,
2008, excluding allocated goodwill of $11,109. We recorded a
loss of $6,935 associated with the sale of this disposal group,
which represents the excess of the carrying value of the assets
less selling costs over the sales price and a charge of
approximately $2,610 related to income tax on the transaction.
The income tax on the disposal was primarily attributable to the
$11,109 of allocated goodwill which was non-deductible for tax
purposes and resulted in a taxable gain on the disposal. We sold
this disposal group to Select Energy Services, L.L.C., an
oilfield service company located in Gainesville, Texas which was
owned by a former officer of one of our subsidiaries. Pursuant
to the agreement, we sublet office space to Select Energy
Services, L.L.C., and provided certain administrative functions
for a period of one year at an
agreed-upon
rate for services per hour. Proceeds from the sale of this
disposal group were used to repay outstanding borrowings under
our U.S. revolving credit facility and for other general
corporate purposes.
The following table summarizes operating results for this
disposal group for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
|
|
|
January 1, 2008
|
|
|
|
|
through
|
|
|
|
|
May 19,
|
|
|
|
|
2008
|
|
|
|
Revenue
|
|
$
|
59,553
|
|
|
|
|
|
Income before taxes
|
|
$
|
3,330
|
|
|
|
|
|
Net income before loss on disposal in 2008
|
|
$
|
2,076
|
|
|
|
|
|
Net income loss
|
|
$
|
(4,859
|
)
|
|
|
|
|
We report segment information based on how our management
organizes the operating segments to make operational decisions
and to assess financial performance. We evaluate performance and
allocate resources based on net income (loss) from continuing
operations before net interest expense, taxes, depreciation and
amortization, non-controlling interest and impairment loss
(Adjusted EBITDA). The calculation of Adjusted
EBITDA should not be viewed as a substitute for calculations
under U.S. GAAP, in particular net income. Adjusted EBITDA
is included in this Annual Report on
Form 10-K
because our management considers it an important supplemental
measure of our performance and believes that it is frequently
used by securities analysts, investors and other interested
parties in the evaluation of companies in our industry, some of
which present EBITDA when reporting their results. We regularly
evaluate our performance as compared to other companies in our
industry that have different financing and capital structures
and/or tax
rates by using Adjusted EBITDA. In addition, we use Adjusted
EBITDA in evaluating acquisition targets. Management also
believes that Adjusted EBITDA is a useful tool for measuring our
ability to meet our future debt service, capital expenditures
and working capital requirements, and Adjusted EBITDA is
commonly used by us and our investors to measure our ability to
service indebtedness. Adjusted EBITDA is not a substitute for
the U.S. GAAP measures of earnings or cash flow and is not
necessarily a measure of our ability to fund our cash needs. It
should be noted that companies calculate EBITDA (including
Adjusted EBITDA) differently and,
95
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
therefore, EBITDA has material limitations as a performance
measure because it excludes interest expense, taxes,
depreciation and amortization. Adjusted EBITDA calculated by us
may not be comparable to the EBITDA (or Adjusted EBITDA)
calculation of another company and also differs from the
calculation of EBITDA under our credit facilities (see
Note 11 for a description of the calculation of EBITDA
under our existing credit facility, as amended). See the table
below for a reconciliation of Adjusted EBITDA to operating
income (loss) by segment.
We have three reportable operating segments: completion and
production services (C&PS), drilling services
and product sales. The accounting policies of our reporting
segments are the same as those used to prepare our consolidated
financial statements as of December 31, 2010, 2009 and
2008. Inter-segment transactions are accounted for on a cost
recovery basis.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling
|
|
|
Product
|
|
|
|
|
|
|
|
|
|
C&PS
|
|
|
Services
|
|
|
Sales
|
|
|
Corporate
|
|
|
Total
|
|
|
Year Ended December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue from external customers
|
|
$
|
1,354,797
|
|
|
$
|
172,821
|
|
|
$
|
33,775
|
|
|
$
|
|
|
|
|
|
|
|
$
|
1,561,393
|
|
Inter-segment revenues
|
|
$
|
248
|
|
|
$
|
236
|
|
|
$
|
5,998
|
|
|
$
|
(6,482
|
)
|
|
|
|
|
|
$
|
|
|
Adjusted EBITDA, as defined
|
|
$
|
369,826
|
|
|
$
|
38,973
|
|
|
$
|
5,197
|
|
|
$
|
(39,088
|
)
|
|
|
|
|
|
$
|
374,908
|
|
Depreciation and amortization
|
|
$
|
159,110
|
|
|
$
|
18,480
|
|
|
$
|
2,211
|
|
|
$
|
2,022
|
|
|
|
|
|
|
$
|
181,823
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
210,716
|
|
|
$
|
20,493
|
|
|
$
|
2,986
|
|
|
$
|
(41,110
|
)
|
|
|
|
|
|
$
|
193,085
|
|
Capital expenditures
|
|
$
|
156,787
|
|
|
$
|
10,950
|
|
|
$
|
320
|
|
|
$
|
1,862
|
|
|
|
|
|
|
$
|
169,919
|
|
As of December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment assets
|
|
$
|
1,488,755
|
|
|
$
|
170,944
|
|
|
$
|
35,015
|
|
|
$
|
105,862
|
|
|
|
|
|
|
$
|
1,800,576
|
|
Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue from external customers
|
|
$
|
897,584
|
|
|
$
|
114,729
|
|
|
$
|
44,081
|
|
|
$
|
|
|
|
|
|
|
|
$
|
1,056,394
|
|
Inter-segment revenues
|
|
$
|
105
|
|
|
$
|
746
|
|
|
$
|
8,237
|
|
|
$
|
(9,088
|
)
|
|
|
|
|
|
$
|
|
|
Adjusted EBITDA, as defined
|
|
$
|
165,787
|
|
|
$
|
9,641
|
|
|
$
|
7,966
|
|
|
$
|
(34,313
|
)
|
|
|
|
|
|
$
|
149,081
|
|
Depreciation and amortization
|
|
$
|
174,929
|
|
|
$
|
21,067
|
|
|
$
|
2,460
|
|
|
$
|
2,276
|
|
|
|
|
|
|
$
|
200,732
|
|
Write-off of deferred financing fees
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(528
|
)
|
|
|
|
|
|
$
|
(528
|
)
|
Fixed asset and other intangible impairment loss
|
|
$
|
2,488
|
|
|
$
|
36,158
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
38,646
|
|
Goodwill impairment loss
|
|
$
|
97,643
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
97,643
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
(109,273
|
)
|
|
$
|
(47,584
|
)
|
|
$
|
5,506
|
|
|
$
|
(36,061
|
)
|
|
|
|
|
|
$
|
(187,412
|
)
|
Capital expenditures
|
|
$
|
30,930
|
|
|
$
|
6,680
|
|
|
$
|
228
|
|
|
$
|
649
|
|
|
|
|
|
|
$
|
38,487
|
|
As of December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment assets
|
|
$
|
1,292,199
|
|
|
$
|
172,605
|
|
|
$
|
37,270
|
|
|
$
|
86,780
|
|
|
|
|
|
|
$
|
1,588,854
|
|
Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue from external customers
|
|
$
|
1,541,709
|
|
|
$
|
234,104
|
|
|
$
|
59,102
|
|
|
$
|
|
|
|
|
|
|
|
$
|
1,834,915
|
|
Inter-segment revenues
|
|
$
|
576
|
|
|
$
|
860
|
|
|
$
|
30,358
|
|
|
$
|
(31,794
|
)
|
|
|
|
|
|
$
|
|
|
Adjusted EBITDA, as defined
|
|
$
|
467,100
|
|
|
$
|
58,743
|
|
|
$
|
12,677
|
|
|
$
|
(38,293
|
)
|
|
|
|
|
|
$
|
500,227
|
|
Depreciation and amortization
|
|
$
|
156,298
|
|
|
$
|
19,961
|
|
|
$
|
2,537
|
|
|
$
|
2,401
|
|
|
|
|
|
|
$
|
181,197
|
|
Goodwill impairment loss
|
|
$
|
243,203
|
|
|
$
|
27,410
|
|
|
$
|
1,393
|
|
|
$
|
|
|
|
|
|
|
|
$
|
272,006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
67,599
|
|
|
$
|
11,372
|
|
|
$
|
8,747
|
|
|
$
|
(40,694
|
)
|
|
|
|
|
|
$
|
47,024
|
|
Capital expenditures
|
|
$
|
211,648
|
|
|
$
|
34,253
|
|
|
$
|
6,244
|
|
|
$
|
1,631
|
|
|
|
|
|
|
$
|
253,776
|
|
As of December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment assets
|
|
$
|
1,631,875
|
|
|
$
|
251,015
|
|
|
$
|
52,048
|
|
|
$
|
52,415
|
|
|
|
|
|
|
$
|
1,987,353
|
|
96
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Inter-segment sales in 2010, 2009 and 2008 were largely due to
service work performed and drilling rigs assembled by a
subsidiary in the product sales business segment that provided
these services and rigs to a subsidiary in the drilling services
business segment as well as other subsidiaries primarily in the
completion and production services business segment.
We do not allocate net interest expense or tax expense to the
operating segments. The write-off of deferred financing fees of
$528 for the year ended December 31, 2009 reduced Adjusted
EBITDA, as defined, for the Corporate and Other segment. The
following table reconciles operating income (loss) as reported
above to net income from continuing operations for each of the
years ended December 31, 2010, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Segment operating income (loss)
|
|
$
|
193,085
|
|
|
$
|
(187,412
|
)
|
|
$
|
47,024
|
|
Interest expense
|
|
|
57,669
|
|
|
|
56,895
|
|
|
|
59,729
|
|
Interest income
|
|
|
(322
|
)
|
|
|
(79
|
)
|
|
|
(301
|
)
|
Income taxes
|
|
|
51,580
|
|
|
|
(63,088
|
)
|
|
|
72,305
|
|
Write-off of deferred financing fees
|
|
|
|
|
|
|
528
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations
|
|
$
|
84,158
|
|
|
$
|
(181,668
|
)
|
|
$
|
(84,709
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes the changes in the carrying
amount of goodwill for continuing operations by segment for the
three-year period ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling
|
|
|
Product
|
|
|
|
|
|
|
C&PS
|
|
|
Services
|
|
|
Sales
|
|
|
Total
|
|
|
Balance at December 31, 2007
|
|
$
|
512,363
|
|
|
$
|
32,973
|
|
|
$
|
3,794
|
|
|
$
|
549,130
|
|
Acquisitions
|
|
|
71,209
|
|
|
|
|
|
|
|
|
|
|
|
71,209
|
|
Impairment charge(a)
|
|
|
(243,481
|
)
|
|
|
(27,410
|
)
|
|
|
(1,393
|
)
|
|
|
(272,284
|
)
|
Contingency adjustment and other
|
|
|
(128
|
)
|
|
|
|
|
|
|
|
|
|
|
(128
|
)
|
Foreign currency translation
|
|
|
(6,335
|
)
|
|
|
|
|
|
|
|
|
|
|
(6,335
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
$
|
333,628
|
|
|
$
|
5,563
|
|
|
$
|
2,401
|
|
|
$
|
341,592
|
|
Impairment charge(a)
|
|
|
(97,643
|
)
|
|
|
|
|
|
|
|
|
|
|
(97,643
|
)
|
Contingency adjustment and other
|
|
|
(126
|
)
|
|
|
|
|
|
|
|
|
|
|
(126
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
$
|
235,859
|
|
|
$
|
5,563
|
|
|
$
|
2,401
|
|
|
$
|
243,823
|
|
Acquisitions
|
|
|
6,710
|
|
|
|
|
|
|
|
|
|
|
|
6,710
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2010
|
|
$
|
242,569
|
|
|
$
|
5,563
|
|
|
$
|
2,401
|
|
|
$
|
250,533
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
We evaluate goodwill for impairment annually, or more often if
indicators of impairment exist. For the year ending
December 31, 2008, we determined that goodwill associated
with our Canadian reportable unit was impaired as of the annual
test date. Furthermore, due to the decline in the U.S. debt and
equity markets, as well as the credit market, we re-performed
the prescribed impairment testing at December 31, 2008 and
noted impairment which impacted several of our reportable units.
Therefore, we recorded an impairment charge of $272,006 for the
year ended December 31, 2008. For the year ending
December 31, 2009, we determined that goodwill associated
with several of our reportable units was also impaired so we
recorded an impairment charge of $97,643. See Note 2,
Significant accounting policies Fair value
measurements. |
97
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Geographic
information (b):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United
|
|
|
|
Other
|
|
|
|
|
States
|
|
Canada
|
|
International
|
|
Total
|
|
Year Ended December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue by sale origin to external customers
|
|
$
|
1,398,091
|
|
|
$
|
81,190
|
|
|
$
|
82,112
|
|
|
$
|
1,561,393
|
|
Income from continuing operations before taxes
|
|
$
|
123,595
|
|
|
$
|
1,255
|
|
|
$
|
10,888
|
|
|
$
|
135,738
|
|
December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-lived assets
|
|
$
|
1,190,545
|
|
|
$
|
34,256
|
|
|
$
|
23,865
|
|
|
$
|
1,248,666
|
|
Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue by sale origin to external customers
|
|
$
|
910,297
|
|
|
$
|
55,514
|
|
|
$
|
90,583
|
|
|
$
|
1,056,394
|
|
Income (loss) from continuing operations before taxes
|
|
$
|
(254,884
|
)
|
|
$
|
(11,069
|
)
|
|
$
|
21,197
|
|
|
$
|
(244,756
|
)
|
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-lived assets
|
|
$
|
1,151,320
|
|
|
$
|
40,577
|
|
|
$
|
27,031
|
|
|
$
|
1,218,928
|
|
Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue by sale origin to external customers
|
|
$
|
1,647,176
|
|
|
$
|
86,250
|
|
|
$
|
101,489
|
|
|
$
|
1,834,915
|
|
Income (loss) from continuing operations before taxes
|
|
$
|
(9,802
|
)
|
|
$
|
(26,412
|
)
|
|
$
|
23,810
|
|
|
$
|
(12,404
|
)
|
December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-lived assets
|
|
$
|
1,477,336
|
|
|
$
|
47,170
|
|
|
$
|
23,470
|
|
|
$
|
1,547,976
|
|
|
|
|
(b) |
|
The segment operating results provided above represent amounts
for continuing operations as presented on the accompanying
statements of operations. Long-lived assets presented above
represent amounts associated with all operations as of the
periods then ended as indicated. Revenues from external
customers are assigned to geographic region based upon the
domicile of the subsidiary providing the services or products to
the customers. |
|
|
16.
|
Legal
matters and contingencies:
|
In the normal course of our business, we are a party to various
pending or threatened claims, lawsuits and administrative
proceedings seeking damages or other remedies concerning our
commercial operations, products, employees and other matters,
including warranty and product liability claims and occasional
claims by individuals alleging exposure to hazardous materials,
on the job injuries and fatalities as a result of our products
or operations. Many of the claims filed against us relate to
motor vehicle accidents which can result in the loss of life or
serious bodily injury. Some of these claims relate to matters
occurring prior to our acquisition of businesses. In certain
cases, we are entitled to indemnification from the sellers of
such businesses.
Although we cannot know or predict with certainty the outcome of
any claim or proceeding or the effect such outcomes may have on
us, we believe that any liability resulting from the resolution
of any of these matters, to the extent not otherwise provided
for or covered by insurance, will not have a material adverse
effect on our financial position, results of operations or
liquidity.
We have historically incurred additional insurance premium
related to a cost-sharing provision of our general liability
insurance policy, and we cannot be certain that we will not
incur additional costs until either existing claims become
further developed or until the limitation periods expire for
each respective policy year. Any such additional
98
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
premiums should not have a material adverse effect on our
financial position, results of operations or liquidity. We
incurred no additional premium related to this cost-sharing
provision of our general liability policy for the years ended
December 31, 2010, 2009 or 2008.
|
|
17.
|
Financial
instruments:
|
(a) Interest
rate risk:
We currently have little exposure to interest rate risks. At
December 31, 2010, 100% of our outstanding debt related to
the senior notes issued in December 2006 with a fixed interest
rate of 8%. We are exposed to variable interest rate impact
related to our outstanding letters of credit under our amended
credit facility, See Note 11, Long-term debt.
|
|
(b)
|
Foreign
currency rate risk:
|
We are exposed to foreign currency fluctuations in relation to
our foreign operations. Approximately 5% of our revenues from
continuing operations were derived from operations conducted in
Canadian dollars for the years ended December 31, 2010 and
2009. For our Canadian operations, we recorded net income from
continuing operations before taxes of $1,255 for the year ended
December 31, 2010 and a net loss from continuing operations
before taxes of $11,069 for the year ended December 31,
2009. Total assets denominated in Canadian dollars at
December 31, 2010 and 2009 were $71,842 and $59,343,
respectively.
A significant portion of our trade accounts receivable are from
companies in the oil and gas industry, and as such, we are
exposed to normal industry credit risks. We evaluate the
credit-worthiness of our major new and existing customers
financial condition and generally do not require collateral.
For the year ended December 31, 2010, we had two customers
who provided 12.2% and 10.7% of our total annual revenue. For
the year ended December 31, 2009, the same two customers
represented 9.9% and 9.7% of our revenue. We did not have
revenues from any single customer which amounted to 10% or more
of our total annual revenue for the year ended December 31,
2008.
|
|
18.
|
Commitments
and contingences:
|
We have non-cancelable operating lease commitments for equipment
and office space. These commitments for the next five years and
thereafter are as follows at December 31, 2010:
|
|
|
|
|
2011
|
|
$
|
27,287
|
|
2012
|
|
|
21,624
|
|
2013
|
|
|
17,538
|
|
2014
|
|
|
10,487
|
|
2015
|
|
|
4,954
|
|
Thereafter
|
|
|
11,055
|
|
|
|
|
|
|
|
|
$
|
92,945
|
|
|
|
|
|
|
We expensed operating lease payments totaling $31,595, $25,477
and $22,750 for the years ended December 31, 2010, 2009 and
2008, respectively.
99
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
19.
|
Related
party transactions:
|
We believe all transactions with related parties have terms and
conditions no less favorable to us than transactions with
unaffiliated parties.
We have entered into lease agreements for properties owned by
certain of our employees and former officers. The leases expire
at different times through December 2016. Total lease expense
pursuant to these leases was $2,993, $2,749 and $2,828 for the
years ended December 31, 2010, 2009 and 2008, respectively.
In connection with the Complete Energy Services, Inc.
(CES) acquisition of Hamm Co. in 2004, CES entered
into a certain Strategic Customer Relationship Agreement with
Continental Resources, Inc. (CRI). By virtue of the
Combination, through a subsidiary, we are now party to such
agreement. The agreement provides CRI the option to engage a
limited amount of our assets into a long-term contract at market
rates. Mr. Hamm is a majority owner of CRI and serves as a
member of our board of directors.
We provided services to companies that were majority-owned by
certain of our directors during 2010 which totaled $131,524, of
which $131,337 was sold to CRI and $187 was sold to other
companies. In 2009, these sales totaled $40,623, of which
$40,343 was sold to CRI, and $280 was sold to other companies
and in 2008, these sales totaled $61,194, of which $60,634 was
sold to CRI, and $560 was sold to other companies. We also
purchased services from companies that are majority-owned by
certain of our directors which totaled $556 in 2010, of which
$490 was purchased from CRI and $66 was purchased from other
companies. These purchases for 2009 totaled $1,423, of which
$1,191 was purchased from CRI and $232 was purchased from other
companies and in 2008, these purchases totaled $2,866, of which
$2,750 was purchased from CRI and $116 was purchased from other
companies. At December 31, 2010 and 2009, our trade
receivables included amounts from CRI of $50,048 and $5,957,
respectively, with no balance in trade payables for either of
these periods.
We provided services to companies majority-owned by certain of
our officers, or current or former officers of our subsidiaries,
for the years ended December 31, 2010, 2009 and 2008. In
2010, these sales totaled $4,065, of which $2,537 was sold to
HEP Oil (HEP), $21 was sold to Peak Oilfield and
$1,507 was sold to other companies. For 2009, these sales
totaled $3,552, of which $2,433 was sold to HEP, $9 was sold to
Peak Oilfield and $1,110 was sold to other companies. For 2008,
these sales totaled $11,256, of which $3,348 was sold to HEP,
$1,660 was sold to Cimarron, $3,513 was sold to Peak Oilfield
and $2,735 was sold to other companies. HEP, Cimarron and Peak
Oilfield are owned by a former officer of one of our
subsidiaries who resigned his position in late 2006 but
continued to provide consulting services through early 2007. We
also purchased services from companies majority-owned by certain
officers, or current or former officers of one of our
subsidiaries. For 2010, these purchases totaled $180,119, of
which $56,994 was purchased from Resource Transport, $40,245 was
purchased from Texas Specialty Sands, LLC primarily for the
purchase of sand used for pressure pumping activities, $31,552
was purchased from Ortowski Construction primarily related to
the manufacture of pressure pumping units, $30,217 was purchased
from ORTEQ Energy Services, a heavy equipment construction
company which also manufactures pressure pumping equipment,
$7,772 was purchased from ProFuel, $7,935 was purchased from
Wood Flowline Products, LLC $43 was purchased from Select Energy
Services LLC and affiliates and $5,361 was purchased from other
companies. For 2009, these purchases totaled $40,373, of which
$13,920 was purchased from Ortowski Construction, $12,005 was
purchased from Texas Specialty Sands, LLC, $3,302 was purchased
from Resource Transport, $2,642 was purchased from ProFuel,
$3,535 was purchased from Wood Flowline Products, LLC, $24 was
purchased from Select Energy Services LLC and affiliates and
$4,945 was purchased from other companies. For 2008, these
purchases totaled $61,708, of which $25,344 was purchased from
Ortowski Construction, $7,910 was purchased from Texas Specialty
Sands, LLC, $4,809 was purchased from Resource Transport, $5,601
was purchased from ProFuel, $16,595 was purchased from Select
Energy Services LLC and affiliates and $1,449 was purchased from
other companies. Ortowski Construction, ORTEQ Energy Services,
Texas Specialty Sands, LLC, Resource Transport, Pro Fuel and
Wood Flowline Products, LLC are owned by parties, one of whom is
a former employee, who are related to a current officer of a
subsidiary, or the officer himself. Select Energy Services LLC
is owned by a former officer of one of our subsidiaries who
purchased a disposal group from us during May 2008. Of the total
purchases
100
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
from Select Energy Services, LLC, $11,098 was purchased from the
businesses sold as part of this disposal group for the period
May 19, 2008 through December 31, 2008. At
December 31, 2010 and 2009, our trade receivables included
amounts from HEP of $310 and $270, respectively.
One of our Mexican subsidiaries, Servicios Petrotec de S.A. de
C.V., has purchased services from entities in which certain of
our current and former employees have ownership interests. We
purchased fluid transportation, industrial cleaning, pumping
equipment and safety equipment, totaling $1,575, $1,262 and
$1,485 for the years ended December 31, 2010, 2009 and
2008, respectively.
We provided services totaling $1,430, $1,012 and $1,697 for the
years ended December 31, 2010, 2009 and 2008, respectively,
to Laramie Energy LLC and Laramie Energy II (collectively
Laramie), companies for which one of our directors
serves as an officer. At December 31, 2010 and 2009, our
trade receivables included amounts due from Laramie totaling
$858 and $326, respectively.
For the years ended December 31, 2010, 2009 and 2008, we
provided services totaling $8,555, $3,613 and $9,468,
respectively, and purchased services totaling $3,456, $8,784 and
$14,108, respectively, from companies, or their affiliates, that
formerly employed our current officers or for customers on whose
board of directors or management team certain of our current
directors serve.
We paid $3,450 in May 2009 pursuant to subordinated note
agreements with certain employees, including former officers of
subsidiaries, related to promissory notes issued in conjunction
with 2005 and 2004 business acquisitions.
Premier Integrated Technologies Ltd. (PIT), an
affiliate of IPS, purchased $3,823, $2,427 and $1,493 of
machining services from a company controlled by employees of PIT
during the years ended December 31, 2010, 2009 and 2008,
respectively.
On May 19, 2008, we sold certain business assets located
primarily in north Texas which included our product supply
stores, certain drilling logistics assets and other completion
and production services assets to Select Energy Services,
L.L.C., an oilfield service company located in Gainesville,
Texas which is partially owned by Mr. Schmitz who resigned
as an officer of one of our subsidiaries in late 2006. The
proceeds from the sale totaled $50,150 in cash and we received
assets with a fair market value of $7,987. We recorded a loss of
$6,935 associated with the sale of this disposal group, and we
will provide certain administrative functions for a period of
one year at an
agreed-upon
rate. For the period May 20, 2008 through December 31,
2008, we sold services totaling $1,509 and purchased products
and services totaling $11,098 from these former subsidiaries.
See Note 14, Discontinued operations. At
December 31, 2010, our trade receivables and payables
included amounts related to these disposed businesses which
totaled $7 and $177, respectively and at December 31, 2009,
our trade receivables and payables included amounts related to
these disposed businesses which totaled $21 and $295,
respectively.
Effective January 1, 2009, we adopted and established (and
subsequently amended and restated for compliance and other
issues) the Complete Production Services, Inc. Deferred
Compensation Plan, whereby eligible participants, including
members of senior management, non-employee directors and certain
highly-compensated individuals, could defer up to 90% of their
compensation and up to 90% of the employees annual
incentive bonus, or 100% of director compensation for services
rendered, into various investment options pre-tax. For amounts
deferred, we will match the contribution
dollar-for-dollar
up to four percent of compensation minus $3.3, and we may make
other discretionary contributions pursuant to resolutions of
this plans administrative committee. Participants
immediately vest in amounts deferred as well as any matching or
discretionary contributions we make. Participants bear the risk
of loss associated with investment gains or losses. We intend
that this plan will meet all the requirements necessary to be a
nonqualified, unfunded, unsecured plan of deferred compensation
within the meaning of Sections 201(2), 301(a)(3) and
401(a)(1) of the Employee Retirement Income Security Act of
1974, as amended. We have recorded an asset and corresponding
liability totaling $882 related to the rabbi trust associated
101
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
with our deferred compensation plan. For the years ended
December 31, 2010 and 2009, we expensed an insignificant
amount related to matching contributions associated with this
deferred compensation plan.
We maintain defined contribution retirement plans for
substantially all of our U.S. and Canadian employees who
have completed six months of service. Employees may voluntarily
contribute up to a maximum percentage of their salaries to these
plans subject to certain statutory maximum dollar values. The
employer contributions vest immediately with respect to the
Canadian RRSP plan and U.S. 401(k) plan. In response to
market conditions, effective May 1, 2009, we amended our
401(k) plan and deferred compensation plan to suspend matching
contributions to such plans through December 31, 2010. We
re-instated our matching contribution in 2011, see Note 24,
Subsequent events.
We expensed $436, $2,231 and $6,101 related to our various
defined contribution plans for the years ended December 31,
2010, 2009 and 2008, respectively.
We provide a seniority premium benefit to substantially all of
our Mexican employees, through a subsidiary, in accordance with
Mexican law. The benefit consists of a one-time payment
equivalent to
12-days
wages for each year of service (calculated at the
employees current wage rate but not exceeding twice the
minimum wage), payable upon voluntary termination after fifteen
years of service, involuntary termination or death. In addition,
we provide statutory mandated severance benefits to
substantially all Mexican employees, which includes a one-time
payment of three months wages, plus
20-days
wages for each year of service, payable upon involuntary
termination without cause and charged to income as incurred. We
accrued $1,249 and $1,604 at December 31, 2010 and 2009,
respectively, related to our liability under this benefit
arrangement in Mexico.
|
|
21.
|
Unaudited
selected quarterly data:
|
The following table presents selected quarterly financial data
for the years ended December 31, 2010 and 2009 (unaudited,
in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 Quarter Ended
|
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
Revenues
|
|
$
|
309,704
|
|
|
$
|
360,245
|
|
|
$
|
418,609
|
|
|
$
|
472,835
|
|
Operating income
|
|
$
|
10,589
|
|
|
$
|
39,869
|
|
|
$
|
68,181
|
|
|
$
|
74,446
|
|
Net income (loss)
|
|
$
|
(2,762
|
)
|
|
$
|
15,671
|
|
|
$
|
33,030
|
|
|
$
|
38,219
|
|
Earnings (loss) per share(a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.04
|
)
|
|
$
|
0.21
|
|
|
$
|
0.43
|
|
|
$
|
0.50
|
|
Diluted
|
|
$
|
(0.04
|
)
|
|
$
|
0.20
|
|
|
$
|
0.42
|
|
|
$
|
0.49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 Quarter Ended
|
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
Revenues
|
|
$
|
336,681
|
|
|
$
|
238,398
|
|
|
$
|
229,913
|
|
|
$
|
251,402
|
|
Operating income (loss)
|
|
$
|
14,006
|
|
|
$
|
(22,902
|
)
|
|
$
|
(64,132
|
)
|
|
$
|
(114,384
|
)
|
Net loss
|
|
$
|
(336
|
)
|
|
$
|
(25,832
|
)
|
|
$
|
(52,025
|
)
|
|
$
|
(103,475
|
)
|
Loss per share(a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.00
|
|
|
$
|
(0.34
|
)
|
|
$
|
(0.69
|
)
|
|
$
|
(1.38
|
)
|
Diluted
|
|
$
|
0.00
|
|
|
$
|
(0.34
|
)
|
|
$
|
(0.69
|
)
|
|
$
|
(1.38
|
)
|
|
|
|
(a) |
|
Quarterly earnings per share amounts were calculated based upon
the weighted average number of shares outstanding for the
applicable quarter. Therefore the sum of the quarterly earnings
per share results may not agree to earnings per share for the
year in the accompanying Statements of Operations, as the annual
results were calculated based upon the weighted average number
of shares outstanding for the year. |
102
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
22.
|
Guarantor
and non-guarantor condensed consolidating financial
statements:
|
The following tables present the financial data required by SEC
Regulation S-X
Rule 3-10(f)
related to condensed consolidating financial statements, and
includes the following: (1) condensed consolidating balance
sheets for the years ended December 31, 2010 and 2009;
(2) condensed consolidating statements of operations for
the years ended December 31, 2010, 2009 and 2008; and
(3) condensed consolidating statements of cash flows for
the years ended December 31, 2010, 2009 and 2008.
Condensed
Consolidating Balance Sheet
December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-guarantor
|
|
|
Eliminations/
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Reclassifications
|
|
|
Consolidated
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
111,834
|
|
|
$
|
569
|
|
|
$
|
31,046
|
|
|
$
|
(16,768
|
)
|
|
$
|
126,681
|
|
Accounts receivable, net
|
|
|
696
|
|
|
|
313,936
|
|
|
|
31,016
|
|
|
|
|
|
|
|
345,648
|
|
Inventory, net
|
|
|
|
|
|
|
21,935
|
|
|
|
11,601
|
|
|
|
|
|
|
|
33,536
|
|
Prepaid expenses
|
|
|
6,388
|
|
|
|
10,980
|
|
|
|
1,332
|
|
|
|
|
|
|
|
18,700
|
|
Income tax receivable
|
|
|
10,164
|
|
|
|
13,298
|
|
|
|
|
|
|
|
|
|
|
|
23,462
|
|
Current deferred tax assets
|
|
|
2,499
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,499
|
|
Other current assets
|
|
|
882
|
|
|
|
502
|
|
|
|
|
|
|
|
|
|
|
|
1,384
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
132,463
|
|
|
|
361,220
|
|
|
|
74,995
|
|
|
|
(16,768
|
)
|
|
|
551,910
|
|
Property, plant and equipment, net
|
|
|
4,730
|
|
|
|
898,013
|
|
|
|
53,285
|
|
|
|
|
|
|
|
956,028
|
|
Investment in consolidated subsidiaries
|
|
|
930,631
|
|
|
|
115,449
|
|
|
|
|
|
|
|
(1,046,080
|
)
|
|
|
|
|
Inter-company receivable
|
|
|
554,482
|
|
|
|
|
|
|
|
445
|
|
|
|
(554,927
|
)
|
|
|
|
|
Goodwill
|
|
|
15,531
|
|
|
|
232,144
|
|
|
|
2,858
|
|
|
|
|
|
|
|
250,533
|
|
Other long-term assets, net
|
|
|
29,966
|
|
|
|
10,161
|
|
|
|
1,978
|
|
|
|
|
|
|
|
42,105
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,667,803
|
|
|
$
|
1,616,987
|
|
|
$
|
133,561
|
|
|
$
|
(1,617,775
|
)
|
|
$
|
1,800,576
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
376
|
|
|
$
|
82,952
|
|
|
$
|
8,539
|
|
|
$
|
(16,768
|
)
|
|
$
|
75,099
|
|
Accrued liabilities
|
|
|
18,269
|
|
|
|
21,355
|
|
|
|
4,667
|
|
|
|
|
|
|
|
44,291
|
|
Accrued payroll and payroll burdens
|
|
|
4,353
|
|
|
|
19,325
|
|
|
|
2,890
|
|
|
|
|
|
|
|
26,568
|
|
Accrued interest
|
|
|
2,439
|
|
|
|
1
|
|
|
|
6
|
|
|
|
|
|
|
|
2,446
|
|
Income taxes payable
|
|
|
(1,043
|
)
|
|
|
|
|
|
|
1,043
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
24,394
|
|
|
|
123,633
|
|
|
|
17,145
|
|
|
|
(16,768
|
)
|
|
|
148,404
|
|
Long-term debt
|
|
|
650,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
650,000
|
|
Inter-company payable
|
|
|
|
|
|
|
553,907
|
|
|
|
1,020
|
|
|
|
(554,927
|
)
|
|
|
|
|
Deferred income taxes
|
|
|
186,693
|
|
|
|
3,794
|
|
|
|
(65
|
)
|
|
|
|
|
|
|
190,422
|
|
Other long-term liabilities
|
|
|
882
|
|
|
|
5,022
|
|
|
|
12
|
|
|
|
|
|
|
|
5,916
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
861,969
|
|
|
|
686,356
|
|
|
|
18,112
|
|
|
|
(571,695
|
)
|
|
|
994,742
|
|
Stockholders equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
805,834
|
|
|
|
930,631
|
|
|
|
115,449
|
|
|
|
(1,046,080
|
)
|
|
|
805,834
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
1,667,803
|
|
|
$
|
1,616,987
|
|
|
$
|
133,561
|
|
|
$
|
(1,617,775
|
)
|
|
$
|
1,800,576
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
103
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Condensed
Consolidating Balance Sheet
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-guarantor
|
|
|
Eliminations/
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Reclassifications
|
|
|
Consolidated
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
64,871
|
|
|
$
|
519
|
|
|
$
|
17,001
|
|
|
$
|
(5,031
|
)
|
|
$
|
77,360
|
|
Accounts receivable, net
|
|
|
610
|
|
|
|
143,135
|
|
|
|
27,539
|
|
|
|
|
|
|
|
171,284
|
|
Inventory, net
|
|
|
|
|
|
|
23,001
|
|
|
|
14,463
|
|
|
|
|
|
|
|
37,464
|
|
Prepaid expenses
|
|
|
3,897
|
|
|
|
13,052
|
|
|
|
994
|
|
|
|
|
|
|
|
17,943
|
|
Income tax receivable
|
|
|
35,404
|
|
|
|
20,201
|
|
|
|
2,001
|
|
|
|
|
|
|
|
57,606
|
|
Current deferred tax assets
|
|
|
8,158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,158
|
|
Other current assets
|
|
|
|
|
|
|
111
|
|
|
|
|
|
|
|
|
|
|
|
111
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
112,940
|
|
|
|
200,019
|
|
|
|
61,998
|
|
|
|
(5,031
|
)
|
|
|
369,926
|
|
Property, plant and equipment, net
|
|
|
4,222
|
|
|
|
876,304
|
|
|
|
60,607
|
|
|
|
|
|
|
|
941,133
|
|
Investment in consolidated subsidiaries
|
|
|
755,435
|
|
|
|
104,974
|
|
|
|
|
|
|
|
(860,409
|
)
|
|
|
|
|
Inter-company receivable
|
|
|
607,325
|
|
|
|
|
|
|
|
|
|
|
|
(607,325
|
)
|
|
|
|
|
Goodwill
|
|
|
15,531
|
|
|
|
225,434
|
|
|
|
2,858
|
|
|
|
|
|
|
|
243,823
|
|
Other long-term assets, net
|
|
|
16,026
|
|
|
|
13,803
|
|
|
|
4,143
|
|
|
|
|
|
|
|
33,972
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,511,479
|
|
|
$
|
1,420,534
|
|
|
$
|
129,606
|
|
|
$
|
(1,472,765
|
)
|
|
$
|
1,588,854
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
$
|
|
|
|
$
|
228
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
228
|
|
Accounts payable
|
|
|
445
|
|
|
|
30,028
|
|
|
|
6,303
|
|
|
|
(5,031
|
)
|
|
|
31,745
|
|
Accrued liabilities
|
|
|
14,064
|
|
|
|
18,257
|
|
|
|
8,781
|
|
|
|
|
|
|
|
41,102
|
|
Accrued payroll and payroll burdens
|
|
|
388
|
|
|
|
10,847
|
|
|
|
2,324
|
|
|
|
|
|
|
|
13,559
|
|
Accrued interest
|
|
|
3,198
|
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
3,206
|
|
Notes payable
|
|
|
1,068
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
1,069
|
|
Income taxes payable
|
|
|
|
|
|
|
|
|
|
|
813
|
|
|
|
|
|
|
|
813
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
19,163
|
|
|
|
59,361
|
|
|
|
18,229
|
|
|
|
(5,031
|
)
|
|
|
91,722
|
|
Long-term debt
|
|
|
650,000
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
650,002
|
|
Inter-company payable
|
|
|
|
|
|
|
601,947
|
|
|
|
5,378
|
|
|
|
(607,325
|
)
|
|
|
|
|
Deferred income taxes
|
|
|
143,427
|
|
|
|
3,793
|
|
|
|
1,020
|
|
|
|
|
|
|
|
148,240
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
812,590
|
|
|
|
665,101
|
|
|
|
24,629
|
|
|
|
(612,356
|
)
|
|
|
889,964
|
|
Stockholders equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
698,889
|
|
|
|
755,433
|
|
|
|
104,977
|
|
|
|
(860,409
|
)
|
|
|
698,890
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
1,511,479
|
|
|
$
|
1,420,534
|
|
|
$
|
129,606
|
|
|
$
|
(1,472,765
|
)
|
|
$
|
1,588,854
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
104
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Condensed
Consolidated Statement of Operations
Year Ended December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-guarantor
|
|
|
Eliminations/
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Reclassifications
|
|
|
Consolidated
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
|
|
$
|
|
|
|
$
|
1,401,665
|
|
|
$
|
132,774
|
|
|
$
|
(6,821
|
)
|
|
$
|
1,527,618
|
|
Product
|
|
|
|
|
|
|
3,247
|
|
|
|
30,528
|
|
|
|
|
|
|
|
33,775
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,404,912
|
|
|
|
163,302
|
|
|
|
(6,821
|
)
|
|
|
1,561,393
|
|
Service expenses
|
|
|
|
|
|
|
889,862
|
|
|
|
102,052
|
|
|
|
(6,821
|
)
|
|
|
985,093
|
|
Product expenses
|
|
|
|
|
|
|
3,452
|
|
|
|
22,495
|
|
|
|
|
|
|
|
25,947
|
|
Selling, general and administrative expenses
|
|
|
39,090
|
|
|
|
122,189
|
|
|
|
14,166
|
|
|
|
|
|
|
|
175,445
|
|
Depreciation and amortization
|
|
|
1,354
|
|
|
|
168,104
|
|
|
|
12,365
|
|
|
|
|
|
|
|
181,823
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before interest and taxes
|
|
|
(40,444
|
)
|
|
|
221,305
|
|
|
|
12,224
|
|
|
|
|
|
|
|
193,085
|
|
Interest expense
|
|
|
58,132
|
|
|
|
5,653
|
|
|
|
105
|
|
|
|
(6,221
|
)
|
|
|
57,669
|
|
Interest income
|
|
|
(6,511
|
)
|
|
|
(8
|
)
|
|
|
(24
|
)
|
|
|
6,221
|
|
|
|
(322
|
)
|
Equity in earnings of consolidated affiliates
|
|
|
(140,929
|
)
|
|
|
(8,926
|
)
|
|
|
|
|
|
|
149,855
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before taxes
|
|
|
48,864
|
|
|
|
224,586
|
|
|
|
12,143
|
|
|
|
(149,855
|
)
|
|
|
135,738
|
|
Taxes
|
|
|
(35,294
|
)
|
|
|
83,657
|
|
|
|
3,217
|
|
|
|
|
|
|
|
51,580
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
84,158
|
|
|
$
|
140,929
|
|
|
$
|
8,926
|
|
|
$
|
(149,855
|
)
|
|
$
|
84,158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
105
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Condensed
Consolidated Statement of Operations
Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-guarantor
|
|
|
Eliminations/
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Reclassifications
|
|
|
Consolidated
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
|
|
$
|
|
|
|
$
|
902,157
|
|
|
$
|
115,768
|
|
|
$
|
(5,612
|
)
|
|
$
|
1,012,313
|
|
Product
|
|
|
|
|
|
|
13,752
|
|
|
|
30,329
|
|
|
|
|
|
|
|
44,081
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
915,909
|
|
|
|
146,097
|
|
|
|
(5,612
|
)
|
|
|
1,056,394
|
|
Service expenses
|
|
|
|
|
|
|
613,823
|
|
|
|
83,953
|
|
|
|
(5,612
|
)
|
|
|
692,164
|
|
Product expenses
|
|
|
|
|
|
|
13,273
|
|
|
|
19,928
|
|
|
|
|
|
|
|
33,201
|
|
Selling, general and administrative expenses
|
|
|
33,785
|
|
|
|
129,240
|
|
|
|
18,395
|
|
|
|
|
|
|
|
181,420
|
|
Depreciation and amortization
|
|
|
1,602
|
|
|
|
185,601
|
|
|
|
13,529
|
|
|
|
|
|
|
|
200,732
|
|
Fixed asset and other intangibles impairment loss
|
|
|
|
|
|
|
38,646
|
|
|
|
|
|
|
|
|
|
|
|
38,646
|
|
Goodwill impairment loss
|
|
|
|
|
|
|
97,643
|
|
|
|
|
|
|
|
|
|
|
|
97,643
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before interest and taxes
|
|
|
(35,387
|
)
|
|
|
(162,317
|
)
|
|
|
10,292
|
|
|
|
|
|
|
|
(187,412
|
)
|
Interest expense
|
|
|
56,955
|
|
|
|
6,713
|
|
|
|
177
|
|
|
|
(6,950
|
)
|
|
|
56,895
|
|
Interest income
|
|
|
(7,010
|
)
|
|
|
(6
|
)
|
|
|
(13
|
)
|
|
|
6,950
|
|
|
|
(79
|
)
|
Write-off of deferred financing costs
|
|
|
528
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
528
|
|
Equity in earnings of consolidated affiliates
|
|
|
133,340
|
|
|
|
(8,846
|
)
|
|
|
|
|
|
|
(124,494
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before taxes
|
|
|
(219,200
|
)
|
|
|
(160,178
|
)
|
|
|
10,128
|
|
|
|
124,494
|
|
|
|
(244,756
|
)
|
Taxes
|
|
|
(37,532
|
)
|
|
|
(26,838
|
)
|
|
|
1,282
|
|
|
|
|
|
|
|
(63,088
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(181,668
|
)
|
|
$
|
(133,340
|
)
|
|
$
|
8,846
|
|
|
$
|
124,494
|
|
|
$
|
(181,668
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
106
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Condensed
Consolidated Statement of Operations
Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-guarantor
|
|
|
Eliminations/
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Reclassifications
|
|
|
Consolidated
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
|
|
$
|
|
|
|
$
|
1,637,755
|
|
|
$
|
142,625
|
|
|
$
|
(4,567
|
)
|
|
$
|
1,775,813
|
|
Product
|
|
|
|
|
|
|
13,988
|
|
|
|
45,114
|
|
|
|
|
|
|
|
59,102
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,651,743
|
|
|
|
187,739
|
|
|
|
(4,567
|
)
|
|
|
1,834,915
|
|
Service expenses
|
|
|
|
|
|
|
997,184
|
|
|
|
101,957
|
|
|
|
(4,567
|
)
|
|
|
1,094,574
|
|
Product expenses
|
|
|
|
|
|
|
11,507
|
|
|
|
30,407
|
|
|
|
|
|
|
|
41,914
|
|
Selling, general and administrative expenses
|
|
|
38,293
|
|
|
|
142,615
|
|
|
|
17,292
|
|
|
|
|
|
|
|
198,200
|
|
Depreciation and amortization
|
|
|
1,516
|
|
|
|
165,065
|
|
|
|
14,616
|
|
|
|
|
|
|
|
181,197
|
|
Impairment charge
|
|
|
27,670
|
|
|
|
218,500
|
|
|
|
25,836
|
|
|
|
|
|
|
|
272,006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before interest and
taxes
|
|
|
(67,479
|
)
|
|
|
116,872
|
|
|
|
(2,369
|
)
|
|
|
|
|
|
|
47,024
|
|
Interest expense
|
|
|
62,247
|
|
|
|
10,939
|
|
|
|
634
|
|
|
|
(14,091
|
)
|
|
|
59,729
|
|
Interest income
|
|
|
(14,245
|
)
|
|
|
(13
|
)
|
|
|
(134
|
)
|
|
|
14,091
|
|
|
|
(301
|
)
|
Equity in earnings of consolidated affiliates
|
|
|
10,431
|
|
|
|
8,111
|
|
|
|
|
|
|
|
(18,542
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before taxes
|
|
|
(125,912
|
)
|
|
|
97,835
|
|
|
|
(2,869
|
)
|
|
|
18,542
|
|
|
|
(12,404
|
)
|
Taxes
|
|
|
(40,457
|
)
|
|
|
107,520
|
|
|
|
5,242
|
|
|
|
|
|
|
|
72,305
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
|
(85,455
|
)
|
|
|
(9,685
|
)
|
|
|
(8,111
|
)
|
|
|
18,542
|
|
|
|
(84,709
|
)
|
Discontinued operations (net of tax)
|
|
|
|
|
|
|
(4,859
|
)
|
|
|
|
|
|
|
|
|
|
|
(4,859
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(85,455
|
)
|
|
$
|
(14,544
|
)
|
|
$
|
(8,111
|
)
|
|
$
|
18,542
|
|
|
$
|
(89,568
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
107
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Condensed
Consolidated Statement of Cash Flows
Year Ended December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-guarantor
|
|
|
Eliminations/
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Reclassifications
|
|
|
Consolidated
|
|
|
Cash provided by:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
84,158
|
|
|
$
|
140,929
|
|
|
$
|
8,926
|
|
|
$
|
(149,855
|
)
|
|
$
|
84,158
|
|
Items not affecting cash:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in loss of consolidated affiliates
|
|
|
(140,929
|
)
|
|
|
(8,926
|
)
|
|
|
|
|
|
|
149,855
|
|
|
|
|
|
Depreciation and amortization
|
|
|
1,354
|
|
|
|
168,104
|
|
|
|
12,365
|
|
|
|
|
|
|
|
181,823
|
|
Other
|
|
|
15,066
|
|
|
|
50,422
|
|
|
|
(632
|
)
|
|
|
|
|
|
|
64,856
|
|
Changes in operating assets and liabilities, net of effect of
acquisitions
|
|
|
30,112
|
|
|
|
(134,999
|
)
|
|
|
1,500
|
|
|
|
(11,292
|
)
|
|
|
(114,679
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
|
(10,239
|
)
|
|
|
215,530
|
|
|
|
22,159
|
|
|
|
(11,292
|
)
|
|
|
216,158
|
|
Investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to property, plant and equipment
|
|
|
(1,862
|
)
|
|
|
(138,808
|
)
|
|
|
(4,353
|
)
|
|
|
|
|
|
|
(145,023
|
)
|
Inter-company receipts
|
|
|
52,843
|
|
|
|
|
|
|
|
|
|
|
|
(52,843
|
)
|
|
|
|
|
Business acquisitions, net of cash acquired
|
|
|
|
|
|
|
(33,721
|
)
|
|
|
|
|
|
|
|
|
|
|
(33,721
|
)
|
Proceeds from sale of fixed assets
|
|
|
|
|
|
|
5,317
|
|
|
|
165
|
|
|
|
|
|
|
|
5,482
|
|
Other
|
|
|
(826
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(826
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used for) investing activities
|
|
|
50,155
|
|
|
|
(167,212
|
)
|
|
|
(4,188
|
)
|
|
|
(52,843
|
)
|
|
|
(174,088
|
)
|
Financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Repayments of long-term debt
|
|
|
|
|
|
|
(228
|
)
|
|
|
(2
|
)
|
|
|
|
|
|
|
(230
|
)
|
Repayments of notes payable
|
|
|
(1,069
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,069
|
)
|
Inter-company borrowings (repayments)
|
|
|
|
|
|
|
(48,040
|
)
|
|
|
(4,358
|
)
|
|
|
52,398
|
|
|
|
|
|
Proceeds from issuances of common stock
|
|
|
8,082
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,082
|
|
Treasury stock purchased
|
|
|
(1,431
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,431
|
)
|
Other
|
|
|
1,465
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,465
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
7,047
|
|
|
|
(48,268
|
)
|
|
|
(4,360
|
)
|
|
|
52,398
|
|
|
|
6,817
|
|
Effect of exchange rate changes on cash
|
|
|
|
|
|
|
|
|
|
|
434
|
|
|
|
|
|
|
|
434
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cash and cash equivalents
|
|
|
46,963
|
|
|
|
50
|
|
|
|
14,045
|
|
|
|
(11,737
|
)
|
|
|
49,321
|
|
Cash and cash equivalents, beginning of period
|
|
|
64,871
|
|
|
|
519
|
|
|
|
17,001
|
|
|
|
(5,031
|
)
|
|
|
77,360
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
111,834
|
|
|
$
|
569
|
|
|
$
|
31,046
|
|
|
$
|
(16,768
|
)
|
|
$
|
126,681
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
108
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Condensed
Consolidated Statement of Cash Flows
Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-guarantor
|
|
|
Eliminations/
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Reclassifications
|
|
|
Consolidated
|
|
|
Cash provided by:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(181,668
|
)
|
|
$
|
(133,340
|
)
|
|
$
|
8,846
|
|
|
$
|
124,494
|
|
|
$
|
(181,668
|
)
|
Items not affecting cash:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in loss of consolidated affiliates
|
|
|
133,340
|
|
|
|
(8,846
|
)
|
|
|
|
|
|
|
(124,494
|
)
|
|
|
|
|
Depreciation and amortization
|
|
|
1,602
|
|
|
|
185,601
|
|
|
|
13,529
|
|
|
|
|
|
|
|
200,732
|
|
Fixed asset and other intangibles impairment loss
|
|
|
|
|
|
|
38,646
|
|
|
|
|
|
|
|
|
|
|
|
38,646
|
|
Goodwill impairment loss
|
|
|
|
|
|
|
97,643
|
|
|
|
|
|
|
|
|
|
|
|
97,643
|
|
Other
|
|
|
14,603
|
|
|
|
14,658
|
|
|
|
3,697
|
|
|
|
|
|
|
|
32,958
|
|
Changes in operating assets and liabilities
|
|
|
96,585
|
|
|
|
1,758
|
|
|
|
(8,742
|
)
|
|
|
7,292
|
|
|
|
96,893
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
64,462
|
|
|
|
196,120
|
|
|
|
17,330
|
|
|
|
7,292
|
|
|
|
285,204
|
|
Investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to property, plant and equipment
|
|
|
(649
|
)
|
|
|
(32,431
|
)
|
|
|
(4,351
|
)
|
|
|
|
|
|
|
(37,431
|
)
|
Inter-company receipts
|
|
|
172,228
|
|
|
|
(502
|
)
|
|
|
|
|
|
|
(171,726
|
)
|
|
|
|
|
Proceeds from sale of fixed assets
|
|
|
|
|
|
|
19,996
|
|
|
|
804
|
|
|
|
|
|
|
|
20,800
|
|
Other
|
|
|
|
|
|
|
(1,497
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,497
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used for) investing activities
|
|
|
171,579
|
|
|
|
(14,434
|
)
|
|
|
(3,547
|
)
|
|
|
(171,726
|
)
|
|
|
(18,128
|
)
|
Financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuances of long-term debt
|
|
|
1,635
|
|
|
|
|
|
|
|
1,559
|
|
|
|
|
|
|
|
3,194
|
|
Repayments of long-term debt
|
|
|
(187,628
|
)
|
|
|
(3,907
|
)
|
|
|
(9,074
|
)
|
|
|
|
|
|
|
(200,609
|
)
|
Repayments of notes payable
|
|
|
(8,244
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,244
|
)
|
Inter-company borrowings (repayments)
|
|
|
|
|
|
|
(177,606
|
)
|
|
|
5,880
|
|
|
|
171,726
|
|
|
|
|
|
Proceeds from issuances of common stock
|
|
|
496
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
496
|
|
Treasury stock purchased
|
|
|
(132
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(132
|
)
|
Deferred financing fees
|
|
|
(2,911
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,911
|
)
|
Other
|
|
|
215
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
215
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
(196,569
|
)
|
|
|
(181,513
|
)
|
|
|
(1,635
|
)
|
|
|
171,726
|
|
|
|
(207,991
|
)
|
Effect of exchange rate changes on cash
|
|
|
|
|
|
|
|
|
|
|
(225
|
)
|
|
|
|
|
|
|
(225
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cash and cash equivalents
|
|
|
39,472
|
|
|
|
173
|
|
|
|
11,923
|
|
|
|
7,292
|
|
|
|
58,860
|
|
Cash and cash equivalents, beginning of period
|
|
|
25,399
|
|
|
|
346
|
|
|
|
5,078
|
|
|
|
(12,323
|
)
|
|
|
18,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
64,871
|
|
|
$
|
519
|
|
|
$
|
17,001
|
|
|
$
|
(5,031
|
)
|
|
$
|
77,360
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
109
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
Condensed
Consolidated Statement of Cash Flows
Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-guarantor
|
|
|
Eliminations/
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Reclassifications
|
|
|
Consolidated
|
|
|
Cash provided by:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(89,568
|
)
|
|
$
|
(14,544
|
)
|
|
$
|
(8,111
|
)
|
|
$
|
22,655
|
|
|
$
|
(89,568
|
)
|
Items not affecting cash:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in loss of consolidated affiliates
|
|
|
14,544
|
|
|
|
8,111
|
|
|
|
|
|
|
|
(22,655
|
)
|
|
|
|
|
Depreciation and amortization
|
|
|
1,516
|
|
|
|
167,059
|
|
|
|
14,616
|
|
|
|
|
|
|
|
183,191
|
|
Impairment charge
|
|
|
27,670
|
|
|
|
218,500
|
|
|
|
25,836
|
|
|
|
|
|
|
|
272,006
|
|
Other
|
|
|
5,182
|
|
|
|
35,204
|
|
|
|
680
|
|
|
|
|
|
|
|
41,066
|
|
Changes in operating assets and liabilities, net of effect of
acquisitions
|
|
|
(61,520
|
)
|
|
|
18,953
|
|
|
|
(8,143
|
)
|
|
|
(5,576
|
)
|
|
|
(56,286
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
|
(102,176
|
)
|
|
|
433,283
|
|
|
|
24,878
|
|
|
|
(5,576
|
)
|
|
|
350,409
|
|
Investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Business acquisitions, net of cash acquired
|
|
|
|
|
|
|
(180,154
|
)
|
|
|
|
|
|
|
|
|
|
|
(180,154
|
)
|
Additions to property, plant and equipment
|
|
|
(1,632
|
)
|
|
|
(229,307
|
)
|
|
|
(22,837
|
)
|
|
|
|
|
|
|
(253,776
|
)
|
Inter-company receipts
|
|
|
87,395
|
|
|
|
|
|
|
|
|
|
|
|
(87,395
|
)
|
|
|
|
|
Proceeds from sale of disposal group
|
|
|
|
|
|
|
50,150
|
|
|
|
|
|
|
|
|
|
|
|
50,150
|
|
Other
|
|
|
|
|
|
|
9,369
|
|
|
|
313
|
|
|
|
|
|
|
|
9,682
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used for) investing activities
|
|
|
85,763
|
|
|
|
(349,942
|
)
|
|
|
(22,524
|
)
|
|
|
(87,395
|
)
|
|
|
(374,098
|
)
|
Financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuances of long-term debt
|
|
|
341,043
|
|
|
|
|
|
|
|
9,072
|
|
|
|
|
|
|
|
350,115
|
|
Repayments of long-term debt
|
|
|
(314,605
|
)
|
|
|
(814
|
)
|
|
|
(13,863
|
)
|
|
|
|
|
|
|
(329,282
|
)
|
Repayments of notes payable
|
|
|
(14,001
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14,001
|
)
|
Inter-company borrowings (repayments)
|
|
|
|
|
|
|
(87,140
|
)
|
|
|
(255
|
)
|
|
|
87,395
|
|
|
|
|
|
Proceeds from issuances of common stock
|
|
|
12,014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,014
|
|
Other
|
|
|
9,144
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,144
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
33,595
|
|
|
|
(87,954
|
)
|
|
|
(5,046
|
)
|
|
|
87,395
|
|
|
|
27,990
|
|
Effect of exchange rate changes on cash
|
|
|
|
|
|
|
|
|
|
|
1,165
|
|
|
|
|
|
|
|
1,165
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cash and cash equivalents
|
|
|
17,182
|
|
|
|
(4,613
|
)
|
|
|
(1,527
|
)
|
|
|
(5,576
|
)
|
|
|
5,466
|
|
Cash and cash equivalents, beginning of period
|
|
|
8,217
|
|
|
|
4,959
|
|
|
|
6,605
|
|
|
|
(6,747
|
)
|
|
|
13,034
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
25,399
|
|
|
$
|
346
|
|
|
$
|
5,078
|
|
|
$
|
(12,323
|
)
|
|
$
|
18,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23.
|
Recent
accounting pronouncements and authoritative
literature:
|
The FASB has addressed the issue of business combinations during
recent years. In December 2007, the FASB issued guidance
regarding business combinations that substantially replaced
previously existing guidance, while maintaining the precepts
prescribed therein, and further requiring that all assets and
liabilities and non-controlling interests of an acquired
business be measured at their fair value, with limited
exceptions, including the recognition of acquisition-related
costs and anticipated restructuring costs separate from the
acquired net assets. In addition, entities must recognize
pre-acquisition contingencies, as well as assets and liabilities
assumed arising from contractual contingencies as of the
acquisition date, measured at acquisition-date fair values, and
must recognize all other contractual contingencies as of the
acquisition date, measured at their acquisition-date fair values
only if it is more likely than not that these contingencies meet
the definition of an asset or liability. In addition, this
standard provides guidance for measuring goodwill and recording
a bargain purchase, defined as a business combination in which
total acquisition-date fair value of the identifiable net assets
acquired exceeds the fair value of the consideration transferred
plus any non-controlling interest in the acquiree, and states
that the acquiring
110
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
entity must recognize that excess in earnings as a gain
attributable to the acquirer. The FASB amended this guidance in
April 2009 as it relates to accounting for assets and
liabilities assumed in a business combination which arise from
contingencies. This amendment requires that contingent assets
acquired and liabilities assumed in a business combination to be
recognized at fair value on the acquisition date if fair value
can be reasonably estimated during the measurement period. If
fair value cannot be reasonably estimated during the measurement
period, the contingent asset or liability would be recognized as
a contingency, in accordance with existing U.S. GAAP, with
reasonable estimation of the amount of loss, if any. This
amendment also eliminated the specific subsequent accounting
guidance for contingent assets and liabilities, without
significantly revising the original guidance. However,
contingent consideration arrangements of an acquiree assumed by
the acquirer in a business combination would still be initially
and subsequently measured at fair value. We originally adopted
the revised guidance for business combinations when it became
effective on January 1, 2009, and the amendment thereto,
subsequently in 2009. In December 2010, the FASB updated this
guidance to require each public entity that presents comparative
financial statements to disclose the revenue and earnings of the
combined entity as if the business combination that occurred
during the current year had occurred as of the beginning of the
comparable prior annual reporting period only. In addition, this
amendment expands the supplemental pro forma disclosures related
to such a business combination to include a description of the
nature and amount of material, nonrecurring pro forma
adjustments directly attributable to the business combination
included in the reported pro forma revenue and earnings. This
most recent amendment should be accounted for prospectively for
business combinations for which the acquisition date is on or
after January 1, 2011, for calendar-year reporting
entities. Early adoption is permitted. Although we did not early
adopt this standard, we do not expect this guidance to have a
material impact on our financial position, results of operations
or cash flows. We will comply with this update for business
combinations that have a material impact on our financial
results.
In May 2009, the FASB issued a standard regarding subsequent
events that provides guidance as to when an entity should
recognize events or transactions occurring after a balance sheet
date in its financial statements and the necessary disclosures
related to these events. Specifically, the entity should
recognize subsequent events that provide evidence about
conditions that existed at the balance sheet date, including
significant estimates used to prepare financial statements.
Originally, this standard required entities to disclose the date
through which subsequent events had been evaluated and whether
that date was the date the financial statements were issued or
the date the financial statements were available to be issued.
We adopted this accounting standard effective June 30, 2009
and applied its provisions prospectively. In February 2010, the
FASB modified this standard to eliminate the requirement for
publicly-traded entities to disclose the date through which
subsequent events have been evaluated.
In January 2010, the FASB issued Fair Value Measurements
and Disclosure (Topic 820) which clarified the disclosure
requirements of existing U.S. GAAP related to fair value
measurements. This standard requires additional disclosures
about recurring and non-recurring fair value measurements as
follows: (1) for transfers in and out of Level 1 and
Level 2 fair value measurements, as those terms are
currently defined in existing authoritative literature, a
reporting entity is required to disclose the amount of the
movement between levels and an explanation for the movement;
(2) for activity at Level 3, primarily fair value
measurements based on unobservable inputs, a reporting entity is
required to present separately information about purchases,
sales, issuances and settlements, as opposed to presenting such
transactions on a net basis; (3) in the event of a
disaggregation, a reporting entity is required to provide fair
value measurement disclosure for each class of assets and
liabilities; and (4) a reporting entity is required to
provide disclosures about the valuation techniques and inputs
used to measure fair value for both recurring and non-recurring
fair value measurements for items that fall in either
Level 2 or Level 3. These disclosure requirements are
effective for interim and annual reporting periods beginning
after December 15, 2009, except for disclosures about
purchases, sales, issuances and settlements in the roll forward
of activity in Level 3 fair value measurements for which
disclosure becomes effective for fiscal years beginning after
December 15, 2010, and for interim periods within those
fiscal years.
On March 30, 2010, the President of the United States
signed the Health Care and Education Reconciliation Act of 2010,
which is a reconciliation bill that amends the Patient
Protection and Affordable Care Act that was signed by the
President on March 23, 2010. Certain provisions of this law
became effective during 2010. We have reviewed our health
insurance plan provisions with third-party consultants and
continue to evaluate our position
111
COMPLETE
PRODUCTION SERVICES, INC.
Notes to
Consolidated Financial
Statements (Continued)
relative to the changes in the law. We do not believe that the
provisions which have taken effect will have a significant
impact on the operation of our existing health insurance plan.
However, future provisions under the law which become effective
in subsequent periods may impact our health insurance plan and
our overall financial position. We are evaluating these
provisions as they become effective and continue to seek
guidance from the FASB and SEC related to the implications of
this new legislation on accounting and disclosure requirements.
We expect that this legislation will have an impact on our
financial position, results of operations and cash flows, but we
cannot determine the extent of the impact at this time.
In December 2010, the FASB issued additional guidance related to
accounting for intangible assets and goodwill. The amendments in
this update modify Step 1 of the goodwill impairment test for
reporting units with zero or negative carrying amounts. For
those reporting units, an entity is required to perform Step 2
of the goodwill impairment test if it is more likely than not
that a goodwill impairment exists. In determining whether it is
more likely than not that a goodwill impairment exists, an
entity should consider whether there are any adverse qualitative
factors indicating that an impairment may exist. The qualitative
factors are consistent with the existing guidance and examples,
which require that goodwill of a reporting unit be tested for
impairment between annual test dates if an event occurs or
circumstances change that would more likely than not reduce the
fair value of a reporting unit below its carrying amount. This
update is effective for public entities with fiscal years
beginning after December 15, 2010 and interim periods
within those years. Early adoption is not permitted. We are
currently evaluating the effect this proposed guidance may have
on our financial position, results of operations and cash flows.
On January 31, 2011, the Compensation Committee of our
Board of Directors approved the annual grant of stock options
and non-vested restricted stock to certain employees, officers
and directors. Pursuant to this authorization, we issued
428,860 shares of non-vested restricted stock at a grant
price of $27.94. We expect to recognize compensation expense
associated with this grant of non-vested restricted stock
totaling $11,982 ratably over the three-year vesting period. In
addition, we granted 213,200 stock options to purchase shares of
our common stock at an exercise price of $27.94. These stock
options vest ratably over a three-year period. We will recognize
compensation expense associated with these stock option grants
over the vesting period.
Pursuant to our 2008 Incentive Award Plan, holders of unvested
restricted stock have the option to authorize us to repurchase
shares equivalent to the cost of the withholding tax associated
with the vesting of restricted stock and to remit the
withholding taxes on behalf of the holder. Pursuant to this
provision, we purchased 64,348 shares of our common stock
on January 29, 2011 for $27.29 per share,
91,417 shares on January 30, 2011 for $27.29 per share
and 43,869 shares on January 31, 2011 for $27.94 per
share. These shares were included in treasury stock at cost.
Effective January 1, 2011, we reinstated the matching
contributions for our defined contribution retirement plans to
provide for 100% matching of contributions, up to 4% of the
employees salary, depending on the plan. For a description
of our retirement plans, see Note 20, Retirement
plans.
During the review of our property, plant and equipment at
December 31, 2010 in conjunction with our annual impairment
testing of long-term assets, we noted approximately $5,814 of
salvage value assigned to various coiled tubing and wireline
assets at one of our operating divisions. Although we evaluated
these assets and the assets of the overall reporting unit for
recoverability and noted no significant impairment based on an
undiscounted cash flow projection, we believe that the salvage
value assigned to these assets is no longer appropriate. These
assets were acquired several years ago, and we believe the
estimate for salvage value used at that time was appropriate.
However, increasingly, our business is focusing on
larger-diameter coiled tubing units and more
technologically-advanced equipment. As such, we have changed our
estimate of salvage value to zero and expect to depreciate these
assets over their remaining useful lives, an average of 1.3
years at December 31, 2010. This change in estimate will be
applied prospectively and is expected to increase our
depreciation expense over the next five years as follows:
2011 $4,867; 2012 $789;
2013 $134 and 2014 $24.
112
|
|
Item 9.
|
Changes
in and Disagreements With Accountants on Accounting and
Financial Disclosure.
|
None.
|
|
Item 9A.
|
Controls
and Procedures.
|
Evaluation
of Disclosure Controls and Procedures
As required by
Rule 13a-15(b)
under the Securities Exchange Act of 1934, as amended (the
Exchange Act), management has evaluated, with the
participation of our Chief Executive Officer and Chief Financial
Officer, the effectiveness of our disclosure controls and
procedures (as defined in
Rules 13a-15(e)
and
15d-15(e)
under the Exchange Act) as of the end of the period covered by
this Annual Report on
Form 10-K.
Disclosure controls and procedures refer to controls and other
procedures designed to ensure that information required to be
disclosed in the reports we file or submit under the Exchange
Act is recorded, processed, summarized and reported, within the
time periods specified in the rules and forms of the Securities
and Exchange Commission. Disclosure controls and procedures
include, without limitation, controls and procedures designed to
ensure that information required to be disclosed by us in our
reports that we file or submit under the Exchange Act is
accumulated and communicated to management, including our Chief
Executive Officer and Chief Financial Officer, as appropriate to
allow timely decisions regarding our required disclosure. In
designing and evaluating our disclosure controls and procedures,
management recognizes that any controls and procedures, no
matter how well designed and operated, can provide only
reasonable assurance of achieving the desired control
objectives, and management was required to apply its judgment in
evaluating and implementing possible controls and procedures.
Based upon our
evaluation, our Chief Executive Officer and Chief Financial
Officer have concluded that, as of December 31, 2010, the
end of the period covered by this Annual Report on
Form 10-K,
our disclosure controls and procedures were effective at a
reasonable assurance level to ensure that information required
to be disclosed in the reports we file and submit under the
Exchange Act is recorded, processed, summarized and reported as
and when required.
Managements
Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining
adequate internal control over financial reporting (as defined
in Rules 13a 15(f) and 15d 15(f)
under the Exchange Act). Our internal control over financial
reporting is a process designed by management, under the
supervision of the Chief Executive Officer and Chief Financial
Officer, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
accounting principles generally accepted in the United States of
America, and includes those policies and procedures that:
(i) pertain to the maintenance of records that in
reasonable detail accurately and fairly reflect the transactions
and dispositions of our assets;
(ii) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial
statements in accordance with accounting principles generally
accepted in the United States, and that our receipts and
expenditures are being made only in accordance with
authorizations of management and our directors; and
(iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use or disposition
of our assets that could have a material effect on our
consolidated financial statements.
Internal control over financial reporting cannot provide
absolute assurance of achieving financial reporting objectives
because of its inherent limitations. Internal control over
financial reporting is a process that involves human diligence
and compliance and is subject to lapses in judgment and
breakdowns resulting from human failures. Internal control over
financial reporting also can be circumvented by collusion or
improver override. Because of its inherent limitations, there is
a risk that internal control over financial reporting may not
prevent or detect, on a timely basis, material misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the
113
degree of compliance with the policies and procedures may
deteriorate. Accordingly, even effective internal control over
financial reporting can only provide reasonable assurance of
achieving their control objectives.
Our management, under the supervision and with the participation
of our Chief Executive Officer and Chief Financial Officer,
assessed the effectiveness of the Companys internal
control over financial reporting as of December 31, 2010.
In making this assessment, management used the criteria set
forth by the committee of Sponsoring Organizations of the
Treadway Commission (COSO) in Internal Control
Integrated Framework.
Based on our evaluation under the framework in Internal
Control Integrated Framework, our management
concluded that, our internal control over financial reporting
was effective as of December 31, 2010.
Grant Thornton LLP, the independent registered accounting firm
who audited the consolidated financial statements included in
this Annual Report, has issued a report on our internal control
over financial reporting dated February 18, 2011, also included
in this Annual Report and expressed an unqualified opinion on
the effectiveness of our internal control over financial
reporting as of December 31, 2010.
Changes
in Internal Control over Financial Reporting
As of December 31, 2010, there were no changes in our
system of internal control over financial reporting (as defined
in Rules 13a 15(f) and 15d 15(f)
under the Exchange Act) that occurred during the last fiscal
quarter then ended that has materially affected, or is
reasonably likely to materially affect, our internal control
over financial reporting.
In 2010, our management approved a plan to implement new
accounting software which will replace our existing accounting
systems at several of our operating divisions in a phased
approach. Two divisions converted during the fourth quarter of
2010 and two divisions will convert during 2011. In addition, we
implemented a new chart of accounts which is being adopted as
these divisions convert to the new software. Although we believe
the new software, once implemented, will enhance our internal
controls over financial reporting and we believe that we have
taken the necessary steps to maintain appropriate internal
control over financial reporting during this period of system
change, we will continuously monitor controls through and around
the system to provide reasonable assurance that controls are
effective during and after each step of this implementation
process.
Joseph C. Winkler
Chairman and Chief Executive Officer
February 18, 2011
Jose A. Bayardo
Sr. Vice President and Chief Financial Officer
February 18, 2011
|
|
Item 9B.
|
Other
Information.
|
None.
PART III
|
|
Item 10.
|
Directors,
Executive Officers and Corporate Governance.
|
The information to be included in the sections entitled,
Election of Directors and Executive
Officers, respectively, in the Definitive Proxy Statement
of the Annual Meeting of Stockholders to be filed by us with the
114
Securities and Exchange Commission no later than 120 days
after December 31, 2010 (the 2010 Proxy
Statement) is incorporated herein by reference.
The information to be included in the section entitled
Section 16(a) Beneficial Ownership Reporting
Compliance in the 2011 Proxy Statement is incorporated
herein by reference.
The information to be included in the section entitled
Corporate Governance in the 2011 Proxy Statement is
incorporated herein by reference.
We have filed, as exhibits to this Annual Report on
Form 10-K,
the certifications of our Principal Executive Officer and
Principal Financial Officer required pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
Item 11.
|
Executive
Compensation.
|
The information to be included in the sections entitled
Executive Compensation and Directors
Compensation in the 2011 Proxy Statement is incorporated
herein by reference.
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters.
|
The information to be included in the section entitled
Security Ownership of Certain Beneficial Owners and
Management in the 2011 Proxy Statement is incorporated
herein by reference.
|
|
Item 13.
|
Certain
Relationships and Related Transactions, and Director
Independence.
|
The information to be included in the sections entitled
Certain Relationships and Related Transactions and
Board Independence in the 2011 Proxy Statement is
incorporated herein by reference.
|
|
Item 14.
|
Principal
Accounting Fees and Services.
|
The information to be included in the section entitled
Independent Registered Public Accountants in the
2011 Proxy Statement is incorporated herein by reference.
PART IV
|
|
Item 15.
|
Exhibits,
Financial Statement Schedules.
|
(a) List the following documents filed as a part
of the report:
|
|
|
|
|
Description
|
|
Page No.
|
|
Report of Independent Registered Public Accounting Firm
|
|
|
62
|
|
Consolidated Balance Sheets as of December 31, 2010 and 2009
|
|
|
64
|
|
Consolidated Statements of Operations for the Years Ended
December 31, 2010, 2009 and 2008
|
|
|
65
|
|
Consolidated Statements of Comprehensive Income (Loss) for the
Years Ended December 31, 2010, 2009 and 2008
|
|
|
66
|
|
Consolidated Statement of Stockholders Equity for the
Years Ended December 31, 2010, 2009 and 2008
|
|
|
67
|
|
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2010, 2009 and 2008
|
|
|
68
|
|
Notes to Consolidated Financial Statements
|
|
|
69
|
|
(b) Exhibits Please see our Exhibit Index, on
Page 117.
115
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized
COMPLETE PRODUCTION SERVICES, INC.
|
|
|
|
By:
|
/s/ JOSEPH
C. WINKLER
|
Name: Joseph C. Winkler
|
|
|
|
Title:
|
Chief Executive Officer
|
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature
appears below constitutes and appoints Joseph C. Winkler and
Jose A. Bayardo, and each of them severally, his true and lawful
attorney or attorneys-in-fact and agents, with full power to act
with or without the others and with full power of substitution
and re-substitution, to execute in his name, place and stead, in
any and all capacities, any or all amendments to this Annual
Report on
Form 10-K,
with all exhibits thereto, and other documents in connection
therewith, with the Securities and Exchange Commission, granting
unto said attorneys-in-fact and agents and each of them, full
power and authority to do and perform in the name of on behalf
of the undersigned, in any and all capacities, each and every
act and thing necessary or desirable to be done in and about the
premises, to all intents and purposes and as fully as they might
or could do in person, hereby ratifying, approving and
confirming all that said attorneys-in-fact and agents or their
substitutes may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
|
|
|
|
|
|
|
Signature
|
|
Position
|
|
Date
|
|
|
|
|
|
|
/s/ JOSEPH
C. WINKLER
Joseph
C. Winkler
|
|
Chief Executive Officer and Chairman of the Board (Principal
Executive Officer)
|
|
February 18, 2011
|
|
|
|
|
|
/s/ JOSE
A. BAYARDO
Jose
A. Bayardo
|
|
Sr. Vice President and Chief Financial Officer (Principal
Financial Officer)
|
|
February 18, 2011
|
|
|
|
|
|
/s/ DEWAYNE
WILLIAMS
Dewayne
Williams
|
|
Vice President-Accounting and Controller (Principal Accounting
Officer)
|
|
February 18, 2011
|
|
|
|
|
|
/s/ ROBERT
BOSWELL
Robert
Boswell
|
|
Director
|
|
February 18, 2011
|
|
|
|
|
|
/s/ HAROLD
G. HAMM
Harold
G. Hamm
|
|
Director
|
|
February 18, 2011
|
|
|
|
|
|
/s/ MIKE
MCSHANE
Mike
McShane
|
|
Director
|
|
February 18, 2011
|
|
|
|
|
|
/s/ W.
MATT RALLS
W.
Matt Ralls
|
|
Director
|
|
February 18, 2011
|
|
|
|
|
|
/s/ MARCUS
WATTS
Marcus
Watts
|
|
Director
|
|
February 18, 2011
|
|
|
|
|
|
/s/ JAMES
D. WOODS
James
D. Woods
|
|
Director
|
|
February 18, 2011
|
116
The following exhibits are incorporated by reference into the
filing indicated or are filed herewith.
EXHIBIT INDEX
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incorporated by
|
Exhibit
|
|
|
|
|
|
Reference to the
|
No.
|
|
|
|
Exhibit Title
|
|
Following
|
|
|
|
|
|
|
|
|
|
|
|
3
|
.1
|
|
|
|
Amended and Restated Certificate of Incorporation
|
|
Form S-1/A, filed January 18, 2006, (file no. 333-128750)
|
|
|
|
|
|
|
|
|
|
|
3
|
.2
|
|
|
|
Amended and Restated Bylaws
|
|
Form 8-K, filed February 27, 2008
|
|
|
|
|
|
|
|
|
|
|
4
|
.1
|
|
|
|
Specimen Stock Certificate representing common stock
|
|
Form S-1/A, filed April 4, 2006, (file no. 333-128750)
|
|
|
|
|
|
|
|
|
|
|
4
|
.2
|
|
|
|
Indenture dated December 6, 2006, between Complete
Production Services, Inc. and the Guarantors Named Therein, with
Wells Fargo Bank, National Association, as Trustee, for
8% Senior Notes due 2016
|
|
Form 8-K, filed December 8, 2006
|
|
|
|
|
|
|
|
|
|
|
4
|
.3
|
|
|
|
Registration Rights Agreement dated November 8, 2006
pursuant to Stock Purchase Agreement dated November 8, 2006
among Complete Production Services, Inc., Integrated Production
Services, LLC and Pumpco Services Inc. and Each Seller Listed on
Schedule I Thereto
|
|
Form 8-K, filed November 14, 2006
|
|
|
|
|
|
|
|
|
|
|
4
|
.4
|
|
|
|
First Supplemental Indenture, dated August 28, 2007, among
Complete Production Services, Inc., the subsidiary guarantors
party thereto, and Wells Fargo Bank, National Association, as
trustee
|
|
Form 10-Q, filed November 2, 2007, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.1
|
|
|
|
Form of Indemnification Agreement
|
|
Form S-1/A, filed November 15, 2005, (file no. 333-128750)
|
|
|
|
|
|
|
|
|
|
|
10
|
.2*
|
|
|
|
Employment Agreement dated as of June 20, 2005 with Joseph
C. Winkler
|
|
Form S-1, filed September 30, 2005, (file no. 333-128750)
|
|
|
|
|
|
|
|
|
|
|
10
|
.3
|
|
|
|
Amended and Restated Stockholders Agreement by and among
Complete Production Services Inc. and the stockholders listed
therein
|
|
Form S-1/A, filed March 20, 2006, (file no. 333-128750)
|
|
|
|
|
|
|
|
|
|
|
10
|
.4
|
|
|
|
Combination Agreement dated as of August 9, 2005, with
Complete Energy Services, Inc., I.E. Miller Services, Inc. and
Complete Energy Services, LLC and I.E. Miller Services, LLC
|
|
Form S-1, filed September 30, 2005, (file no. 333-128750)
|
|
|
|
|
|
|
|
|
|
|
10
|
.5
|
|
|
|
Second Amended and Restated Credit Agreement, dated as of
December 6, 2006 by and among Complete Production Services,
Inc., as U.S. Borrower, Integrated Production Services Ltd., as
Canadian Borrower, Wells Fargo Bank, National Association, as
U.S. Administrative Agent, U.S. Issuing Lender and U.S.
Swingline Lender, HSBC Bank Canada, as Canadian Administrative
Agent, Canadian Issuing Lender and Canadian Swingline Lender,
and the Lenders party thereto, Wells Fargo Bank, National
Association as Lead Arranger and Amegy Bank N.A. and Comerica
Bank, as Co-Documentation Agents
|
|
Form 10-K, filed March 9, 2007, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.6*
|
|
|
|
Integrated Production Services, Inc. 2001 Stock Incentive Plan
|
|
Form S-1/A, filed November 15, 2005, (file no. 333-128750)
|
|
|
|
|
|
|
|
|
|
|
10
|
.7*
|
|
|
|
Complete Energy Services, Inc. 2003 Stock Incentive Plan
|
|
Form S-1/A, filed November 15, 2005, (file no. 333-128750)
|
|
|
|
|
|
|
|
|
|
|
10
|
.8*
|
|
|
|
First Amendment to Complete Energy Services, Inc. 2003 Stock
Incentive Plan
|
|
Form S-1/A, filed November 15, 2005, (file no. 333-128750)
|
|
|
|
|
|
|
|
|
|
|
10
|
.9*
|
|
|
|
Second Amendment to Complete Energy Services, Inc. 2003 Stock
Incentive Plan
|
|
Form S-1/A, filed November 15, 2005, (file no. 333-128750)
|
|
|
|
|
|
|
|
|
|
|
10
|
.10*
|
|
|
|
Amended and Restated Integrated Production Services, Inc. 2003
Parchman Restricted Stock Plan
|
|
Form S-1/A, filed November 15, 2005, (file no. 333-128750)
|
|
|
|
|
|
|
|
|
|
|
10
|
.11*
|
|
|
|
Amended and Restated 2001 Stock Incentive Plan
|
|
Form S-1/A, filed April 4, 2006, (file no. 333-128750)
|
|
|
|
|
|
|
|
|
|
|
10
|
.12*
|
|
|
|
Amendment No. 1 to the Complete Production Services, Inc.
Amended and Restated 2001 Stock Incentive Plan
|
|
Form 10-K, filed March 9, 2007 (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.13*
|
|
|
|
I.E. Miller Services, Inc. 2004 Stock Incentive Plan
|
|
Form S-1/A, filed November 15, 2005, (file no. 333-128750)
|
117
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incorporated by
|
Exhibit
|
|
|
|
|
|
Reference to the
|
No.
|
|
|
|
Exhibit Title
|
|
Following
|
|
|
|
|
|
|
|
|
|
|
|
10
|
.14
|
|
|
|
Strategic Customer Relationship Agreement
|
|
Form S-1/A, filed November 15, 2005, (file no. 333-128750)
|
|
|
|
|
|
|
|
|
|
|
10
|
.15*
|
|
|
|
Form of Restricted Stock Grant Agreement (Employee)
|
|
Form S-1/A, filed November 15, 2005, (file no. 333-128750)
|
|
|
|
|
|
|
|
|
|
|
10
|
.16*
|
|
|
|
Form of Restricted Stock Grant Agreement (Non-employee Director)
|
|
Form S-1/A, filed November 15, 2005, (file no. 333-128750)
|
|
|
|
|
|
|
|
|
|
|
10
|
.17*
|
|
|
|
Form of Non-Qualified Option Grant Agreement (Executive Officer)
|
|
Form S-1/A, filed April 4, 2006, (file no. 333-128750)
|
|
|
|
|
|
|
|
|
|
|
10
|
.18*
|
|
|
|
Form of Non-Qualified Option Grant Agreement (Non-Employee
Director)
|
|
Form S-1/A, filed April 4, 2006, (file no. 333-128750)
|
|
|
|
|
|
|
|
|
|
|
10
|
.19*
|
|
|
|
Compensation Package Term Sheet James F.
Maroney, III
|
|
Form S-1/A, filed March 20, 2006, (file no. 333-128750)
|
|
|
|
|
|
|
|
|
|
|
10
|
.20*
|
|
|
|
Compensation Package Term Sheet Kenneth L. Nibling
|
|
Form S-1/A, filed March 20, 2006, (file no. 333-128750)
|
|
|
|
|
|
|
|
|
|
|
10
|
.21*
|
|
|
|
Incentive Plan Guidelines for Senior Management
|
|
Form 8-K, filed February 22, 2007
|
|
|
|
|
|
|
|
|
|
|
10
|
.22*
|
|
|
|
Form of Non-qualified Stock Option Grant Agreement
|
|
Form 8-K, filed February 2, 2007
|
|
|
|
|
|
|
|
|
|
|
10
|
.23*
|
|
|
|
Form of Restricted Stock Agreement Executive Officer
(Post-September 2006)
|
|
Form 8-K, filed February 2, 2007
|
|
|
|
|
|
|
|
|
|
|
10
|
.24*
|
|
|
|
Restricted Stock Agreement Terms and Conditions (Revised
2006) Employee
|
|
Form 10-K, filed March 9, 2007, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.25*
|
|
|
|
Signature Page for Restricted Stock Agreement
Employee
|
|
Form 10-K, filed March 9, 2007, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.26*
|
|
|
|
Non-Employee Director Restricted Stock Agreement
|
|
Form 10-K, filed March 9, 2007, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.27*
|
|
|
|
Stock Option Terms and Conditions (Revised 2006)
Employee
|
|
Form 10-K, filed March 9, 2007, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.28*
|
|
|
|
Signature Page for Executive Officers
|
|
Form 10-K, filed March 9, 2007, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.29*
|
|
|
|
Director Option Agreement
|
|
Form 10-K, filed March 9, 2007, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.30*
|
|
|
|
Form of Executive Agreement
|
|
Form 10-Q, filed May 4, 2007, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.31*
|
|
|
|
Amendment to Employment Agreement, dated March 21, 2007
between Complete Production Services, Inc. and Mr. Joseph
C. Winkler
|
|
Form 10-Q, filed May 4, 2007, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.32*
|
|
|
|
Pumpco Services, Inc. 2005 Stock Incentive Plan
|
|
Registration Statement on Form S-8, filed March 28, 2007,
(file no. 333-141628)
|
|
|
|
|
|
|
|
|
|
|
10
|
.33
|
|
|
|
First Amendment to Second Amended and Restated Credit Agreement,
dated as of December 6, 2006 by and among Complete
Production Services, Inc., as U.S. Borrower, Integrated
Production Services Ltd., as Canadian Borrower, Wells Fargo
Bank, National Association, as U.S. Administrative Agent, U.S.
Issuing Lender and U.S. Swingline Lender, HSBC Bank Canada, as
Canadian Administrative Agent, Canadian Issuing Lender and
Canadian Swingline Lender, and the Lenders party thereto, Wells
Fargo Bank, National Association as Lead Arranger and Amegy Bank
N.A. and Comerica Bank, as Co-Documentation Agents, effective
June 29, 2007.
|
|
Form 10-Q, filed August 3, 2007, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.34
|
|
|
|
Second Amendment to Credit Agreement and Omnibus Amendment to
Security Documents, dated October 9, 2007 but effective
October 19, 2007, among Complete Production Services, Inc.,
Integrated Production Services, Ltd., Wells Fargo Bank, National
Association, as administrative agent, swing line lender and
issuing lender and HSBC Bank Canada, as administrative agent,
swing line lender and issuing lender.
|
|
Form 10-Q, filed November 2, 2007, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.35*
|
|
|
|
Complete Production Services, Inc. 2008 Incentive Award Plan
|
|
Appendix A of Definitive Proxy Statement on Schedule 14, filed
April 7, 2008
|
|
|
|
|
|
|
|
|
|
|
10
|
.36*
|
|
|
|
Form of Non-Qualified Stock Option Agreement
|
|
Form 10-Q, filed August 1, 2008, (file no. 001-32858)
|
118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incorporated by
|
Exhibit
|
|
|
|
|
|
Reference to the
|
No.
|
|
|
|
Exhibit Title
|
|
Following
|
|
|
|
|
|
|
|
|
|
|
|
10
|
.37*
|
|
|
|
Agreement for Non-Employee Directors
|
|
Form 10-Q, filed August 1, 2008, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.38*
|
|
|
|
Form of Signature Page for Stock Option Agreement Terms and
Conditions
|
|
Form 10-Q, filed August 1, 2008, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.39*
|
|
|
|
Restricted Stock Agreement Terms and Conditions
|
|
Form 10-Q, filed August 1, 2008, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.40*
|
|
|
|
Form of Stock Agreement
|
|
Form 10-Q, filed August 1, 2008, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.41*
|
|
|
|
Signature Page to the Restricted Stock Award Agreement Terms and
Conditions
|
|
Form 10-Q, filed August 1, 2008, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.42*
|
|
|
|
Restricted Stock Agreement for Non-Employee Directors
|
|
Form 10-Q, filed August 1, 2008, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.43*
|
|
|
|
Retirement Agreement between Complete Production Services, Inc.
and J. Michael Mayer, effective October 7, 2008.
|
|
Form 8-K, filed October 9, 2008, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.44*
|
|
|
|
Complete Production Services, Inc. Deferred Compensation Plan,
effective January 1, 2009
|
|
Form 10-K, filed February 27, 2009, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.45*
|
|
|
|
Amended and Restated Employment Agreement, effective
December 31, 2008 between Complete Production Services,
Inc. and Mr. Joseph C. Winkler
|
|
Form 10-K, filed February 27, 2009, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.46*
|
|
|
|
Form of Amended and Restated Complete Production Services
Executive Agreement
|
|
Form 10-K, filed February 27, 2009, (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.47
|
|
|
|
Second Supplemental Indenture among the Guarantor Subsidiaries
of Complete Production Services, Inc., and Wells Fargo Bank,
National Association, as trustee under the Indenture, dated
April 1, 2009
|
|
Form 10-Q, filed April 30, 2009 (file no.001-32858)
|
|
|
|
|
|
|
|
|
|
|
10
|
.48
|
|
|
|
Third Amendment to Credit Agreement, Omnibus Amendment to Credit
Documents and Assignment, dated as of October 13, 2009,
among Complete Production Services, Inc., Integrated Production
Services Ltd., certain subsidiary guarantors party thereto, the
lenders party thereto, Wells Fargo Bank, National Association,
Wells Fargo Foothill, LLC and HSBC Bank Canada
|
|
Form 8-K, filed October 16, 2009
|
|
|
|
|
|
|
|
|
|
|
10
|
.49*
|
|
|
|
Retirement Agreement between the Company and Robert L.
Weisgarber dated May 15, 2009
|
|
Form 8-K, filed May 18, 2009
|
|
|
|
|
|
|
|
|
|
|
10
|
.50*
|
|
|
|
Amendment No. 1 to the Complete Production Services, Inc.
2008 Incentive Award Plan
|
|
Proxy Statement on Schedule 14A, filed May 11, 2009
|
|
|
|
|
|
|
|
|
|
|
10
|
.51*
|
|
|
|
Complete Production Services, Inc. Amended and Restated Deferred
Compensation Plan
|
|
Form 10-Q, filed April 30, 2010 (file no. 001-32858)
|
|
|
|
|
|
|
|
|
|
|
21
|
.1
|
|
|
|
Subsidiaries of Complete Production Services, Inc.
|
|
Filed herewith
|
|
|
|
|
|
|
|
|
|
|
23
|
.1
|
|
|
|
Consent of Grant Thornton LLP
|
|
Filed herewith
|
|
|
|
|
|
|
|
|
|
|
24
|
.1
|
|
|
|
Power of Attorney (included on signature page)
|
|
Filed herewith
|
|
|
|
|
|
|
|
|
|
|
31
|
.1
|
|
|
|
Certification of Chief Executive Officer Pursuant to
Rule 13a 14 of the Securities and Exchange Act
of 1934, as Adopted Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
|
|
Filed herewith
|
|
|
|
|
|
|
|
|
|
|
31
|
.2
|
|
|
|
Certification of Chief Financial Officer Pursuant to
Rule 13a 14 of the Securities and Exchange Act
of 1934, as Adopted Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
|
|
Filed herewith
|
|
|
|
|
|
|
|
|
|
|
32
|
.1
|
|
|
|
Certification of Chief Executive Officer Pursuant to
18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
|
|
Filed herewith
|
|
|
|
|
|
|
|
|
|
|
32
|
.2
|
|
|
|
Certification of Chief Financial Officer Pursuant to
18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
|
|
Filed herewith
|
119
|
|
|
|
|
|
|
|
|
|
|
|
|
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Incorporated by
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Exhibit
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Reference to the
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No.
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Exhibit Title
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Following
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101
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Complete Production Services, Inc. Annual Report on
Form 10-K
for the year ended December 31, 2010, formatted in
Extensible Business Reporting Language (XBRL): (i) the
Consolidated Balance Sheets at December 31, 2010 and
December 31, 2009, (ii) the Consolidated Statements of
Operations for the year ended December 31, 2010, 2009 and
2008, (iii) the Consolidated Stockholders Equity for
the years ended December 31, 2010, 2009, 2008,
(iv) the Consolidated Statements of Cash Flows for the
years ended December 31, 2010, and December 31, 2009,
and (v) the Notes to Consolidated Financial Statements
(tagged as blocks of text).
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Filed herewith
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* |
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Management employment agreements, compensatory arrangements or
option plans |
120