e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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(Mark One)
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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, 2006
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OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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FOR THE TRANSITION PERIOD
FROM TO
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Commission file number 1-2199
ALLIS-CHALMERS ENERGY
INC.
(Exact name of registrant as
specified in its charter)
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Delaware
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39-0126090
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(State or other jurisdiction
of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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5075 WESTHEIMER,
SUITE 890
HOUSTON, TEXAS
(Address of principal
executive offices)
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77056
(Zip code)
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(713) 369-0550
Registrants telephone
number, including area code
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE
ACT:
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Title of Security:
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Name of Exchange:
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Common Stock, par value
$0.01 per share
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American Stock Exchange
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SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE
ACT:
NONE
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes o No þ
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or
15(d). Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to ITEM 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer or a non-accelerated
filer. See definition of accelerated filer and
large accelerated filer in
Rule 12b-2
of the Exchange Act (Check one):
Large accelerated
filer o Accelerated
filer þ Non-accelerated
filer o
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
The aggregate market value of the common equity held by
non-affiliates of the registrant, computed using the closing
price of the common stock of $13.59 per share on June 30,
2006, as reported on the American Stock Exchange, was
approximately $139,745,249 (affiliates included for this
computation only: directors, executive officers and holders of
more than 5% of the registrants common stock).
As of March 1, 2007 there were 34,251,443 shares of
common stock issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
Certain information called for by
Items 10, 11, 12, 13 and 14 of Part III will
be included in an amendment to this annual report on
Form 10-K
or incorporated by reference from the registrants
definitive proxy statement for its 2007 annual meeting of
stockholders.
DEFINITIONS
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air drilling |
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A technique in which oil, natural gas, or geothermal wells are
drilled by creating a pressure within the well that is lower
than the reservoir pressure. The result is increased rate of
penetration, reduced formation damage and reduced drilling costs. |
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blow out preventors |
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A large safety device placed on the surface of an oil or natural
gas well to maintain high pressure well bores. |
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booster |
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A machine that increases the pressure
and/or
volume of air when used in conjunction with a compressor or a
group of compressors. |
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capillary tubing |
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A small diameter tubing installed in producing wells and through
which chemicals are injected to enhance production and reduce
corrosion and other problems. |
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casing |
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A pipe placed in a drilled well to secure the well bore and
formation. |
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choke manifolds |
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An arrangement of pipes, valves and special valves on the rig
floor that controls pressure during drilling by diverting
pressure away from the blow-out preventors and the annulus of
the well. |
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coiled tubing |
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A small diameter tubing used to service producing and
problematic wells and to work in high pressure applications
during drilling, production and workover operations. |
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directional drilling |
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The technique of drilling a well while varying the angle of
direction of a well and changing the direction of a well to hit
a specific target. |
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double studded adapter |
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A device that joins two dissimilar connections on certain
equipment, including valves, piping and blow-out preventers. |
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drill pipe |
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A pipe that attaches to the drill bit to drill a well. |
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spiral heavy weight drill pipe |
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A heavy drill pipe used for special applications primarily in
directional drilling. The spiral design increases
flexibility and penetration of the pipe. |
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horizontal drilling |
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The technique of drilling wells at a
90-degree
angle. |
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laydown machines |
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A truck mounted machine used to move drill pipe, casing and
tubing onto a pipe rack (from which a derrick crane lifts the
drill pipe, casing and tubing and inserts it into the well). |
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land drilling rig |
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Composed of a drawworks or hoist, a derrick, a power plant,
rotating equipment and pumps to circulate the drilling fluid and
the drill string. |
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logging-while-drilling |
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The technique of measuring, in real time, the formation pressure
and the position of equipment inside of a well. |
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measurement-while-drilling |
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The technique used to measure direction and angle while drilling
a well. |
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mist pump |
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A drilling pump that uses mist as the circulation medium for
injecting small amounts of foaming agent, corrosion agent and
other chemical solutions into the well. |
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pulling rig |
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A type of well-servicing rig used to pull downhole equipment,
such as tubing, rods or the pumps from a well, and replace them
when |
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necessary. A pulling rig is also used to set downhole tools and
perform lighter jobs. |
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spacer spools |
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High pressure connections or links which are stacked to elevate
the blow out preventors to the drilling rig floor. |
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straight-hole drilling |
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The technique of drilling that allows very little or no vertical
deviation. |
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test plugs |
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A device used to test the connections of well heads and the blow
out preventors. |
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torque turn service or torque turn
equipment |
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A monitoring device to insure proper makeup of the casing. |
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tubing |
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A pipe placed inside the casing to allow the well to produce. |
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tubing work strings |
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The tubing used on workover rigs through which high pressure
liquids, gases or mixtures are pumped into a well to perform
production operations. |
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wear bushings |
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A device placed inside a wellhead to protect the wellhead from
wear. |
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workover rigs |
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Similar to a land drilling rig, however, they are smaller than
the drilling rig for the same depth of well. These rigs are used
to complete the drilled wells or to repair them whenever
necessary. |
4
SPECIAL
NOTE
REGARDING FORWARD-LOOKING STATEMENTS
This annual report contains forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933,
as amended, or the Securities Act, regarding our business,
financial condition, results of operations and prospects. Words
such as expects, anticipates, intends, plans, believes, seeks,
estimates and similar expressions or variations of such words
are intended to identify forward-looking statements. However,
these are not the exclusive means of identifying forward-looking
statements. Although such forward-looking statements reflect our
good faith judgment, such statements can only be based on facts
and factors currently known to us. Consequently, forward-looking
statements are inherently subject to risks and uncertainties,
and actual outcomes may differ materially from the results and
outcomes discussed in the forward-looking statements. Further
information about the risks and uncertainties that may impact us
are described in Risk Factors beginning on
page 13 of this annual report. You should read those
sections carefully. You should not place undue reliance on
forward-looking statements, which speak only as of the date of
this annual report. We undertake no obligation to update
publicly any forward-looking statements in order to reflect any
event or circumstance occurring after the date of this annual
report or currently unknown facts or conditions or the
occurrence of unanticipated events.
PART I.
We provide services and equipment to oil and natural gas
exploration and production companies, domestically in Texas,
Louisiana, New Mexico, Colorado, Oklahoma, Mississippi, Utah,
Wyoming, Arkansas, Alabama, West Virginia, offshore in the Gulf
of Mexico, and internationally primarily in Argentina and
Mexico. We operate in six sectors of the oil and natural gas
service industry: rental tools, international drilling,
directional drilling services; casing and tubing services;
compressed air drilling services; and production services. Our
central operating strategy is to provide high-quality,
technologically advanced services and equipment. As a result of
our commitment to customer service, we have developed strong
relationships with many of the leading oil and natural gas
companies, including both independents and majors.
Our growth strategy is focused on identifying and pursuing
opportunities in markets we believe are growing faster than the
overall oilfield services industry in which we believe we can
capitalize on our competitive strengths. Over the past several
years, we have significantly expanded the geographic scope of
our operations and the range of services we provide through
organic growth and strategic acquisitions. Our organic growth
has primarily been achieved through expanding our geographic
scope, acquiring complementary property and equipment, hiring
personnel to service new regions and cross-selling our products
and services from existing operating locations. Since 2001, we
have completed 19 acquisitions, including six in 2005 and five
significant acquisitions in 2006.
Unless the context requires otherwise, references in this annual
report to Allis-Chalmers, we,
us, our and ours refer to
Allis-Chalmers Energy Inc., together with its subsidiaries.
Our annual reports on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K
and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Securities Exchange Act of
1934, as amended, or the Exchange Act, are made available free
of charge on our website at www.alchenergy.com as soon as
reasonably practicable after we electronically file or furnish
them to the Securities and Exchange Commission, or SEC.
We have adopted a Code of Business Ethics and Conduct to provide
guidance to our directors, officers and employees on matters of
business ethics and conduct. Our Code of Business Ethics and
Conduct is available on the investor relations section of our
website.
Information contained on or connected to our website is not
incorporated by reference into this annual report on
Form 10-K
and should not be considered part of this report or any other
filing we make with the SEC.
Divisional and geographic financial information appears in
Item 8. Financial Information Notes to
Consolidated Financial Statements Note 16.
5
Our
History
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We were incorporated in 1913 under Delaware law.
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We reorganized in bankruptcy in 1988 and sold all of our major
businesses. From 1988 to May 2001 we had only one operating
company in the equipment repair business.
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In May 2001, under new management we consummated a merger in
which we acquired OilQuip Rentals, Inc., or OilQuip, and its
wholly-owned subsidiary, Mountain Compressed Air, Inc., or
Mountain Air.
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In December 2001, we sold Houston Dynamic Services, Inc., our
last pre-bankruptcy business.
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In February 2002, we acquired approximately 81% of the capital
stock of Allis-Chalmers Tubular Services Inc., or Tubular,
formerly known as Jens Oilfield Service, Inc. and
substantially all of the capital stock of Strata Directional
Technology, Inc., or Strata.
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In July 2003, we entered into a limited liability company
operating agreement with M-I L.L.C., or M-I, a joint venture
between Smith International and Schlumberger N.V., to form a
Delaware limited liability company named AirComp LLC, or
AirComp. Pursuant to this agreement, we owned 55% and M-I owned
45% of AirComp.
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In September 2004, we acquired the remaining 19% of the capital
stock of Tubular.
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In September 2004, we acquired all of the outstanding stock of
Safco-Oil Field Products, Inc., or Safco.
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In November 2004, AirComp acquired substantially all of the
assets of Diamond Air Drilling Services, Inc. and Marquis Bit
Co., LLC, which we refer to collectively as Diamond Air.
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In December 2004, we acquired Downhole Injection Services, LLC,
or Downhole.
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In January 2005, we changed our name from Allis-Chalmers
Corporation to Allis-Chalmers Energy Inc.
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In April 2005, we acquired all of the outstanding stock of Delta
Rental Service, Inc., or Delta.
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In May 2005, we acquired all of the outstanding stock of Capcoil
Tubing Services, Inc., or Capcoil.
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In July 2005, we acquired M-Is interest in AirComp, and
acquired the compressed air drilling assets of W. T.
Enterprises, Inc., or W.T.
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Effective August 2005, we acquired all of the outstanding stock
of Target Energy Inc., or Target.
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In September 2005, we acquired the casing and tubing assets of
IHS/Spindletop, a division of Patterson Services, Inc., a
subsidiary of RPC, Inc.
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In January 2006, we acquired all of the outstanding stock of
Specialty Rental Tools, Inc., or Specialty.
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In February 2006, we merged Downhole into Capcoil and renamed
the merged entity, Allis-Chalmers Production Services Inc. We
also merged Specialty and Delta into Safco and renamed the
merged entity, Allis-Chalmers Rental Tools, Inc. In
December 2006, we renamed to Allis-Chalmers Rental Services Inc,
or Rental.
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In April 2006, we acquired all of the outstanding stock of
Rogers Oil Tool Services, Inc., or Rogers.
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In August 2006, we acquired all of the outstanding stock of DLS
Drilling, Logistics & Services Corporation, or DLS.
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In October 2006, we acquired all of the outstanding stock of
Petro-Rentals, Incorporated, or Petro Rentals.
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In December 2006, we acquired all of the outstanding stock of
Tanus Argentina S.A., or Tanus.
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In December 2006, we acquired substantially all of the assets of
Oil & Gas Rental Services, Inc., or OGR.
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In December 2006, we merged Target into Strata and Rogers into
Tubular.
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As a result of these transactions, our prior results may not be
indicative of current or future operations of those sectors.
6
Industry
Overview
We provide products and services primarily to domestic onshore
and offshore oil and natural gas exploration and production
companies. The main factor influencing demand for our products
and services is the level of drilling activity by oil and
natural gas companies, which, in turn, depends largely on
current and anticipated future crude oil and natural gas prices
and production depletion rates. According to the Energy
Information Agency of the U.S. Department of Energy, or
EIA, from 1990 to 2005, demand for oil and natural gas in the
United States grew at an average annual rate of 1.5%, while
supply decreased at an average annual rate of just over 2%.
Current industry forecasts suggest an increasing demand for oil
and natural gas coupled with a flat or declining production
curve, which we believe should result in the continuation of
historically high crude oil and natural gas commodity prices.
The EIA forecasts that U.S. oil and natural gas consumption
will increase at an average annual rate of 1.4% and 1.3% through
2025, respectively. Conversely, the EIA estimates that
U.S. oil production will remain flat and natural gas
production will increase at an average annual rate of 0.6%.
We anticipate that oil and natural gas exploration and
production companies will continue to increase capital spending
for their exploration and drilling programs. In recent years,
much of this expansion has focused on natural gas drilling
activities. According to Baker Hughes rig count data, the
average total rig count in the United States increased 91% from
918 in 2000 to 1,752 as of March 2, 2007, while the average
natural gas rig count increased 103% from 720 in 2000 to 1,458
as of March 2, 2007. While the number of rigs drilling for
natural gas has increased significantly since the beginning of
1996, natural gas production has only increased by approximately
1.5% over the same period of time. This is largely a function of
increasing decline rates for natural gas wells in the United
States. We believe that a continued increase in drilling
activity will be required for the natural gas industry to help
meet the expected increased demand for natural gas in the United
States.
We believe oil and natural gas producers are becoming
increasingly focused on their core competencies in identifying
reserves and reducing burdensome capital and maintenance costs.
In addition, we believe our customers are currently
consolidating their supplier bases to streamline their
purchasing operations and benefit from economies of scale.
Competitive
Strengths
We believe the following competitive strengths will enable us to
capitalize on future opportunities:
Strategic position in high growth markets. We
focus on markets we believe are growing faster than the overall
oilfield services industry and in which we can capitalize on our
competitive strengths. Pursuant to this strategy, we have become
a significant provider of products and services in directional
drilling, air drilling and production-related services employing
coiled tubing and capillary tubing. We employ approximately
85 full-time directional drillers, and we believe our
ability to attract and retain experienced drillers has made us a
leader in the segment. We also believe we are one of the largest
air drillers based on amount of air drilling equipment. In
addition, we have significant operations in what we believe will
be among the higher growth oil and natural gas producing regions
within the United States and internationally, including the
Barnett Shale in North Texas, onshore and offshore Louisiana,
the Piceance Basin in Southern Colorado, all five oil and
natural gas producing regions in Mexico, and all five major oil
and natural gas producing regions of Argentina.
Strong relationships with diversified customer
base. We have strong relationships with many of
the major and independent oil and natural gas producers and
service companies in Texas, Louisiana, New Mexico, Colorado,
Oklahoma, Mississippi, Utah, Wyoming, Arkansas, offshore in the
Gulf of Mexico, Argentina and Mexico. Our largest customers
include Anadarko Petroleum, Apache Corporation, BHP-Billiton,
BP, Chevron, ConocoPhilips, Dominion Resources, El Paso
Corporation, Materiales y Equipo Petroleo, or Matyep, McMoran
Oil & Gas, Murphy Oil, Newfield Exploration, Occidental
Petroleum Corporation, Pan American Energy, Petrohawk Energy,
Helix Energy Solutions Group, Repsol-YPF and Total Austral.
Since 2002, we have broadened our customer base as a result of
our acquisitions, technical expertise and reputation for quality
customer service and by providing customers with technologically
advanced equipment and highly skilled operating personnel.
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Successful execution of growth strategy. Over
the past five years, we have grown both organically and through
successful acquisitions of competing businesses. Since 2001, we
have completed 19 acquisitions. We strive to improve the
operating performance of our acquired businesses by increasing
their asset utilization and operating efficiency. These
acquisitions and organic growth have expanded our geographic
presence and customer base and, in turn, have enabled us to
cross-sell various products and services through our existing
operating locations.
Diversified and increased cash flow
sources. We operate as a diversified oilfield
service company through our six business segments. We believe
that our product and service offerings and geographical presence
through our six business segments provide us with diverse
sources of cash flow. Our acquisition of DLS provides greater
international presence coupled with relatively stable long-term
drilling contracts. Our acquisition of Petro Rentals
significantly enhances our production-related services and
equipment, and our recent acquisition of substantially all the
assets of OGR further expands our rental tools segment and
increases our offshore and international operations.
Experienced management team. Our executive
management team has extensive experience in the energy sector,
and consequently has developed strong and longstanding
relationships with many of the major and independent exploration
and production companies. We believe that our management team
has demonstrated its ability to grow our businesses organically,
make strategic acquisitions and successfully integrate these
acquired businesses into our operations.
Business
Strategy
The key elements of our growth strategy include:
Mitigate cyclical risk through balanced
operations. We strive to mitigate cyclical risk
in the oilfield service sector by balancing our operations
between onshore versus offshore; drilling versus production;
rental tools versus service; domestic versus international; and
natural gas versus crude oil. We will continue to shape our
organic and acquisition growth efforts to provide further
balance across these five categories.
Expand geographically to provide greater access and service
to key customer segments. We have locations in
Texas, New Mexico, Colorado, Oklahoma and Louisiana in order to
enhance our proximity to customers and more efficiently serve
their needs. Our acquisition of DLS expanded our geographic
footprint into Argentina. We plan to continue to establish new
locations in the United States and internationally.
Prudently pursue strategic acquisitions. To
complement our organic growth, we seek to opportunistically
complete, at attractive valuations, strategic acquisitions that
will be accretive to earnings, complement our products and
services, expand our geographic footprint and market presence,
and further diversify our customer base.
Expand products and services provided in existing operating
locations. Since the beginning of 2004, we have
invested approximately $62.1 million in capital
expenditures to grow our business organically by expanding our
product and service offerings. This strategy is consistent with
our belief that oil and natural gas producers more heavily favor
integrated suppliers that can provide a broad product and
service offering in many geographic locations.
Increase utilization of assets. We seek to
increase revenues and enhance margins by continuing to increase
the utilization of our assets with new and existing customers.
We expect to accomplish this through leveraging longstanding
relationships with our customers and cross-selling our suite of
services and equipment, while taking advantage of continued
improvements in industry fundamentals. We also expect to
continue to implement this strategy in our recently expanded
rental tools segment, thus improving the utilization and
profitability of this newly acquired business with minimal
additional investment.
Business
Segments
Rental Tools. We provide specialized rental
equipment, including premium drill pipe, spiral heavy weight
drill pipe, tubing work strings, blow out preventors, choke
manifolds and various valves and handling
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tools, for both onshore and offshore well drilling, completion
and workover operations. Most wells drilled for oil and natural
gas require some form of rental equipment in both the drilling
and completion of a well. We have an inventory of specialized
equipment, which includes double studded adapters, test plugs,
wear bushings, adaptor spools, baskets, spacer spools and other
assorted handling tools in various sizes to meet our
customers demands. We charge customers for rental
equipment on a daily basis. Our customers are liable for the
cost of inspection, repairs and lost or damaged equipment. We
currently provide rental equipment in Texas, Oklahoma,
Louisiana, Mississippi, Colorado, offshore in the Gulf of Mexico
and internationally in Malaysia, Colombia, Russia, Mexico and
Canada.
Our rental tools segment was established with the acquisition of
Safco in September 2004 and of Delta in April 2005. We
significantly expanded our rental tools segment in January 2006
with the acquisition of Specialty. Specialty had been in the
rental business for over 25 years, providing oil and
natural gas operators and oilfield services companies with
rental equipment. The acquisition of Specialty gave us a broader
scope of rental equipment to offer our existing customer base,
and allowed us to better compete in deep water drilling
operations in the area of premium drill pipe and handling
equipment. The acquisition of Specialty added new customer
relationships and enhanced our relationships with key existing
customers. In February 2006, we merged Specialty and Delta into
Safco and named the entity, Allis-Chalmers Rental Tools, Inc.
which we subsequently renamed Allis-Chalmers Rental Services,
Inc. We further expanded this segment with the acquisition of
substantially all the assets of OGR in December 2006. The assets
we acquired included an extensive inventory of premium rental
equipment, including drill pipe, spiral heavy weight drill pipe,
tubing work strings, landing strings, blow out preventors, choke
manifolds and various valves and handling tools for oil and
natural gas drilling. Included in the acquisition were
OGRs facilities in Morgan City, Louisiana and Victoria,
Texas.
International Drilling. We provide drilling,
completion, workover and related services for oil and natural
gas wells. Headquartered in Buenos Aires, Argentina, DLS
operates out of the San Jorge, Cuyan, Neuquén, Austral
and Noroeste basins of Argentina. DLS also offers a wide variety
of other oilfield services such as drilling fluids and
completion fluids and engineering and logistics to complement
its customers field organization.
DLS operates a fleet of 51 rigs, including 20 drilling rigs, 18
workover rigs and 12 pulling rigs in Argentina and one drilling
rig in Bolivia. Argentine rig operations are generally conducted
in remote regions of the country and require substantial
infrastructure and support. As of March 1, 2007, all of
DLS rig fleet was actively marketed, except for one
drilling rig that is presently inactive and requires
approximately $6.4 million in capital expenditures.
DLS currently services several of the major and independent oil
and natural gas producing companies in Argentina, including Pan
American Energy, Repsol-YPF, Apache Corporation, Occidental
Petroleum Corporation and Total Austral SA. Major competitors of
DLS include Pride International, Inc., Servicios WellTech, S.A.,
Ensign Energy Services Inc. (formerly ODE), Nabors Industries
Ltd. and Helmerich & Payne, Inc.
Directional Drilling Services. We utilize
state-of-the-art
equipment to provide well planning and engineering services,
directional drilling packages, downhole motor technology, well
site directional supervision, exploratory and development
re-entry drilling, downhole guidance services and other drilling
services to our customers. We also provide
logging-while-drilling and measurement-while-drilling services.
We have a team of approximately 85 full-time directional
drillers and maintain a selection of approximately 160 drilling
motors. According to Baker Hughes, as of March 2, 2007, 42%
of all wells in the United States are drilled directionally
and/or
horizontally. Management believes directional drilling offers
several advantages over conventional drilling including:
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improvement of total cumulative recoverable reserves;
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improved reservoir production performance beyond conventional
vertical wells; and
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reduction of the number of field development wells.
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Our straight-hole motors offer opportunity to capture additional
market share. We currently provide our directional drilling
services in Texas, Louisiana, Oklahoma and Colorado.
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Casing and Tubing Services. We provide
specialized equipment and trained operators to perform a variety
of pipe handling services, including installing casing and
tubing, changing out drill pipe and retrieving production tubing
for both onshore and offshore drilling and workover operations,
which we refer to as casing and tubing services. All wells
drilled for oil and natural gas require casing to be installed
for drilling, and if the well is producing, tubing will be
required in the completion phase. We currently provide casing
and tubing services primarily in Texas, Louisiana and both
onshore and offshore in the Gulf of Mexico and Mexico.
We expanded our casing and tubing services in September 2005 by
acquiring the casing and tubing assets of IHS/Spindletop, a
division of Patterson Services, Inc., a subsidiary of RPC, Inc.
We paid $15.7 million for RPC, Inc.s casing and
tubing assets, which consisted of casing and tubing installation
equipment, including hammers, elevators, trucks, pickups, power
units, laydown machines, casing tools and torque turn equipment.
The acquisition of RPC, Inc.s casing and tubing assets
increased our capability in casing and tubing services and
expanded our geographic capability. We opened new field offices
in Corpus Christi, Texas, Kilgore, Texas, Lafayette, Louisiana
and Houma, Louisiana. The acquisition allowed us to enter the
East Texas and Louisiana market for casing and tubing services
as well as offshore in the Gulf of Mexico. Additionally, the
acquisition greatly expanded our premium tubing services.
We expanded this segment again in April 2006 with the
acquisition of Rogers for $13.7 million. Historically,
Rogers rented, sold and serviced power drill pipe tongs and
accessories and rental tongs for snubbing and well control
applications and provided specialized tong operators for rental
jobs. In December 2006, we merged Rogers into Tubular.
We provide equipment used in casing and tubing services in
Mexico to Matyep. Matyep provides equipment and services for
offshore and onshore drilling operations to Petroleos Mexicanos,
known as Pemex, in Villahermosa, Reynosa, Veracruz and Ciudad
del Carmen, Mexico. Matyep provides all personnel, repairs,
maintenance, insurance and supervision for provision of the
casing and tubing crew and torque turn service. Services to
offshore drilling operations in Mexico are traditionally
seasonal, with less activity during the first quarter of each
calendar year due to weather conditions.
For the years ended December 31, 2006, 2005 and 2004, our
Mexico operations accounted for approximately $6.5 million,
$6.4 million and $5.1 million, respectively, of our
revenues. We provide extended payment terms to Matyep and
maintain a high accounts receivable balance due to these terms.
The accounts receivable balance was approximately
$3.2 million at December 31, 2006 and approximately
$2.2 million at December 31, 2005. Tubular has been
providing services to Pemex in association with Matyep since
1997.
Compressed Air Drilling Services. We provide
compressed air equipment, chemicals and other specialized
products for underbalanced drilling and production applications.
With a combined fleet of over 175 compressors and boosters, we
believe we are one of the worlds largest providers of
compressed air or underbalanced drilling services in the United
States. We also provide premium air hammers and bits to oil and
natural gas companies for use in underbalanced drilling. Our
broad and diversified product line enables us to compete in the
underbalanced market with equipment and services packages
engineered and customized to specifically meet customer
requirements.
Underbalanced drilling shortens the time required to drill a
well and enhances production by minimizing formation damage.
There is a trend in the industry to drill, complete and workover
wells with underbalanced operations and we expect the market to
continue to grow.
In July 2005, we purchased the compressed air drilling assets of
W. T., operating in West Texas and acquired the remaining 45%
equity interest in AirComp from M-I. The acquired assets include
air compressors, boosters, mist pumps, rolling stock and other
equipment. These assets were integrated into AirComps
assets and complement and add to AirComps product and
service offerings. We currently provide compressed air drilling
services in Alabama, Arkansas, Colorado, Mississippi, New
Mexico, Oklahoma, Texas, Utah, West Virginia and Wyoming.
Production Services. We provide a variety of
quality production-related rental tools and equipment and
services, including wire line services, land and offshore
pumping services and coil tubing. We also provide specialized
equipment and trained operators to install and retrieve
capillary tubing, through which chemicals are injected into
producing wells to increase production and reduce corrosion.
Chemicals are injected through
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the tubing to targeted zones up to depths of approximately
20,000 feet. The result is improved production from
treatment of downhole corrosion, scale, paraffin and salt
build-up in
producing wells. Natural gas wells with low bottom pressures can
experience fluid accumulation in the tubing and well bore. This
injection system can inject a foaming agent which lightens the
fluids allowing them to flow out of the well. Additionally,
corrosion inhibitors can be introduced to reduce corrosion in
the well. In addition, we perform workover services with coiled
tubing units. Our production services segment was established
with the acquisition of Downhole, in December 2004, and the
acquisition of Capcoil, in May 2005. In February 2006, we merged
Downhole into Capcoil and named the new entity Allis-Chalmers
Production Services, Inc., or Production Services. In October
2006, we expanded our production services segment with the
acquisition of Petro Rentals. Petro Rentals serves both the
onshore and offshore markets, providing a variety of quality
rental tools and equipment and services, with an emphasis on
production-related equipment and services, including wire line
services and equipment, land and offshore pumping services and
coiled tubing.
We have an inventory of specialized equipment consisting of
capillary and coil tubing units in various sizes ranging from
1/4
to
11/4
along with nitrogen pumping and transportation equipment. We
purchased two additional capillary units and two additional coil
tubing units in 2006, one additional coil tubing unit was
received in the first quarter of 2007 and an additional coil
tubing unit is expected to be delivered by the end of the second
quarter of 2007. The new coil tubing units range in size from
11/4
to
13/4.
We also maintain a full range of stainless and carbon steel
coiled tubing and related supplies used in the installation of
the tubing. We sell or rent the tubing and charge a fee for its
installation, servicing and removal, which includes the service
personnel and associated equipment on a turnkey or hourly basis.
We do not provide the chemicals injected into the well. We
currently provide production services in Texas, Louisiana,
Oklahoma and Mexico.
Cyclical
Nature Of Oilfield Services Industry
The oilfield services industry is highly cyclical. The most
critical factor in assessing the outlook for the industry is the
worldwide supply and demand for oil and the domestic supply and
demand for natural gas. The peaks and valleys of demand are
further apart than those of many other cyclical industries. This
is primarily a result of the industry being driven by commodity
demand and corresponding price increases. As demand increases,
producers raise their prices. The price escalation enables
producers to increase their capital expenditures. The increased
capital expenditures ultimately result in greater revenues and
profits for services and equipment companies. The increased
capital expenditures also ultimately result in greater
production which historically has resulted in increased supplies
and reduced prices.
Demand for our services has been strong throughout 2004, 2005
and 2006. Management believes demand will remain strong
throughout 2007 due to high oil and natural gas prices and the
capital expenditure plans of the exploration and production
companies. Because of these market fundamentals for oil and
natural gas, management believes the long-term trend of activity
in our markets is favorable. However, these factors could be
more than offset by other developments affecting the worldwide
supply and demand for oil and natural gas products.
Customers
In 2006, one of our customers, Pan American Energy LLC Sucursal
Argentina, or Pan American Energy, represented 11.7% of our
consolidated revenues. In 2005, none of our customers accounted
for more than 10% of our revenues. Our primary customers are the
major and independent oil and natural gas companies operating in
the United States, Argentina and Mexico. In 2004, Matyep in
Mexico represented 10.8% and Burlington Resources Inc.
represented 10.1% of our consolidated revenues. The loss without
replacement of our larger existing customers could have a
material adverse effect on our results of operations.
Suppliers
The equipment utilized in our business is generally available
new from manufacturers or at auction. Currently, due to the high
level of activity in the oilfield services industry, there is a
high demand for new and used equipment. Consequently, there is a
limited amount of many types of equipment available at auction
and significant backlogs on new equipment. However, the cost of
acquiring new equipment to expand our business could increase as
a result of the high demand for equipment in the industry.
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Competition
We experience significant competition in all areas of our
business. In general, the markets in which we compete are highly
fragmented, and a large number of companies offer services that
overlap and are competitive with our services and products. We
believe that the principal competitive factors are technical and
mechanical capabilities, management experience, past performance
and price. While we have considerable experience, there are many
other companies that have comparable skills. Many of our
competitors are larger and have greater financial resources than
we do.
The rental tool business is highly fragmented with hundreds of
companies offering various rental tool services. Our largest
competitors include Weatherford, Quail Rental Tools, Knight
Rental Tools and W-H Energy Services (Thomas Tools).
Our five largest competitors in the contract drilling and
workover service business, which operate primarily in Argentina,
are Pride International, Servicios WellTech, Ensign Energy
Services (formerly ODE), Nabors and Helmerich & Payne.
We believe that there are five major directional drilling
companies, Schlumberger, Halliburton, Baker Hughes, W-H Energy
Services (Pathfinder) and Weatherford, that market both
worldwide and in the United States as well as numerous small
regional players.
Significant competitors in the casing and tubing markets we
serve include Franks Casing Crew and Rental Tools,
Weatherford, BJ Services, Tesco and Premier. These markets
remain highly competitive and fragmented with numerous casing
and tubing crew companies working in the United States. Our
primary competitors in Mexico are South American Enterprises and
Weatherford, both of which provide similar products and services.
Our largest competitor for compressed air drilling services is
Weatherford. Weatherford focuses on large projects, but also
competes in the more common compressed air, mist, foam and
aerated mud drilling applications. Other competition comes from
smaller regional companies.
We believe we own approximately 30% of the capillary tubing
units in the southwestern United States that are used for
capillary chemical injection services. There are two other
significant competitors in the capillary chemical injection
services portion of the production services market, Weatherford
and BJ Services. Additionally, in the coiled tubing services
market there are numerous competitors, most of which have larger
coiled tubing services operations than us.
Backlog
We do not view backlog of orders as a significant measure for
our business because our jobs are short-term in nature,
typically one to 30 days, without significant on-going
commitments.
Employees
Our strategy includes acquiring companies with strong management
and entering into long-term employment contracts with key
employees in order to preserve customer relationships and assure
continuity following acquisition. In general, we believe we have
good relations with our employees. None of our employees, other
than our DLS employees, are represented by a union. We actively
train employees across various functions, which we believe is
crucial to motivate our workforce and maximize efficiency.
Employees showing a higher level of skill are trained on more
technologically complex equipment and given greater
responsibility. All employees are responsible for on-going
quality assurance. At March 1, 2007, we had approximately
2,567 employees. Almost all of DLS operations are subject
to collective bargaining agreements. We believe that we maintain
a satisfactory relationship with the unions to which DLS
employees belong.
Insurance
We carry a variety of insurance coverages for our operations,
and we are partially self-insured for certain claims in amounts
that we believe to be customary and reasonable. However, there
is a risk that our insurance may not be sufficient to cover any
particular loss or that insurance may not cover all losses.
Insurance rates have in the past been subject to wide
fluctuation and changes in coverage could result in less
coverage, increases in cost or higher deductibles and retentions.
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Seasonality
Oil and natural gas operations of our customers located offshore
and onshore in the Gulf of Mexico and in Mexico may be adversely
affected by hurricanes and tropical storms, resulting in reduced
demand for our services. For example, in the summer of 2005, the
Gulf of Mexico suffered an unusually high number of hurricanes
with unusual intensity. In addition, our customers
operations in the Mid-Continent and Rocky Mountain regions of
the United States are also adversely affected by seasonal
weather conditions. These weather conditions limit our access to
these job sites and our ability to service wells in these areas.
These constraints decrease drilling activity and the resulting
shortages or high costs could delay our operations and
materially increase our operating and capital costs.
Federal
Regulations and Environmental Matters
Our operations are subject to federal, state and local laws and
regulations relating to the energy industry in general and the
environment in particular. Environmental laws have in recent
years become more stringent and have generally sought to impose
greater liability on a larger number of potentially responsible
parties. Because we provide services to companies producing oil
and natural gas, which are toxic substances, we may become
subject to claims relating to the release of such substances
into the environment. While we are not currently aware of any
situation involving an environmental claim that would likely
have a material adverse effect on us, it is possible that an
environmental claim could arise that could cause our business to
suffer. We do not anticipate any material expenditures to comply
with environmental regulations affecting our operations.
In addition to claims based on our current operations, we are
from time to time named in environmental claims relating to our
activities prior to our reorganization in 1988 (See
Item 3. Legal Proceedings).
Intellectual
Property Rights
Except for our relationships with our customers and suppliers
described above, we do not own any patents, trademarks,
licenses, franchises or concessions which we believe are
material to the success of our business. As part of our overall
corporate strategy to focus on our core business of providing
services to the oil and natural gas industry and to increase
stockholder value, we are investigating the sale or license of
our worldwide rights to trade names and logos for products and
services outside the energy sector.
Our business, financial condition, results of operations and the
trading price of our securities can be materially and adversely
affected by many events and conditions, including the following:
Risks
Associated With Our Company
We may
fail to acquire additional businesses, which will restrict our
growth and may have a material adverse effect on our stock price
or on our ability to meet our obligations under (and the price
of) our securities.
Our business strategy is to acquire companies operating in the
oilfield services industry. However, there can be no assurance
that we will be successful in acquiring any additional
companies. Successful acquisition of new companies will depend
on various factors, including but not limited to:
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our ability to obtain financing;
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the competitive environment for acquisitions; and
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the integration and synergy issues described in the next risk
factor.
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There can be no assurance that we will be able to acquire and
successfully operate any particular business or that we will be
able to expand into areas that we have targeted. If we fail to
acquire additional businesses, our financial condition, our
results of operations, the price of our common stock and our
ability to meet our obligations under long-term notes may be
materially adversely affected.
Difficulties
in integrating acquired businesses may result in reduced
revenues and income.
We may not be able to successfully integrate the businesses of
our operating subsidiaries or any business we may acquire in the
future. The integration of the businesses will be complex and
time consuming, will
13
place a significant strain on management and our information
systems, and this strain could disrupt our businesses.
Furthermore, if our combined businesses continue to grow
rapidly, we may be required to replace our current information
and accounting systems with systems designed for companies that
are larger than ours. We may be adversely impacted by unknown
liabilities of acquired businesses. We may encounter substantial
difficulties, costs and delays involved in integrating common
accounting, information and communication systems, operating
procedures, internal controls and human resources practices,
including incompatibility of business cultures and the loss of
key employees and customers. These difficulties may reduce our
ability to gain customers or retain existing customers, and may
increase operating expenses, resulting in reduced revenues and
income and a failure to realize the anticipated benefits of
acquisitions.
In particular, the Specialty, DLS and OGR acquisitions are our
largest acquisitions to date and, consequently, the inherent
integration risks may have a greater effect on us than the risks
posed by our previous acquisitions. We will be conducting parts
of the integration of these companies simultaneously, and as a
result we could strain our current resources. Furthermore, we
will depend on these entities continued performance as a
source of cash flow to service our debt obligations.
We have made numerous acquisitions during the past five years.
As a result of these transactions, our past performance is not
indicative of future performance, and investors should not base
their expectations as to our future performance on our
historical results.
Our
acquisition of DLS has substantially changed the nature of our
operations and business.
Our acquisition of DLS has substantially changed the nature and
geographic location of our operations and business as a result
of the character and location of DLS businesses, which
have substantially different operating characteristics and are
in different geographic locations from our other businesses.
Prior to our acquisition of DLS, we had operated as an oilfield
services company domestically in Texas, Louisiana, New Mexico,
Colorado, Oklahoma, Mississippi, Utah, Wyoming, offshore in the
Gulf of Mexico, and internationally in Mexico. DLS
business is located primarily in Argentina, and we have no
significant operations in South America other than through DLS.
Accordingly, this acquisition has subjected and will continue to
subject us to risks inherent in operating in a foreign country
where we do not have significant prior experience. DLS
business consists of employing drilling and workover rigs for
drilling, completion and repair services for oil and gas wells.
We do not own any drilling rigs or workover rigs other than
through DLS, and have not historically provided such services
prior to our acquisition of DLS. Consequently, we may not be
able to realize the economic benefits of this acquisition as
efficiently as in our prior acquisitions, if at all.
Failure
to maintain effective disclosure controls and procedures
and/or
internal controls over financial reporting could have a material
adverse effect on our operations.
As part of our growth strategy, we have recently completed
several acquisitions of privately-held businesses, including
closely-held entities, and in the future, we may make additional
strategic acquisitions of privately-held businesses. Prior to
becoming part of our consolidated company, these acquired
businesses have not been required to implement or maintain the
disclosure controls and procedures or internal controls over
financial reporting that federal law requires of publicly-held
companies such as ours. Similarly, it is likely that our future
acquired businesses will not have been required to maintain such
disclosure controls and procedures or internal controls prior to
their acquisition. Likewise, upon the completion of any future
acquisition, we will be required to integrate the acquired
business into our consolidated companys system of
disclosure controls and procedures and internal controls over
financial reporting, but we cannot assure you as to how long the
integration process may take for any business that we may
acquire. Furthermore, during the integration process, we may not
be able to fully implement our consolidated disclosure controls
and internal controls over financial reporting. With respect to
our acquisition of DLS and our recent acquisition of
substantially all of the assets of OGR, this risk is exacerbated
by each of DLS and OGRs relative size, when compared
to the rest of our consolidated company.
Likewise, during the course of our integration of any acquired
business (including DLS and OGR), we may identify needed
improvements to our or such acquired business internal
controls and may be required to design enhanced processes and
controls in order to make such improvements. This could result
in significant
14
delays and costs to us and could require us to divert
substantial resources, including management time, from other
activities.
If we fail to achieve and maintain the adequacy of our
disclosure controls and procedures
and/or our
internal controls, as such standards are modified, supplemented
or amended from time to time, we may not be able to conclude
that we have effective disclosure controls and procedures
and/or
effective internal controls over financial reporting in
accordance with Section 404 of the Sarbanes-Oxley Act. If:
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we are not successful in improving our financial reporting
process, our disclosure controls and procedures
and/or our
internal controls over financial reporting;
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we identify deficiencies
and/or one
or more material weaknesses in our internal controls over
financial reporting; or
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we are not successful in integrating acquired businesses (such
as DLS and OGR) into our consolidated companys system of
disclosure controls and procedures and internal controls over
financial reporting,
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then our independent registered public accounting firm may be
unable to attest that our managements assessment of our
internal controls over financial reporting is fairly stated, or
they may be unable to express an opinion on our
managements evaluation of, or on the effectiveness of, our
internal controls.
If it is determined that our disclosure controls and procedures
and/or our
internal controls over financial reporting are not effective
and/or we
fail to satisfy the requirements of Section 404 of the
Sarbanes-Oxley Act on a timely basis, we may not be able to
provide reliable financial and other reports or prevent fraud,
which, in turn, could harm our business and operating results,
cause investors to lose confidence in the accuracy and
completeness of our financial reports, have a material adverse
effect on the trading price of our common stock
and/or
adversely affect our ability to timely file our periodic reports
with the SEC. Any failure to timely file our periodic reports
with the SEC may give rise to a default under the indentures
governing our outstanding 9.0% senior notes due 2014, and
our outstanding 8.5% senior notes due 2017 (which we refer
to collectively as our outstanding senior notes) and any other
debt securities we may offer and, ultimately, an acceleration of
amounts due thereunder. In addition, a default under the
indentures generally will also give rise to a default under our
credit agreement and could cause the acceleration of amounts due
under the credit agreement. If an acceleration of our
outstanding senior notes or our other debt were to occur, we
cannot assure you that we would have sufficient funds to repay
such obligations.
Historically,
we have been dependent on a few customers operating in a single
industry; the loss of one or more customers could adversely
affect our financial condition and results of
operations.
Our customers are engaged in the oil and natural gas drilling
business in the United States, Mexico and elsewhere.
Historically, we have been dependent upon a few customers for a
significant portion of our revenues. In 2006, one of our
customers, Pan American Energy represented 11.7% of our
consolidated revenues. In 2005, no single customer generated
over 10% of our revenues. In 2004, Matyep represented 10.8% of
our revenues, and Burlington Resources represented 10.1% of our
revenues. Additionally, DLS currently relies on one customer for
a majority of its revenue. In 2006, Pan American Energy
represented 51.9% of DLS revenues. In 2005, Pan American
Energy represented 55% of DLS revenues. This concentration
of customers may increase our overall exposure to credit risk,
and customers will likely be similarly affected by changes in
economic and industry conditions. Our financial condition and
results of operations will be materially adversely affected if
one or more of our significant customers fails to pay us or
ceases to contract with us for our services on terms that are
favorable to us or at all.
Our
international operations may expose us to political and other
uncertainties, including risks of:
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terrorist acts, war and civil disturbances;
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changes in laws or policies regarding the award of contracts; and
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the inability to collect or repatriate currency, income, capital
or assets.
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Part of our strategy is to prudently and opportunistically
acquire businesses and assets that complement our existing
products and services, and to expand our geographic footprint.
If we make acquisitions in other countries, we may increase our
exposure to the risks discussed above.
15
Environmental
liabilities could result in substantial losses.
Since our reorganization under the U.S. federal bankruptcy
laws in 1988, a number of parties, including the Environmental
Protection Agency, have asserted that we are responsible for the
cleanup of hazardous waste sites with respect to our
pre-bankruptcy activities. We believe that such claims are
barred by applicable bankruptcy law, and we have not experienced
any material expense in relation to any such claims. However, if
we do not prevail with respect to these claims in the future, or
if additional environmental claims are asserted against us
relating to our current or future activities in the oil and
natural gas industry, we could become subject to material
environmental liabilities that could have a material adverse
effect on our financial condition and results of operations.
Products
liability claims relating to discontinued operations could
result in substantial losses.
Since our reorganization under the U.S. federal bankruptcy
laws in 1988, we have been regularly named in products liability
lawsuits primarily resulting from the manufacture of products
containing asbestos. In connection with our bankruptcy, a
special products liability trust was established to address
products liability claims. We believe that claims against us are
barred by applicable bankruptcy law, and that the products
liability trust will continue to be responsible for products
liability claims. Since 1988, no court has ruled that we are
responsible for products liability claims. However, if we are
held responsible for product liability claims, we could suffer
substantial losses that could have a material adverse effect on
our financial condition and results of operations. We have not
manufactured products containing asbestos since our
reorganization in 1988.
We may
be subject to claims for personal injury and property damage,
which could materially adversely affect our financial condition
and results of operations.
Our products and services are used for the exploration and
production of oil and natural gas. These operations are subject
to inherent hazards that can cause personal injury or loss of
life, damage to or destruction of property, equipment, the
environment and marine life, and suspension of operations.
Litigation arising from an accident at a location where our
products or services are used or provided may cause us to be
named as a defendant in lawsuits asserting potentially large
claims. We maintain customary insurance to protect our business
against these potential losses. Our insurance has deductibles or
self-insured retentions and contains certain coverage
exclusions. However, we could become subject to material
uninsured liabilities that could have a material adverse effect
on our financial condition and results of operations.
The
loss of key executives would adversely affect our ability to
effectively finance and manage our business, acquire new
businesses, and obtain and retain customers.
We are dependent upon the efforts and skills of our executives
to finance and manage our business, identify and consummate
additional acquisitions and obtain and retain customers. These
executives include:
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Chief Executive Officer and Chairman Munawar H.
Hidayatallah; and
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Vice Chairman, President and Chief Operating Officer Burt A.
Adams.
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In December 2006, David Wilde resigned as our President and
Chief Operating Officer. In light of Mr. Wildes
significant contributions to our recent growth, his resignation
could have a material adverse effect on our future performance.
In addition, our development and expansion will require
additional experienced management and operations personnel. No
assurance can be given that we will be able to identify and
retain these employees. The loss of the services of one or more
of our key executives could increase our exposure to the other
risks described in this Risk Factors section. We do
not maintain key man insurance on any of our personnel.
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Risks
Associated With Our Industry
Cyclical
declines in oil and natural gas prices may result in reduced use
of our services, affecting our business, financial condition and
results of operations and our ability to meet our capital
expenditure obligations and financial commitments.
The oil and natural gas exploration and drilling business is
highly cyclical. Generally, as oil and natural gas prices
decrease, exploration and drilling activity declines as
marginally profitable projects become uneconomic and are either
delayed or eliminated. Declines in the number of operating
drilling rigs result in reduced use of and prices for our
services. Accordingly, when oil and natural gas prices are
relatively low, our revenues and income will suffer. Oil and
natural gas prices depend on many factors beyond our control,
including the following:
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economic conditions in the United States and elsewhere;
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changes in global supply and demand for oil and natural gas;
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the level of production of the Organization of Petroleum
Exporting Countries, commonly called OPEC;
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the level of production of non-OPEC countries;
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the price and quantity of imports of foreign oil and natural gas;
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political conditions, including embargoes, in or affecting other
oil and natural gas producing activities;
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the level of global oil and natural gas inventories; and
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advances in exploration, development and production technologies.
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Depending on the market prices of oil and natural gas, companies
exploring for oil and natural gas may cancel or curtail their
drilling programs, thereby reducing demand for drilling
services. Our contracts are generally short-term, and oil and
natural gas companies tend to respond quickly to upward or
downward changes in prices. Any reduction in the demand for
drilling services may materially erode both pricing and
utilization rates for our services and adversely affect our
financial results. As a result, we may suffer losses, be unable
to make necessary capital expenditures and be unable to meet our
financial obligations.
Our
industry is highly competitive, with intense price
competition.
The markets in which we operate are highly competitive.
Contracts are traditionally awarded on a competitive bid basis.
Pricing is often the primary factor in determining which
qualified contractor is awarded a job. The competitive
environment has intensified as recent mergers among oil and
natural gas companies have reduced the number of available
customers. Many other oilfield services companies are larger
than we are and have resources that are significantly greater
than our resources. These competitors are better able to
withstand industry downturns, compete on the basis of price and
acquire new equipment and technologies, all of which could
affect our revenues and profitability. These competitors compete
with us both for customers and for acquisitions of other
businesses. This competition may cause our business to suffer.
We believe that competition for contracts will continue to be
intense in the foreseeable future.
We may
experience increased labor costs or the unavailability of
skilled workers and the failure to retain key personnel could
hurt our operations.
Companies in our industry, including us, are dependent upon the
available labor pool of skilled employees. We compete with other
oilfield services businesses and other employers to attract and
retain qualified personnel with the technical skills and
experience required to provide our customers with the highest
quality service. We are also subject to the Fair Labor Standards
Act, which governs such matters as minimum wage, overtime and
other working conditions. A shortage in the labor pool of
skilled workers or other general inflationary pressures or
changes in applicable laws and regulations could make it more
difficult for us to attract and retain personnel and could
require us to enhance our wage and benefits packages. There can
be no assurance that labor costs will not increase. Any increase
in our operating costs could cause our business to suffer.
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Severe
weather could have a material adverse impact on our
business.
Our business could be materially and adversely affected by
severe weather. Repercussions of severe weather conditions may
include:
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curtailment of services;
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weather-related damage to facilities and equipment resulting in
suspension of operations;
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inability to deliver materials to job sites in accordance with
contract schedules; and
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loss of productivity.
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In addition, oil and natural gas operations of our customers
located offshore and onshore in the Gulf of Mexico and in Mexico
may be adversely affected by hurricanes and tropical storms,
resulting in reduced demand for our services. Further, our
customers operations in the Mid-Continent and Rocky
Mountain regions of the United States are also adversely
affected by seasonal weather conditions. This limits our access
to these job sites and our ability to service wells in these
areas. These constraints decrease drilling activity and the
resulting shortages or high costs could delay our operations and
materially increase our operating and capital costs.
Our
business may be affected by terrorist activity and by security
measures taken in response to terrorism.
We may experience loss of business or delays or defaults in
payments from payers that have been affected by actual or
potential terrorist activities. Some oil and natural gas
drilling companies have implemented security measures in
response to potential terrorist activities, including access
restrictions, that could adversely affect our ability to market
our services to new and existing customers and could increase
our costs. Terrorist activities and potential terrorist
activities and any resulting economic downturn could adversely
impact our results of operations, impair our ability to raise
capital or otherwise adversely affect our ability to grow our
business.
We are
subject to government regulations.
We are subject to various federal, state, local and foreign laws
and regulations relating to the energy industry in general and
the environment in particular. Environmental laws have in recent
years become more stringent and have generally sought to impose
greater liability on a larger number of potentially responsible
parties. Although we are not aware of any proposed material
changes in any federal, state, local or foreign statutes, rules
or regulations, any changes could materially affect our
financial condition and results of operations.
Risks
Associated With DLS Business and Industry
A
material or extended decline in expenditures by oil and gas
companies due to a decline or volatility in oil and gas prices,
a decrease in demand for oil and gas or other factors may reduce
demand for DLS services and substantially reduce DLS
revenues, profitability, cash flows
and/or
liquidity.
The profitability of DLS operations depends upon
conditions in the oil and natural gas industry and,
specifically, the level of exploration and production
expenditures of oil and gas company customers. The oil and
natural gas industry is cyclical and subject to governmental
price controls. The demand for contract drilling and related
services is directly influenced by many factors beyond DLS
control, including:
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oil and gas prices and expectations about future prices;
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the demand for oil and gas, both in Latin America and globally;
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the cost of producing and delivering oil and natural gas;
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advances in exploration, development and production technology;
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government regulations, including governmental imposed commodity
price controls, export controls and renationalization of a
countrys oil and natural gas industry;
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local and international political and economic conditions;
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the ability of OPEC to set and maintain production levels and
prices;
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the level of production by non-OPEC countries; and
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the policies of various governments regarding exploration and
development of their oil and gas reserves.
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Depending on the factors outlined above, companies exploring for
oil and natural gas may cancel or curtail their drilling
programs, thereby reducing demand for drilling services. Such a
reduction in demand may erode daily rates and utilization of
DLS rigs. Any significant decrease in daily rates or
utilization of DLS rigs could materially reduce DLS
revenues, profitability, cash flows
and/or
liquidity.
A
majority of DLS revenues are derived from one customer.
The termination of the contract with this customer could have a
significant negative effect on the revenues, results of
operations and financial condition of DLS.
A majority of DLS revenues are currently received pursuant
to a strategic agreement with Pan American Energy. Pan American
Energy is a joint venture that is owned 60% by British Petroleum
and 40% by Bridas Corporation, an affiliate of the former DLS
stockholders from which we acquired DLS, and which we refer to
collectively as the DLS sellers. This agreement terminates on
June 30, 2008. However, Pan American Energy may terminate
the agreement (i) without cause at any time with
60 days notice, or (ii) in the event of a breach
of the agreement by DLS if such breach is not cured within
20 days of notice of the breach. DLS is currently in
negotiations to extend this agreement to December 2010.
Because a majority of DLS revenues are currently generated
under this agreement, DLS revenues and earnings will be
materially adversely affected if this agreement is terminated
unless DLS is able to enter into a satisfactory substitute
arrangement. We cannot assure you that in the event of such a
termination DLS would be able to enter into a substitute
arrangement on terms similar to those contained in the current
agreement with Pan American Energy.
DLS
operations and financial condition could be affected by union
activity and general labor unrest. Additionally, DLS labor
expenses could increase as a result of governmental regulation
of payments to employees.
In Argentina, labor organizations have substantial support and
have considerable political influence. The demands of labor
organizations have increased in recent years as a result of the
general labor unrest and dissatisfaction resulting from the
disparity between the cost of living and salaries in Argentina
as a result of the devaluation of the Argentine peso. There can
be no assurance that DLS will not face labor disruptions in the
future or that any such disruptions will not have a material
adverse effect on DLS financial condition or results of
operations.
The Argentine government has in the past and may in the future
promulgate laws, regulations and decrees requiring companies in
the private sector to maintain minimum wage levels and provide
specified benefits to employees, including significant mandatory
severance payments. In the aftermath of the Argentine economic
crisis of 2001 and 2002, both the government and private sector
companies have experienced significant pressure from employees
and labor organizations relating to wage levels and employee
benefits. In early 2005, the Argentine government promised not
to order salary increases by decree. However, there has been no
abatement of pressure to mandate salary increases, and it is
possible the government will adopt measures that will increase
salaries or require DLS to provide additional benefits, which
would increase DLS costs and potentially reduce DLS
profitability, cash flow
and/or
liquidity.
Rig
upgrade, refurbishment and construction projects are subject to
risks, including delays and cost overruns, which could have an
adverse effect on DLS results of operations and cash
flows.
DLS often has to make upgrade and refurbishment expenditures for
its rig fleet to comply with DLS quality management and
preventive maintenance system or contractual requirements or
when repairs are required in response to an inspection by a
governmental authority. DLS may also make significant
expenditures when it moves rigs from one location to another.
Additionally, DLS may make substantial
19
expenditures for the construction of new rigs. Rig upgrade,
refurbishment and construction projects are subject to the risks
of delay or cost overruns inherent in any large construction
project, including the following:
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shortages of material or skilled labor;
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unforeseen engineering problems;
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unanticipated change orders;
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work stoppages;
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adverse weather conditions;
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long lead times for manufactured rig components;
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unanticipated cost increases; and
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inability to obtain the required permits or approvals.
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Significant cost overruns or delays could adversely affect
DLS financial condition and results of operations.
Additionally, capital expenditures for rig upgrade,
refurbishment or construction projects could exceed DLS
planned capital expenditures, impairing DLS ability to
service its debt obligations.
An
oversupply of comparable rigs in the geographic markets in which
DLS competes could depress the utilization rates and dayrates
for DLS rigs and materially reduce DLS revenues and
profitability.
Utilization rates, which are the number of days a rig actually
works divided by the number of days the rig is available for
work, and dayrates, which are the contract prices customers pay
for rigs per day, are also affected by the total supply of
comparable rigs available for service in the geographic markets
in which DLS competes. Improvements in demand in a geographic
market may cause DLS competitors to respond by moving
competing rigs into the market, thus intensifying price
competition. Significant new rig construction could also
intensify price competition. In the past, there have been
prolonged periods of rig oversupply with correspondingly
depressed utilization rates and dayrates largely due to earlier,
speculative construction of new rigs. Improvements in dayrates
and expectations of longer-term, sustained improvements in
utilization rates and dayrates for drilling rigs may lead to
construction of new rigs. These increases in the supply of rigs
could depress the utilization rates and dayrates for DLS
rigs and materially reduce DLS revenues and profitability.
Worldwide
political and economic developments may hurt DLS
operations materially.
Currently, DLS derives substantially all of its revenues from
operations in Argentina and a small portion from operations in
Bolivia. DLS operations are subject to the following
risks, among others:
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expropriation of assets;
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nationalization of components of the energy industry in the
geographic areas where DLS operates;
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foreign currency fluctuations and devaluation;
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new economic and tax policies;
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restrictions on currency, income, capital or asset repatriation;
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political instability, war and civil disturbances;
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uncertainty or instability resulting from armed hostilities or
other crises in the Middle East or the geographic areas in which
DLS operates; and
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acts of terrorism.
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DLS attempts to limit the risks of currency fluctuation and
restrictions on currency repatriation where possible by
obtaining contracts providing for payment of a percentage of the
contract in U.S. dollars or freely convertible foreign
currency. To the extent possible, DLS seeks to limit its
exposure to local currencies by matching the acceptance of local
currencies to DLS expense requirements in those
currencies. Although DLS has done this in the past, DLS may not
be able to take these actions in the future, thereby exposing
DLS to foreign currency fluctuations that could cause its
results of operations, financial condition and cash flows to
deteriorate materially.
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Over the past several years, Argentina and Bolivia have
experienced political and economic instability that resulted in
significant changes in their general economic policies and
regulations.
DLS derives a small portion of its revenues from operating one
drilling rig in Bolivia. Recently, Bolivian President Evo
Morales announced the nationalization of Bolivias natural
gas industry and ordered the Bolivian military to occupy
Bolivias natural gas fields. This measure will likely
adversely affect the Bolivian operations of foreign oil and
natural gas companies operating in Bolivia, including DLS
customers and potential future customers, and accordingly,
DLS prospects for future business in Bolivia may be
harmed. In addition, in light of these recent political
developments in Bolivia, DLS assets in Bolivia may be
subject to an increased risk of expropriation or government
imposed restrictions on movement to a new location.
In light of the early stage and uncertainty of political
developments affecting the energy industry in Bolivia, we are
unable to predict the effect that recent events may have on
DLS operations, financial results or business plans. There
is a risk that the changes resulting from the recent events in
Bolivia will adversely affect DLS financial position or
results of operations, and DLS operations may be further
adversely affected by continuing economic and political
instability in Bolivia. Furthermore, if nationalistic measures
similar to those developing in Bolivia were to be adopted in
other countries where DLS may in the future seek drilling
contracts, DLS prospects in such countries may be
adversely affected.
DLS operations are also subject to other risks, including
foreign monetary and tax policies, expropriation,
nationalization and nullification or modification of contracts.
Additionally, DLS ability to compete may be limited by
foreign governmental regulations that favor or require the
awarding of contracts to local contractors or by regulations
requiring foreign contractors to employ citizens of, or purchase
supplies from, a particular jurisdiction. Furthermore, DLS may
face governmentally imposed restrictions from time to time on
its ability to transfer funds.
Devaluation
of the Argentine peso will adversely affect DLS results of
operations.
The Argentine peso has been subject to significant devaluation
in the past and may be subject to significant fluctuations in
the future. Given the economic and political uncertainties in
Argentina, it is impossible to predict whether, and to what
extent, the value of the Argentine peso may depreciate or
appreciate against the U.S. dollar. We cannot predict how
these uncertainties will affect DLS financial results, but
there is a risk that DLS financial performance could be
adversely affected. Moreover, we cannot predict whether the
Argentine government will further modify its monetary policy
and, if so, what effect any of these changes could have on the
value of the Argentine peso. Such changes could have an adverse
effect on DLS financial condition and results of
operations.
Argentina
continues to face considerable political and economic
uncertainty.
Although general economic conditions have shown improvement and
political protests and social disturbances have diminished
considerably since the economic crisis of 2001 and 2002, the
rapid and radical nature of the changes in the Argentine social,
political, economic and legal environment over the past several
years and the absence of a clear political consensus in favor of
any particular set of economic policies have given rise to
significant uncertainties about the countrys economic and
political future. It is currently unclear whether the economic
and political instability experienced over the past several
years will continue and it is possible that, despite recent
economic growth, Argentina may return to a deeper recession,
higher inflation and unemployment and greater social unrest. If
instability persists, there could be a material adverse effect
on DLS results of operations and financial condition.
In the event of further social or political crisis, companies in
Argentina may also face the risk of further civil and social
unrest, strikes, expropriation, nationalization, forced
renegotiation or modification of existing contracts and changes
in taxation policies, including royalty and tax increases and
retroactive tax claims.
In addition, investments in Argentine companies may be further
affected by changes in laws and policies of the United States
affecting foreign trade, taxation and investment.
21
An
increase in inflation could have a material adverse effect on
DLS results of operations.
The devaluation of the Argentine peso created pressures on the
domestic price system that generated high rates of inflation in
2002 before substantially stabilizing in 2003 and remaining
stable in 2004. In 2005, however, inflation rates began to
increase. In addition, in response to the economic crisis in
2002, the federal government granted the Central Bank greater
control over monetary policy than was available to it under the
previous monetary regime, known as the
Convertibility regime, including the ability to
print currency, to make advances to the federal government to
cover its anticipated budget deficit and to provide financial
assistance to financial institutions with liquidity problems. We
cannot assure you that inflation rates will remain stable in the
future. Significant inflation could have a material adverse
effect on DLS results of operations and financial
condition.
DLS
customers may seek to cancel or renegotiate some of DLS
drilling contracts during periods of depressed market conditions
or if DLS experiences operational difficulties.
Substantially all of DLS contracts with major customers
are dayrate contracts, where DLS charges a fixed charge per day
regardless of the number of days needed to drill the well.
During depressed market conditions, a customer may no longer
need a rig that is currently under contract or may be able to
obtain a comparable rig at a lower daily rate. As a result,
customers may seek to renegotiate the terms of their existing
drilling contracts or avoid their obligations under those
contracts. In addition, DLS customers may have the right
to terminate existing contracts if DLS experiences operational
problems. The likelihood that a customer may seek to terminate a
contract for operational difficulties is increased during
periods of market weakness. The cancellation of a number of
DLS drilling contracts could materially reduce DLS
revenues and profitability.
DLS is
subject to numerous governmental laws and regulations, including
those that may impose significant liability on DLS for
environmental and natural resource damages.
Many aspects of DLS operations are subject to laws and
regulations that may relate directly or indirectly to the
contract drilling and well servicing industries, including those
requiring DLS to control the discharge of oil and other
contaminants into the environment or otherwise relating to
environmental protection. The countries where DLS operates have
environmental laws and regulations covering the discharge of oil
and other contaminants and protection of the environment in
connection with operations. Failure to comply with these laws
and regulations may result in the assessment of administrative,
civil and even criminal penalties, the imposition of remedial
obligations, and the issuance of injunctions that may limit or
prohibit DLS operations. Laws and regulations protecting
the environment have become more stringent in recent years and
may in certain circumstances impose strict liability, rendering
DLS liable for environmental and natural resource damages
without regard to negligence or fault on DLS part. These
laws and regulations may expose DLS to liability for the conduct
of, or conditions caused by, others or for acts that were in
compliance with all applicable laws at the time the acts were
performed. The application of these requirements, the
modification of existing laws or regulations or the adoption of
new laws or regulations curtailing exploratory or development
drilling for oil and gas could materially limit future contract
drilling opportunities or materially increase DLS costs or
both.
DLS is
subject to hazards customary for drilling operations, which
could adversely affect its financial
performance if DLS is not adequately indemnified or
insured.
Substantially all of DLS operations are subject to hazards
that are customary for oil and gas drilling operations,
including blowouts, reservoir damage, loss of well control,
cratering, oil and gas well fires and explosions, natural
disasters, pollution and mechanical failure. Any of these risks
could result in damage to or destruction of drilling equipment,
personal injury and property damage, suspension of operations or
environmental damage. Generally, drilling contracts provide for
the division of responsibilities between a drilling company and
its customer, and DLS generally obtains indemnification from its
customers by contract for some of these risks. However, there
may be limitations on the enforceability of indemnification
provisions that allow a contractor to be indemnified for damages
resulting from the contractors fault. To the extent that
DLS is unable to transfer such risks to customers by contract or
indemnification agreements, DLS generally seeks protection
through insurance. However, DLS has a significant amount of
self-insured retention or deductible
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for certain losses relating to workers compensation,
employers liability, general liability and property
damage. There is no assurance that such insurance or
indemnification agreements will adequately protect DLS against
liability from all of the consequences of the hazards and risks
described above. The occurrence of an event not fully insured or
for which DLS is not indemnified against, or the failure of a
customer or insurer to meet its indemnification or insurance
obligations, could result in substantial losses. In addition,
there can be no assurance that insurance will continue to be
available to cover any or all of these risks, or, even if
available, that insurance premiums or other costs will not rise
significantly in the future, so as to make the cost of such
insurance prohibitive.
Risks
Associated With an Investment in Our Common Stock
In
connection with our recent acquisitions of DLS and substantially
all the assets of OGR, the DLS
sellers have the right to designate two nominees for election to
our board of directors and OGR has the right to designate one
nominee for election to our board of directors. The interests of
the DLS sellers and OGR may be different from
yours.
The DLS sellers collectively hold 2.5 million shares of our
common stock, representing approximately 7.3% of our issued and
outstanding shares as of March 1, 2007. Under the investors
rights agreement that we entered into in connection with the DLS
acquisition, the DLS sellers have the right to designate two
nominees for election to our board of directors. OGR holds
3.2 million shares of our common stock, representing
approximately 9.3% of our issued and outstanding shares as of
March 1, 2007. Under the investor rights agreement that we
entered into in connection with the OGR acquisition, OGR has the
right to designate one nominee for election to our board of
directors. As a result, the DLS sellers and OGR have a greater
ability to determine the composition of our board of directors
and to control our future operations and strategy as compared to
the voting power and control that could be exercised by a
stockholder owning the same number of shares and not benefiting
from board designation rights.
Conflicts of interest between the DLS sellers and OGR, on the
one hand, and other holders of our securities, on the other
hand, may arise with respect to sales of shares of capital stock
owned by the DLS sellers or OGR or other matters. In addition,
the interests of the DLS sellers or OGR regarding any proposed
merger or sale may differ from the interests of other holders of
our securities.
The board designation rights described above could also have the
effect of delaying or preventing a change in our control or
otherwise discouraging a potential acquirer from attempting to
obtain control of us, which in turn could have a material and
adverse effect on the market price of our securities
and/or our
ability to meet our obligations thereunder.
We may
have a contingent liability arising out of a possible violation
of Section 5 of the Securities Act in connection with
electronic communications sent to potential investors in our
common stock.
On or about July 20, 2006, one of the proposed underwriters
of our common stock offering, which closed on August 14,
2006, sent
e-mails
and/or
instant messages to approximately 20 potential investors in our
common stock. Although we did not authorize these
communications, and we believe they were not made or intended to
be made on our behalf, these communications may have constituted
violations of Section 5 of the Securities Act. Accordingly,
if the recipients of these emails purchased shares in the August
2006 common stock offering, they might have the right, under
certain circumstances, to require us to repurchase those shares.
Consequently, we could have a contingent liability arising out
of these possible violations of the Securities Act. The
magnitude of this liability is presently impossible to quantify,
and would depend upon the number of shares purchased by the
recipients of such communications and the trading price of our
common stock. However, the proposed underwriter who sent these
electronic communications did not act as an underwriter in the
August 2006 common stock offering, and we and the underwriters
that did participate in the August 2006 common stock offering
took measures designed to ensure that the recipients of the
communications did not have the opportunity to purchase shares
in that offering. Furthermore, if any investors in our common
stock do assert any such liability, we intend to contest the
matter vigorously, and in light of the remedial measures and our
belief that the communications were not made or intended to be
made on our behalf, we do not believe that any such liability
would be material to our financial condition.
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Our
stock price may decrease in response to various factors, which
could adversely affect our business and cause our stockholders
to suffer significant losses. These factors
include:
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decreases in prices for oil and natural gas resulting in
decreased demand for our services;
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variations in our operating results and failure to meet
expectations of investors and analysts;
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increases in interest rates;
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the loss of customers;
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failure of customers to pay for our services;
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competition;
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illiquidity of the market for our common stock;
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developments specifically affecting the Argentine economy;
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sales of common stock by existing stockholders; and
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other developments affecting us or the financial markets.
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A reduced stock price will result in a loss to investors and
will adversely affect our ability to issue stock to fund our
activities.
Existing
stockholders interest in us may be diluted by additional
issuances of equity securities.
We expect to issue additional equity securities to fund the
acquisition of additional businesses and pursuant to employee
benefit plans. We may also issue additional equity for other
purposes. These securities may have the same rights as our
common stock or, alternatively, may have dividend, liquidation,
or other preferences to our common stock. The issuance of
additional equity securities will dilute the holdings of
existing stockholders and may reduce the share price of our
common stock.
We do
not expect to pay dividends on our common stock, and investors
will be able to receive cash in respect of the shares of common
stock only upon the sale of the shares.
We have not paid any cash dividends on our common stock within
the last ten years, and we have no intention in the foreseeable
future to pay any cash dividends on our common stock.
Furthermore, our credit agreement, the indenture governing our
outstanding senior notes restrict our ability to pay dividends
on our common stock. Therefore, an investor in our common stock
will obtain an economic benefit from the common stock only after
an increase in its trading price and only by selling the common
stock.
Substantial
sales of our common stock could adversely affect our stock
price.
Sales of a substantial number of shares of common stock, or the
perception that such sales could occur, could adversely affect
the market price of our common stock by introducing a large
number of sellers to the market. Such sales could cause the
market price of our common stock to decline.
We have 34,251,443 shares outstanding as of March 1,
2007. At December 31, 2006, we had reserved an additional
3,099,365 shares of common stock for issuance under our
equity compensation plans, of which 1,346,365 shares were
issuable upon the exercise of outstanding options with a
weighted average exercise price of $7.02 per share. In
addition, we have reserved 4,000 shares of common stock for
issuance upon the exercise of outstanding options (with an
exercise price of $13.75 per share) granted to former and
continuing board members in 1999 and 2000. At December 31,
2006, we also have reserved 4,000 shares of common stock
for issuance upon the exercise of outstanding warrants (with an
exercise price of $4.65 per share).
In connection with our acquisition of DLS, we entered into an
investors rights agreement with the seller parties to the DLS
stock purchase agreement, who collectively hold 2.5 million
shares of our common stock. In connection with our acquisition
of substantially all the assets of OGR, we entered into an
investor rights agreement with OGR, who holds 3.2 million
shares of our common stock. Under these agreements, the DLS
sellers and OGR are entitled to certain rights with respect to
the registration of the sale of such shares under the Securities
Act. By exercising their registration rights and causing a large
number of shares to be sold in the public market, these holders
could cause the market price of our common stock to decline.
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We cannot predict whether future sales of our common stock, or
the availability of our common stock for sale, will adversely
affect the market price for our common stock or our ability to
raise capital by offering equity securities.
Risks
Associated With Our Indebtedness
We
have a substantial amount of debt, which could adversely affect
our financial health and prevent us from making principal and
interest payments on our outstanding senior notes and our other
debt.
At December 31, 2006, after giving effect to the sale of
the senior notes and the issuance of our common stock in January
2007 and the application of the proceeds therefrom, as if such
transaction had occurred on that date, we had approximately
$518.4 million of consolidated total indebtedness
outstanding and approximately $15.3 million of additional
secured borrowing capacity available under our credit agreement.
Our substantial debt could:
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make it more difficult for us to satisfy our obligations with
respect to our outstanding senior notes, any other debt
securities we may offer and our other debt;
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increase our vulnerability to general adverse economic and
industry conditions, including declines in oil and natural gas
prices and declines in drilling activities;
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limit our ability to obtain additional financing for future
working capital, capital expenditures, mergers and other general
corporate purposes;
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require us to dedicate a substantial portion of our cash flow
from operations to payments on our debt, thereby reducing the
availability of our cash flow for operations and other purposes;
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limit our flexibility in planning for, or reacting to, changes
in our business and the industry in which we operate;
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make us more vulnerable to increases in interest rates;
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place us at a competitive disadvantage compared to our
competitors that have less debt; and
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have a material adverse effect on us if we fail to comply with
the covenants in the indentures relating to our outstanding
senior notes, and any other debt securities we may offer or in
the instruments governing our other debt.
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In addition, we may incur substantial additional debt in the
future. Each of the indentures governing our outstanding senior
notes permits (and we anticipate that the indentures governing
any other debt securities we may offer will also permit) us to
incur additional debt, and our credit agreement permits
additional borrowings. If new debt is added to our current debt
levels, these related risks could increase.
We may not maintain sufficient revenues to sustain profitability
or to meet our capital expenditure requirements and our
financial obligations. Also, we may not be able to generate a
sufficient amount of cash flow to meet our debt service
obligations.
Our ability to make scheduled payments or to refinance our
obligations with respect to our debt will depend on our
financial and operating performance, which, in turn, is subject
to prevailing economic conditions and to certain financial,
business, and other factors beyond our control. If our cash flow
and capital resources are insufficient to fund our debt service
obligations, we may be forced to reduce or delay scheduled
expansion and capital expenditures, sell material assets or
operations, obtain additional capital or restructure our debt.
We cannot assure you that our operating performance, cash flow
and capital resources will be sufficient for payment of our debt
in the future. In the event that we are required to dispose of
material assets or operations or restructure our debt to meet
our debt service and other obligations, we cannot assure you
that the terms of any such transaction would be satisfactory to
us or if or how soon any such transaction could be completed.
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If we
fail to obtain additional financing, we may be unable to
refinance our existing debt, expand our current operations or
acquire new businesses, which could result in a failure to grow
or result in defaults in our obligations under our credit
agreement, our outstanding senior notes or our other debt
securities.
In order to refinance indebtedness, expand existing operations
and acquire additional businesses, we will require substantial
amounts of capital. There can be no assurance that financing,
whether from equity or debt financings or other sources, will be
available or, if available, will be on terms satisfactory to us.
If we are unable to obtain such financing, we will be unable to
acquire additional businesses and may be unable to meet our
obligations under our credit agreement, our senior notes or any
other debt securities we may offer.
The
indentures governing our outstanding senior notes and our credit
agreement impose (and we anticipate that the indentures
governing any other debt securities we may offer will also
impose) restrictions on us that may limit the discretion of
management in operating our business and that, in turn, could
impair our ability to meet our obligations.
The indentures governing our outstanding senior notes and our
credit agreement contain (and we anticipate that the indentures
governing any other debt securities we may offer will also
contain) various restrictive covenants that limit
managements discretion in operating our business. In
particular, these covenants limit our ability to, among other
things:
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incur additional debt;
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make certain investments or pay dividends or distributions on
our capital stock or purchase or redeem or retire capital stock;
|
|
|
|
sell assets, including capital stock of our restricted
subsidiaries;
|
|
|
|
restrict dividends or other payments by restricted subsidiaries;
|
|
|
|
create liens;
|
|
|
|
enter into transactions with affiliates; and
|
|
|
|
merge or consolidate with another company.
|
The credit agreement also requires us to maintain specified
financial ratios and satisfy certain financial tests. Our
ability to maintain or meet such financial ratios and tests may
be affected by events beyond our control, including changes in
general economic and business conditions, and we cannot assure
you that we will maintain or meet such ratios and tests or that
the lenders under the credit agreement will waive any failure to
meet such ratios or tests.
These covenants could materially and adversely affect our
ability to finance our future operations or capital needs.
Furthermore, they may restrict our ability to expand, to pursue
our business strategies and otherwise to conduct our business.
Our ability to comply with these covenants may be affected by
circumstances and events beyond our control, such as prevailing
economic conditions and changes in regulations, and we cannot
assure you that we will be able to comply with them. A breach of
these covenants could result in a default under the indentures
governing our outstanding senior notes and any other debt
securities we may offer
and/or the
credit agreement. If there were an event of default under any of
the indentures
and/or the
credit agreement, the affected creditors could cause all amounts
borrowed under these instruments to be due and payable
immediately. Additionally, if we fail to repay indebtedness
under our credit agreement when it becomes due, the lenders
under the credit agreement could proceed against the assets
which we have pledged to them as security. Our assets and cash
flow might not be sufficient to repay our outstanding debt in
the event of a default.
|
|
ITEM 1B.
|
UNRESOLVED
STAFF COMMENTS
|
None.
26
The following table describes the location and general character
of the principal physical properties used in each of our
companys businesses as of March 1, 2007. Our
principal executive office is rented and located in Houston,
Texas and the table below presents all of our operating
locations and whether the property is owned or leased.
|
|
|
|
|
Business Segment
|
|
Location
|
|
Owned/Leased
|
|
Rental Tools
|
|
Houston, Texas
|
|
Leased 2 locations
|
|
|
Victoria, Texas
|
|
Owned
|
|
|
Broussard, Louisiana
|
|
Leased
|
|
|
Morgan City, Louisiana
|
|
Owned
|
|
|
New Orleans, Louisiana
|
|
Leased
|
International Drilling
|
|
Buenos Aires, Argentina
|
|
Leased
|
|
|
Comodoro Rivadavia, Argentina
|
|
Owned
|
|
|
Neuquén, Argentina
|
|
Owned
|
|
|
Rincon de los Sauces, Argentina
|
|
Owned
|
|
|
Tartagal, Argentina
|
|
Owned
|
|
|
Santa Cruz, Bolivia
|
|
Leased
|
Directional Drilling Services
|
|
Corpus Christi, Texas
|
|
Leased
|
|
|
Houston, Texas
|
|
Leased 2 locations
|
|
|
Oklahoma City, Oklahoma
|
|
Leased
|
|
|
Lafayette, Louisiana
|
|
Leased
|
Casing and Tubing Services
|
|
Corpus Christi, Texas
|
|
Leased
|
|
|
Edinburg, Texas
|
|
Owned
|
|
|
Kilgore, Texas
|
|
Leased
|
|
|
Pearsall, Texas
|
|
Leased
|
|
|
Broussard, Louisiana
|
|
Leased 2 locations
|
|
|
Houma, Louisiana
|
|
Leased
|
Compressed Air Drilling Services
|
|
Fort Stockton, Texas
|
|
Leased
|
|
|
Grandbury, Texas
|
|
Leased
|
|
|
Houston, Texas
|
|
Leased
|
|
|
San Angelo, Texas
|
|
Leased
|
|
|
Sonora, Texas
|
|
Leased
|
|
|
Carlsbad, New Mexico
|
|
Leased
|
|
|
Farmington, New Mexico
|
|
Leased
|
|
|
Denver, Colorado
|
|
Leased
|
|
|
Grand Junction, Colorado
|
|
Leased
|
|
|
Wilburton, Oklahoma
|
|
Leased
|
Production Services
|
|
Alvin, Texas
|
|
Leased
|
|
|
Carthage, Texas
|
|
Leased
|
|
|
Corpus Christi, Texas
|
|
Leased
|
|
|
Kilgore, Texas
|
|
Leased 2 locations
|
|
|
Midland, Texas
|
|
Leased
|
|
|
Arcadia, Louisiana
|
|
Leased
|
|
|
Broussard, Louisiana
|
|
1 Owned & 1 Leased
|
|
|
Cordell, Oklahoma
|
|
Leased
|
|
|
Houma, Louisiana
|
|
Leased
|
|
|
ITEM 3.
|
LEGAL
PROCEEDINGS
|
On June 29, 1987, we filed for reorganization under
Chapter 11 of the United States Bankruptcy Code. Our plan
of reorganization was confirmed by the Bankruptcy Court after
acceptance by our creditors and stockholders, and was
consummated on December 2, 1988.
At confirmation of our plan of reorganization, the United States
Bankruptcy Court approved the establishment of the A-C
Reorganization Trust as the primary vehicle for distributions
and the administration
27
of claims under our plan of reorganization, two trust funds to
service health care and life insurance programs for retired
employees and a trust fund to process and liquidate future
product liability claims. The trusts assumed responsibility for
substantially all remaining cash distributions to be made to
holders of claims and interests pursuant to our plan of
reorganization. We were thereby discharged of all debts that
arose before confirmation of our plan of reorganization.
We do not administer any of the aforementioned trusts and retain
no responsibility for the assets transferred to or distributions
to be made by such trusts pursuant to our plan of reorganization.
As part of our plan of reorganization, we settled
U.S. Environmental Protection Agency claims for cleanup
costs at all known sites where we were alleged to have disposed
of hazardous waste. The EPA settlement included both past and
future cleanup costs at these sites and released us of liability
to other potentially responsible parties in connection with
these specific sites. In addition, we negotiated settlements of
various environmental claims asserted by certain state
environmental protection agencies.
Subsequent to our bankruptcy reorganization, the EPA and state
environmental protection agencies have in a few cases asserted
that we are liable for cleanup costs or fines in connection with
several hazardous waste disposal sites containing products
manufactured by us prior to consummation of our plan of
reorganization. In each instance, we have taken the position
that the cleanup costs and all other liabilities related to
these sites were discharged in the bankruptcy, and the cases
have been disposed of without material cost. A number of Federal
Courts of Appeal have issued rulings consistent with this
position, and based on such rulings, we believe that we will
continue to prevail in our position that our liability to the
EPA and third parties for claims for environmental cleanup costs
that had pre-petition triggers have been discharged. A number of
claimants have asserted claims for environmental cleanup costs
that had pre-petition triggers, and in each event, the A-C
Reorganization Trust, under its mandate to provide plan of
reorganization implementation services to us, has responded to
such claims, generally, by informing claimants that our
liabilities were discharged in the bankruptcy. Each of such
claims has been disposed of without material cost. However,
there can be no assurance that we will not be subject to
environmental claims relating to pre-bankruptcy activities that
would have a material adverse effect on us.
The EPA and certain state agencies continue from time to time to
request information in connection with various waste disposal
sites containing products manufactured by us before consummation
of the plan of reorganization that were disposed of by other
parties. Although we have been discharged of liabilities with
respect to hazardous waste sites, we are under a continuing
obligation to provide information with respect to our products
to federal and state agencies. The A-C Reorganization Trust,
under its mandate to provide plan of reorganization
implementation services to us, has responded to these
informational requests because pre-bankruptcy activities are
involved.
We were advised in late 2005 that the A-C Reorganization Trust
is in the process of terminating and distributing its assets,
and as a result, we will assume the responsibility of responding
to claimants and to the EPA and state agencies previously
undertaken by the A-C Reorganization Trust. However, we have
been advised by the A-C Reorganization Trust that its cost of
providing these services has not been material in the past, and
therefore we do not expect to incur material expenses as a
result of responding to such requests. However, there can be no
assurance that we will not be subject to environmental claims
relating to pre-bankruptcy activities that would have a material
adverse effect on us.
We are named as a defendant from time to time in product
liability lawsuits alleging personal injuries resulting from our
activities prior to our reorganization involving asbestos. These
claims are referred to and handled by a special products
liability trust formed to be responsible for such claims in
connection with our reorganization. As with environmental
claims, we do not believe we are liable for product liability
claims relating to our business prior to our bankruptcy;
moreover, the products liability trust continues to defend all
such claims. However, there can be no assurance that we will not
be subject to material product liability claims in the future.
We are involved in various other legal proceedings, including
labor contract litigation, in the ordinary course of business.
The legal proceedings are at different stages; however, we
believe that the likelihood of material loss relating to any
such legal proceedings is remote.
28
|
|
ITEM 4.
|
SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS
|
On November 28, 2006, we held our Annual Meeting of
Stockholders. At the meeting, the stockholders voted on the
following matters:
1. The election of nine directors to serve a one-year term
expiring at the 2007 annual meeting of stockholders.
2. The ratification of the appointment of UHY LLP as our
independent auditor for the fiscal year ending December 31,
2006.
3. The adoption of our 2006 Incentive Stock Plan.
The nine nominees to our Board of Directors were elected at the
meeting, and the other proposals received the affirmative vote
required for approval. The number of votes cast for, against or
withheld, as well as the number of abstentions and broker
non-votes, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Against or
|
|
|
Abstentions and
|
|
|
|
|
|
|
For
|
|
|
Withheld
|
|
|
Broker Non-votes
|
|
|
|
1.
|
|
|
Election of
Directors
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ali H. M. Afdhal
|
|
|
18,981,441
|
|
|
|
339,698
|
|
|
|
|
|
|
|
|
|
Alejandro P. Bulgheroni
|
|
|
18,791,812
|
|
|
|
529,327
|
|
|
|
|
|
|
|
|
|
Carlos A. Bulgheroni
|
|
|
18,791,762
|
|
|
|
529,377
|
|
|
|
|
|
|
|
|
|
Jeffrey R. Freedman
|
|
|
17,759,199
|
|
|
|
1,561,940
|
|
|
|
|
|
|
|
|
|
Victor F. Germack
|
|
|
19,170,055
|
|
|
|
151,084
|
|
|
|
|
|
|
|
|
|
Munawar H. Hidayatallah
|
|
|
19,096,922
|
|
|
|
224,217
|
|
|
|
|
|
|
|
|
|
John E. McConnaughy, Jr.
|
|
|
18,353,294
|
|
|
|
967,845
|
|
|
|
|
|
|
|
|
|
Robert E. Nederlander
|
|
|
19,009,582
|
|
|
|
311,557
|
|
|
|
|
|
|
|
|
|
Leonard Toboroff
|
|
|
18,791,812
|
|
|
|
529,327
|
|
|
|
|
|
|
2.
|
|
|
Ratification of UHY LLP as our
independent accountants
|
|
|
19,269,608
|
|
|
|
42,267
|
|
|
|
9,264
|
|
|
3.
|
|
|
Adoption of 2006 Incentive Stock
Plan
|
|
|
7,811,990
|
|
|
|
3,618,967
|
|
|
|
7,863,905
|
|
PART II
|
|
ITEM 5.
|
MARKET
FOR REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
|
MARKET
PRICE INFORMATION
Our common stock is traded on the American Stock Exchange under
the symbol ALY. The following table sets forth, for
periods indicated, the range of high and low sale prices of our
common stock reported on the American Stock Exchange.
|
|
|
|
|
|
|
|
|
Calendar Quarter
|
|
High
|
|
|
Low
|
|
|
2005
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
7.25
|
|
|
$
|
3.64
|
|
Second Quarter
|
|
|
6.00
|
|
|
|
4.38
|
|
Third Quarter
|
|
|
14.70
|
|
|
|
5.65
|
|
Fourth Quarter
|
|
|
13.75
|
|
|
|
8.61
|
|
2006
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
18.50
|
|
|
$
|
12.46
|
|
Second Quarter
|
|
|
17.62
|
|
|
|
10.85
|
|
Third Quarter
|
|
|
19.33
|
|
|
|
9.80
|
|
Fourth Quarter
|
|
|
25.55
|
|
|
|
12.15
|
|
29
Holders
As of March 1, 2007, there were approximately 1,927 holders
of record of our common stock. On March 1, 2007, the
closing price for our common stock reported on the American
Stock Exchange was $15.99 per share.
Dividends
No dividends were declared or paid during the past three years,
and no dividends are anticipated to be declared or paid in the
foreseeable future. Our credit facilities and the indentures
governing our senior notes restrict our ability to pay dividends
on our common stock.
EQUITY
COMPENSATION PLAN INFORMATION
The following table provides information as of December 31,
2006 with respect to the shares of our common stock that may be
issued under our existing equity compensation plans.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
|
|
|
|
|
|
Securities to be
|
|
|
Weighted
|
|
|
|
|
|
|
Issued Upon
|
|
|
Average Exercise
|
|
|
Number of Securities
|
|
|
|
Exercise of
|
|
|
Price of
|
|
|
Remaining Available
|
|
|
|
Outstanding
|
|
|
Outstanding
|
|
|
for Future Issuance
|
|
|
|
Options, Warrants
|
|
|
Options, Warrants
|
|
|
Under Equity
|
|
Plan Category
|
|
and Rights
|
|
|
and Rights
|
|
|
Compensation Plans
|
|
|
Equity compensation plans approved
by security holders
|
|
|
1,346,365
|
|
|
$
|
6.86
|
|
|
|
1,726,000
|
|
Equity compensation plans not
approved by security holders
|
|
|
8,000
|
|
|
$
|
9.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,354,365
|
|
|
$
|
6.87
|
|
|
|
1,726,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
Compensation Plans Not Approved By Security Holders
These plans comprise the following:
In 1999 and 2000, the Board compensated former and continuing
Board members who had served from 1989 to March 31, 1999
without compensation by issuing promissory notes totaling
$325,000 and by granting stock options to these same
individuals. Options to purchase 4,800 shares of common
stock were granted with an exercise price of $13.75. These
options vested immediately and expire in March 2010. As of
December 31, 2006, 4,000 of these options remain
outstanding.
In connection with the private placement in April 2004, we
issued warrants for the purchase of 800,000 shares of our
common stock at an exercise price of $2.50 per share. A
total of 486,557 of these warrants were exercised in 2005 and
the remaining warrants were exercised in 2006. Warrants for
4,000 shares of our common stock at an exercise price of
$4.65 were also issued in May 2004 and remained outstanding as
of December 31, 2006. The warrants were exercised in
January 2007.
30
PERFORMANCE
GRAPH
Set forth below is a line graph comparing the annual percentage
change in the cumulative return to the stockholders of our
common stock with the cumulative return of the Nasdaq Market
Index and the CoreData Services Oil and Gas Equipment and
Services Index for the period commencing January 1, 2001
and ending on December 31, 2006. The CoreData Services Oil
and Gas Equipment and Services Index is an index of
approximately 75 oil and gas equipment and services providers.
The information contained in the performance graph shall not be
deemed to be soliciting material or to be
filed with the SEC, nor shall such information be
incorporated by reference into any future filing under the
Securities Act or Exchange Act, except to the extent that we
specifically incorporate it by reference into such filing.
The graph assumes that $100 was invested on January 1, 2001
in our common stock and in each index, and that all dividends
were reinvested. No dividends have been declared or paid on our
common stock. Stockholder returns over the indicated period
should not be considered indicative of future shareholder
returns.
COMPARISON
OF 5-YEAR CUMULATIVE TOTAL RETURN
AMONG ALLIS-CHALMERS ENERGY INC.
NASDAQ MARKET INDEX AND OIL & GAS EQUIPMENT/SERVICES
ASSUMES $100
INVESTED ON JAN. 1, 2001
ASSUMES DIVIDEND REINVESTED
FISCAL YEAR ENDING DEC. 31, 2006
COMPARISON
OF CUMULATIVE TOTAL RETURN OF ONE OR MORE
COMPANIES, PEER GROUPS, INDUSTRY INDEXES AND/OR BROAD
MARKETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ending
|
Company/Index/Market
|
|
12/31/2001
|
|
12/31/2002
|
|
12/31/2003
|
|
12/31/2004
|
|
12/30/2005
|
|
12/29/2006
|
Allis-Chalmers Energy
Inc.
|
|
|
100.00
|
|
|
|
53.68
|
|
|
|
54.74
|
|
|
|
103.16
|
|
|
|
262.53
|
|
|
|
485.05
|
|
Oil & Gas
Equipment/Services
|
|
|
100.00
|
|
|
|
93.04
|
|
|
|
113.49
|
|
|
|
155.77
|
|
|
|
235.41
|
|
|
|
277.90
|
|
NASDAQ Market Index
|
|
|
100.00
|
|
|
|
69.75
|
|
|
|
104.88
|
|
|
|
113.70
|
|
|
|
116.19
|
|
|
|
128.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31
|
|
ITEM 6.
|
SELECTED
FINANCIAL DATA.
|
The following selected historical financial information for each
of the five years ended December 31, 2006, has been derived
from our audited consolidated financial statements and related
notes. This information is only a summary and should be read in
conjunction with material contained in Managements
Discussion and Analysis of Financial Condition and Results of
Operations, which includes a discussion of factors
materially affecting the comparability of the information
presented, and in conjunction with our financial statements
included elsewhere herein. As discussed in Item 7,
Managements Discussion and Analysis of Financial
Condition and Results of Operations, we have during the
past five years effected a number of business combinations and
other transactions that materially affect the comparability of
the information set forth below (in thousands, except per share
amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2006
|
|
2005
|
|
2004
|
|
2003
|
|
2002
|
|
|
|
|
|
|
(Restated)
|
|
(Restated)
|
|
|
|
Statement of Operations
Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
307,304
|
|
|
$
|
105,344
|
|
|
$
|
47,726
|
|
|
$
|
32,724
|
|
|
$
|
17,990
|
|
Income (loss) from operations
|
|
$
|
66,656
|
|
|
$
|
13,218
|
|
|
$
|
4,227
|
|
|
$
|
2,625
|
|
|
$
|
(1,072
|
)
|
Net income (loss) from continuing
operations
|
|
$
|
35,626
|
|
|
$
|
7,175
|
|
|
$
|
888
|
|
|
$
|
2,927
|
|
|
$
|
(3,969
|
)
|
Net income (loss) attributed to
common stockholders
|
|
$
|
35,626
|
|
|
$
|
7,175
|
|
|
$
|
764
|
|
|
$
|
2,271
|
|
|
$
|
(4,290
|
)
|
Per Share Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (loss) from continuing
operations per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.73
|
|
|
$
|
0.48
|
|
|
$
|
0.10
|
|
|
$
|
0.58
|
|
|
$
|
(1.14
|
)
|
Diluted
|
|
$
|
1.66
|
|
|
$
|
0.44
|
|
|
$
|
0.09
|
|
|
$
|
0.50
|
|
|
$
|
(1.14
|
)
|
Weighted average number of common
shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
20,548
|
|
|
|
14,832
|
|
|
|
7,930
|
|
|
|
3,927
|
|
|
|
3,766
|
|
Diluted
|
|
|
21,410
|
|
|
|
16,238
|
|
|
|
9,510
|
|
|
|
5,850
|
|
|
|
3,766
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Balance Sheet Data
|
|
|
As of December 31,
|
|
|
2006
|
|
2005
|
|
2004
|
|
2003
|
|
2002
|
|
|
|
|
|
|
|
|
(Restated)
|
|
|
|
Total assets
|
|
$
|
908,326
|
|
|
$
|
137,355
|
|
|
$
|
80,192
|
|
|
$
|
53,662
|
|
|
$
|
34,778
|
|
Long-term debt classified as:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
$
|
6,999
|
|
|
$
|
5,632
|
|
|
$
|
5,541
|
|
|
$
|
3,992
|
|
|
$
|
13,890
|
|
Long-term
|
|
$
|
561,446
|
|
|
$
|
54,937
|
|
|
$
|
24,932
|
|
|
$
|
28,241
|
|
|
$
|
7,331
|
|
Redeemable convertible Preferred
stock
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
4,171
|
|
|
$
|
3,821
|
|
Stockholders equity
|
|
$
|
253,933
|
|
|
$
|
60,875
|
|
|
$
|
35,109
|
|
|
$
|
4,541
|
|
|
$
|
1,009
|
|
Book value per share (basic)
|
|
$
|
12.36
|
|
|
$
|
4.10
|
|
|
$
|
4.43
|
|
|
$
|
1.16
|
|
|
$
|
0.27
|
|
|
|
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 selected historical financial data and our
accompanying financial statements and the notes to those
financial statements included elsewhere in this document. The
following discussion contains forward-looking statements within
the meaning of the Private Securities Litigation Reform Act of
1995 that reflect our plans, estimates and beliefs. Our actual
results could differ materially from those anticipated in these
forward-looking statements as a result of risks and
uncertainties, including, but not limited to, those discussed
under Item 1A. Risk Factors.
32
Overview
of Our Business
We are a multi-faceted oilfield services company that provides
services and equipment to oil and natural gas exploration and
production companies, domestically in Texas, Louisiana, New
Mexico, Colorado, Oklahoma, Mississippi, Utah, Wyoming,
Arkansas, Alabama, West Virginia, offshore in the Gulf of
Mexico, and internationally, primarily in Argentina and Mexico.
We operate in six sectors of the oil and natural gas service
industry: rental tools, international drilling, directional
drilling services; casing and tubing services; compressed air
drilling services; and production services.
We derive operating revenues from rates per job that we charge
for the labor and equipment required to provide a service and
rates per day for equipment and tools that we rent to our
customers. The price we charge for our services depends upon
several factors, including the level of oil and natural gas
drilling activity and the competitive environment in the
particular geographic regions in which we operate. Contracts are
awarded based on the price, quality of service and equipment,
and the general reputation and experience of our personnel. The
demand for drilling services has historically been volatile and
is affected by the capital expenditures of oil and natural gas
exploration and development companies, which can fluctuate based
upon the prices of oil and natural gas or the expectation for
the prices of oil and natural gas.
The number of working drilling rigs, typically referred to as
the rig count, is an important indicator of activity
levels in the oil and natural gas industry. The rig count in the
United States increased from 862 as of December 31, 2002 to
1,752 as of March 2, 2007, according to the Baker Hughes
rig count. Furthermore, directional and horizontal rig counts
increased from 283 as of December 31, 2002 to 738 as of
March 2, 2007, which accounted for 33% and 42% of the total
U.S. rig count, respectively.
Our cost of revenues represents all direct and indirect costs
associated with the operation and maintenance of our equipment.
The principal elements of these costs are direct and indirect
labor and benefits, repairs and maintenance of our equipment,
insurance, equipment rentals, fuel and depreciation. Operating
expenses do not fluctuate in direct proportion to changes in
revenues because, among other factors, we have a fixed base of
inventory of equipment and facilities to support our operations,
and in periods of low drilling activity we may also seek to
preserve labor continuity to market our services and maintain
our equipment.
Cyclical
Nature of Equipment Rental and Services Industry
The oilfield services industry is highly cyclical. The most
critical factor in assessing the outlook for the industry is the
worldwide supply and demand for oil and the domestic supply and
demand for natural gas. The peaks and valleys of demand are
further apart than those of many other cyclical industries. This
is primarily a result of the industry being driven by commodity
demand and corresponding price increases. As demand increases,
producers raise their prices. The price escalation enables
producers to increase their capital expenditures. The increased
capital expenditures ultimately result in greater revenues and
profits for services and equipment companies. The increased
capital expenditures also ultimately result in greater
production which historically has resulted in increased supplies
and reduced prices.
Demand for our services has been strong throughout 2004, 2005
and 2006 due to high oil and natural gas prices and increased
demand and declining production costs for natural gas as
compared to other energy sources. Management believes the
current market fundamentals are indicative of a favorable
long-term trend of activity in our markets. However, these
factors could be more than offset by other developments
affecting the worldwide supply and demand for oil and natural
gas products.
Restatement
We understated diluted earnings per share due to an incorrect
calculation of our weighted shares outstanding for each of the
first three quarters of 2004, for the year ended
December 31, 2004 and for the quarter ended March 31,
2005. In addition, we understated basic earnings per share due
to an incorrect calculation of our weighted average basic shares
outstanding for the quarter ended September 30, 2004.
Consequently, we restated our financial statements for each of
those periods. The incorrect calculation resulted from a
mathematical error and an improper application of Statement of
Financial Accounting Standards No. 128, Earnings
Per Share, or SFAS, No. 128. The effect of the
restatement was to reduce weighted average diluted shares
outstanding for the relevant periods and to reduce weighted
average basic shares
33
outstanding for the quarter ended September 30, 2004.
Therefore, diluted earnings per share were increased for the
relevant periods and basic earnings per share were increased for
the quarter ended September 30, 2004. (See Note 2 to
our consolidated financial statements for the three years ended
December 31, 2006).
In connection with the formation of AirComp in 2003, we, along
with M-I
contributed assets to AirComp in exchange for a 55% interest and
45% interest, respectively, in AirComp. We originally accounted
for the formation of AirComp as a joint venture, but in February
2005 determined that the transaction should have been accounted
for using purchase accounting pursuant to
SFAS No. 141, Business Combinations
and SEC Staff Accounting Bulletin No. 51
Accounting for Sales of Stock by a Subsidiary.
Consequently, we restated our financial statements for the
first three quarters of 2004 (See Note 2 to our
consolidated financial statements for the three years ended
December 31, 2006).
Results
of Operations
In September 2004, we acquired the remaining 19% of Tubular and
we acquired Safco. In November 2004, AirComp acquired
substantially all of the assets of Diamond Air and, in December
2004, we acquired Downhole. We consolidated the results of these
acquisitions from the day they were acquired.
In April 2005, we acquired Delta and, in May 2005, we acquired
Capcoil. We report the operations of Downhole and Capcoil as our
production services segment and the operations of Safco and
Delta as our rental tools segment. In July 2005, we acquired the
45% interest of
M-I in our
compressed air drilling subsidiary, AirComp, making us the 100%
owner of AirComp. In addition, in July 2005, we acquired the
compressed air drilling assets of W. T. On August 1, 2005,
we acquired 100% of the outstanding capital stock of Target. The
results of Target are included in our directional drilling
segment as their measurement while drilling equipment is
utilized in that segment. On September 1, 2005, we acquired
the casing and tubing service assets of Patterson Services, Inc.
We consolidated the results of these acquisitions from the day
they were acquired.
In January 2006, we acquired all of the outstanding stock of
Specialty and in December 2006, we acquired substantially all of
the assets of OGR. We report the operations of Specialty and OGR
in our rental tool segment. In April 2006, we acquired all of
the outstanding stock of Rogers. We report the operations of
Rogers in our casing and tubing services segment. In August
2006, we acquired all of the outstanding stock of DLS and in
December 2006, we acquired all of the outstanding stock of
Tanus. We report the operations of DLS and Tanus in our
international drilling segment. In October 2006, we acquired all
of the outstanding stock of Petro Rentals. We report the
operations of Petro Rentals in our production services segment.
We consolidated the results of these acquisitions from the day
they were acquired.
The foregoing acquisitions affect the comparability from period
to period of our historical results, and our historical results
may not be indicative of our future results.
Comparison
of Years Ended December 31, 2006 and December 31,
2005
Our revenues for the year ended December 31, 2006 was
$307.3 million, an increase of 191.7% compared to
$105.3 million for the year ended December 31, 2005.
Revenues increased in all of our business segments due to the
successful integration of acquisitions completed in the third
quarter of 2005 and during 2006, the investment in new
equipment, improved pricing for our services, the addition of
operations and sales personnel and the opening of new operations
offices. Revenues increased most significantly due to the
acquisition of DLS on August 14, 2006 which expanded our
operations to a sixth operating segment, international drilling.
Revenues also increased significantly at our rental tools
segment due to the acquisition of Specialty effective
January 1, 2006. Our casing and tubing services segment
also had a substantial increase in revenue, primarily due to the
acquisitions of the casing and tubing assets of Patterson
Services, Inc. on September 1, 2005, and the acquisition of
Rogers as of April 1, 2006, along with the investment in
additional equipment, improved market conditions and increased
market penetration for our services in South Texas, East Texas,
Louisiana and the U.S. Gulf of Mexico. Revenues increased
at our compressed air drilling segment due to the purchase of
additional equipment and improved pricing for our services. Our
directional drilling services segment revenues increased in the
2006 period compared to the 2005 period due to improved pricing
for directional drilling services, the August 2005 acquisition
of Target which provides measurement-while-drilling tools, or
MWD and the purchase of additional down-hole motors and MWDs
which increased our capacity and market presence.
34
Our gross margin for the year ended December 31, 2006
increased 243.8% to $105.1 million, or 34.2% of revenues,
compared to $30.6 million, or 29.0%, of revenues for the
year ended December 31, 2005. The increase in gross profit
is due to the increase in revenues in all of our business
segments. The increase in gross profit as a percentage of
revenues is primarily due to the acquisition of Specialty as of
January 1, 2006, in the high margin rental tool business,
the improved pricing for our services generally and the
investments in new capital equipment. Also contributing to our
improved gross profit margin was the acquisition of Target, the
purchase of additional MWDs and the acquisition of Rogers.
The increase in gross profit was partially offset by an increase
in depreciation expense of 315.7% to $20.3 million compared
to $4.9 million for 2005. The increase is due to additional
depreciable assets resulting from the acquisitions and capital
expenditures. Our cost of revenues consists principally of our
labor costs and benefits, equipment rentals, maintenance and
repairs of our equipment, depreciation, insurance and fuel.
Because many of our costs are fixed, our gross profit as a
percentage of revenues is generally affected by our level of
revenues.
General and administrative expense was $35.5 million for
the year ended December 31, 2006 compared to
$15.6 million for the year ended December 31, 2005.
General and administrative expense increased due to additional
expenses associated with the acquisitions, and the hiring of
additional sales, operations and administrative personnel.
General and administrative expense also increased because of
increased accounting and consulting fees and other expenses in
connection with initiatives to strengthen our internal control
processes, costs related to Sarbanes Oxley compliance efforts
and increased corporate accounting and administrative staff. As
a percentage of revenues, general and administrative expenses
were 11.6% in 2006 compared to 14.8% in 2005.
We adopted SFAS No. 123R, Share-Based Payment,
effective January 1, 2006. This statement requires all
share-based payments to employees, including grants of employee
stock options, to be recognized in the financial statements
based on their grant-date fair values. We adopted
SFAS No. 123R using the modified prospective
transition method, utilizing the Black-Scholes option pricing
model for the calculation of the fair value of our employee
stock options. Under the modified prospective method, we record
compensation cost related to unvested stock awards as of
December 31, 2005 by recognizing the unamortized grant date
fair value of these awards over the remaining vesting periods of
those awards with no change in historical reported earnings.
Therefore, we recorded an expense of $3.4 million related
to stock awards for the year ended December 31, 2006 of
which $3.0 million was recorded in general and
administrative expense with the balance being recorded as a
direct cost. Prior to January 1, 2006, we accounted for our
stock-based compensation using Accounting Principle Board
Opinion No. 25, or APB No. 25. Under APB No. 25,
compensation expense is recognized for stock options with an
exercise price that is less than the market price on the grant
date of the option. Accordingly, no compensation cost was
recognized under APB No. 25.
Amortization expense was $2.9 million for the year ended
December 31, 2006 compared to $1.8 million for the
year ended December 31, 2005. The increase in amortization
expense is due to the amortization of intangible assets in
connection with our acquisitions and the amortization of
deferred financing costs which included approximately
$1.1 million.
Income from operations for the year ended December 31, 2006
totaled $66.7 million, a 404.3% increase over the
$13.2 million in income from operations for the year ended
December 31, 2005, reflecting the increase in our revenues
and gross profit, offset in part by increased general and
administrative expenses. Our income from operations as a
percentage of revenues increased to 21.7% in 2006 from 12.5% in
2005 due to the increase in our gross margin which offset the
increases in amortization expense and general and administrative
expenses.
Our net interest expense was $19.3 million for the year
ended December 31, 2006, compared to $4.4 million for
the year ended December 31, 2005. Interest expense
increased in 2006 due to our increased debt. In January of 2006
we issued $160.0 million of senior notes bearing interest
at 9.0% to fund the acquisition of Specialty, pay off other
outstanding debt and for working capital. In August 2006 we
issued an additional $95.0 million of senior notes bearing
interest at 9.0% to fund a portion of the acquisition of DLS. On
December 18, 2006, we borrowed $300.0 million in a
senior unsecured bridge loan to fund the acquisition of OGR. The
average interest rate on the bridge loan was approximately
10.6%. Interest expense for 2006 includes the write-off of
$453,000 related to financing fees on the bridge loan. This
bridge loan was repaid on
35
January 29, 2007 and the remaining $1.2 million of
financing fees will be written off in 2007. In the third quarter
of 2005, we incurred debt retirement expense of
$1.1 million related to the refinancing of our debt. This
amount includes prepayment penalties and the write-off of
deferred financing fees from a previous financing.
Minority interest in income of subsidiaries for the year ended
December 31, 2006 was $0 compared to $488,000 for the
corresponding period in 2005 due to the our acquisition of the
minority interest at AirComp on July 11, 2005.
Our provision for income taxes for the year ended
December 31, 2006 was $11.4 million, or 24.3% of our
net income before income taxes, compared to $1.3 million,
or 15.8% of our net income before income taxes for 2005. The
increase in our provision for income taxes is attributable to
the significant increase in our operating income which resulted
in the utilization of our deferred tax assets including our net
operating losses, and the increase in percentage of income taxes
to net income before income taxes attributable to our operations
in Argentina which are taxed at 35.0%.
We had net income attributed to common stockholders of
$35.6 million for the year ended December 31, 2006, an
increase of 396.5%, compared to net income attributed to common
stockholders of $7.2 million for the year ended
December 31, 2005.
The following table compares revenues and income from operations
for each of our business segments for the years ended
December 31, 2006 and December 31, 2005. Income from
operations consists of our revenues less cost of revenues,
general and administrative expenses, and depreciation and
amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
Income (Loss) from Operations
|
|
|
|
2006
|
|
|
2005
|
|
|
Change
|
|
|
2006
|
|
|
2005
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Rental tools
|
|
$
|
51,521
|
|
|
$
|
5,059
|
|
|
$
|
46,462
|
|
|
$
|
26,293
|
|
|
$
|
1,300
|
|
|
$
|
24,993
|
|
International drilling
|
|
|
69,490
|
|
|
|
|
|
|
|
69,490
|
|
|
|
12,233
|
|
|
|
|
|
|
|
12,233
|
|
Directional drilling services
|
|
|
72,811
|
|
|
|
43,901
|
|
|
|
28,910
|
|
|
|
17,666
|
|
|
|
7,389
|
|
|
|
10,277
|
|
Casing and tubing services
|
|
|
50,887
|
|
|
|
20,932
|
|
|
|
29,955
|
|
|
|
12,544
|
|
|
|
4,994
|
|
|
|
7,550
|
|
Compressed air drilling services
|
|
|
43,045
|
|
|
|
25,662
|
|
|
|
17,383
|
|
|
|
10,810
|
|
|
|
5,612
|
|
|
|
5,198
|
|
Production services
|
|
|
19,550
|
|
|
|
9,790
|
|
|
|
9,760
|
|
|
|
2,137
|
|
|
|
(99
|
)
|
|
|
2,236
|
|
General corporate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(15,027
|
)
|
|
|
(5,978
|
)
|
|
|
(9,049
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
307,304
|
|
|
$
|
105,344
|
|
|
$
|
201,960
|
|
|
$
|
66,656
|
|
|
$
|
13,218
|
|
|
$
|
53,438
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental Tools Segment. Our rental tools
revenues were $51.5 million for the year ended
December 31, 2006, an increase from the $5.1 million
in revenues for the year ended December 31, 2005. Income
from operations increased to $26.3 million in 2006 compared
to $1.3 million in 2005. The increase in revenue and
operating income is primarily attributable to the acquisition of
Specialty effective January 1, 2006, improved pricing,
improved utilization of our inventory of rental equipment and to
a lesser extent, the acquisition of the OGR assets in December
2006.
International Drilling Segment. Our
international drilling revenues were $69.5 million for the
year ended December 31, 2006, and our income from
operations was $12.2 million. This segment of our
operations was created with the acquisition of DLS in August of
2006. In November 2006, our DLS employees were involved in a
ten-day
labor strike in Argentina, which affected the entire oil
industry in Argentina and had a negative impact on our results.
Directional Drilling Services
Segment. Revenues for the year ended
December 31, 2006 for our directional drilling services
segment were $72.8 million, an increase of 65.9% from the
$43.9 million in revenues for the year ended
December 31, 2005. Income from operations increased 139.1%
to $17.7 million for 2006 from $7.4 million for 2005.
The improved results for this segment are due to the increase in
drilling activity in the Texas and Gulf Coast areas, improved
pricing, the acquisition of Target as of August 1, 2005
36
and the purchase of an additional six MWDs. Our increased
operating expenses as a result of the addition of operations and
personnel were more than offset by the growth in revenues and
improved pricing for our services
Casing and Tubing Services Segment. Revenues
for the year ended December 31, 2006 for the casing and
tubing services segment were $50.9 million, an increase of
143.1% from the $20.9 million in revenues for the year
ended December 31, 2005. Revenues from domestic operations
increased to $44.4 million in 2006 from $14.5 million
in 2005 as a result of the acquisition of Rogers, the
acquisition of the casing and tubing assets of Patterson
Services, Inc. on September 1, 2005 and investment in new
equipment, all of which resulted in increased market penetration
for our services in South Texas, East Texas, Louisiana and the
U.S. Gulf of Mexico. The year ended December 2005 was also
adversely impacted by hurricane activity in September of 2005.
Revenues from Mexican operations increased to $6.5 million
in 2006 from $6.4 million in 2005. Income from operations
increased 151.2% to $12.5 million in 2006 from
$5.0 million in 2005. The increase in this segments
operating income is due to increased revenues both domestically
and in our Mexico operations.
Compressed Air Drilling Services Segment. Our
compressed air drilling revenues were $43.0 million for the
year ended December 31, 2006, an increase of 67.7% compared
to $25.7 million in revenues for the year ended
December 31, 2005. Income from operations increased 92.6%
to $10.8 million in 2006 compared to income from operations
of $5.6 million in 2005. Our compressed air drilling
revenues and operating income for the 2006 period increased
compared to the 2005 period due in part to the acquisition of
the air drilling assets of W. T., our investment in additional
equipment and improved pricing in West Texas.
Production Services Segment. Our production
services revenues were $19.6 million for the year ended
December 31, 2006, compared to $9.8 million in
revenues for the year ended December 31, 2005. Income from
operations was $2.1 million in 2006 compared to a loss from
operations of $99,000 in 2005. The increase in revenue is
attributable to the acquisition of Petro-Rentals completed in
October 2006, the acquisition of Capcoil on May 1, 2005 and
improved utilization and pricing for our services. The increase
in operating income is primarily related to the operations of
Petro-Rentals and the addition of two coil tubing units in the
fourth quarter of 2006.
Comparison
of Years Ended December 31, 2005 and December 31,
2004
Our revenue for the year ended December 31, 2005 was
$105.3 million, an increase of 120.7% compared to
$47.7 million for the year ended December 31, 2004.
The increase in revenues was principally due to acquisitions
completed in the fourth quarter of 2004 and the second and third
quarters of 2005, the addition of operations and sales
personnel, the opening of new operations offices, and the
purchase of additional equipment. Acquisitions completed during
this period enabled us to establish our rental tool and
production services segments which resulted in an increased
offering of products and services and an expansion of our
customer base.
Directional drilling services segment revenues increased in the
2005 period compared to the 2004 period due to the addition of
operations and sales personnel, the opening of new operations
offices and the purchase of additional downhole motors which
increased our capacity and market presence. Revenues increased
at our compressed air drilling segment due to acquisition of the
air drilling assets of W. T. on July 11, 2005, the
acquisitions of Diamond Air on November 1, 2004 and
improved pricing for our services in West Texas. Revenues
increased at our casing and tubing services segment due to the
acquisition of the casing and tubing assets of Patterson
Services Inc. on September 1, 2005, increased revenues from
Mexico, improved market conditions, improved market penetration
for our services in South Texas and the addition of operating
personnel and equipment which broadened our capabilities. Also
contributing to increased revenues were the acquisitions of
Safco as of September 1, 2004, Downhole as of
December 1, 2004, Delta as of April 1, 2005 and
Capcoil as of May 1, 2005. Downhole and Capcoil comprised
our production services segment and Safco and Delta comprised
our rental tool segment
Our gross margin for the year ended December 31, 2005
increased 146.1% to $30.6 million, or 29.0% of revenues,
compared to $12.4 million, or 26.0%, of revenues for the
year ended December 31, 2004. The increase is due to
increased revenues and improved pricing in the directional
drilling services segment,
37
increased revenues at our compressed air drilling services
segment, including revenues resulting from the acquisition of
Diamond Air and the compressed air drilling assets of W.T.,
increased revenues from Mexico, improved market conditions for
our domestic casing and tubing segment and the growth of our
rental tools segment through the acquisition of Delta on
April 1, 2005. Depreciation expense increased 80.4% to
$4.9 million in 2005 compared to $2.7 million in 2004.
The increase is due to additional depreciable assets resulting
from capital expenditures and acquisitions in 2004 and 2005. Our
cost of revenues consists principally of our labor costs and
benefits, equipment rentals, maintenance and repairs of our
equipment, depreciation, insurance and fuel. Because many of our
costs are fixed, our gross profit as a percentage of revenues is
generally affected by our level of revenues.
General and administrative expense was $15.6 million for
the year ended December 31, 2005 compared to
$7.3 million for the year ended December 31, 2004.
General and administrative expense increased due to the
additional expenses associated with the acquisitions completed
in the second half of 2004 and in 2005, and the hiring of
additional sales and administrative personnel. General and
administrative expense also increased because of increased legal
and accounting fees and other expenses related to our financing
and acquisition activities, increased consulting fees in
connection with our internal controls and corporate governance
process, and increased corporate accounting and administrative
staff. As a percentage of revenues, general and administrative
expenses were 14.8% for 2005 and 15.3% for 2004.
Amortization expense was $1.8 million for the year ended
December 31, 2005 compared to $0.9 million for the
year ended December 31, 2004. The increase in amortization
expense is due to the amortization of intangible assets in
connection with our acquisitions and the amortization of
deferred financing costs.
Income from operations for the year ended December 31, 2005
totaled $13.2 million, a 212.7% increase over the
$4.2 million in income from operations for the year ended
December 31, 2004, reflecting the increase in our revenues
and gross profit, offset in part by increased general and
administrative expenses.
Our interest expense was $4.4 million for the year ended
December 31, 2005, compared to $2.8 million for the
year ended December 31, 2004. Interest expense increased
during 2005 due to the increased borrowings associated with the
acquisitions completed in the second and third quarters of 2005,
equipment purchases and higher average interest rates, offset in
part by the prepayment, in December 2004, of our 12%
$2.4 million subordinated note. Additionally, in 2005, we
incurred debt retirement expense of $1.1 million related to
the refinancing of our debt. This amount includes prepayment
penalties and the write-off of deferred financing fees from a
previous financing.
Minority interest in income of subsidiaries for the year ended
December 31, 2005 was $488,000 compared to $321,000 for the
corresponding period in 2004 due to the increase in
profitability at AirComp due in part to the acquisition of
Diamond Air as of November 1, 2004. The minority interest
at AirComp was acquired on July 11, 2005 and the minority
interest in Tubular, which was 19%-owned by director Jens
Mortensen, was acquired on September 30, 2004.
We had net income attributed to common stockholders of
$7.2 million for the year ended December 31, 2005, an
increase of 839.1%, compared to net income attributed to common
stockholders of $0.8 million for the year ended
December 31, 2004. The net income attributed to common
stockholders in the 2004 period is after $124,000 in preferred
stock dividends.
38
The following table compares revenues and income from operations
for each of our business segments for the years ended
December 31, 2005 and December 31, 2004. Income from
operations consists of our revenues less cost of revenues,
general and administrative expenses, and depreciation and
amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
Income (Loss) from Operations
|
|
|
|
2005
|
|
|
2004
|
|
|
Change
|
|
|
2005
|
|
|
2004
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Rental tools
|
|
$
|
5,059
|
|
|
$
|
611
|
|
|
$
|
4,448
|
|
|
$
|
1,300
|
|
|
$
|
(71
|
)
|
|
$
|
1,371
|
|
Directional drilling services
|
|
|
43,901
|
|
|
|
24,787
|
|
|
|
19,114
|
|
|
|
7,389
|
|
|
|
3,061
|
|
|
|
4,328
|
|
Casing and tubing services
|
|
|
20,932
|
|
|
|
10,391
|
|
|
|
10,541
|
|
|
|
4,994
|
|
|
|
3,217
|
|
|
|
1,777
|
|
Compressed air drilling services
|
|
|
25,662
|
|
|
|
11,561
|
|
|
|
14,101
|
|
|
|
5,612
|
|
|
|
1,169
|
|
|
|
4,443
|
|
Production services
|
|
|
9,790
|
|
|
|
376
|
|
|
|
9,414
|
|
|
|
(99
|
)
|
|
|
4
|
|
|
|
(103
|
)
|
General corporate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,978
|
)
|
|
|
(3,153
|
)
|
|
|
(2,825
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
105,344
|
|
|
$
|
47,726
|
|
|
$
|
57,618
|
|
|
$
|
13,218
|
|
|
$
|
4,227
|
|
|
$
|
8,991
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental Tools Segment. Our rental tools
revenues were $5.1 million for the year ended
December 31, 2005, an increase of 728.0% compared to
$0.6 million in revenues for the year ended
December 31, 2004. Income from operations increased to
$1.3 million in 2005 compared to a loss from operations of
$71,000 in 2004. Operations for this segment include Safco,
acquired in September 2004, and Delta, acquired in April 2005.
Directional Drilling Services
Segment. Revenues for the year ended
December 31, 2005 for our directional drilling services
segment were $43.9 million, an increase of 77.1% from the
$24.8 million in revenues for the year ended
December 31, 2004. Income from operations increased 141.4%
to $7.4 million for 2005 from $3.1 million for 2004.
The improved results for this segment are due to the increase in
drilling activity in the Texas and Gulf Coast areas, the
establishment of new operations in West Texas and Oklahoma, the
addition of operations and sales personnel, the purchase of
additional downhole motors which increased our capacity and
market presence and the acquisition of Target, a provider of
measurement while drilling equipment, effective August 2005. Our
operating income increased due to higher revenue explained above
and cost savings achieved as a result of the purchases of most
of the downhole motors used in directional drilling, which we
had previously rented.
Casing and Tubing Services Segment. Revenues
for the year ended December 31, 2005 for the casing and
tubing services segment were $20.9 million, an increase of
101.4% from the $10.4 million in revenues for the year
ended December 31, 2004. Revenues from domestic operations
increased to $14.5 million in 2005 from $5.2 million
in 2004 as a result of the acquisition of the casing and tubing
assets of Patterson Services, Inc. on September 1, 2005,
improved market conditions for our services in South Texas and
the addition of personnel which added to our capabilities and
our offering of services. Revenues from Mexican operations
increased to $6.4 million in 2005 from $5.2 million in
2004 as a result of increased drilling activity in Mexico and
the addition of equipment that increased our capacity. Income
from operations increased 55.2% to $5.0 million in 2005
from $3.2 million in 2004. The increase in this
segments operating income is due to increased revenues
both domestically and in our Mexico operations.
Compressed Air Drilling Services Segment. Our
compressed air drilling revenues were $25.7 million for the
year ended December 31, 2005, an increase of 122.0%
compared to $11.6 million in revenues for the year ended
December 31, 2004. Income from operations increased 380.1%
to $5.6 million in 2005 compared to income from operations
of $1.2 million in 2004. Our compressed air drilling
revenues and operating income for the 2005 period increased
compared to the 2004 period due in part to the acquisition of
the air drilling assets of W. T., the acquisitions of Diamond
Air as of November 1, 2004 and improved pricing in West
Texas.
Production Services Segment. Our production
services revenues were $9.8 million for the year ended
December 31, 2005, compared to $376,000 in revenues for the
year ended December 31, 2004. Loss from operations was
$99,000 in 2005 compared to an operating income of $4,000 in
2004. Operations for this segment consist of Downhole, acquired
December 1, 2004, and Capcoil, acquired May 1, 2005.
Our results for the year ended December 31, 2005 for this
segment were negatively affected by costs incurred to expand our
39
international presence for production services and by downtime
experienced by one of our larger coil tubing units.
Liquidity
and Capital Resources
Our on-going capital requirements arise primarily from our need
to service our debt, to acquire and maintain equipment, to fund
our working capital requirements and to complete acquisitions.
Our primary sources of liquidity are proceeds from the issuance
of debt and equity securities and cash flows from operations. We
had cash and cash equivalents of $39.7 million at
December 31, 2006 compared to $1.9 million at
December 31, 2005.
Operating
Activities
In the year ended December 31, 2006, we generated
$53.7 million in cash from operating activities. Net income
for the year ended December 31, 2006 was
$35.6 million. Non-cash additions to net income totaled
$29.7 million in the 2006 period consisting primarily of
$23.2 million of depreciation and amortization,
$3.4 million related to the expensing of stock options as
required under SFAS No. 123R, $2.2 million of
deferred income tax, $781,000 for a provision for bad debts and
$453,000 of amortization on the bridge loan fees, partially
offset by $2.4 million of gain from the disposition of
equipment.
During the year ended December 31, 2006, changes in working
capital used $9.9 million in cash, principally due to an
increase of $23.2 million in accounts receivable, a
decrease of $2.3 million in accounts payable, offset in
part by an increase of $11.4 million in accrued interest,
an increase of $3.4 million in accrued employee benefits
and payroll taxes and an increase of $872,000 in accrued
expenses. Our accounts receivables increased at
December 31, 2006 primarily due to the increase in our
revenues in 2006. Accrued interest increased at
December 31, 2006 due principally to interest accrued on
our 9.0% senior notes which is payable semi-annually. Our
accrued employee benefits and payroll taxes and other accrued
expenses increased primarily due to the increase in costs due to
our growth in revenues and acquisition completed in 2006.
In the year ended December 31, 2005, we generated
$3.6 million in cash from operating activities. Net income
for the year ended December 31, 2005 was $7.2 million.
Non-cash additions to net income totaled $7.4 million in
the 2005 period consisting primarily of $6.7 million of
depreciation and amortization, $488,000 of minority interest in
the income of a subsidiary, $653,000 in write-off of financing
fees in conjunction with a refinancing and $219,000 for a
provision for bad debts and the $669,000 of gain from the
disposition of equipment.
During the year ended December 31, 2005, changes in working
capital used $11.0 million in cash, principally due to an
increase of $10.7 million in accounts receivable, an
increase of $2.1 million in other current assets, an
increase in other assets of $936,000, a decrease in other
liabilities of $266,000 and a decrease of $97,000 in accrued
expenses, offset in part by an increase of $2.4 million in
accounts payable, an increase of $324,000 in accrued interest
and a increase of $443,000 in accrued employee benefits and
payroll taxes. Our accounts receivables increased at
December 31, 2005 due primarily to the increase in our
revenues in 2005. Other current assets increased
$2.1 million due primarily to an increase in inventory.
Accounts payable increased by $2.4 million at
December 31, 2005 due to the increase in our cost of sales
associated with the increase in our revenues and the
acquisitions completed in 2005 and 2004.
In the year ended December 31, 2004, we generated
$3.3 million in cash from operating activities. Net income
before preferred stock dividend for the year ended
December 31, 2004 was $888,000. Non-cash additions to net
income totaled $4.4 million in the 2004 period consisting
of $3.6 million of depreciation and amortization, $321,000
of minority interest in the income of a subsidiary, $350,000 in
amortization of discount on debt and $104,000 for a provision
for bad debts.
During the year ended December 31, 2004, changes in working
capital used $2.0 million in cash, principally due to an
increase of $2.4 million in accounts receivable, an
increase of $638,000 in other assets, and a decrease of $398,000
in accrued expenses and other liabilities, offset in part by an
increase of $1.1 million in accounts payable and an
increase of $299,000 in accrued interest. Our accounts
receivables increased at December 31, 2004 due primarily to
the increase in our revenues in 2004. Current assets increased
40
$638,000 due primarily to an increase in prepaid insurance
premiums. Accounts payable increased by $1.1 million at
December 31, 2004 due to the increase in our cost of sales
associated with the increase in our revenues and the
acquisitions completed in the fourth quarter of 2004.
Investing
Activities
During the year ended December 31, 2006, we used
$559.4 million in investing activities consisting of six
acquisitions and our capital expenditures. During the year ended
December 31, 2006, we completed the following acquisitions
for a total net cash outlay of $526.6 million, consisting
of the purchase price and acquisition costs less cash acquired:
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|
|
|
|
Effective January 1, 2006, we acquired Specialty for a
purchase price of $96.0 million in cash.
|
|
|
|
Effective April 1, 2006, we acquired Rogers for a purchase
price of $11.3 million in cash, 125,285 shares of our
common stock and a promissory note for $750,000.
|
|
|
|
On August 14, 2006, we acquired DLS for a purchase price of
$93.7 million in cash, 2.5 million shares of our
common stock and the assumption of $9.1 million of
indebtedness.
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|
|
|
On October 16, 2006, we acquired Petro Rentals for a
purchase price of $20.2 million in cash,
246,761 shares of our common stock and the payment of
approximately $9.6 million of debt.
|
|
|
|
Effective December 1, 2006, we acquired Tanus for a
purchase price of $2.5 million in cash.
|
|
|
|
On December 18, 2006, we acquired substantially all of the
assets of OGR for a purchase price of approximately
$291.0 million in cash and 3.2 million shares of our
common stock.
|
In addition we made capital expenditures of approximately
$39.7 million during the year ended December 31, 2006,
including $4.5 million to replace
lost-in-hole
equipment and to increase our inventory of equipment in the
rental tools segment, $5.8 million to purchase, improve and
replace equipment in our international drilling segment,
$5.1 million to purchase equipment for our directional
drilling services segment, $7.7 million to purchase and
improve equipment in our compressed air drilling service
segment, $11.0 million to purchase and improve our casing
equipment and approximately $5.3 million to expand our
production services segment. We also received $6.9 million
from the sale of assets during the year ended December 31,
2006, comprised mostly from equipment
lost-in-hole
from our rental tools segment ($3.8 million) and our
directional drilling segment ($1.8 million).
During the year ended December 31, 2005, we used
$53.1 million in investing activities. During the year
ended December 31, 2005, we completed the following
acquisitions for a total net cash outlay of $36.9 million,
consisting of the purchase price and acquisition costs less cash
acquired:
|
|
|
|
|
On April 1, 2005 we acquired Delta for a purchase price of
$4.6 million in cash, 223,114 shares of our common
stock and two promissory notes totaling $350,000.
|
|
|
|
On May 1, 2005, we acquired Capcoil for a purchase price of
$2.7 million in cash, 168,161 shares of our common
stock and the payment or assumption of approximately
$1.3 million of debt.
|
|
|
|
On July 11, 2005, we acquired the compressed air drilling
assets of W.T. for a purchase price of $6.0 million in cash.
|
|
|
|
On July 11, 2005, we acquired from M-I its 45%
interest in AirComp and subordinated note in the principal
amount of $4.8 million issued by AirComp, for which we paid
M-I $7.1 million in cash and reissued a $4.0 million
subordinated note.
|
|
|
|
Effective August 1, 2005, we acquired Target for a purchase
price of $1.3 million in cash and forgiveness of a lease
receivable of $592,000.
|
|
|
|
On September 1, 2005, we acquired the casing and tubing
service assets of Patterson Services, Inc. for a purchase price
of approximately $15.6 million.
|
In addition we made capital expenditures of approximately
$17.8 million during the year ended December 31, 2005,
including $2.9 million to purchase equipment for our
directional drilling services segment, $7.0 million to
purchase and improve equipment in our compressed air drilling
service segment, $5.2 million to purchase and improve our
casing equipment and approximately $1.5 million to expand
our production
41
services segment. We also received $1.6 million from the
sale of assets during the year ended December 31, 2005,
comprised mostly from equipment lost in the hole from our
directional drilling segment ($1.0 million) and our rental
tool segment ($408,000).
During the year ended December 31, 2004, we used
$9.1 million in investing activities, consisting
principally of capital expenditures of approximately
$4.6 million, including $1.6 million to purchase
equipment for our directional drilling services segment,
$1.3 million to purchase casing equipment and
$1.4 million to make capital repairs to existing equipment
in our compressed air drilling services segment. During the year
ended December 31, 2004, we completed the following
acquisitions for a net cash outlay of $4.6 million.
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|
|
|
|
As of September 1, 2004 we completed, for
$1.0 million, the acquisition of 100% of the outstanding
stock of Safco.
|
|
|
|
As of November 1, 2004, AirComp acquired substantially all
the assets of Diamond Air for $4.6 million in cash and the
assumption of approximately $450,000 of debt. We contributed our
share of the purchase price, or $2.5 million, to AirComp in
order to fund the purchase.
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|
|
|
Effective December 1, 2004, we acquired Downhole for
approximately $1.1 million in cash, 568,466 shares of
our common stock and payment or assumption of $950,000 of debt.
|
Financing
Activities
During the year ended December 31, 2006, financing
activities provided a net of $543.6 million in cash. We
received $557.8 million in borrowings under long-term debt
facilities, consisting primarily of the issuance of
$255.0 million of our 9.0% senior notes due 2014 and a
$300.0 million senior unsecured bridge loan. The bridge
loan, which was repaid on January 29, 2007, was used to
fund the acquisition of OGR. We also received $46.3 million
in net proceeds from the issuance of 3,450,000 shares of
our common stock, $6.4 million on the tax benefit of
options and $6.3 million from the proceeds of warrant and
option exercises for 1,851,377 shares of our common stock.
The proceeds were used to repay long-term debt totaling
$54.0 million, repay $6.4 million in net borrowings
under our revolving lines of credit, repay related party debt of
$3.0 million and to pay $9.9 million in debt issuance
costs.
During the year ended December 31, 2005, financing
activities provided a net of $44.1 million in cash. We
received $56.3 million in borrowings under long-term debt
facilities, $15.5 million in net proceeds from the issuance
of 1,761,034 shares of our common stock, $2.5 million
in net borrowings under our revolving lines of credit and
$1.4 million from the proceeds of warrant and option
exercises for 1,076,154 shares of our common stock. The
proceeds were used to repay long-term debt totaling
$28.2 million, repay related party debt of
$1.5 million and to pay $1.8 million in debt issuance
costs.
During the year ended December 31, 2004, financing
activities provided a net of $11.8 million in cash. We
received $16.9 million in net proceeds from the issuance of
6,081,301 shares of our common stock, $8.2 million in
borrowings under long-term debt facilities and a $689,000
increase in net borrowings under our revolving lines of credit.
The proceeds were used to repay long-term debt totaling
$13.5 million and to pay $391,000 in debt issuance costs.
On January 18, 2006 and August 14, 2006, we closed on
private offerings, to qualified institutional buyers pursuant to
Rule 144A under the Securities Act, of $160.0 million
and $95.0 million aggregate principal amount of our senior
notes, respectively. The senior notes are due January 15,
2014 and bear interest at 9.0%. The proceeds were used to fund
the acquisitions of Specialty and DLS, to repay existing debt
and for general corporate purposes. Debt repaid included all
outstanding balances under our credit agreement, including a
$42.1 million term loan and $6.4 million in working
capital advances, a $4.0 million subordinated note issued
in connection with acquisition of AirComp, approximately
$3.0 million subordinated note issued in connection with
the acquisition of Tubular, approximately $548,000 on a real
estate loan and approximately $350,000 on outstanding equipment
financing.
On January 18, 2006, we also executed an amended and
restated credit agreement which provides for a
$25.0 million revolving line of credit with a maturity of
January 2010. This agreement contains customary events of
default and financial covenants and limits our ability to incur
additional indebtedness, make capital expenditures, pay
dividends or make other distributions, create liens and sell
assets. Our obligations under the
42
agreement are secured by substantially all of our assets
excluding the DLS assets, but including 2/3 of our shares of
DLS. At December 31, 2006, no amounts were borrowed on the
facility but availability is reduced by outstanding letters of
credit of $9.7 million.
As part of our acquisition of DLS, we assumed various bank loans
with floating interest rates based on LIBOR plus a margin and
terms ranging from 2 to 5 years. The weighted average
margin was 7.0% at December 31, 2006. These bank loans are
denominated in U.S. dollars and the outstanding amount due
as of December 31, 2006 was $7.3 million.
On December 18, 2006, we closed on the OGR acquisition with
the proceeds from a $300.0 million unsecured bridge
financing. The bridge loan had a term of 18 months.
Tranche A of the bridge was for $225.0 million and
bore interest at LIBOR plus 3.75%, and Tranche B was for
$75.0 million and bore interest at LIBOR plus 5.75% The
bridge was repaid on January 29, 2007 from the proceeds of
a private offering of $250.0 million aggregate principal
amount of 8.5% senior notes due 2017 and the proceeds from an
offering of 6.0 million shares of our common stock.
In connection with the acquisition of Rogers, we issued to the
seller a note in the amount of $750,000. The note bears interest
at 5.0% and is due April 3, 2009.
As part of the acquisition of Mountain Air in 2001, we issued a
note to the sellers of Mountain Air in the original amount of
$2.2 million accruing interest at a rate of 5.75% per
annum. The note was reduced to $1.5 million as a result of
the settlement of a legal action against the sellers in 2003. In
March 2005, we reached an agreement with the sellers and holders
of the note as a result of an action brought against us by the
sellers. Under the terms of the agreement, we paid the holders
of the note $1.0 million in cash, and agreed to pay an
additional $350,000 on June 1, 2006, and an additional
$150,000 on June 1, 2007, in settlement of all claims. At
December 31, 2006 the outstanding amounts due were $150,000.
In connection with the purchase of Safco, we agreed to pay a
total of $150,000 to the sellers in exchange for a non-compete
agreement. We are required to make annual payments of $50,000
through September 30, 2007. In connection with the purchase
of Capcoil, we agreed to pay a total of $500,000 to two
management employees in exchange for non-compete agreements. We
are required to make annual payments of $110,000 through May
2008. Total amounts due under theses non-compete agreements at
December 31, 2006 was $270,000.
In 2000 we compensated directors, including current directors
Nederlander and Toboroff, who served on the board of directors
from 1989 to March 31, 1999 without compensation, by
issuing promissory notes totaling $325,000. The notes bore
interest at the rate of 5.0%. At December 31, 2006, the
principal and accrued interest on these notes totaled
approximately $32,000.
We have various equipment financing loans with interest rates
ranging from 5.0% to 8.7% and terms ranging from 2 to
5 years. As of December 31, 2006, the outstanding
balances for equipment financing loans were $3.5 million.
We also have various capital leases with terms that expire in
2008. As of December 31, 2006, amounts outstanding under
capital leases were approximately $414,000.
In April 2006 and August 2006, we obtained insurance premium
financings in the amount of $1.9 million and $896,000 with
fixed interest rates of 5.6% and 6.0%, respectively Under terms
of the agreements, amounts outstanding are paid over
10 month and 11 month repayment schedules. The
outstanding balances of these notes was approximately
$1.0 million as of December 31, 2006.
43
The following table summarizes our obligations and commitments
to make future payments under our notes payable, operating
leases, employment contracts and consulting agreements for the
periods specified as of December 31, 2006.
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|
|
|
|
|
|
|
|
|
|
|
|
|
Payments by Period
|
|
|
|
|
|
|
Less Than
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1 Year
|
|
|
2-3 Years
|
|
|
4-5 Years
|
|
|
After 5 Years
|
|
|
|
(In thousands)
|
|
|
Contractual
Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes payable(a)
|
|
$
|
518,032
|
|
|
$
|
6,586
|
|
|
$
|
4,646
|
|
|
$
|
1,800
|
|
|
$
|
505,000
|
|
Capital leases(b)
|
|
|
413
|
|
|
|
413
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest payments on notes
payable(a)
|
|
|
379,759
|
|
|
|
45,797
|
|
|
|
88,858
|
|
|
|
88,456
|
|
|
|
156,648
|
|
Operating leases
|
|
|
5,418
|
|
|
|
2,013
|
|
|
|
2,658
|
|
|
|
277
|
|
|
|
470
|
|
Employment contracts
|
|
|
5,394
|
|
|
|
3,064
|
|
|
|
2,330
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual cash obligations
|
|
$
|
909,016
|
|
|
$
|
57,873
|
|
|
$
|
98,492
|
|
|
$
|
90,533
|
|
|
$
|
662,118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes obligations on our $255 million 8.5% senior
notes closed in January 2007. The proceeds from the
8.5% senior notes and our January 2007 common stock
offering were used to repay the $300 million bridge loan
facility that was outstanding at December 31, 2006. |
|
(b) |
|
These amounts represent our minimum capital lease payments, net
of interest payments totaling $15,000. |
We have identified capital expenditure projects that will
require up to approximately $80.0 million in 2007,
exclusive of any acquisitions. We believe that our cash
generated from operations, cash on hand and cash available under
our credit facilities will provide sufficient funds for our
identified projects.
We intend to implement a growth strategy of increasing the scope
of services through both internal growth and acquisitions. We
are regularly involved in discussions with a number of potential
acquisition candidates. We expect to make capital expenditures
to acquire and to maintain our existing equipment. Our
performance and cash flow from operations will be determined by
the demand for our services which in turn are affected by our
customers expenditures for oil and natural gas exploration
and development and industry perceptions and expectations of
future oil and natural gas prices in the areas where we operate.
We will need to refinance our existing debt facilities as they
become due and provide funds for capital expenditures and
acquisitions. To effect our expansion plans, we will require
additional equity or debt financing in excess of our current
working capital and amounts available under credit facilities.
There can be no assurance that we will be successful in raising
the additional debt or equity capital or that we can do so on
terms that will be acceptable to us.
Recent
Developments
In January 2007, we closed on a private offering, to qualified
institutional buyers pursuant to Rule 144A under the
Securities Act, of $255.0 million principal amount of our
8.5% senior notes due 2017. The proceeds of the senior
notes offering, together with a portion of the proceeds of our
concurrent common stock offering, were used to repay the debt
outstanding under our $300 million bridge loan facility,
which we incurred to finance our acquisition of substantially
all the assets of OGR.
In January 2007, we closed on a public offering of
6.0 million shares of our common stock at $17.65 per
share. The proceeds of the common stock offering, together with
the proceeds of our concurrent senior notes offering, were used
to repay the debt outstanding under our $300 million bridge
loan facility, which we incurred to finance our acquisition of
substantially all the assets of OGR and for general corporate
purposes.
On February 7, 2007, Zane Tankel was elected as a member of
our Board of Directors.
Critical
Accounting Policies
We have identified the policies below as critical to our
business operations and the understanding of our results of
operations. The impact and any associated risks related to these
policies on our business operations
44
is discussed throughout Managements Discussion and
Analysis of Financial Condition and Results of Operations where
such policies affect our reported and expected financial
results. For a detailed discussion on the application of these
and other accounting policies, see Note 1 in the Notes to
the Consolidated Financial Statements included elsewhere in this
document. Our preparation of this report requires us to make
estimates and assumptions that affect the reported amount of
assets and liabilities, disclosure of contingent assets and
liabilities at the date of our financial statements, and the
reported amounts of revenue and expenses during the reporting
period. There can be no assurance that actual results will not
differ from those estimates.
Allowance For Doubtful Accounts. The
determination of the collectibility of amounts due from our
customers requires us to use estimates and make judgments
regarding future events and trends, including monitoring our
customer payment history and current credit worthiness to
determine that collectibility is reasonably assured, as well as
consideration of the overall business climate in which our
customers operate. Those uncertainties require us to make
frequent judgments and estimates regarding our customers
ability to pay amounts due us in order to determine the
appropriate amount of valuation allowances required for doubtful
accounts. Provisions for doubtful accounts are recorded when it
becomes evident that the customers will not be able to make the
required payments at either contractual due dates or in the
future.
Revenue Recognition. We provide rental
equipment and drilling services to our customers at per day and
per job contractual rates and recognize the drilling related
revenue as the work progresses and when collectibility is
reasonably assured. The Securities and Exchange
Commissions Staff Accounting Bulletin No. 104,
Revenue Recognition in Financial Statements, provides
guidance on the SEC staffs views on application of
generally accepted accounting principles to selected revenue
recognition issues. Our revenue recognition policy is in
accordance with generally accepted accounting principles and
SAB No. 104.
Impairment Of Long-Lived Assets. Long-lived
assets, which include property, plant and equipment, goodwill
and other intangibles, comprise a significant amount of our
total assets. We make judgments and estimates in conjunction
with the carrying value of these assets, including amounts to be
capitalized, depreciation and amortization methods and useful
lives. Additionally, the carrying values of these assets are
reviewed for impairment or whenever events or changes in
circumstances indicate that the carrying amounts may not be
recoverable. An impairment loss is recorded in the period in
which it is determined that the carrying amount is not
recoverable. This requires us to make long-term forecasts of our
future revenues and costs related to the assets subject to
review. These forecasts require assumptions about demand for our
products and services, future market conditions and
technological developments. Significant and unanticipated
changes to these assumptions could require a provision for
impairment in a future period.
Goodwill And Other Intangibles. As of
December 31, 2006, we have recorded approximately
$125.8 million of goodwill and $32.8 million of other
identifiable intangible assets. We perform purchase price
allocations to intangible assets when we make a business
combination. Business combinations and purchase price
allocations have been consummated for acquisitions in all of our
reportable segments. The excess of the purchase price after
allocation of fair values to tangible assets is allocated to
identifiable intangibles and thereafter to goodwill.
Subsequently, we perform our initial impairment tests and annual
impairment tests in accordance with Financial Accounting
Standards Board No. 141, Business Combinations, and
Financial Accounting Standards Board No. 142, Goodwill
and Other Intangible Assets. These initial valuations used
two approaches to determine the carrying amount of the
individual reporting units. The first approach is the Discounted
Cash Flow Method, which focuses on our expected cash flow. In
applying this approach, the cash flow available for distribution
is projected for a finite period of years. Cash flow available
for distribution is defined as the amount of cash that could be
distributed as a dividend without impairing our future
profitability or operations. The cash flow available for
distribution and the terminal value (our value at the end of the
estimation period) are then discounted to present value to
derive an indication of value of the business enterprise. This
valuation method is dependent upon the assumptions made
regarding future cash flow and cash requirements. The second
approach is the Guideline Company Method which focuses on
comparing us to selected reasonably similar publicly traded
companies. Under this method, valuation multiples are:
(i) derived from operating data of selected similar
companies; (ii) evaluated and adjusted based on our
strengths and weaknesses relative to the selected guideline
companies; and (iii) applied to our operating data to
arrive at an indication of value. This valuation method is
dependent upon the assumption that our value can be evaluated by
analysis of our earnings and our strengths and weaknesses
relative to the selected similar companies.
45
Significant and unanticipated changes to these assumptions could
require a provision for impairment in a future period.
Income Taxes. The determination and evaluation
of our annual income tax provision involves the interpretation
of tax laws in various jurisdictions in which we operate and
requires significant judgment and the use of estimates and
assumptions regarding significant future events such as the
amount, timing and character of income, deductions and tax
credits. Changes in tax laws, regulations and our level of
operations or profitability in each jurisdiction may impact our
tax liability in any given year. While our annual tax provision
is based on the information available to us at the time, a
number of years may elapse before the ultimate tax liabilities
in certain tax jurisdictions are determined. Current income tax
expense reflects an estimate of our income tax liability for the
current year, withholding taxes, changes in tax rates and
changes in prior year tax estimates as returns are filed.
Deferred tax assets and liabilities are recognized for the
anticipated future tax effects of temporary differences between
the financial statement basis and the tax basis of our assets
and liabilities using the enacted tax rates in effect at year
end. A valuation allowance for deferred tax assets is recorded
when it is more-likely-than-not that the benefit from the
deferred tax asset will not be realized.
It is our intention to permanently reinvest all of the
undistributed earnings of our non-U.S. subsidiaries in such
subsidiaries. Accordingly, we have not provided for U.S.
deferred taxes on the undistributed earnings of our non-U.S.
subsidiaries. If a distribution is made to us from the
undistributed earnings of these subsidiaries, we could be
required to record additional taxes. Because we cannot predict
when, if at all, we will make a distribution of these
undistributed earnings, we are unable to make a determination of
the amount of unrecognized deferred tax liability.
Recently
Issued Accounting Standards
In February 2006, the FASB issued SFAS No. 155,
Accounting for Certain Hybrid Financial
Instruments. SFAS No. 155 provides
entities with relief from having to separately determine the
fair value of an embedded derivative that would otherwise be
required to be bifurcated from its host contract in accordance
with SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities. SFAS No. 155
allows an entity to make an irrevocable election to measure such
a hybrid financial instrument at fair value in its entirely,
with changes in fair value recognized in earning.
SFAS No. 155 is effective for all financial
instruments acquired , issued or subject to a remeasurement
event occurring after the beginning of an entitys first
fiscal year that begins after September 15, 2006. We
believe that the adoption of SFAS No. 155 will not
have a material impact on our financial position, results of
operations or cash flows.
In March 2006, the FASB issued SFAS No. 156,
Accounting for Servicing of Financial
Assets An Amendment to FASB Statement
No. 140. SFAS No. 156 requires entities to
recognize a servicing asset or liability each time they
undertake an obligation to service a financial asset by entering
into a servicing contract in certain situations. This statement
also requires all separately recognized servicing assets and
servicing liabilities to be initially measured at fair value and
permits a choice of either the amortization or fair value
measurement method for subsequent measurement. The effective
date of this statement is for annual periods beginning after
September 15, 2006, with earlier adoption permitted as of
the beginning of an entitys fiscal year provided the
entity has not issued any financial statements for that year. We
do not plan to adopt SFAS No. 156 early, and we are
currently assessing the impact on our Consolidated Financial
Statements.
In July 2006, the FASB issued FASB Interpretation, FIN,
No. 48, Accounting for Uncertainty in Income
Taxes An Interpretation of FASB Statement
No. 109. FIN No. 48 clarifies the accounting
for uncertainty in income taxes recognized in an
enterprises financial statements in accordance with
SFAS No. 109, Accounting for Income Taxes. It
prescribes a recognition threshold and measurement attribute for
the financial statement recognition and measurement of a tax
position taken or expected to be taken in a tax return. This new
standard also provides guidance on derecognition,
classification, interest and penalties, accounting in interim
periods, disclosure and transition. The provisions of
FIN No. 48 are to be applied to all tax positions upon
initial adoption of this standard. Only tax positions that meet
the more
likely-than-not
recognition threshold at the effective date may be recognized or
continue to be recognized upon adoption of FIN No. 48.
The cumulative effect of applying the provisions of
FIN No. 48 should be reported as an adjustment to the
opening balance of
46
retaining earnings (or other appropriate components of equity or
net assets in the statement of financial position) for that
fiscal year. The provisions of FIN No. 48 are
effective for fiscal years beginning after December 15,
2006. We are currently evaluating the impact of applying the
provisions of FIN No. 48.
In September 2006, the FASB issued SFAS No. 157, Fair
Value Measurements. SFAS No. 157 clarifies the
principle that fair value should be based on the assumptions
that market participants would use when pricing an asset or
liability and establishes a fair value hierarchy that
prioritizes the information used to develop those assumptions.
Under the standard, fair value measurements would be separately
disclosed by level within the fair value hierarchy.
SFAS No. 157 is effective for financial statements
issued for fiscal years beginning after November 15, 2007,
and interim periods within those fiscal years, with early
adoption permitted. We believe that the adoption of
SFAS No. 157 will not have a material impact on our
financial position, results of operations or cash flows.
In September 2006, the FASB issued FSP No. AUG AIR-1,
Accounting for Planned Major Maintenance Activities. FSP
No. AUG AIR-1 prohibits the use of the
accrued-in-advance
method for accounting for major maintenance activities and
confirms the acceptable methods of accounting for planned major
maintenance activities. FSP No. AUG AIR-1 is effective the
first fiscal year beginning after December 15, 2006. We
believe that the adoption of FSP No. AUG AIR-1 will not
have a material impact on our financial position, results of
operations or cash flows.
In September 2006, the Securities and Exchange Commission issued
Staff Accounting Bulletin 108, Considering the Effects
of Prior Year Misstatements when Quantifying Misstatements in
Current Year Financial Statements
(SAB 108). SAB 108 requires that
public companies utilize a dual-approach to
assessing the quantitative effects of financial misstatements.
This dual approach includes both an income statement focused
assessment and a balance sheet focused assessment. SAB 108
is effective for fiscal years ending after November 15,
2006. We adopted SAB 108 on December 31, 2006, and
there was no impact on our consolidated financial statements.
Off-Balance
Sheet Arrangements
We have no off balance sheet arrangements, other than normal
operating leases and employee contracts, that have or are likely
to have a current or future material effect on our financial
condition, changes in financial condition, revenues, expenses,
results of operations, liquidity, capital expenditures or
capital resources. We have a $25.0 million revolving line
of credit with a maturity of January 2010. At December 31,
2006, no amounts were borrowed on the facility but availability
is reduced by outstanding letters of credit of
$9.7 million. We do not guarantee obligations of any
unconsolidated entities.
|
|
ITEM 7A.
|
QUANTITATIVE
AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.
|
We are exposed to market risk primarily from changes in interest
rates and foreign currency exchange risks.
Interest
Rate Risk
Fluctuations in the general level of interest rates on our
current and future fixed and variable rate debt obligations
expose us to market risk. We are vulnerable to significant
fluctuations in interest rates on our variable rate debt and on
any future refinancing of our fixed rate debt and on future debt.
At December 31, 2006, we were exposed to interest rate
fluctuations on approximately $8.1 million of bank loans
carrying variable interest rates. A hypothetical one hundred
basis point increase in interest rates for these notes payable
would increase our annual interest expense by approximately
$81,000. Due to the uncertainty of fluctuations in interest
rates and the specific actions that might be taken by us to
mitigate the impact of such fluctuations and their possible
effects, the foregoing sensitivity analysis assumes no changes
in our financial structure.
We have also been subject to interest rate market risk for
short-term invested cash and cash equivalents. The principal of
such invested funds would not be subject to fluctuating value
because of their highly liquid short-term nature. As of
December 31, 2006, we had $28.3 million invested in
short-term maturing investments.
47
Foreign
Currency Exchange Rate Risk
We have designated the U.S. dollar as the functional
currency for our operations in international locations as we
contract with customers, purchase equipment and finance capital
using the U.S. dollar. Local currency transaction gains and
losses, arising from remeasurement of certain assets and
liabilities denominated in local currency, are included in our
consolidated statements of income. For the year ended
December 31, 2006, we had a net foreign exchange loss of
$515,000 relating to our DLS operations. We conduct business in
Mexico through our Mexican partner, Matyep. This business
exposes us to foreign exchange risk. To control this risk, we
provide for payment in U.S. dollars.
|
|
ITEM 8.
|
FINANCIAL
STATEMENTS.
|
INDEX TO
FINANCIAL STATEMENTS
ALLIS-CHALMERS
ENERGY INC. AND SUBSIDIARIES
|
|
|
|
|
|
|
Page
|
|
|
|
|
49
|
|
|
|
|
50
|
|
|
|
|
52
|
|
|
|
|
53
|
|
|
|
|
54
|
|
|
|
|
55
|
|
|
|
|
56
|
|
Supplemental Information to
Consolidated Financial Statements Summarized
Quarterly Financial Data
|
|
|
91
|
|
48
MANAGEMENTS
REPORT TO THE STOCKHOLDERS OF ALLIS-CHALMERS ENERGY
INC.
Managements
Report on Internal Control Over Financial Reporting
As management, we are responsible for establishing and
maintaining adequate internal control over financial reporting
for Allis-Chalmers Energy Inc. and its subsidiaries, or
Allis-Chalmers. In order to evaluate the effectiveness of
internal control over financial reporting, as required by
Section 404 of the Sarbanes-Oxley Act of 2002, we have
conducted an assessment, including testing, using the criteria
in Internal Control-Integral Framework issued by the
Committee of Sponsoring Organization of the Treadway Commission
(COSO). Allis-Chalmers system of internal control over
financial reporting is designed 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. Because of its inherent limitation,
internal control over financial reporting may not prevent or
detect misstatements.
Based on our assessment, we have concluded that Allis-Chalmers
maintained effective internal control over financial reporting
as of December 31, 2006, based on criteria in Internal
Control-Integrated Framework issued by the COSO. Our
assessment of the effectiveness of Allis-Chalmers internal
control over financial reporting as of December 31, 2006
has been audited by UHY LLP, an independent registered public
accounting firm, as stated in their report, which is included
herein.
Managements
Certifications
The certifications of Allis-Chalmers Chief Executive
Officer and Chief Financial Officer required by the
Sarbanes-Oxley Act of 2002 have been included as
Exhibits 31 and 32 in Allis-Chalmers
Form 10-K.
ALLIS-CHALMERS
ENERGY INC.
|
|
|
|
|
|
|
|
|
By:
|
|
/s/ Munawar H. Hidayatallah
|
|
|
|
By:
|
|
/s/ Victor Perez
|
|
|
Munawar H. Hidayatallah
|
|
|
|
|
|
Victor Perez
|
|
|
Chief Executive Officer
|
|
|
|
|
|
Chief Financial Officer
|
49
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Allis-Chalmers Energy Inc.
Houston, Texas
We have audited the accompanying consolidated balance sheets of
Allis-Chalmers Energy Inc. and subsidiaries (the
Company) as of December 31, 2006 and 2005, and
the related consolidated statements of operations,
stockholders equity and cash flows for each of the three
years in the period ended December 31, 2006. These
consolidated financial statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these consolidated 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 audits 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
consolidated financial position of Allis-Chalmers Energy Inc.
and subsidiaries as of December 31, 2006 and 2005, and the
consolidated results of their operations and their cash flows
for each of the three years in the period ended
December 31, 2006, 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), the
effectiveness of Allis-Chalmers Energy Inc. and
subsidiaries internal control over financial reporting as
of December 31, 2006, based on criteria established in
Internal Control-Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission
(COSO), and our report dated March 15, 2007 expressed an
unqualified opinion on managements assessment of, and the
effective operation of, internal control over financial
reporting.
As discussed in Note 1 to the consolidated financial
statements, effective January 1, 2006, the Company changed
its method of accounting for stock-based compensation.
Houston, Texas
March 15, 2007
50
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and
Stockholders of Allis-Chalmers Energy Inc.:
We have audited managements assessment, included in the
accompanying Managements Report on Internal Control Over
Financial Reporting appearing on Page 49, that
Allis-Chalmers Energy Inc. and subsidiaries, or the Company,
maintained effective internal control over financial reporting
as of December 31, 2006, based on criteria established in
Internal Control-Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway
Commission. The Companys management is responsible for
maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control
over finance reporting. Our responsibility is to express an
opinion on managements assessment and an opinion on the
effectiveness of the Companys internal control over
financial reporting based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting of 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, evaluating
managements assessment, testing and evaluating the design
and operating effectiveness of internal control, 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 receipts and expenditures of the company are
being made only in accordance with authorization 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, managements assessment that Allis-Chalmers
Energy Inc. and subsidiaries maintained effective internal
control over financial reporting as of December 31, 2006,
is fairly stated, in all material respects, based on criteria
established in Internal Control-Integrated Framework
issued by Committee of Sponsoring Organizations of the
Treadway Commission. Also, in our opinion, Allis-Chalmers Energy
Inc. and subsidiaries maintained, in all material respects,
effective internal control over financial reporting as of
December 31, 2006, based on criteria established in
Internal Control-Integrated Framework issued by Committee
of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of Allis-Chalmers Energy Inc. and
subsidiaries as of December 31, 2006 and 2005, and the
related consolidated statements of operations, stockholders
equity, and cash flows for each of the three years in the period
ended December 31, 2006, and our report dated
March 15, 2007 expressed an unqualified opinion on those
consolidated financial statements.
Houston, Texas
March 15, 2007
51
ALLIS-CHALMERS
ENERGY INC.
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except
|
|
|
|
for share and per share amounts)
|
|
|
ASSETS
|
Cash and cash equivalents
|
|
$
|
39,745
|
|
|
$
|
1,920
|
|
Trade receivables, net of
allowance for doubtful accounts of $826 and $383 at
December 31, 2006 and 2005, respectively
|
|
|
95,766
|
|
|
|
26,964
|
|
Inventories
|
|
|
28,615
|
|
|
|
5,945
|
|
Prepaid expenses and other
|
|
|
16,636
|
|
|
|
823
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
180,762
|
|
|
|
35,652
|
|
Property and equipment, at costs
net of accumulated depreciation of $29,743 and $9,996 at
December 31, 2006 and 2005, respectively
|
|
|
554,258
|
|
|
|
80,574
|
|
Goodwill
|
|
|
125,835
|
|
|
|
12,417
|
|
Other intangible assets, net of
accumulated amortization of $4,475 and $3,163 at
December 31, 2006 and 2005, respectively
|
|
|
32,840
|
|
|
|
6,783
|
|
Debt issuance costs, net of
accumulated amortization of $1,501 and $299 at December 31,
2006 and 2005, respectively
|
|
|
9,633
|
|
|
|
1,298
|
|
Other assets
|
|
|
4,998
|
|
|
|
631
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
908,326
|
|
|
$
|
137,355
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS EQUITY
|
Current maturities of long-term
debt
|
|
$
|
6,999
|
|
|
$
|
5,632
|
|
Trade accounts payable
|
|
|
25,666
|
|
|
|
9,018
|
|
Accrued salaries, benefits and
payroll taxes
|
|
|
10,888
|
|
|
|
1,271
|
|
Accrued interest
|
|
|
11,867
|
|
|
|
289
|
|
Accrued expenses
|
|
|
16,951
|
|
|
|
4,350
|
|
Accounts payable, related parties
|
|
|
|
|
|
|
60
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
72,371
|
|
|
|
20,620
|
|
Deferred income tax liability
|
|
|
19,953
|
|
|
|
|
|
Long-term debt, net of current
maturities
|
|
|
561,446
|
|
|
|
54,937
|
|
Other long-term liabilities
|
|
|
623
|
|
|
|
923
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
654,393
|
|
|
|
76,480
|
|
Commitments and Contingencies
|
|
|
|
|
|
|
|
|
Stockholders Equity
|
|
|
|
|
|
|
|
|
Preferred stock, $0.01 par
value (25,000,000 shares authorized, none issued)
|
|
|
|
|
|
|
|
|
Common stock, $0.01 par value
(100,000,000 shares authorized; 28,233,411 issued and
outstanding at December 31, 2006 and 16,859,988 issued and
outstanding at December 31, 2005)
|
|
|
282
|
|
|
|
169
|
|
Capital in excess of par value
|
|
|
216,208
|
|
|
|
58,889
|
|
Retained earnings
|
|
|
37,443
|
|
|
|
1,817
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
253,933
|
|
|
|
60,875
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and
stockholders equity
|
|
$
|
908,326
|
|
|
$
|
137,355
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated
Financial Statements.
52
ALLIS-CHALMERS
ENERGY INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
(Restated)
|
|
|
|
(In thousands, except per
|
|
|
|
share amounts)
|
|
|
Revenues
|
|
$
|
307,304
|
|
|
$
|
105,344
|
|
|
$
|
47,726
|
|
Cost of revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs
|
|
|
181,919
|
|
|
|
69,889
|
|
|
|
32,598
|
|
Depreciation
|
|
|
20,261
|
|
|
|
4,874
|
|
|
|
2,702
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin
|
|
|
105,124
|
|
|
|
30,581
|
|
|
|
12,426
|
|
General and administrative expense
|
|
|
35,536
|
|
|
|
15,576
|
|
|
|
7,323
|
|
Amortization
|
|
|
2,932
|
|
|
|
1,787
|
|
|
|
876
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
66,656
|
|
|
|
13,218
|
|
|
|
4,227
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(20,235
|
)
|
|
|
(4,446
|
)
|
|
|
(2,808
|
)
|
Interest income
|
|
|
972
|
|
|
|
49
|
|
|
|
32
|
|
Other
|
|
|
(347
|
)
|
|
|
186
|
|
|
|
272
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(19,610
|
)
|
|
|
(4,211
|
)
|
|
|
(2,504
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before minority interest
and income taxes
|
|
|
47,046
|
|
|
|
9,007
|
|
|
|
1,723
|
|
Minority interest in income of
subsidiaries
|
|
|
|
|
|
|
(488
|
)
|
|
|
(321
|
)
|
Provision for income taxes
|
|
|
(11,420
|
)
|
|
|
(1,344
|
)
|
|
|
(514
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
35,626
|
|
|
|
7,175
|
|
|
|
888
|
|
Preferred stock dividend
|
|
|
|
|
|
|
|
|
|
|
(124
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributed to common
stockholders
|
|
$
|
35,626
|
|
|
$
|
7,175
|
|
|
$
|
764
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common
share basic
|
|
$
|
1.73
|
|
|
$
|
0.48
|
|
|
$
|
0.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common
share diluted
|
|
$
|
1.66
|
|
|
$
|
0.44
|
|
|
$
|
0.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common
shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
20,548
|
|
|
|
14,832
|
|
|
|
7,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
21,410
|
|
|
|
16,238
|
|
|
|
9,510
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated
Financial Statements.
53
ALLIS-CHALMERS
ENERGY INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital in
|
|
|
Retained
|
|
|
|
|
|
|
Common Stock
|
|
|
Excess of
|
|
|
Earnings
|
|
|
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Par Value
|
|
|
(Deficit)
|
|
|
Total
|
|
|
|
(In thousands, except share amounts)
|
|
|
Balances, December 31, 2003,
as restated
|
|
|
3,926,668
|
|
|
|
39
|
|
|
|
10,748
|
|
|
|
(6,246
|
)
|
|
|
4,541
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
888
|
|
|
|
888
|
|
Issuance of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions
|
|
|
1,868,466
|
|
|
|
19
|
|
|
|
8,592
|
|
|
|
|
|
|
|
8,611
|
|
Private placement
|
|
|
6,081,301
|
|
|
|
61
|
|
|
|
15,600
|
|
|
|
|
|
|
|
15,661
|
|
Services
|
|
|
17,000
|
|
|
|
|
|
|
|
99
|
|
|
|
|
|
|
|
99
|
|
Conversion of preferred stock
|
|
|
1,718,090
|
|
|
|
17
|
|
|
|
4,278
|
|
|
|
|
|
|
|
4,295
|
|
Issuance of stock purchase warrants
|
|
|
|
|
|
|
|
|
|
|
1,138
|
|
|
|
|
|
|
|
1,138
|
|
Accrual of preferred dividends
|
|
|
|
|
|
|
|
|
|
|
(124
|
)
|
|
|
|
|
|
|
(124
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2004
|
|
|
13,611,525
|
|
|
|
136
|
|
|
|
40,331
|
|
|
|
(5,358
|
)
|
|
|
35,109
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,175
|
|
|
|
7,175
|
|
Issuance of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions
|
|
|
411,275
|
|
|
|
4
|
|
|
|
1,746
|
|
|
|
|
|
|
|
1,750
|
|
Secondary public offering, net of
offering costs
|
|
|
1,761,034
|
|
|
|
18
|
|
|
|
15,441
|
|
|
|
|
|
|
|
15,459
|
|
Stock options and warrants
exercised
|
|
|
1,076,154
|
|
|
|
11
|
|
|
|
1,371
|
|
|
|
|
|
|
|
1,382
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2005
|
|
|
16,859,988
|
|
|
|
169
|
|
|
|
58,889
|
|
|
|
1,817
|
|
|
|
60,875
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35,626
|
|
|
|
35,626
|
|
Issuance of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions
|
|
|
6,072,046
|
|
|
|
61
|
|
|
|
94,919
|
|
|
|
|
|
|
|
94,980
|
|
Secondary public offering, net of
offering costs
|
|
|
3,450,000
|
|
|
|
34
|
|
|
|
46,263
|
|
|
|
|
|
|
|
46,297
|
|
Stock options and warrants
exercised
|
|
|
1,851,377
|
|
|
|
18
|
|
|
|
6,303
|
|
|
|
|
|
|
|
6,321
|
|
Stock based compensation
|
|
|
|
|
|
|
|
|
|
|
3,394
|
|
|
|
|
|
|
|
3,394
|
|
Tax benefits on stock plans
|
|
|
|
|
|
|
|
|
|
|
6,440
|
|
|
|
|
|
|
|
6,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2006
|
|
|
28,233,411
|
|
|
$
|
282
|
|
|
$
|
216,208
|
|
|
$
|
37,443
|
|
|
$
|
253,933
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated
Financial Statements.
54
ALLIS-CHALMERS
ENERGY INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
35,626
|
|
|
$
|
7,175
|
|
|
$
|
888
|
|
Adjustments to reconcile net
income to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
20,261
|
|
|
|
4,874
|
|
|
|
2,702
|
|
Amortization
|
|
|
2,932
|
|
|
|
1,787
|
|
|
|
876
|
|
Write-off of deferred financing
fees due to refinancing
|
|
|
453
|
|
|
|
653
|
|
|
|
|
|
Issuance of stock options for
services
|
|
|
|
|
|
|
|
|
|
|
14
|
|
Stock based compensation
|
|
|
3,394
|
|
|
|
|
|
|
|
|
|
Provision for bad debts
|
|
|
781
|
|
|
|
219
|
|
|
|
104
|
|
Amortization of discount on debt
|
|
|
|
|
|
|
9
|
|
|
|
350
|
|
Imputed interest
|
|
|
355
|
|
|
|
|
|
|
|
|
|
Deferred taxes
|
|
|
2,215
|
|
|
|
|
|
|
|
|
|
Minority interest in income of
subsidiaries
|
|
|
|
|
|
|
488
|
|
|
|
321
|
|
(Gain) on sale of property
|
|
|
(2,444
|
)
|
|
|
(669
|
)
|
|
|
|
|
Changes in working capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Increase) in accounts receivable
|
|
|
(23,175
|
)
|
|
|
(10,656
|
)
|
|
|
(2,396
|
)
|
(Increase) in due from related
party
|
|
|
|
|
|
|
|
|
|
|
(7
|
)
|
(Increase) in other current assets
|
|
|
(132
|
)
|
|
|
(2,143
|
)
|
|
|
(612
|
)
|
Decrease (increase) in other assets
|
|
|
308
|
|
|
|
(936
|
)
|
|
|
(19
|
)
|
(Decrease) increase in accounts
payable
|
|
|
(2,337
|
)
|
|
|
2,373
|
|
|
|
1,140
|
|
Increase in accrued interest
|
|
|
11,382
|
|
|
|
324
|
|
|
|
299
|
|
Increase (Decrease) in accrued
expenses
|
|
|
872
|
|
|
|
(97
|
)
|
|
|
(276
|
)
|
(Decrease) in other liabilities
|
|
|
(224
|
)
|
|
|
(266
|
)
|
|
|
(141
|
)
|
Increase in accrued salaries,
benefits and payroll taxes
|
|
|
3,392
|
|
|
|
443
|
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
|
53,659
|
|
|
|
3,578
|
|
|
|
3,262
|
|
Cash Flows from Investing
Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions, net of cash acquired
|
|
|
(526,572
|
)
|
|
|
(36,888
|
)
|
|
|
(4,459
|
)
|
Purchase of property and equipment
|
|
|
(39,697
|
)
|
|
|
(17,767
|
)
|
|
|
(4,603
|
)
|
Proceeds from sale of property and
equipment
|
|
|
6,881
|
|
|
|
1,579
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing
activities
|
|
|
(559,388
|
)
|
|
|
(53,076
|
)
|
|
|
(9,062
|
)
|
Cash Flows from Financing
Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of
long-term debt
|
|
|
557,820
|
|
|
|
56,251
|
|
|
|
8,169
|
|
Payments on long-term debt
|
|
|
(54,030
|
)
|
|
|
(28,202
|
)
|
|
|
(13,259
|
)
|
Payments on related party debt
|
|
|
(3,031
|
)
|
|
|
(1,522
|
)
|
|
|
(246
|
)
|
Net (repayments) borrowings on
lines of credit
|
|
|
(6,400
|
)
|
|
|
2,527
|
|
|
|
689
|
|
Proceeds from issuance of common
stock, net of offering costs
|
|
|
46,297
|
|
|
|
15,459
|
|
|
|
16,883
|
|
Proceeds from exercise of options
and warrants
|
|
|
6,321
|
|
|
|
1,382
|
|
|
|
|
|
Tax benefit on options
|
|
|
6,440
|
|
|
|
|
|
|
|
|
|
Debt issuance costs
|
|
|
(9,863
|
)
|
|
|
(1,821
|
)
|
|
|
(391
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing
activities
|
|
|
543,554
|
|
|
|
44,074
|
|
|
|
11,845
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash
and cash equivalents
|
|
|
37,825
|
|
|
|
(5,424
|
)
|
|
|
6,045
|
|
Cash and cash equivalents at
beginning of year
|
|
|
1,920
|
|
|
|
7,344
|
|
|
|
1,299
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end
of year
|
|
$
|
39,745
|
|
|
$
|
1,920
|
|
|
$
|
7,344
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated
Financial Statements.
55
ALLIS-CHALMERS
ENERGY INC.
NOTE 1
NATURE OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
Organization
of Business
Allis-Chalmers Energy Inc. (Allis-Chalmers,
we, our or us) was
incorporated in Delaware in 1913. We are a multi-faceted
oilfield services company that provides services and equipment
to oil and natural gas exploration and production companies,
domestically in Texas, Louisiana, New Mexico, Colorado,
Oklahoma, Mississippi, Utah, Wyoming, Arkansas, Alabama, West
Virginia, offshore in the Gulf of Mexico, and internationally,
primarily in Argentina and Mexico. We operate in six sectors of
the oil and natural gas service industry: rental tools,
international drilling, directional drilling services; casing
and tubing services; compressed air drilling services; and
production services.
The nature of our operations and the many regions in which we
operate subject us to changing economic, regulatory and
political conditions. We are vulnerable to near-term and
long-term changes in the demand for and prices of oil and
natural gas and the related demand for oilfield service
operations.
Use of
Estimates
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the financial statements, and the reported amounts of revenues
and expenses during the reporting period. Future events and
their effects cannot be perceived with certainty. Accordingly,
our accounting estimates require the exercise of judgment. While
management believes that the estimates and assumptions used in
the preparation of the consolidated financial statements are
appropriate, actual results could differ from those estimates.
Estimates are used for, but are not limited to, determining the
following: allowance for doubtful accounts, recoverability of
long-lived assets and intangibles, useful lives used in
depreciation and amortization, income taxes and valuation
allowances. The accounting estimates used in the preparation of
the consolidated financial statements may change as new events
occur, as more experience is acquired, as additional information
is obtained and as our operating environment changes.
Principles
of Consolidation
The consolidated financial statements include the accounts of
Allis-Chalmers and its subsidiaries. Our subsidiaries at
December 31, 2006 are Oil Quip Rentals, Inc. (Oil
Quip), Mountain Compressed Air Inc. (Mountain
Air), Allis-Chalmers Tubular Services Inc.
(Tubular), Strata Directional Technology, Inc.
(Strata), AirComp LLC (AirComp),
Allis-Chalmers Rental Services, Inc. (Rental),
Allis-Chalmers Production Services, Inc.
(Production), Allis-Chalmers Management LP,
Drilling, Logistics & Services Corporation
(DLS) and Petro-Rentals, Incorporated
(Petro-Rental). All significant inter-company
transactions have been eliminated.
Revenue
Recognition
We provide rental equipment and drilling services to our
customers at per day and per job contractual rates and recognize
the drilling related revenue as the work progresses and when
collectibility is reasonably assured. Payments from customers
for the cost of oilfield rental equipment that is damaged or
lost-in-hole are reflected as revenues. We recognized revenue
from damaged or lost-in-hole equipment of $2.4 million,
$970,000 and $41,000 for the year ended December 31, 2006,
2005 and 2004, respectively. The Securities and Exchange
Commissions (SEC) Staff Accounting Bulletin (SAB)
No. 104, Revenue Recognition In Financial Statements
(SAB No. 104), provides guidance on
the SEC staffs views on the application of generally
accepted accounting principles to selected revenue recognition
issues. Our revenue recognition policy is in accordance with
generally accepted accounting principles and
SAB No. 104.
56
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
Allowance
for Doubtful Accounts
Accounts receivable are customer obligations due under normal
trade terms. We sell our services to oil and natural gas
exploration and production companies. We perform continuing
credit evaluations of its customers financial condition
and although we generally do not require collateral, letters of
credit may be required from customers in certain circumstances.
The allowance for doubtful accounts represents our estimate of
the amount of probable credit losses existing in our accounts
receivable. Significant individual accounts receivable balances
which have been outstanding greater than 90 days are
reviewed individually for collectibility We have a limited
number of customers with individually large amounts due at any
given date. Any unanticipated change in any one of these
customers credit worthiness or other matters affecting the
collectibility of amounts due from such customers could have a
material effect on the results of operations in the period in
which such changes or events occur. After all attempts to
collect a receivable have failed, the receivable is written off
against the allowance. As of December 31, 2006 and 2005, we
had recorded an allowance for doubtful accounts of $826,000 and
$383,000 respectively. Bad debt expense was $781,000, $219,000
and $104,000 for the years ended December 31, 2006, 2005
and 2004, respectively.
Cash
Equivalents
We consider all highly liquid investments with an original
maturity of three months or less at the time of purchase to be
cash equivalents.
Inventories
Inventories are stated at the lower of cost or market. Cost is
determined using the first-in, first-out (FIFO)
method or the average cost method, which approximates FIFO, and
includes the cost of materials, labor and manufacturing overhead.
Property
and Equipment
Property and equipment is recorded at cost less accumulated
depreciation. Certain equipment held under capital leases are
classified as equipment and the related obligations are recorded
as liabilities.
Maintenance and repairs, which do not improve or extend the life
of the related assets, are charged to operations when incurred.
Refurbishments and renewals are capitalized when the value of
the equipment is enhanced for an extended period. When property
and equipment are sold or otherwise disposed of, the asset
account and related accumulated depreciation account are
relieved, and any gain or loss is included in operations.
The cost of property and equipment currently in service is
depreciated over the estimated useful lives of the related
assets, which range from three to twenty years. Depreciation is
computed on the straight-line method for financial reporting
purposes. Capital leases are amortized using the straight-line
method over the estimated useful lives of the assets and lease
amortization is included in depreciation expense. Depreciation
expense charged to operations was $20.3 million,
$4.9 million and $2.7 million for the years ended
December 31, 2006, 2005 and 2004, respectively.
Goodwill,
Intangible Assets and Amortization
Goodwill, including goodwill associated with equity method
investments, and other intangible assets with infinite lives are
not amortized, but tested for impairment annually or more
frequently if circumstances indicate that impairment may exist.
Intangible assets with finite useful lives are amortized either
on a straight-
57
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
line basis over the assets estimated useful life or on a
basis that reflects the pattern in which the economic benefits
of the intangible assets are realized.
The impairment test requires the allocation of goodwill and all
other assets and liabilities to reporting units. If the fair
value of the reporting unit is less than the book value
(including goodwill) then goodwill is reduced to its implied
fair value and the amount of the writedown is charged against
earnings. We perform impairment tests on the carrying value of
our goodwill on an annual basis as of December 31st for
each of our reportable segments. As of December 31, 2006
and 2005, no impairment was deemed necessary. Increases in
estimated future costs or decreases in projected revenues could
lead to an impairment of all or a portion of our goodwill in
future period.
Impairment
of Long-Lived Assets
Long-lived assets, which include property, plant and equipment
and other intangible assets, and certain other assets are
reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount may not be
recoverable. An impairment loss is recorded in the period in
which it is determined that the carrying amount is not
recoverable. The determination of recoverability is made based
upon the estimated undiscounted future net cash flows, excluding
interest expense. The impairment loss is determined by comparing
the fair value, as determined by a discounted cash flow
analysis, with the carrying value of the related assets.
Financial
Instruments
Financial instruments consist of cash and cash equivalents,
accounts receivable and payable, and debt. The carrying value of
cash and cash equivalents and accounts receivable and payable
approximate fair value due to their short-term nature. We
believe the fair values and the carrying value of our debt would
not be materially different due to the instruments
interest rates approximating market rates for similar borrowings
at December 31, 2006 and 2005.
Concentration
of Credit and Customer Risk
Financial instruments that potentially subject us to
concentrations of credit risk consist principally of cash and
cash equivalents and trade accounts receivable. As of
December 31, 2006, we have approximately $2.0 million
of cash and cash equivalents residing in Argentina. We transact
our business with several financial institutions. However, the
amount on deposit in six financial institutions exceeded the
$100,000 federally insured limit at December 31, 2006 by a
total of $10.5 million. Management believes that the
financial institutions are financially sound and the risk of
loss is minimal.
We sell our services to major and independent domestic and
international oil and natural gas companies. We perform ongoing
credit valuations of our customers and provide allowances for
probable credit losses where appropriate. In 2006, one of our
customers, Pan American Energy LLC Sucursal Argentina, or Pan
American Energy, represented 11.7% of our consolidated revenues.
In 2005 none of our customers accounted for more than 10% of our
consolidated revenues. In the year ended December 31, 2004,
Materiales y Equipo Petroleo, or Matyep in Mexico represented
10.8%, and Burlington Resources represented 10.1% of our
consolidated revenues, respectively. Revenues from Matyep
represented 8.3%, 94.5% and 98.0% of our international revenues
in 2006, 2005 and 2004, respectively. Revenues from Pan American
Energy represented 45.6% of our international revenues.
Debt
Issuance Costs
The costs related to the issuance of debt are capitalized and
amortized to interest expense using the straight-line method,
which approximates the interest method, over the maturity
periods of the related debt.
58
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
Income
Taxes
Our income tax expense is based on our income, statutory tax
rates and tax planning opportunities available to us in the
various jurisdictions in which we operate. We provide for income
taxes based on the tax laws and rates in effect in the countries
in which operations are conducted and income is earned. Our
income tax expense is expected to fluctuate from year to year as
our operations are conducted in different taxing jurisdictions
and the amount of pre-tax income fluctuates.
The determination and evaluation of our annual income tax
provision involves the interpretation of tax laws in various
jurisdictions in which we operate and requires significant
judgment and the use of estimates and assumptions regarding
significant future events such as the amount, timing and
character of income, deductions and tax credits. Changes in tax
laws, regulations and our level of operations or profitability
in each jurisdiction may impact our tax liability in any given
year. While our annual tax provision is based on the information
available to us at the time, a number of years may elapse before
the ultimate tax liabilities in certain tax jurisdictions are
determined.
Current income tax expense reflects an estimate of our income
tax liability for the current year, withholding taxes, changes
in tax rates and changes in prior year tax estimates as returns
are filed. Deferred tax assets and liabilities are recognized
for the anticipated future tax effects of temporary differences
between the financial statement basis and the tax basis of our
assets and liabilities using the enacted tax rates in effect at
year end. A valuation allowance for deferred tax assets is
recorded when it is more-likely-than-not that the benefit from
the deferred tax asset will not be realized.
It is our intention to permanently reinvest all of the
undistributed earnings of our
non-U.S. subsidiaries
in such subsidiaries. Accordingly, we have not provided for
U.S. deferred taxes on the undistributed earnings of our
non-U.S. subsidiaries.
If a distribution is made to us from the undistributed earnings
of these subsidiaries, we could be required to record additional
taxes. Because we cannot predict when, if at all, we will make a
distribution of these undistributed earnings, we are unable to
make a determination of the amount of unrecognized deferred tax
liability.
Stock-Based
Compensation
We adopted SFAS No. 123R, Share-Based Payment
(SFAS No. 123R), effective
January 1, 2006. This statement requires all share-based
payments to employees, including grants of employee stock
options, to be recognized in the financial statements based on
their grant-date fair values. Compensation cost for awards
granted prior to, but not vested, as of January 1, 2006
would be based on the grant date attributes originally used to
value those awards for pro forma purposes under
SFAS No. 123, Accounting for Stock-Based
Compensation (SFAS No. 123). We
adopted SFAS No. 123R using the modified prospective
transition method, utilizing the Black-Scholes option pricing
model for the calculation of the fair value of our employee
stock options. Under the modified prospective method, we record
compensation cost related to unvested stock awards as of
December 31, 2005 by recognizing the unamortized grant date
fair value of these awards over the remaining vesting periods of
those awards with no change in historical reported earnings. We
estimated forfeiture rates for 2006 based on our historical
experience.
The Black-Scholes model incorporates assumptions to value
stock-based awards. The risk-free rate of interest is the
related U.S. Treasury yield curve for periods within the
expected term of the option at the time of grant. The dividend
yield on our common stock is assumed to be zero as we have
historically not paid dividends and have no current plans to do
so in the future. The expected volatility is based on historical
volatility of our common stock.
Prior to January 1, 2006, we accounted for our stock-based
compensation using Accounting Principle Board Opinion
No. 25 (APB No. 25). Under APB
No. 25, compensation expense is recognized for stock
options with an exercise price that is less than the market
price on the grant date of the option. For stock
59
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
options with exercise prices at or above the market value of the
stock on the grant date, we adopted the disclosure-only
provisions of SFAS No. 123. We also adopted the
disclosure-only provisions of SFAS No. 123 for the
stock options granted to our employees and directors.
Accordingly, no compensation cost was recognized under APB
No. 25. Our net income for the year ended December 31,
2006 includes approximately $3.4 million of compensation
costs related to share-based payments. The tax benefit recorded
in association with the share-based payments was
$1.2 million for the year-ended December 31, 2006. As
of December 31, 2006 there is $1.3 million of
unrecognized compensation expense related to non-vested stock
based compensation grants.
Had compensation expense for the options granted been recorded
based on the fair value at the grant date for the options,
consistent with the provisions of SFAS 123, our net
income/(loss) and net income/(loss) per share for the years
ended December 31, 2005 and 2004 would have been decreased
to the pro forma amounts indicated below (in thousands, except
per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
(Restated)
|
|
|
Net income attributed to common
stockholders as reported:
|
|
|
|
|
|
$
|
7,175
|
|
|
$
|
764
|
|
Less total stock based employee
compensation expense determined under fair value based method
for all awards net of tax related effects
|
|
|
|
|
|
|
(4,284
|
)
|
|
|
(1,072
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro-forma net income (loss)
attributed to common stockholders
|
|
|
|
|
|
$
|
2,891
|
|
|
$
|
(308
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
As reported
|
|
|
$
|
0.48
|
|
|
$
|
0.10
|
|
|
|
|
Pro forma
|
|
|
$
|
0.19
|
|
|
$
|
(0.04
|
)
|
Diluted
|
|
|
As reported
|
|
|
$
|
0.44
|
|
|
$
|
0.09
|
|
|
|
|
Pro forma
|
|
|
$
|
0.18
|
|
|
$
|
(0.04
|
)
|
Options were granted in 2006, 2005 and 2004. See Note 12
for further disclosures regarding stock options. The following
assumptions were applied in determining the pro forma
compensation costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Expected dividend yield
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected price volatility
|
|
|
72.28
|
%
|
|
|
84.28
|
%
|
|
|
89.76
|
%
|
Risk-free interest rate
|
|
|
5.1
|
%
|
|
|
5.6
|
%
|
|
|
7.00
|
%
|
Expected life of options
|
|
|
7 years
|
|
|
|
7 years
|
|
|
|
7 years
|
|
Weighted average fair value of
options granted at market value
|
|
|
$10.58
|
|
|
|
$5.02
|
|
|
|
$3.19
|
|
Segments
of an Enterprise and Related Information
We disclose the results of our segments in accordance with
SFAS No. 131, Disclosures About Segments Of An
Enterprise And Related Information
(SFAS No. 131). We designate the
internal organization that is used by management for allocating
resources and assessing performance as the source of our
reportable segments. SFAS No. 131 also requires
disclosures about products and services, geographic areas and
major customers Please see Note 16 for further disclosure
of segment information in accordance with SFAS No. 131.
60
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
Income
Per Common Share
We compute income per common share in accordance with the
provisions of SFAS No. 128, Earnings Per Share
(SFAS No. 128). SFAS No. 128
requires companies with complex capital structures to present
basic and diluted earnings per share. Basic earnings per share
are computed on the basis of the weighted average number of
shares of common stock outstanding during the period. For
periods through April 12, 2004, preferred dividends are
deducted from net income and have been considered in the
calculation of income available to common stockholders in
computing basic earnings per share. Diluted earnings per share
is similar to basic earnings per share, but presents the
dilutive effect on a per share basis of potential common shares
(e.g., convertible preferred stock, stock options, etc.) as if
they had been converted. Potential dilutive common shares that
have an anti-dilutive effect (e.g., those that increase income
per share) are excluded from diluted earnings per share.
The components of basic and diluted earnings per share are as
follows (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
(Restated)
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available for common
stockholders
|
|
$
|
35,626
|
|
|
$
|
7,175
|
|
|
$
|
764
|
|
Plus income impact of assumed
conversions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividends/interest
|
|
|
|
|
|
|
|
|
|
|
124
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income applicable to common
stockholders plus assumed conversions
|
|
$
|
35,626
|
|
|
$
|
7,175
|
|
|
$
|
888
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for basic earnings per
share weighted average shares outstanding
|
|
|
20,548
|
|
|
|
14,832
|
|
|
|
7,930
|
|
Effect of potentially dilutive
common shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
Convertible preferred stock and
employee and director stock options
|
|
|
862
|
|
|
|
1,406
|
|
|
|
1,580
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding and assumed conversions
|
|
|
21,410
|
|
|
|
16,238
|
|
|
|
9,510
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share
|
|
$
|
1.73
|
|
|
$
|
0.48
|
|
|
$
|
0.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share
|
|
$
|
1.66
|
|
|
$
|
0.44
|
|
|
$
|
0.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification
Certain prior period balances have been reclassified to conform
to current year presentation.
New
Accounting Pronouncements
In February 2006, the FASB issued SFAS No. 155,
Accounting for Certain Hybrid Financial Instruments
(SFAS No. 155). SFAS No. 155
provides entities with relief from having to separately
determine the fair value of an embedded derivative that would
otherwise be required to be bifurcated from its host contract in
accordance with SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities.
SFAS No. 155 allows an entity to make an irrevocable
election to measure such a hybrid financial instrument at fair
value in its entirely, with changes in fair value recognized in
earning. SFAS No. 155 is effective for all financial
instruments acquired , issued or subject to a remeasurement
event occurring after the beginning of an entitys
61
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
first fiscal year that begins after September 15, 2006. We
believe that the adoption of SFAS No. 155 will not
have a material impact on our financial position, results of
operations or cash flows.
In March 2006, the FASB issued SFAS No. 156,
Accounting for Servicing of Financial Assets An
Amendment to FASB Statement No. 140
(SFAS No. 156).
SFAS No. 156 requires entities to recognize a
servicing asset or liability each time they undertake an
obligation to service a financial asset by entering into a
servicing contract in certain situations. This statement also
requires all separately recognized servicing assets and
servicing liabilities to be initially measured at fair value and
permits a choice of either the amortization or fair value
measurement method for subsequent measurement. The effective
date of this statement is for annual periods beginning after
September 15, 2006, with earlier adoption permitted as of
the beginning of an entitys fiscal year provided the
entity has not issued any financial statements for that year. We
do not plan to adopt SFAS No. 156 early, and we are
currently assessing the impact on our Consolidated Financial
Statements.
In July 2006, the FASB issued FASB Interpretation,
FIN No. 48, Accounting for Uncertainty in Income
Taxes An Interpretation of FASB Statement
No. 109 (FIN No. 48).
FIN No. 48 clarifies the accounting for uncertainty in
income taxes recognized in an enterprises financial
statements in accordance with SFAS No. 109,
Accounting for Income Taxes. It prescribes a recognition
threshold and measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected
to be taken in a tax return. This new standard also provides
guidance on derecognition, classification, interest and
penalties, accounting in interim periods, disclosure and
transition. The provisions of FIN No. 48 are to be
applied to all tax positions upon initial adoption of this
standard. Only tax positions that meet the more
likely-than-not
recognition threshold at the effective date may be recognized or
continue to be recognized upon adoption of FIN No. 48.
The cumulative effect of applying the provisions of
FIN No. 48 should be reported as an adjustment to the
opening balance of retaining earnings (or other appropriate
components of equity or net assets in the statement of financial
position) for that fiscal year. The provisions of
FIN No. 48 are effective for fiscal years beginning
after December 15, 2006. We are currently evaluating the
impact of applying the provisions of FIN No. 48.
In September 2006, the FASB issued SFAS No. 157, Fair
Value Measurements (SFAS No. 157).
SFAS No. 157 clarifies the principle that fair value
should be based on the assumptions that market participants
would use when pricing an asset or liability and establishes a
fair value hierarchy that prioritizes the information used to
develop those assumptions. Under the standard, fair value
measurements would be separately disclosed by level within the
fair value hierarchy. SFAS No. 157 is effective for
financial statements issued for fiscal years beginning after
November 15, 2007, and interim periods within those fiscal
years, with early adoption permitted. We believe that the
adoption of SFAS No. 157 will not have a material
impact on our financial position, results of operations or cash
flows.
In September 2006, the FASB issued FSP No. AUG AIR-1,
Accounting for Planned Major Maintenance Activities
(FSP No. AUG AIR-1). FSP No. AUG AIR-1
prohibits the use of the
accrued-in-advance
method for accounting for major maintenance activities and
confirms the acceptable methods of accounting for planned major
maintenance activities. FSP No. AUG AIR-1 is effective the
first fiscal year beginning after December 15, 2006. We
believe that the adoption of FSP No. AUG AIR-1 will not
have a material impact on our financial position, results of
operations or cash flows.
In September 2006, the Securities and Exchange Commission issued
Staff Accounting Bulletin 108, Considering the Effects
of Prior Year Misstatements when Quantifying Misstatements in
Current Year Financial Statements
(SAB 108). SAB 108 requires that
public companies utilize a dual-approach to
assessing the quantitative effects of financial misstatements.
This dual approach includes both an income statement focused
assessment and a balance sheet focused assessment. SAB 108
is effective for fiscal years ending after November 15,
2006. We adopted SAB 108 on December 31, 2006, and
there was no impact on our consolidated financial statements.
62
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
NOTE 2
RESTATEMENT
Earnings
Per Share
We understated diluted earnings per share due to an incorrect
calculation of our weighted shares outstanding for each of the
first three quarters of 2004, for the year ended
December 31, 2004 and for the quarter ended March 31,
2005 In addition, we understated basic earnings per share due to
an incorrect calculation of our weighted average basic shares
outstanding for the quarter ended September 30, 2004.
Consequently, we have restated our financial statements for each
of those periods. The incorrect calculation resulted from a
mathematical error and an improper application of
SFAS No. 128.
A restated earnings per share calculation for all affected
periods reflecting the above adjustments to our results as
previously restated (see following section), is presented below
(amounts in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2005
|
|
|
|
As
|
|
|
|
|
|
|
|
|
|
Previously
|
|
|
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Income per common
share diluted
|
|
$
|
0.09
|
|
|
$
|
0.02
|
|
|
$
|
0.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common
shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
17,789
|
|
|
|
(3,094
|
)
|
|
|
14,695
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2004
|
|
|
|
As
|
|
|
|
|
|
|
|
|
|
Previously
|
|
|
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Income per common
share diluted
|
|
$
|
0.07
|
|
|
$
|
0.02
|
|
|
$
|
0.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common
shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
11,959
|
|
|
|
(2,449
|
)
|
|
|
9,510
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2004
|
|
|
|
As
|
|
|
|
|
|
|
|
|
|
Previously
|
|
|
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Income per common
share basic
|
|
$
|
0.04
|
|
|
$
|
0.02
|
|
|
$
|
0.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common
share diluted
|
|
$
|
0.04
|
|
|
$
|
0.01
|
|
|
$
|
0.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common
shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
11,599
|
|
|
|
(3,301
|
)
|
|
|
8,298
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
14,407
|
|
|
|
(4,579
|
)
|
|
|
9,828
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2004
|
|
|
|
As
|
|
|
|
|
|
|
|
|
|
Previously
|
|
|
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Income per common
share diluted
|
|
$
|
0.04
|
|
|
$
|
0.01
|
|
|
$
|
0.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common
shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
10,237
|
|
|
|
(2,618
|
)
|
|
|
7,619
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
63
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2004
|
|
|
|
As
|
|
|
|
|
|
|
|
|
|
Previously
|
|
|
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Income per common
share diluted
|
|
$
|
0.05
|
|
|
$
|
0.03
|
|
|
$
|
0.08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common
shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
5,762
|
|
|
|
478
|
|
|
|
6,240
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AirComp
Acquisition
In connection with the formation of AirComp LLC in 2003, we,
along with M-I L.L.C. contributed assets to AirComp in exchange
for a 55% interest and 45% interest, respectively, in AirComp.
We originally accounted for the formation of AirComp as a joint
venture. However in February 2005, we determined that the
transaction should have been accounted for using purchase
accounting pursuant to SFAS No. 141, Business
Combinations and recorded the sale of an interest in a
subsidiary, in accordance with SEC Staff Accounting
Bulletin No. 51, Accounting for Sales of Stock by a
Subsidiary. Consequently, we restated our financial
statements for the three quarters ended September 30, 2004,
to reflect the following adjustments:
Increase
in Book Value of Fixed Assets.
Under joint venture accounting, we originally recorded the value
of the assets contributed by M-I to AirComp at M-Is
historical cost of $6.9 million. Under purchase accounting,
we increased the recorded value of the assets contributed by M-I
by approximately $3.3 million to $10.3 million to
reflect their fair market value as determined by a third party
appraisal. In addition, under joint venture accounting, we
established negative goodwill which reduced fixed assets in the
amount of $1.6 million. The negative goodwill was amortized
by us over the lives of the related fixed assets. Under purchase
accounting, we increased fixed assets by $1.6 million to
reverse the negative goodwill previously recorded and reversed
amortization expenses recorded in 2004. Therefore, the cost of
fixed assets was increased by a total of $4.9 million at
the time of acquisition. As a result of the increase in fixed
assets and the reversal of amortization of negative goodwill,
depreciation expense increased.
The 2004 financial statements have been restated from the
previously filed interim financial statements included in
Form 10-Q
for the first, second and third quarters of 2004. The effect of
the restatement on the individual quarterly financial statements
is as follows (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Three Months
|
|
|
Three Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
March 31,
|
|
|
June 30,
|
|
|
September 30,
|
|
|
|
2004
|
|
|
2004
|
|
|
2004
|
|
|
Net income (loss) attributed to
common stockholders
|
|
|
|
|
|
|
|
|
|
|
|
|
Previously reported
|
|
$
|
501
|
|
|
$
|
434
|
|
|
$
|
576
|
|
Adjustment
depreciation expense
|
|
|
(139
|
)
|
|
|
(79
|
)
|
|
|
(79
|
)
|
Adjustment minority
interest expense
|
|
|
22
|
|
|
|
22
|
|
|
|
22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restated
|
|
$
|
384
|
|
|
$
|
377
|
|
|
$
|
519
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share, basic
|
|
|
|
|
|
|
|
|
|
|
|
|
Previously reported
|
|
$
|
0.13
|
|
|
$
|
0.07
|
|
|
$
|
0.05
|
|
Total adjustments
|
|
|
(0.03
|
)
|
|
|
(0.01
|
)
|
|
|
(0.01
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restated
|
|
$
|
0.10
|
|
|
$
|
0.06
|
|
|
$
|
0.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
64
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
NOTE 3
POST RETIREMENT BENEFIT OBLIGATIONS
Medical
And Life
Pursuant to the Plan of Reorganization that was confirmed by the
Bankruptcy Court after acceptances by our creditors and
stockholders and was consummated on December 2, 1988, we
assumed the contractual obligation to Simplicity Manufacturing,
Inc. (SMI) to reimburse SMI for 50% of the actual cost of
medical and life insurance claims for a select group of retirees
(SMI Retirees) of the prior Simplicity Manufacturing Division of
Allis-Chalmers. The actuarial present value of the expected
retiree benefit obligation is determined by an actuary and is
the amount that results from applying actuarial assumptions to
(1) historical claims-cost data, (2) estimates for the
time value of money (through discounts for interest) and
(3) the probability of payment (including decrements for
death, disability, withdrawal, or retirement) between today and
expected date of benefit payments. As of December 31, 2006
and 2005, we have post-retirement benefit obligations of
$304,000 and $335,000, respectively.
401(k)
Savings Plan
On June 30, 2003, we adopted the 401(k) Profit Sharing Plan
(the Plan). The Plan is a defined contribution
savings plan designed to provide retirement income to our
eligible employees. The Plan is intended to be qualified under
Section 401(k) of the Internal Revenue Code of 1986, as
amended. It is funded by voluntary pre-tax contributions from
eligible employees who may contribute a percentage of their
eligible compensation, limited and subject to statutory limits.
The Plan is also funded by discretionary matching employer
contributions from us. Eligible employees cannot participate in
the Plan until they have attained the age of 21 and completed
six-months of service with us. Each participant is 100% vested
with respect to the participants contributions while our
matching contributions are vested over a three-year period in
accordance with the Plan document. Contributions are invested,
as directed by the participant, in investment funds available
under the Plan. Matching contributions of approximately
$735,000, $114,000 and $35,000 were paid in 2006, 2005 and 2004,
respectively.
NOTE 4
ACQUISITIONS
In September 2004, we acquired 100% of the outstanding stock of
Safco-Oil Field Products, Inc. (Safco) for
$1.0 million. Safco rented spiral drill pipe to the oil
drilling industry. Safco has been renamed and is now
Allis-Chalmers Rental Services, Inc.
In September 2004, we acquired the remaining 19% of Tubular in
exchange for 1.3 million shares of our common stock. The
total value of the consideration paid to the seller, Jens
Mortensen, was $6.4 million which was equal to the number
of shares of common stock issued to Mr. Mortensen
(1.3 million) multiplied by the last sale price ($4.95) of
the common stock as reported on the American Stock Exchange on
the date of issuance. This amount was treated as a contribution
to stockholders equity. On the balance sheet, the
$1.9 million minority interest in Tubular was eliminated.
The balance of the contribution of $4.4 million was
allocated as follows: In June 2004, we obtained an appraisal of
the fixed assets of Tubular which valued the fixed assets at
$20.1 million. The book value of the fixed assets was
$15.8 million and the fixed assets appraised value was
$4.3 million over the book value. We increased the value of
our fixed assets by 19% of the amount of the excess of the
appraised value over the book value, or $.8 million. The
remaining balance of $3.6 million was allocated to goodwill.
In November 2004, AirComp acquired substantially all the assets
of Diamond Air Drilling Services, Inc. and Marquis Bit Co.,
L.L.C. collectively (Diamond Air) for
$4.6 million in cash and the assumption of approximately
$450,000 of accrued liabilities. We contributed
$2.5 million and M-I L.L.C. contributed $2.1 million
to AirComp LLC in order to fund the purchase. Goodwill of
$375,000 and other intangible assets of $2.3 million were
recorded in connection with the acquisition. Diamond Air
provided air drilling technology
65
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
and products to the oil and gas industry in West Texas, New
Mexico and Oklahoma. Diamond Air is a leading brand of air
hammers and hammer bit products.
In December 2004, we acquired Downhole Injection Services, LLC
(Downhole) for approximately $1.1 million in
cash, 568,466 shares of our common stock and the assumption
of approximately $950,000 of debt. Goodwill of $442,000 and
other intangible assets of $795,000 were recorded in connection
with the acquisition. Downhole provided economical chemical
treatments to wells by inserting small diameter, stainless steel
coiled tubing into producing oil and gas wells. In 2006,
Downhole was merged into Allis-Chalmers Production Services Inc.
On April 1, 2005, we acquired 100% of the outstanding stock
of Delta Rental Service, Inc. (Delta) for
$4.6 million in cash, 223,114 shares of our common
stock and two promissory notes totaling $350,000. The purchase
price was allocated to fixed assets and inventory. Delta,
located in Lafayette, Louisiana, was a rental tool company
providing specialty rental items to the oil and gas industry
such as spiral heavy weight drill pipe, test plugs used to test
blow-out preventors, well head retrieval tools, spacer spools
and assorted handling tools. In 2006, Delta was merged into
Rental.
On May 1, 2005, we acquired 100% of the outstanding capital
stock of Capcoil Tubing Services, Inc. (Capcoil) for
$2.7 million in cash, 168,161 shares of our common
stock and the payment or assumption of approximately
$1.3 million of debt. Capcoil, located in Kilgore, Texas,
is engaged in downhole well servicing by providing coil tubing
services to enhance production from existing wells. Goodwill of
$184,000 and other identifiable intangible assets of
$1.4 million were recorded in connection with the
acquisition. In 2006, Capcoil was renamed Allis-Chalmers
Production Services Inc.
On July 11, 2005, we acquired the compressed air drilling
assets of W.T Enterprises, Inc., based in South Texas, for
$6.0 million in cash. The equipment includes compressors,
boosters, mist pumps and vehicles. Goodwill of $82,000 and other
identifiable intangible assets of $1.5 million were
recorded in connection with the acquisition.
On July 11, 2005, we acquired from M-I L.L.C.
(M-I) its 45% interest in AirComp and subordinated
note in the principal amount of $4.8 million issued by
AirComp, for which we paid M-I $7.1 million in cash and
issued to M-I a $4.0 million subordinated note bearing
interest at 5% per annum. As a result, we now own 100% of
AirComp
Effective August 1, 2005, we acquired 100% of the
outstanding capital stock of Target Energy Inc.
(Target) for $1.3 million in cash and
forgiveness of a lease receivable of approximately
$0.6 million. The purchase price was allocated to the fixed
assets of Target. The results of Target are included in our
directional and horizontal drilling segment as their Measure
While Drilling equipment is utilized in that segment. Target was
merged with Strata in December 2006.
On September 1, 2005, we acquired the casing and tubing
service assets of Patterson Services, Inc. for approximately
$15.6 million. These assets are located in Corpus Christi,
Texas; Kilgore, Texas; Lafayette, Louisiana and Houma, Louisiana.
66
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
Effective January 1, 2006, we acquired 100% of the
outstanding stock of Specialty Rental Tools, Inc., or Specialty,
for $96.0 million in cash. Specialty, located in Lafayette,
Louisiana, was engaged in the rental of high quality drill pipe,
heavy weight spiral drill pipe, tubing work strings, blow-out
preventors, choke manifolds and various valves and handling
tools for oil and natural gas drilling. The following table
summarizes the allocation of the purchase price to the estimated
fair value of the assets acquired and liabilities assumed at the
date of acquisition (in thousands):
|
|
|
|
|
Current assets
|
|
$
|
7,645
|
|
Property and equipment
|
|
|
90,622
|
|
|
|
|
|
|
Total assets acquired
|
|
|
98,267
|
|
|
|
|
|
|
Current liabilities
|
|
|
2,193
|
|
Long-term debt
|
|
|
74
|
|
|
|
|
|
|
Total liabilities assumed
|
|
|
2,267
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
96,000
|
|
|
|
|
|
|
Approximately $588,000 of costs were incurred in relation to the
Specialty acquisition. Specialtys historical property and
equipment values were increased by approximately
$71.6 million based on third-party valuations. Specialty
was merged into Rental in 2006.
Effective April 1, 2006, we acquired 100% of the
outstanding stock of Rogers Oil Tools, Inc., or Rogers, based in
Lafayette, Louisiana, for a total consideration of approximately
$13.7 million, which includes $11.3 million in cash,
$1.6 million in our common stock and a $750,000 three-year
promissory note. In addition, we purchased all the patents and
proprietary technology that Tommie L. Rogers, Rogers
founder and Chief Executive Officer, developed at Rogers. Rogers
sells, services and rents power drill pipe tongs and accessories
and rental tongs for snubbing and well control applications.
Rogers also provides specialized tong operators for rental jobs.
The following table summarizes the allocation of the purchase
price to the estimated fair value of the assets acquired and
liabilities assumed at the date of acquisition (in thousands):
|
|
|
|
|
Current assets
|
|
$
|
4,520
|
|
Property and equipment
|
|
|
9,866
|
|
Intangible assets
|
|
|
4,941
|
|
|
|
|
|
|
Total assets acquired
|
|
|
19,327
|
|
|
|
|
|
|
Current liabilities
|
|
|
1,717
|
|
Deferred income tax liabilities
|
|
|
3,760
|
|
Other long-term liabilities
|
|
|
150
|
|
|
|
|
|
|
Total liabilities assumed
|
|
|
5,627
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
13,700
|
|
|
|
|
|
|
Approximately $380,000 of costs were incurred in relation to the
Rogers acquisition. Rogers historical property and
equipment values were increased by approximately
$8.4 million based on third-party valuations. Intangible
assets include $2.8 million assigned to goodwill,
$2.0 million assigned to patents and $150,000 assigned to
non-compete based on third-party valuations and employment
contracts. The amortizable intangibles have a weighted-average
useful life of 11.3 years. Rogers was merged into Tubular
in December 2006.
Effective August 14, 2006, we acquired 100% of the
outstanding stock of DLS, based in Argentina, for a total
consideration of approximately $117.9 million, which
includes $93.7 million in cash, $38.1 million in our
common stock, $3.4 million of acquisition costs, less
approximately $17.3 million of debt assigned to us. DLS
67
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
operates a fleet of 51 rigs, including 20 drilling rigs, 18
workover rigs and 12 pulling rigs in Argentina and one drilling
rig in Bolivia. The following table summarizes the preliminary
allocation of the purchase price to the estimated fair value of
the assets acquired and liabilities assumed at the date of
acquisition (in thousands):
|
|
|
|
|
Current assets
|
|
$
|
52,033
|
|
Property and equipment
|
|
|
130,389
|
|
Other long-term assets
|
|
|
21
|
|
|
|
|
|
|
Total assets acquired
|
|
|
182,443
|
|
|
|
|
|
|
Current liabilities
|
|
|
34,386
|
|
Long-term debt, less current
portion
|
|
|
5,921
|
|
Intercompany note
|
|
|
17,256
|
|
Deferred tax liabilities
|
|
|
6,948
|
|
|
|
|
|
|
Total liabilities assumed
|
|
|
64,511
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
117,932
|
|
|
|
|
|
|
Approximately $3.4 million of costs were incurred in
relation to the DLS acquisition. DLS historical property
and equipment values were increased by approximately
$22.7 million based on third-party valuations. We do not
expect any material differences from the preliminary allocation
of the purchase price and the final purchase price allocations.
On October 16, 2006, we acquired 100% of the outstanding
stock of Petro Rental, based in Lafayette, Louisiana, for a
total consideration of approximately $33.6 million, which
includes $20.2 million in cash, $3.8 million in our
common stock and payment of $9.6 million of existing Petro
Rental debt. Petro-Rental provides a variety of
production-related rental tools and equipment and services,
including wire line services and equipment, land and offshore
pumping services and coiled tubing. The following table
summarizes the preliminary allocation of the purchase price to
the estimated fair value of the assets acquired and liabilities
assumed at the date of acquisition (in thousands):
|
|
|
|
|
Current assets
|
|
$
|
8,175
|
|
Property and equipment
|
|
|
28,792
|
|
Intangible assets
|
|
|
5,811
|
|
Other long-term assets
|
|
|
2
|
|
|
|
|
|
|
Total assets acquired
|
|
|
42,780
|
|
|
|
|
|
|
Current liabilities
|
|
|
2,135
|
|
Deferred tax liabilities
|
|
|
6,954
|
|
|
|
|
|
|
Total liabilities assumed
|
|
|
9,089
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
33,691
|
|
|
|
|
|
|
Approximately $82,000 of costs were incurred in relation to the
Petro Rental acquisition. Petro Rentals historical
property and equipment values were increased by approximately
$13.4 million based on third-party valuations. We do not
expect any material differences from the preliminary allocation
of the purchase price and the final purchase price allocations.
Intangible assets include $3.0 million assigned to goodwill
and $2.8 million assigned to customer relationships based
on third-party valuations. The amortizable intangibles have a
weighted-average useful life of 10 years.
Effective December 1, 2006, we acquired 100% of the
outstanding stock of Tanus Argentina S.A. (Tanus),
based in Argentina, for a total consideration of
$2.5 million. Tanus is engaged in the research and
68
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
manufacturing of additives for the oil, natural gas and water
well drilling and completion fluids in Argentina. The following
table summarizes the preliminary allocation of the purchase
price to the estimated fair value of the assets acquired and
liabilities assumed at the date of the acquisition (in
thousands).
|
|
|
|
|
Current assets
|
|
$
|
2,254
|
|
Property and equipment
|
|
|
2
|
|
Goodwill
|
|
|
1,504
|
|
|
|
|
|
|
Total assets acquired
|
|
|
3,760
|
|
Current liabilities
|
|
|
1,243
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
2,517
|
|
|
|
|
|
|
Approximately $17,000 of costs were incurred in relation to the
Tanus acquisition. We do not expect any material differences
from the preliminary allocation of the purchase price and the
final purchase price allocations. The results of Tanus are
reported with DLS under our international drilling segment.
On December 18, 2006, we acquired substantially all of the
assets of Oil & Gas Rental Services, Inc., or OGR,
based in Morgan City, Louisiana, for a total consideration of
approximately $342.4 million, which includes
$291.0 million in cash, and $51.4 million in our
common stock. The following table summarizes the preliminary
allocation of the purchase price to the estimated fair value of
the assets acquired at the date of acquisition (in thousands):
|
|
|
|
|
Current assets
|
|
$
|
12,735
|
|
Property and equipment
|
|
|
199,015
|
|
Investments
|
|
|
4,618
|
|
Intangible assets
|
|
|
128,976
|
|
|
|
|
|
|
Total assets acquired
|
|
$
|
345,344
|
|
|
|
|
|
|
Approximately $3.0 million of costs were incurred in
relation to the OGR Rental acquisition. OGRs historical
property and equipment values were increased by approximately
$168.9 million based on third-party valuations. We do not
expect any material differences from the preliminary allocation
of the purchase price and the final purchase price allocations.
Intangible assets include $106.1 million assigned to
goodwill, $22.0 million to customer relations, $831,000 to
patents and $35,000 assigned to employment agreements based on
third-party valuations. The amortizable intangibles have a
weighted-average useful life of 10.1 years.
The acquisitions were accounted for using the purchase method of
accounting. The results of operations of the acquired entities
since the date of acquisition are included in our consolidated
income statement.
69
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
The following unaudited pro forma consolidated summary financial
information for the year ended December 31, 2006
illustrates the effects of the acquisitions and the related
public offerings of debt and equity for Rogers, DLS,
Petro-Rentals and OGR as if the acquisitions occurred as of
January 1, 2006, based on the historical results of the
acquisitions. The following unaudited pro forma consolidated
summary financial information for the year ended
December 31, 2005 illustrates the effects of the
acquisitions and the related public offerings of debt and equity
for Delta, Capcoil, W.T., the minority interest in AirComp,
Specialty, Rogers, DLS, Petro-Rentals and OGR as if the
acquisitions had occurred as of January 1, 2005, based on
the historical results of the acquisitions. The following
unaudited pro forma consolidated summary financial information
for the year ended December 31, 2004 illustrates the
effects of the acquisitions and the related public offerings of
debt and equity for Diamond Air, Downhole, Delta, Capcoil, W.T.,
the minority interest in AirComp, Specialty, Rogers, DLS,
Petro-Rentals and OGR as if the acquisitions had occurred as of
beginning of the period, based on the historical results of the
acquisitions (unaudited). The historical results for OGR are
based on their historical year end of October 31 (in
thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Revenues
|
|
$
|
502,418
|
|
|
$
|
346,230
|
|
|
$
|
273,825
|
|
Operating income
|
|
$
|
93,082
|
|
|
$
|
49,868
|
|
|
$
|
38,308
|
|
Net income (loss)
|
|
$
|
32,358
|
|
|
$
|
1,264
|
|
|
$
|
(7,849
|
)
|
Net income (loss) per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.96
|
|
|
$
|
0.04
|
|
|
$
|
(0.33
|
)
|
Diluted
|
|
$
|
0.94
|
|
|
$
|
0.04
|
|
|
$
|
(0.33
|
)
|
NOTE 5
INVENTORIES
Inventories are comprised of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Manufactured
|
|
|
|
|
|
|
|
|
Finished goods
|
|
$
|
1,476
|
|
|
$
|
1,402
|
|
Work in process
|
|
|
2,266
|
|
|
|
787
|
|
Raw materials
|
|
|
2,638
|
|
|
|
233
|
|
|
|
|
|
|
|
|
|
|
Total manufactured
|
|
|
6,380
|
|
|
|
2,422
|
|
Hammers
|
|
|
1,016
|
|
|
|
584
|
|
Drive pipe
|
|
|
716
|
|
|
|
666
|
|
Rental supplies
|
|
|
1,845
|
|
|
|
64
|
|
Chemicals and drilling fluids
|
|
|
2,673
|
|
|
|
201
|
|
Rig parts and related inventory
|
|
|
9,762
|
|
|
|
|
|
Coiled tubing and related inventory
|
|
|
1,627
|
|
|
|
1,145
|
|
Shop supplies and related inventory
|
|
|
4,596
|
|
|
|
863
|
|
|
|
|
|
|
|
|
|
|
Total inventory
|
|
$
|
28,615
|
|
|
$
|
5,945
|
|
|
|
|
|
|
|
|
|
|
70
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
NOTE 6
PROPERTY AND OTHER INTANGIBLE ASSETS
Property and equipment is comprised of the following at
December 31 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
|
|
|
|
|
|
|
Period
|
|
|
2006
|
|
|
2005
|
|
|
Land
|
|
|
|
|
|
$
|
1,810
|
|
|
$
|
27
|
|
Building and improvements
|
|
|
15-20 years
|
|
|
|
5,392
|
|
|
|
637
|
|
Transportation equipment
|
|
|
3-10 years
|
|
|
|
22,744
|
|
|
|
7,772
|
|
Drill pipe and rental equipment
|
|
|
3-20 years
|
|
|
|
321,821
|
|
|
|
6,813
|
|
Drilling, workover and pulling rigs
|
|
|
20 years
|
|
|
|
120,517
|
|
|
|
|
|
Machinery and equipment
|
|
|
3-20 years
|
|
|
|
105,926
|
|
|
|
70,189
|
|
Furniture, computers, software and
leasehold improvements
|
|
|
3-7 years
|
|
|
|
3,522
|
|
|
|
2,073
|
|
Construction in
progress equipment
|
|
|
N/A
|
|
|
|
2,269
|
|
|
|
3,059
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
584,001
|
|
|
|
90,570
|
|
Less: accumulated depreciation
|
|
|
|
|
|
|
(29,743
|
)
|
|
|
(9,996
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
|
|
|
|
$
|
554,258
|
|
|
$
|
80,574
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The net book value of equipment recorded under capital leases
was $1.0 million and $1.1 million at December 31,
2006 and 2005, respectively.
Intangible assets are as follows at December 31 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization
|
|
|
|
|
|
|
|
|
|
Period
|
|
|
2006
|
|
|
2005
|
|
|
Intellectual property
|
|
|
20 years
|
|
|
$
|
1,009
|
|
|
$
|
1,009
|
|
Non-compete agreements
|
|
|
3-5 years
|
|
|
|
4,580
|
|
|
|
4,630
|
|
Customer relationships
|
|
|
10 years
|
|
|
|
27,552
|
|
|
|
2,954
|
|
Patent
|
|
|
12-15 years
|
|
|
|
3,327
|
|
|
|
496
|
|
Other intangible assets
|
|
|
2-10 years
|
|
|
|
847
|
|
|
|
857
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
37,315
|
|
|
|
9,946
|
|
Less: accumulated amortization
|
|
|
|
|
|
|
(4,475
|
)
|
|
|
(3,163
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangibles assets, net
|
|
|
|
|
|
$
|
32,840
|
|
|
$
|
6,783
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
Gross
|
|
|
Accumulated
|
|
|
Current Year
|
|
|
Gross
|
|
|
Accumulated
|
|
|
Current Year
|
|
|
|
Value
|
|
|
Amortization
|
|
|
Amortization
|
|
|
Value
|
|
|
Amortization
|
|
|
Amortization
|
|
|
Intellectual property
|
|
$
|
1,009
|
|
|
$
|
349
|
|
|
$
|
55
|
|
|
$
|
1,009
|
|
|
$
|
293
|
|
|
$
|
54
|
|
Non-compete agreements
|
|
|
4,580
|
|
|
|
2,707
|
|
|
|
1,091
|
|
|
|
4,630
|
|
|
|
1,916
|
|
|
|
884
|
|
Customer relationships
|
|
|
27,552
|
|
|
|
789
|
|
|
|
449
|
|
|
|
2,954
|
|
|
|
540
|
|
|
|
274
|
|
Patent
|
|
|
3,327
|
|
|
|
203
|
|
|
|
165
|
|
|
|
496
|
|
|
|
39
|
|
|
|
33
|
|
Other intangible assets
|
|
|
847
|
|
|
|
427
|
|
|
|
97
|
|
|
|
857
|
|
|
|
375
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
37,315
|
|
|
$
|
4,475
|
|
|
$
|
1,857
|
|
|
$
|
9,946
|
|
|
$
|
3,163
|
|
|
$
|
1,248
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
71
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
Future amortization of intangible assets at December 31,
2006 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible Amortization by Period
|
|
|
|
Years Ended December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 and
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
Thereafter
|
|
|
Intellectual property
|
|
$
|
55
|
|
|
$
|
55
|
|
|
$
|
55
|
|
|
$
|
55
|
|
|
$
|
440
|
|
Non-compete agreements
|
|
|
887
|
|
|
|
564
|
|
|
|
362
|
|
|
|
60
|
|
|
|
|
|
Customer relationships
|
|
|
2,743
|
|
|
|
2,740
|
|
|
|
2,740
|
|
|
|
2,740
|
|
|
|
15,800
|
|
Patent
|
|
|
274
|
|
|
|
274
|
|
|
|
274
|
|
|
|
274
|
|
|
|
2,028
|
|
Other intangible assets
|
|
|
112
|
|
|
|
107
|
|
|
|
90
|
|
|
|
80
|
|
|
|
31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Intangible Amortization
|
|
$
|
4,071
|
|
|
$
|
3,740
|
|
|
$
|
3,521
|
|
|
$
|
3,209
|
|
|
$
|
18,299
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We had income before income taxes of $35.9 million,
$8.5 million and $1.4 million in the U.S. for the
years ended December 31, 2006, 2005 and 2004, respectively.
In 2006, we also had income before income taxes of
$11.1 million in
non-U.S. countries.
We treat the withholding taxes incurred by our
U.S. subsidiaries in foreign countries as foreign tax,
although we do anticipate using those tax payments to offset
U.S. tax.
The income tax provision consists of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Current income tax expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
5,865
|
|
|
$
|
123
|
|
|
$
|
|
|
State
|
|
|
898
|
|
|
|
595
|
|
|
|
|
|
Foreign
|
|
|
2,442
|
|
|
|
626
|
|
|
|
514
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,205
|
|
|
|
1,344
|
|
|
|
514
|
|
Deferred income tax expense
(benefit):
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(946
|
)
|
|
|
|
|
|
|
|
|
State
|
|
|
573
|
|
|
|
|
|
|
|
|
|
Foreign
|
|
|
2,588
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,215
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
11,420
|
|
|
$
|
1,344
|
|
|
$
|
514
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We are required to file a consolidated U.S. federal income
tax return. We pay foreign income taxes in Argentina related to
DLSs operations and in Mexico related to Allis-Chalmers
Tubular Services revenues from Matyep. There are
approximately $2.4 million of U.S. foreign tax credits
available to us. Our foreign tax credits begin to expire in the
year 2007.
72
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
The following table reconciles the U.S. statutory tax rate
to our actual tax rate:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Statutory income tax rate
|
|
|
35.0
|
%
|
|
|
34.0
|
%
|
|
|
34.0
|
%
|
State taxes, net of federal benefit
|
|
|
2.1
|
|
|
|
6.1
|
|
|
|
|
|
Valuation allowances
|
|
|
(57.7
|
)
|
|
|
(98.7
|
)
|
|
|
(209.4
|
)
|
Nondeductible items, permanent
differences and other
|
|
|
44.9
|
|
|
|
74.4
|
|
|
|
212.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate
|
|
|
24.3
|
%
|
|
|
15.8
|
%
|
|
|
36.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Significant components of deferred income tax assets and the
related allowance as of December 31, were as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Deferred income tax assets:
|
|
|
|
|
|
|
|
|
Net future (taxable) deductible
items
|
|
$
|
899
|
|
|
$
|
384
|
|
Share based compensation
|
|
|
578
|
|
|
|
|
|
Net operating loss carry forwards
|
|
|
1,698
|
|
|
|
5,656
|
|
Foreign tax credit
|
|
|
2,420
|
|
|
|
|
|
A-C Reorganization Trust and
Product Liability Trust claims
|
|
|
5,500
|
|
|
|
29,098
|
|
|
|
|
|
|
|
|
|
|
Total deferred income tax assets
|
|
|
11,095
|
|
|
|
35,138
|
|
Valuation allowance
|
|
|
|
|
|
|
(27,131
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred income tax assets
|
|
|
11,095
|
|
|
|
8,007
|
|
Deferred income tax liabilities
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
(28,226
|
)
|
|
|
(8,007
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred income tax assets
(liabilities)
|
|
$
|
(17,131
|
)
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Net current deferred income tax
asset
|
|
$
|
2,822
|
|
|
$
|
|
|
Net noncurrent deferred income tax
liability
|
|
|
(19,953
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred income tax assets
(liabilities)
|
|
$
|
(17,131
|
)
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Net future tax-deductible items relate primarily to timing
differences. Timing differences are differences between the tax
basis of assets and liabilities and their reported amounts in
the financial statements that will result in differences between
income for tax purposes and income for financial statement
purposes in future years.
The Tax Reform Act of 1986 contains provisions that limit the
utilization of net operating loss and tax credit carry forwards
if there has been a change of ownership as described
in Section 382 of the Internal Revenue Code. Such a change
of ownership may limit our utilization of our net operating loss
and tax credit carry forwards, and could be triggered by a
public offering or by subsequent sales of securities by us or
our stockholders. This provision has limited the amount of net
operating losses available to us currently, but we are
projecting the release of net operating losses under the
provisions of Section 382. Net operating loss carry
forwards for tax purposes at December 31, 2006 and 2005
were estimated to be $4.9 million and $16.6 million,
respectively, expiring through 2024.
Prior to 2006, we did not record an asset for the
U.S. foreign tax credit as we believed they would not be
recoverable based on our taxable income.
73
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
Our 1988 Plan of Reorganization established the A-C
Reorganization Trust to settle claims and to make distributions
to creditors and certain stockholders. We transferred cash and
certain other property to the A-C Reorganization Trust on
December 2, 1988. Payments made by us to the A-C
Reorganization Trust did not generate tax deductions for us upon
the transfer but generate deductions for us as the A-C
Reorganization Trust makes payments to holders of claims. The
Plan of Reorganization also created a trust to process and
liquidate product liability claims. Payments made by the A-C
Reorganization Trust to the product liability trust did not
generate current tax deductions for us upon the payment but
generate deductions for us as the product liability trust makes
payments to liquidate claims or incurs other expenses. We
believe the aforementioned trusts are grantor trusts and
therefore we include the income or loss of these trusts in our
income or loss for tax purposes, resulting in an adjustment of
the tax basis of net operating and capital loss carry forwards.
The income or loss of these trusts is not included in our
results of operations for financial reporting purposes.
A valuation allowance is established for deferred tax assets
when management, based upon available information, considers it
more likely than not that a benefit from such assets will not be
realized. The valuation allowance was relieved in 2006 due to
the increase in our operating results for the year ended
December 31, 2006, which we project will utilize all of the
net operating loss carryforwards that are available to us and
the revaluation of the deferred tax asset related to the A-C
Reorganization Trust and Product Liability Trust. In 2005 and
2004, we had a valuation allowance equal to the excess of
deferred tax assets over deferred tax liabilities as we were
unable to determine that it was more likely than not that the
deferred tax asset will be realized.
Our long-term debt consists of the following: (in thousands)
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Senior notes
|
|
$
|
255,000
|
|
|
$
|
|
|
Bridge loan
|
|
|
300,000
|
|
|
|
|
|
Bank term loans
|
|
|
7,302
|
|
|
|
42,090
|
|
Revolving line of credit
|
|
|
|
|
|
|
6,400
|
|
Subordinated note payable to M-I
LLC
|
|
|
|
|
|
|
4,000
|
|
Subordinated seller note
|
|
|
|
|
|
|
3,031
|
|
Seller note
|
|
|
900
|
|
|
|
850
|
|
Obligations under non-compete
agreements
|
|
|
270
|
|
|
|
698
|
|
Notes payable to former directors
|
|
|
32
|
|
|
|
96
|
|
Real estate loan
|
|
|
|
|
|
|
548
|
|
Equipment & vehicle
installment notes
|
|
|
3,502
|
|
|
|
1,939
|
|
Insurance premium financing
|
|
|
1,025
|
|
|
|
|
|
Capital lease obligations
|
|
|
414
|
|
|
|
917
|
|
|
|
|
|
|
|
|
|
|
Total debt
|
|
|
568,445
|
|
|
|
60,569
|
|
Less: short-term debt and current
maturities
|
|
|
6,999
|
|
|
|
5,632
|
|
|
|
|
|
|
|
|
|
|
Long-term debt obligations
|
|
$
|
561,446
|
|
|
$
|
54,937
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2006 and 2005, our debt was
approximately $568.4 million and $60.6 million,
respectively. Our weighted average interest rate for all of our
outstanding debt was approximately 9.8% at December 31,
2006 and 7.5% at December 31, 2005.
74
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
Maturities of debt obligations at December 31, 2006 are as
follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt
|
|
|
Capital Leases
|
|
|
Total
|
|
|
Year Ending:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
$
|
6,585
|
|
|
$
|
414
|
|
|
$
|
6,999
|
|
December 31, 2008
|
|
|
53,146
|
|
|
|
|
|
|
|
53,146
|
|
December 31, 2009
|
|
|
1,500
|
|
|
|
|
|
|
|
1,500
|
|
December 31, 2010
|
|
|
1,450
|
|
|
|
|
|
|
|
1,450
|
|
December 31, 2011
|
|
|
350
|
|
|
|
|
|
|
|
350
|
|
Thereafter
|
|
|
505,000
|
|
|
|
|
|
|
|
505,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
568,031
|
|
|
$
|
414
|
|
|
$
|
568,445
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior
notes, bank loans and line of credit agreements
On January 18, 2006 and August 14, 2006, we closed on
private offerings, to qualified institutional buyers pursuant to
Rule 144A under the Securities Act of 1933, of $160.0 and
$95.0 million aggregate principal amount of our senior
notes, respectively. The senior notes are due January 15,
2014 and bear interest at 9.0%. The proceeds were used to fund
the acquisitions of Specialty and DLS, to repay existing debt
and for general corporate purposes.
On December 18, 2006, we closed on a $300.0 million
senior unsecured bridge loan. The bridge loan is due
18 months after closing and bears a weighted average
interest rate of 10.6%. The bridge loan, which was repaid on
January 29, 2007, was used to fund the acquisition of OGR.
Prior to January 18, 2006, we were party to a July 2005
credit agreement that provided for the following senior secured
credit facilities:
|
|
|
|
|
A $13.0 million revolving line of credit. Borrowings were
limited to 85% of eligible accounts receivable plus 50% of
eligible inventory (up to a maximum of $2.0 million of
borrowings based on inventory). This line of credit was to be
used to finance working capital requirements and other general
corporate purposes, including the issuance of standby letters of
credit. Outstanding borrowings under this line of credit were
$6.4 million at a margin above prime and LIBOR rates plus
margin averaging approximately 8.1% as of December 31, 2005.
|
|
|
|
Two term loans totaling $42.0 million. Outstanding
borrowings under these term loans were $42.0 million as of
December 31, 2005. These loans were at LIBOR rates plus a
margin which averages approximately 7.8% at December 31,
2005.
|
Borrowings under the July 2005 credit facilities were to mature
in July 2007. Amounts outstanding under the term loans as of
July 2006 were to be repaid in monthly principal payments based
on a 48 month repayment schedule with the remaining balance
due at maturity. Additionally, during the second year, we were
to be required to prepay the remaining balance of the term loans
by 75% of excess cash flow, if any, after debt service and
capital expenditures. The interest rate payable on borrowings
was based on a margin over the London Interbank Offered Rate,
referred to as LIBOR, or the prime rate, and there was a 0.5%
fee on the undrawn portion of the revolving line of credit. The
margin over LIBOR was to increase by 1.0% in the second year.
All amounts outstanding under our July 2005 credit agreement
were paid off with the proceeds of our senior notes offering on
January 18, 2006. On January 18, 2006, we also
executed an amended and restated credit agreement which provides
for a $25.0 million revolving line of credit with a
maturity of January 2010. Our January 2006 amended and restated
credit agreement contains customary events of default and
financial
75
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
covenants and limits our ability to incur additional
indebtedness, make capital expenditures, pay dividends or make
other distributions, create liens and sell assets. Our
obligations under the January 2006 amended and restated credit
agreement are secured by substantially all of our assets
excluding the DLS assets, but including
2/3
of our shares of DLS. At December 31, 2006, no amounts were
borrowed on the facility but availability is reduced by
outstanding letters of credit of $9.7 million.
As part of our acquisition of DLS, we assumed various bank loans
with floating interest rates based on LIBOR plus a margin and
terms ranging from 2 to 5 years. The weighted average
interest rates on these loans was 7.0% at December 31,
2006. The bank loans are denominated in U.S. dollars and
the outstanding amount due as of December 31, 2006 was
$7.3 million.
Tubular had two bank term loans with a remaining balance $90,000
at December 31, 2005, with interest accruing at a floating
interest rate based on prime plus 2.0% (9.25% at
December 31, 2005). Monthly principal payments were $13,000
plus interest. The maturity date of one of the loans, with a
balance of $60,000, was September 17, 2006, while the
second loan, with a balance of $30,000, had a final maturity of
January 12, 2007. The balances of these two loans were
repaid in full in January 2006 with the proceeds from our
senior notes offering.
Notes
payable and real estate loan
On July 11, 2005, we acquired from M-I its 45% equity
interest in AirComp and the subordinated note in the principal
amount of $4.8 million issued by AirComp, for which we paid
M-I $7.1 million in cash and issued a new $4.0 million
subordinated note bearing interest at 5.0% per annum. The
subordinated note issued to M-I required quarterly interest
payments and the principal amount was due October 9, 2007.
Contingent upon a future equity offering, the subordinated note
was convertible into up to 700,000 shares of our common
stock at a conversion price equal to the market value of the
common stock at the time of conversion. This note was repaid
from the proceeds of our offering of $95.0 million of
9.0% senior notes, which we completed in August 2006.
As of December 31, 2005, Tubular had a subordinated note
outstanding and payable to Jens Mortensen, the seller of Tubular
and one of our directors, in the amount of $3.0 million
with a fixed interest rate of 7.5%. Interest was payable
quarterly and the final maturity of the note was
January 31, 2006. The subordinated note was subordinated to
the rights of our bank lenders. The balance of this subordinated
note was repaid in full in January 2006 with proceeds from our
senior notes offering.
As part of the acquisition of Mountain Air in 2001, we issued a
note to the sellers of Mountain Air in the original amount of
$2.2 million accruing interest at a rate of 5.75% per
annum. The note was reduced to $1.5 million as a result of
the settlement of a legal action against the sellers in 2003. In
March 2005, we reached an agreement with the sellers and holders
of the note as a result of an action brought against us by the
sellers. Under the terms of the agreement, we paid the holders
of the note $1.0 million in cash, and agreed to pay an
additional $350,000 on June 1, 2006, and an additional
$150,000 on June 1, 2007, in settlement of all claims. At
December 31, 2006 and 2005 the outstanding amounts due were
$150,000 and $500,000, respectively.
In connection with the purchase of Delta, we issued to the
sellers a note in the amount of $350,000. The note bore interest
at 2% and the principal and accrued interest was repaid on its
maturity of April 1, 2006. At December 31, 2005 the
outstanding amounts due was $350,000. The note was repaid during
2006. In connection with the acquisition of Rogers, we issued to
the seller a note in the amount of $750,000. The note bears
interest at 5.0% and is due April 3, 2009.
In connection with the purchase of Tubular, we agreed to pay a
total of $1.2 million to Mr. Mortensen in exchange for
a non-compete agreement. Monthly payments of $20,576 are due
under this agreement through January 31, 2007. In
connection with the purchase of Safco-Oil Field Products, Inc.,
or Safco, we also agreed
76
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
to pay a total of $150,000 to the sellers in exchange for a
non-compete agreement. We are required to make annual payments
of $50,000 through September 30, 2007. In connection with
the purchase of Capcoil, we agreed to pay a total of $500,000 to
two management employees in exchange for non-compete agreements.
We are required to make annual payments of $110,000 through May
2008. Total amounts due under these non-compete agreements at
December 31, 2006 and 2005 were $270,000 and $698,000,
respectively.
In 2000 we compensated directors, including current directors
Nederlander and Toboroff, who served on the board of directors
from 1989 to March 31, 1999 without compensation, by
issuing promissory notes totaling $325,000. The notes bear
interest at the rate of 5.0%. At December 31, 2006 and
2005, the principal and accrued interest on these notes totaled
approximately $32,000 and $96,000, respectively.
We also had a real estate loan which was payable in equal
monthly installments of $4,344 with the remaining outstanding
balance due on January 1, 2010. The loan had a floating
interest rate based on prime plus 2.0%. The outstanding
principal balance was $548,000 at December 31, 2005. The
balance of this loan was repaid in full in January 2006 with
proceeds from our senior notes offering.
Other
debt
We have various rig and equipment financing loans with interest
rates ranging from 5.0% to 8.7% and terms of 2 to 5 years.
As of December 31, 2006 and 2005, the outstanding balances
for rig and equipment financing loans were $3.5 million and
$1.9 million, respectively. In April 2006 and August 2006,
we obtained insurance premium financings in the amount of
$1.9 million and $896,000 with fixed interest rates of 5.6%
and 6.0%, respectively. Under terms of the agreements, amounts
outstanding are paid over 10 month and 11 month
repayment schedules. The outstanding balance of these notes was
approximately $1.0 million as of December 31, 2006. We
also have various capital leases with terms that expire in 2008.
As of December 31, 2006 and 2005, amounts outstanding under
capital leases were $414,000 and $917,000, respectively. In
January 2006, we prepaid $350,000 of the outstanding equipment
loans with proceeds from our senior notes offering.
|
|
NOTE 9
|
COMMITMENTS
AND CONTINGENCIES
|
We have placed orders for capital equipment totaling
$42.3 million to be received and paid for through 2007. Of
this amount, $27.4 million is for rental equipment,
principally drillpipe, $4.6 million is for six measurement
while drilling kits and ancillary equipment for our directional
drilling segment and $3.4 million is for two new capillary
tubing units for our production services segment and
$4.5 million is for casing and tubing tools and equipment.
The orders are subject to cancellation with minimal loss of
prior cash deposits, if any.
We rent office space on a five-year lease which expires November
2009. We also rent certain other facilities and shop yards for
equipment storage and maintenance. Facility rent expense for the
years ended December 31, 2006, 2005 and 2004 was
$1.6 million, $987,000 and $577,000, respectively.
At December 31, 2006, future minimum rental commitments for
all operating leases are as follows (in thousands):
|
|
|
|
|
Years Ending:
|
|
|
|
|
December 31, 2007
|
|
$
|
2,013
|
|
December 31, 2008
|
|
|
1,716
|
|
December 31, 2009
|
|
|
942
|
|
December 31, 2010
|
|
|
160
|
|
December 31, 2011
|
|
|
117
|
|
Thereafter
|
|
|
470
|
|
|
|
|
|
|
Total
|
|
$
|
5,418
|
|
|
|
|
|
|
77
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
NOTE 10
|
STOCKHOLDERS
EQUITY
|
On March 3, 2004, we entered into an agreement with an
investment banking firm whereby they would provide underwriting
and fundraising activities on our behalf. In exchange for their
services, the investment banking firm received a stock purchase
warrant to purchase 340,000 shares of common stock at an
exercise price of $2.50 per share. The warrant was
exercised in August of 2005. The fair value of the total
warrants issued in connection with the fundraising activities
was established in accordance with the Black-Scholes valuation
model and as a result, $641,000 was added to stockholders
equity. The following assumptions were utilized to determine
fair value: no dividend yield; expected volatility of 89.7%;
risk free interest rate of 7.00%; and expected life of five
years.
During 2004, we issued two warrants (Warrants A and
B) for the purchase of 233,000 total shares of our common
stock at an exercise price of $0.75 per share and one
warrant for the purchase of 67,000 shares of our common
stock at an exercise price of $5.00 per share
(Warrant C) in connection with subordinated debt
financing. Warrants A and B were redeemed for a total of
$1,500,000 on December 7, 2004. The fair value of Warrant C
was established in accordance with the Black-Scholes valuation
model and as a result, $47,000 was added to stockholders
equity. The following assumptions were utilized to determine
fair value: no dividend yield; expected volatility of 67.24%;
risk free interest rate of 5.00%; and expected life of four
years.
On April 2, 2004, we completed the following transactions:
|
|
|
|
|
In exchange for an investment of $2.0 million, we issued
620,000 shares of our common stock for a purchase price
equal to $2.50 per share, and issued warrants to purchase
800,000 shares of our common stock at an exercise price of
$2.50 per share, expiring on April 1, 2006, to an
investor group (the Investor Group) consisting of
entities affiliated with Donald and Christopher Engel and
directors Robert Nederlander and Leonard Toboroff. The aggregate
purchase price for the common stock was $1.55 million and
the fair value for the warrants was $450,000.
|
|
|
|
Energy Spectrum converted its 3,500,000 shares of
Series A 10% Cumulative Convertible Preferred Stock,
including accrued dividend rights, into 1,718,090 shares of
common stock. Energy Spectrum was granted the preferred stock in
connection with the Strata acquisition.
|
On August 10, 2004, we completed the private placement of
3,504,667 shares of our common stock at a price of
$3.00 per share. Our net proceeds, after selling
commissions and expenses, were approximately $9.6 million.
We issued shares pursuant to an exemption from the Securities
Act of 1933, and agreed to subsequently register the common
stock under the Securities Act of 1933 to allow investors to
resell the common stock in public markets.
On September 30, 2004, we completed the private placement
of 1,956,634 shares of our common stock at a price of
$3.00 per share. Our net proceeds, after selling commission
and expenses, were approximately $5.3 million. We issued
shares pursuant to an exemption from the Securities Act of 1933,
and agreed to subsequently register the common stock under the
Securities Act of 1933 to allow investors to resell the common
stock in public markets.
On September 30, 2004, we issued 1.3 million shares of
common stock to Jens Mortensen, a director, in exchange for his
19% interest in Tubular. As a result of this transaction, we own
100% of Tubular. The total value of the consideration paid to
Jens was $6.4 million, which was equal to the number of
shares of common stock issued to Mr. Mortensen multiplied
by the last sale price ($4.95) of the common stock as reported
on the American Stock Exchange on the date of issuance. This
amount was treated as a contribution to stockholders equity.
On December 10, 2004, we acquired Downhole for
approximately $1.1 million in cash, 568,466 shares of
our common stock and payment or assumption of $950,000 of debt.
Approximately $2.2 million, the value of
78
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
the common stock issued to Downholes sellers based on the
closing price of our common stock issued at the date of the
acquisition, was added to stockholders equity.
As of January 1, 2005, in relation to the acquisition of
Downhole, we executed a business development agreement with CTTV
Investments LLC, an affiliate of ChevronTexaco Inc., whereby we
issued 20,000 shares of our common stock to CTTV and
further agreed to issue up to an additional 60,000 shares
to CTTV contingent upon our subsidiaries receiving certain
levels of revenues in 2005 from ChevronTexaco and its
affiliates. CTTV was a minority owner of Downhole, which we
acquired in 2004. Based on the terms of the agreement, no
additional shares were issued in 2006 or 2005.
On April 1, 2005, we acquired 100% of the outstanding stock
of Delta, for $4.6 million in cash, 223,114 shares of
our common stock and two promissory notes totaling $350,000.
Approximately $1.0 million, the value of the common stock
issued to Deltas sellers based on the closing price of our
common stock issued at the date of the acquisition, was added to
stockholders equity.
On May 1, 2005, we acquired 100% of the outstanding capital
stock of Capcoil for $2.7 million in cash,
168,161 shares of our common stock and the payment or
assumption of approximately $1.3 million of debt.
Approximately $750,000, the value of the common stock issued to
Capcoils sellers based on the closing price of our common
stock issued at the date of the acquisition, was added to
stockholders equity.
In August 2005, our stockholders approved an amendment to our
certificate of incorporation to increase the authorized number
of shares of our common stock from 20 million to
100 million and to increase our authorized preferred stock
from 10 million shares to 25 million shares and, we
completed a secondary public offering in which we sold
1,761,034 shares for approximately $15.5 million, net
of expenses.
We also had options and warrants exercised during 2005. Those
exercises resulted in 1,076,154 shares of our common stock
being issued for $1.4 million.
We issued 125,285, 2.5 million, 246,761 and
3.2 million shares of our common stock in relation to the
Rogers, DLS, Petro Rental and OGR acquisition, respectively (see
Note 4).
On August 14, 2006 we closed on a public offering of
3,450,000 shares of our common stock at a public offering
price of $14.50 per share. Net proceeds from the public
offering of $46.3 million were used to fund a portion of
our acquisition of DLS.
We also had options and warrants exercised in 2006, which
resulted in 1,851,377 shares of our common stock being
issued for approximately $6.3 million. We recognized
approximately $3.4 million of compensation expense related
to stock options in 2006 that was recorded as capital in excess
of par value (see Note 1). We also recorded approximately
$6.4 million of tax benefit related to our stock
compensation plans.
NOTE 11
REVERSE STOCK SPLIT
We effected a reverse stock split on June 10, 2004. As a
result of the reverse stock split, every five shares of our
common stock was combined into one share of common stock. The
reverse stock split reduced the number of shares of outstanding
common stock from 31,393,789 to approximately 6,265,000 and
reduced the number of our stockholders from 6,070 to
approximately 2,140. All share and related amounts presented
have been retroactively adjusted for the stock split.
NOTE 12
STOCK OPTIONS
In 2000, we issued stock options and promissory notes to certain
current and former directors as compensation for services as
directors (See Note 8), and our Board of Directors granted
stock options to these same individuals. Options to purchase
4,800 shares of our common stock were granted with an
exercise price of $13.75 per share. These options vested
immediately and may be exercised any time prior to
March 28,
79
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
2010. As of December 31, 2006 4,000 of the stock options
remain outstanding. No compensation expense has been recorded
for these options that were issued with an exercise price equal
to the fair value of the common stock at the date of grant.
On May 31, 2001, the Board granted to Leonard Toboroff, one
of our directors, an option to purchase 100,000 shares of
our common stock at $2.50 per share, exercisable for
10 years from October 15, 2001. The option was granted
for services provided by Mr. Toboroff to OilQuip prior to
the merger, including providing financial advisory services,
assisting in OilQuips capital structure and assisting
OilQuip in finding strategic acquisition opportunities. We
recorded compensation expense of $500,000 for the issuance of
the option for the year ended December 31, 2001. As of
December 31, 2006, all of the stock options have been
exercised.
The 2003 Incentive Stock Plan (2003 Plan), as
amended, permits us to grant to our key employees and outside
directors various forms of stock incentives, including, among
others, incentive and non-qualified stock options and restricted
stock. The 2003 Plan is administered by the Compensation
Committee of the Board, which consists of two or more directors
appointed by the Board. The following benefits may be granted
under the 2003 Plan: (a) stock appreciation rights;
(b) restricted stock; (c) performance awards;
(d) incentive stock options; (e) nonqualified stock
options; and (f) other stock-based awards. Stock incentive
terms are not to be in excess of ten years. The maximum number
of shares that may be issued under the 2003 Plan shall be the
lesser of 3,000,000 shares and 15% of the total number of
shares of common stock outstanding.
The 2006 Incentive Plan (2006 Plan), was approved by
our stockholders in November 2006. The 2006 Plan is administered
by the Compensation Committee of the Board, which consists of
two or more directors appointed by the Board. The maximum number
of shares of the Companys common stock, par value
$0.01 per share (Common Stock), that may be
issued under the 2006 Plan is equal to 1,500,000 shares,
subject to adjustment in the event of stock splits and certain
other corporate events. The 2006 Plan provides for the grant of
any or all of the following types of awards: (i) stock
options, including incentive stock options and non-qualified
stock options; (ii) bonus stock; (iii) restricted
stock awards; (iv) performance awards; and (v) other
stock-based awards. Except with respect to awards of incentive
stock options, all employees, consultants and non-employee
directors of the Company and its affiliates are eligible to
participate in the 2006 Plan. The term of each Award shall be
for such period as may be determined by the Committee; provided,
that in no event shall the term of any Award exceed a period of
ten (10) years from the date of its grant.
A summary of our stock option activity and related information
is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
December 31, 2005
|
|
|
December 31, 2004
|
|
|
|
Shares
|
|
|
Weighted Ave.
|
|
|
Shares
|
|
|
Weighted Ave.
|
|
|
Shares
|
|
|
Weighted Avg.
|
|
|
|
Under
|
|
|
Exercise
|
|
|
Under
|
|
|
Exercise
|
|
|
Under
|
|
|
Exercise
|
|
|
|
Option
|
|
|
Price
|
|
|
Option
|
|
|
Price
|
|
|
Option
|
|
|
Price
|
|
|
Beginning balance
|
|
|
2,860,867
|
|
|
$
|
5.10
|
|
|
|
1,215,000
|
|
|
$
|
3.20
|
|
|
|
973,300
|
|
|
$
|
2.78
|
|
Granted
|
|
|
15,000
|
|
|
|
14.74
|
|
|
|
1,695,000
|
|
|
|
6.44
|
|
|
|
248,000
|
|
|
|
4.85
|
|
Canceled
|
|
|
(54,567
|
)
|
|
|
5.97
|
|
|
|
(15,300
|
)
|
|
|
3.33
|
|
|
|
(6,300
|
)
|
|
|
2.78
|
|
Exercised
|
|
|
(1,470,935
|
)
|
|
|
3.54
|
|
|
|
(33,833
|
)
|
|
|
2.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
|
1,350,365
|
|
|
$
|
6.88
|
|
|
|
2,860,867
|
|
|
$
|
5.10
|
|
|
|
1,215,000
|
|
|
$
|
3.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
80
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
The following table summarizes additional information about our
stock options outstanding as of December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
|
|
|
|
|
|
|
Shares Under
|
|
|
Remaining
|
|
|
|
|
|
|
|
Exercise Price
|
|
|
Option
|
|
|
Contractual Life
|
|
|
Options Exercisable
|
|
|
Exercise Price
|
|
|
$
|
2.75
|
|
|
|
56,300
|
|
|
|
6.96 years
|
|
|
|
56,300
|
|
|
$
|
2.75
|
|
$
|
3.86
|
|
|
|
429,900
|
|
|
|
8.09 years
|
|
|
|
129,899
|
|
|
$
|
3.86
|
|
$
|
4.85
|
|
|
|
227,000
|
|
|
|
7.87 years
|
|
|
|
227,000
|
|
|
$
|
4.85
|
|
$
|
4.87
|
|
|
|
101,165
|
|
|
|
8.40 years
|
|
|
|
62,822
|
|
|
$
|
4.87
|
|
$
|
10.85
|
|
|
|
517,667
|
|
|
|
8.96 years
|
|
|
|
325,988
|
|
|
$
|
10.85
|
|
$
|
13.75
|
|
|
|
4,000
|
|
|
|
3.24 years
|
|
|
|
4,000
|
|
|
$
|
13.75
|
|
$
|
14.74
|
|
|
|
14,333
|
|
|
|
9.57 years
|
|
|
|
4,336
|
|
|
$
|
14.74
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6.88
|
|
|
|
1,350,365
|
|
|
|
8.36 years
|
|
|
|
810,345
|
|
|
$
|
7.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2006, there was $914,000 of total
unrecognized compensation cost related to stock option, with
$900,000 to be recognized during the year ended
December 31, 2007 and the remaining portion during the year
ended December 31, 2008.
Restricted
Stock Awards
In addition to stock options, our 2003 and 2006 Plan allow for
the grant of restricted stock awards (RSA), which is
an award of common stock with no exercise price, where each unit
represents the right to receive at the end of a stipulated
period one unrestricted share of stock with no exercise price.
The RSA restrictions lapse periodically over an extended period
of time not exceeding 10 years. We determine the fair value
of RSAs based on the market price of our common stock on the
date of grant. Compensation cost for RSAs is primarily
recognized on a straight-line basis over the vesting or service
period and is net of forfeitures.
The following table summarizes activity in our nonvested
restricted stock awards:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
|
|
|
Grant-Date Fair Value
|
|
|
|
Number of Shares
|
|
|
per Share
|
|
|
Nonvested at December 31, 2005
|
|
|
|
|
|
$
|
|
|
Granted
|
|
|
|
|
|
|
|
|
Vested
|
|
|
27,000
|
|
|
|
18.30
|
|
Forfeited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested at December 31, 2006
|
|
|
27,000
|
|
|
$
|
18.30
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2006, there was $393,000 of total
unrecognized compensation cost related to nonvested RSAs, which
is expected to be recognized during the year ended
December 31, 2007.
NOTE 13
STOCK PURCHASE WARRANTS
In conjunction with the Mountain Air purchase by OilQuip in
February of 2001, Mountain Air issued a common stock warrant for
620,000 shares to a third-party investment firm that
assisted us in its initial identification and purchase of the
Mountain Air assets. The warrant entitles the holder to acquire
up to 620,000 shares of common stock of Mountain Air at an
exercise price of $.01 per share over a nine-year period
commencing on February 7, 2001.
81
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
We issued two warrants (Warrants A and B) for the
purchase of 233,000 total shares of our common stock at an
exercise price of $0.75 per share and one warrant for the
purchase of 67,000 shares of our common stock at an
exercise price of $5.00 per share (Warrant C)
in connection with our subordinated debt financing for Mountain
Air in 2001. Warrants A and B were paid off on December 7,
2004. Warrant C was exercised during November 2006.
On February 6, 2002, in connection with the acquisition of
substantially all of the outstanding stock of Strata, we issued
a warrant for the purchase of 87,500 shares of our common
stock at an exercise price of $0.75 per share over the term
of four years. The warrants were exercised in August of 2005.
In connection with the Strata Acquisition, on February 19,
2003, we issued Energy Spectrum an additional warrant to
purchase 175,000 shares of our common stock at an exercise
price of $0.75 per share. The warrants were exercised in
August of 2005.
In March 2004, we issued a warrant to purchase
340,000 shares of our common stock at an exercise price of
$2.50 per share to Morgan Joseph & Co., in
consideration of financial advisory services to be provided by
Morgan Joseph pursuant to a consulting agreement. The warrants
were exercised in August 2005.
In April 2004, we issued warrants to purchase 20,000 shares
of common stock at an exercise price of $0.75 per share to
Wells Fargo Credit, Inc., in connection with the extension of
credit by Wells Fargo Credit Inc. The warrants were exercised in
August 2005.
In April 2004, we completed a private placement of
620,000 shares of common stock and warrants to purchase
800,000 shares of common stock to the following investors:
Christopher Engel; Donald Engel; the Engel Defined Benefit Plan;
RER Corp., a corporation wholly-owned by director Robert
Nederlander; and Leonard Toboroff, a director. The investors
invested $1,550,000 in exchange for 620,000 shares of
common stock for a purchase price equal to $2.50 per share,
and invested $450,000 in exchange for warrants to purchase
800,000 shares of common stock at an exercise of
$2.50 per share, expiring on April 1, 2006. A total of
486,557 of these warrants were exercised in 2005 with the
remaining portion exercised during 2006.
In May 2004, we issued a warrant to purchase 3,000 shares
of our common stock at an exercise price of $4.75 per share
to Jeffrey R. Freedman in consideration of financial advisory
services to be provided by Mr. Freedman pursuant to a
consulting agreement. The warrants were exercised in May 2004.
Mr. Freedman was also granted 16,000 warrants in May of
2004 exercisable at $4.65 per share. These warrants were
exercised in November of 2005.
Warrants for 4,000 shares of our common stock at an
exercise price of $4.65 were also issued in May 2004 and remain
outstanding as of December 31, 2006.
NOTE 14
CONDENSED CONSOLIDATED FINANCIAL INFORMATION
Set forth on the following pages are the condensed consolidating
financial statements of (i) Allis-Chalmers Energy Inc.,
(ii) its subsidiaries that are guarantors of the senior
notes and revolving credit facility and (iii) the
subsidiaries that are not guarantors of the senior notes and
revolving credit facility (in thousands). Prior to the
acquisition of DLS, all of our subsidiaries were guarantors of
our senior notes and revolving credit facility, the parent
company had no independent assets or operations, the guarantees
were full and unconditional and joint and several.
82
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
CONDENSED
CONSOLIDATING BALANCE SHEETS
December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers
|
|
|
|
|
|
Subsidiary
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors
|
|
|
Adjustments
|
|
|
Total
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
|
|
|
$
|
37,769
|
|
|
$
|
1,976
|
|
|
$
|
|
|
|
$
|
39,745
|
|
Trade receivables, net
|
|
|
|
|
|
|
62,089
|
|
|
|
33,971
|
|
|
|
(294
|
)
|
|
|
95,766
|
|
Inventories
|
|
|
|
|
|
|
13,194
|
|
|
|
15,421
|
|
|
|
|
|
|
|
28,615
|
|
Intercompany receivables
|
|
|
67,909
|
|
|
|
|
|
|
|
|
|
|
|
(67,909
|
)
|
|
|
|
|
Note receivable from affiliate
|
|
|
5,502
|
|
|
|
|
|
|
|
|
|
|
|
(5,502
|
)
|
|
|
|
|
Prepaid expenses and other
|
|
|
5,703
|
|
|
|
10,200
|
|
|
|
733
|
|
|
|
|
|
|
|
16,636
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
79,114
|
|
|
|
123,252
|
|
|
|
52,101
|
|
|
|
(73,705
|
)
|
|
|
180,762
|
|
Property and equipment, net
|
|
|
|
|
|
|
422,297
|
|
|
|
131,961
|
|
|
|
|
|
|
|
554,258
|
|
Goodwill
|
|
|
|
|
|
|
124,331
|
|
|
|
1,504
|
|
|
|
|
|
|
|
125,835
|
|
Other intangible assets, net
|
|
|
598
|
|
|
|
32,153
|
|
|
|
89
|
|
|
|
|
|
|
|
32,840
|
|
Debt issuance costs, net
|
|
|
9,633
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,633
|
|
Note receivable from affiliates
|
|
|
12,339
|
|
|
|
|
|
|
|
|
|
|
|
(12,339
|
)
|
|
|
|
|
Investments in affiliates
|
|
|
722,202
|
|
|
|
|
|
|
|
|
|
|
|
(722,202
|
)
|
|
|
|
|
Other assets
|
|
|
257
|
|
|
|
4,719
|
|
|
|
22
|
|
|
|
|
|
|
|
4,998
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
824,143
|
|
|
$
|
706,752
|
|
|
$
|
185,677
|
|
|
$
|
(808,246
|
)
|
|
$
|
908,326
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and
Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term
debt
|
|
$
|
32
|
|
|
$
|
3,809
|
|
|
$
|
3,158
|
|
|
$
|
|
|
|
$
|
6,999
|
|
Trade accounts payable
|
|
|
31
|
|
|
|
13,510
|
|
|
|
12,125
|
|
|
|
|
|
|
|
25,666
|
|
Accrued salaries, benefits and
payroll taxes
|
|
|
|
|
|
|
2,993
|
|
|
|
7,895
|
|
|
|
|
|
|
|
10,888
|
|
Accrued interest
|
|
|
11,755
|
|
|
|
|
|
|
|
112
|
|
|
|
|
|
|
|
11,867
|
|
Accrued expenses
|
|
|
135
|
|
|
|
9,247
|
|
|
|
7,863
|
|
|
|
(294
|
)
|
|
|
16,951
|
|
Intercompany payables
|
|
|
|
|
|
|
425,610
|
|
|
|
17
|
|
|
|
(425,627
|
)
|
|
|
|
|
Note payable to affiliate
|
|
|
|
|
|
|
|
|
|
|
5,502
|
|
|
|
(5,502
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
11,953
|
|
|
|
455,169
|
|
|
|
36,672
|
|
|
|
(431,423
|
)
|
|
|
72,371
|
|
Long-term debt, net of current
maturities
|
|
|
555,750
|
|
|
|
770
|
|
|
|
4,926
|
|
|
|
|
|
|
|
561,446
|
|
Note payable to affiliate
|
|
|
|
|
|
|
|
|
|
|
12,339
|
|
|
|
(12,339
|
)
|
|
|
|
|
Deferred income tax liability
|
|
|
2,203
|
|
|
|
10,714
|
|
|
|
7,036
|
|
|
|
|
|
|
|
19,953
|
|
Other long-term liabilities
|
|
|
304
|
|
|
|
319
|
|
|
|
|
|
|
|
|
|
|
|
623
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
570,210
|
|
|
|
466,972
|
|
|
|
60,973
|
|
|
|
(443,762
|
)
|
|
|
654,393
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
83
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers
|
|
|
|
|
|
Subsidiary
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors
|
|
|
Adjustments
|
|
|
Total
|
|
|
Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock
|
|
|
282
|
|
|
|
3,526
|
|
|
|
42,963
|
|
|
|
(46,489
|
)
|
|
|
282
|
|
Capital in excess of par value
|
|
|
216,208
|
|
|
|
167,508
|
|
|
|
74,969
|
|
|
|
(242,477
|
)
|
|
|
216,208
|
|
Retained earnings
|
|
|
37,443
|
|
|
|
68,746
|
|
|
|
6,772
|
|
|
|
(75,518
|
)
|
|
|
37,443
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
253,933
|
|
|
|
239,780
|
|
|
|
124,704
|
|
|
|
(364,484
|
)
|
|
|
253,933
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stock
holders equity
|
|
$
|
824,143
|
|
|
$
|
706,752
|
|
|
$
|
185,677
|
|
|
$
|
(808,246
|
)
|
|
$
|
908,326
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED
CONSOLIDATING INCOME STATEMENTS
For the Year Ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers
|
|
|
|
|
|
Subsidiary
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors
|
|
|
Adjustments
|
|
|
Total
|
|
|
Revenues
|
|
$
|
|
|
|
$
|
237,814
|
|
|
$
|
69,490
|
|
|
$
|
|
|
|
$
|
307,304
|
|
Cost of revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs
|
|
|
|
|
|
|
130,978
|
|
|
|
50,941
|
|
|
|
|
|
|
|
181,919
|
|
Depreciation
|
|
|
|
|
|
|
16,198
|
|
|
|
4,063
|
|
|
|
|
|
|
|
20,261
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost of revenues
|
|
|
|
|
|
|
147,176
|
|
|
|
55,004
|
|
|
|
|
|
|
|
202,180
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin
|
|
|
|
|
|
|
90,638
|
|
|
|
14,486
|
|
|
|
|
|
|
|
105,124
|
|
General and administrative
|
|
|
2,643
|
|
|
|
30,651
|
|
|
|
2,242
|
|
|
|
|
|
|
|
35,536
|
|
Amortization
|
|
|
1,120
|
|
|
|
1,801
|
|
|
|
11
|
|
|
|
|
|
|
|
2,932
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
(3,763
|
)
|
|
|
58,186
|
|
|
|
12,233
|
|
|
|
|
|
|
|
66,656
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in affiliates, net
of tax
|
|
|
58,077
|
|
|
|
|
|
|
|
|
|
|
|
(58,077
|
)
|
|
|
|
|
Interest, net
|
|
|
(18,733
|
)
|
|
|
67
|
|
|
|
(597
|
)
|
|
|
|
|
|
|
(19,263
|
)
|
Other
|
|
|
45
|
|
|
|
97
|
|
|
|
(489
|
)
|
|
|
|
|
|
|
(347
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
39,389
|
|
|
|
164
|
|
|
|
(1,086
|
)
|
|
|
(58,077
|
)
|
|
|
(19,610
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
35,626
|
|
|
|
58,350
|
|
|
|
11,147
|
|
|
|
(58,077
|
)
|
|
|
47,046
|
|
Provision for income taxes
|
|
|
|
|
|
|
(7,045
|
)
|
|
|
(4,375
|
)
|
|
|
|
|
|
|
(11,420
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
35,626
|
|
|
$
|
51,305
|
|
|
$
|
6,772
|
|
|
$
|
(58,077
|
)
|
|
$
|
35,626
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
84
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOW
For the Year Ended December 31, 2006 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Chalmers
|
|
|
|
|
|
Subsidiaries
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
(Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors)
|
|
|
Adjustments
|
|
|
Total
|
|
|
Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
35,626
|
|
|
$
|
51,305
|
|
|
$
|
6,772
|
|
|
$
|
(58,077
|
)
|
|
$
|
35,626
|
|
Adjustments to reconcile net
income to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
|
|
|
|
16,198
|
|
|
|
4,063
|
|
|
|
|
|
|
|
20,261
|
|
Amortization
|
|
|
1,121
|
|
|
|
1,811
|
|
|
|
|
|
|
|
|
|
|
|
2,932
|
|
Write-off of deferred financing
fees
|
|
|
453
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
453
|
|
Stock based compensation
|
|
|
3,394
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,394
|
|
Provision for bad debts
|
|
|
|
|
|
|
781
|
|
|
|
|
|
|
|
|
|
|
|
781
|
|
Imputed interest
|
|
|
|
|
|
|
355
|
|
|
|
|
|
|
|
|
|
|
|
355
|
|
Equity earnings in affiliates
|
|
|
(58,077
|
)
|
|
|
|
|
|
|
|
|
|
|
58,077
|
|
|
|
|
|
Deferred taxes
|
|
|
(619
|
)
|
|
|
247
|
|
|
|
2,587
|
|
|
|
|
|
|
|
2,215
|
|
(Gain) on sale of equipment
|
|
|
|
|
|
|
(2,428
|
)
|
|
|
(16
|
)
|
|
|
|
|
|
|
(2,444
|
)
|
Changes in operating assets and
liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Increase) in accounts receivables
|
|
|
|
|
|
|
(23,144
|
)
|
|
|
(31
|
)
|
|
|
|
|
|
|
(23,175
|
)
|
(Increase) decrease in other
current assets
|
|
|
(2,483
|
)
|
|
|
1,121
|
|
|
|
1,230
|
|
|
|
|
|
|
|
(132
|
)
|
(Increase) decrease in other assets
|
|
|
296
|
|
|
|
101
|
|
|
|
(89
|
)
|
|
|
|
|
|
|
308
|
|
(Decrease) increase in accounts
payable
|
|
|
(82
|
)
|
|
|
3,587
|
|
|
|
(5,842
|
)
|
|
|
|
|
|
|
(2,337
|
)
|
(Decrease) increase in accrued
interest
|
|
|
11,508
|
|
|
|
(45
|
)
|
|
|
(81
|
)
|
|
|
|
|
|
|
11,382
|
|
(Decrease) increase in accrued
expenses
|
|
|
(390
|
)
|
|
|
1,633
|
|
|
|
(371
|
)
|
|
|
|
|
|
|
872
|
|
(Decrease) increase in accrued
salaries, benefits and payroll taxes
|
|
|
(1,951
|
)
|
|
|
2,780
|
|
|
|
2,563
|
|
|
|
|
|
|
|
3,392
|
|
(Decrease) increase in other
liabilities
|
|
|
(31
|
)
|
|
|
(193
|
)
|
|
|
|
|
|
|
|
|
|
|
(224
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by
operating activities
|
|
|
(11,235
|
)
|
|
|
54,109
|
|
|
|
10,785
|
|
|
|
|
|
|
|
53,659
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing
Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of businesses, net of
cash
|
|
|
(528,167
|
)
|
|
|
3,649
|
|
|
|
(2,054
|
)
|
|
|
|
|
|
|
(526,572
|
)
|
Notes receivable from affiliates
|
|
|
(585
|
)
|
|
|
|
|
|
|
|
|
|
|
585
|
|
|
|
|
|
85
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Chalmers
|
|
|
|
|
|
Subsidiaries
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
(Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors)
|
|
|
Adjustments
|
|
|
Total
|
|
|
Purchase of property and equipment
|
|
|
|
|
|
|
(33,930
|
)
|
|
|
(5,767
|
)
|
|
|
|
|
|
|
(39,697
|
)
|
Proceeds from sale of equipment
|
|
|
|
|
|
|
6,730
|
|
|
|
151
|
|
|
|
|
|
|
|
6,881
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) in
investing activities
|
|
|
(528,752
|
)
|
|
|
(23,551
|
)
|
|
|
(7,670
|
)
|
|
|
585
|
|
|
|
(559,388
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing
Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from long-term debt
|
|
|
555,000
|
|
|
|
2,820
|
|
|
|
|
|
|
|
|
|
|
|
557,820
|
|
Payments on long-term debt
|
|
|
(42,414
|
)
|
|
|
(9,875
|
)
|
|
|
(1,741
|
)
|
|
|
|
|
|
|
(54,030
|
)
|
Payments on related party debt
|
|
|
|
|
|
|
(3,031
|
)
|
|
|
|
|
|
|
|
|
|
|
(3,031
|
)
|
Net (payments) borrowings on lines
of credit
|
|
|
(6,400
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,400
|
)
|
Accounts receivable from affiliates
|
|
|
(16,444
|
)
|
|
|
|
|
|
|
|
|
|
|
16,444
|
|
|
|
|
|
Accounts payable to affiliates
|
|
|
|
|
|
|
16,427
|
|
|
|
17
|
|
|
|
(16,444
|
)
|
|
|
|
|
Note payable to affiliate
|
|
|
|
|
|
|
|
|
|
|
585
|
|
|
|
(585
|
)
|
|
|
|
|
Proceeds from issuance of common
stock
|
|
|
46,297
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
46,297
|
|
Proceeds from exercise of options
and warrants
|
|
|
6,321
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,321
|
|
Tax benefit on options
|
|
|
6,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,440
|
|
Debt issuance costs
|
|
|
(9,863
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,863
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by
financing activities
|
|
|
538,937
|
|
|
|
6,341
|
|
|
|
(1,139
|
)
|
|
|
(585
|
)
|
|
|
543,554
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash
equivalents
|
|
|
(1,050
|
)
|
|
|
36,899
|
|
|
|
1,976
|
|
|
|
|
|
|
|
37,825
|
|
Cash and cash equivalents at
beginning of year
|
|
|
1,050
|
|
|
|
870
|
|
|
|
|
|
|
|
|
|
|
|
1,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end
of period
|
|
$
|
|
|
|
$
|
37,769
|
|
|
$
|
1,976
|
|
|
$
|
|
|
|
$
|
39,745
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 15
|
RELATED
PARTY TRANSACTIONS
|
In July 2005, we entered into a lease of a yard in Buffalo,
Texas which is part owned by our former Chief Operating Officer,
David Wilde. The monthly rent was $3,500.
Until December 2004, our Chief Executive Officer and Chairman,
Munawar H. Hidayatallah and his wife were personal guarantors of
substantially all of the financing extended to us by commercial
banks. In December 2004, we refinanced most of our outstanding
bank debt and obtained the release of certain guarantees. After
the refinancing, Mr. Hidayatallah continued to guarantee
the Tubular $4.0 million subordinated seller note until
July 2005. We paid Mr. Hidayatallah an annual guarantee fee
equal to one-quarter of one percent of the total amount of the
debt guaranteed by Mr. Hidayatallah. These fees aggregated
to $7,250 during 2005 and were paid quarterly, in arrears, based
upon the average amount of debt outstanding in the prior quarter.
86
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
In April 2004, we entered into an oral consulting agreement with
Leonard Toboroff, one of our directors, pursuant to which we pay
him $12,000 per month in 2006 and $10,000 per month in
2005 to advise us regarding financing and acquisition
opportunities.
Jens Mortensen, one of our former directors, is the former owner
of Tubular and held a 19% minority interest in Tubular until
September 30, 2004. He was also the holder of a
$4.0 million subordinated note payable issued by Tubular
and at December 31, 2005 was owed $60,000 in accrued
interest and $267,000 related to a non-compete agreement. (See
Note 8). The subordinated note was repaid in January of
2006 and the accrued interest was paid in January 2006.
Mr. Mortensen, formerly the sole proprietor of Tubular,
owns a shop yard which he leases to Jens on a monthly
basis. Lease payments made under the terms of the lease were $0,
$16,800 and $28,800 for the years ended December 31, 2006,
2005 and 2004, respectively. In addition, Mr. Mortensen and
members of his family own 100% of Tex-Mex Rental &
Supply Co., a Texas corporation, that sold approximately $0, $0
and $167,000 of equipment and other supplies to Tubular for the
years ended December 31, 2006, 2005 and 2004, respectively.
DLS was acquired from three British Virgin Island corporations.
Two of our Directors; Alejandro P. Bulgheroni and Carlos A.
Bulgheroni, indirectly beneficially own substantially all of the
shares of the DLS sellers. DLS largest customer is Pan
American Energy which is a joint venture by British Petroleum
and Bridas Corporation. Alejandro P. Bulgheroni and Carlos A.
Bulgheroni, indirectly beneficially own substantially all of the
shares of the Bridas Corporation.
As described in Note 8, several of our former directors
were issued promissory notes in 2000 in lieu of compensation for
services. Our current maturities of long-term debt includes
$32,000 and $96,000 as of December 31, 2006 and 2005,
respectively, relative to these notes.
|
|
NOTE 16
|
SEGMENT
INFORMATION
|
At December 31, 2006, we had six operating segments
including: Rental Tools, International Drilling, Directional
Drilling Services, Casing and Tubing Services, Compressed Air
Drilling Services and Production Services. All of the segments
provide services to the energy industry. The revenues, operating
income (loss), depreciation and amortization, capital
expenditures and assets of each of the reporting segments plus
the Corporate function are reported below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental tools
|
|
$
|
51,521
|
|
|
$
|
5,059
|
|
|
$
|
611
|
|
International drilling
|
|
|
69,490
|
|
|
|
|
|
|
|
|
|
Directional drilling services
|
|
|
72,811
|
|
|
|
43,901
|
|
|
|
24,787
|
|
Casing and tubing services
|
|
|
50,887
|
|
|
|
20,932
|
|
|
|
10,391
|
|
Compressed air drilling services
|
|
|
43,045
|
|
|
|
25,662
|
|
|
|
11,561
|
|
Production services
|
|
|
19,550
|
|
|
|
9,790
|
|
|
|
376
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
307,304
|
|
|
$
|
105,344
|
|
|
$
|
47,726
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
87
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Operating Income
(Loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental tools
|
|
$
|
26,293
|
|
|
$
|
1,300
|
|
|
$
|
(71
|
)
|
International drilling
|
|
|
12,233
|
|
|
|
|
|
|
|
|
|
Directional drilling services
|
|
|
17,666
|
|
|
|
7,389
|
|
|
|
3,061
|
|
Casing and tubing services
|
|
|
12,544
|
|
|
|
4,994
|
|
|
|
3,217
|
|
Compressed air drilling services
|
|
|
10,810
|
|
|
|
5,612
|
|
|
|
1,169
|
|
Production services
|
|
|
2,137
|
|
|
|
(99
|
)
|
|
|
4
|
|
General corporate
|
|
|
(15,027
|
)
|
|
|
(5,978
|
)
|
|
|
(3,153
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income from operations
|
|
$
|
66,656
|
|
|
$
|
13,218
|
|
|
$
|
4,227
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and Amortization
Expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental tools
|
|
$
|
7,268
|
|
|
$
|
492
|
|
|
$
|
40
|
|
International drilling
|
|
|
4,074
|
|
|
|
|
|
|
|
|
|
Directional drilling services
|
|
|
1,464
|
|
|
|
887
|
|
|
|
466
|
|
Casing and tubing services
|
|
|
3,908
|
|
|
|
2,006
|
|
|
|
1,597
|
|
Compressed air drilling services
|
|
|
3,057
|
|
|
|
1,946
|
|
|
|
1,329
|
|
Production services
|
|
|
2,005
|
|
|
|
912
|
|
|
|
26
|
|
General corporate
|
|
|
1,417
|
|
|
|
418
|
|
|
|
120
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depreciation and
amortization expense
|
|
$
|
23,193
|
|
|
$
|
6,661
|
|
|
$
|
3,578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental tools
|
|
$
|
4,538
|
|
|
$
|
435
|
|
|
$
|
232
|
|
International drilling
|
|
|
5,770
|
|
|
|
|
|
|
|
|
|
Directional drilling services
|
|
|
5,128
|
|
|
|
2,922
|
|
|
|
1,552
|
|
Casing and tubing services
|
|
|
10,980
|
|
|
|
5,207
|
|
|
|
1,285
|
|
Compressed air drilling services
|
|
|
7,716
|
|
|
|
7,008
|
|
|
|
1,399
|
|
Production services
|
|
|
5,253
|
|
|
|
1,514
|
|
|
|
106
|
|
General corporate
|
|
|
312
|
|
|
|
681
|
|
|
|
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures
|
|
$
|
39,697
|
|
|
$
|
17,767
|
|
|
$
|
4,603
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill:
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental tools
|
|
$
|
106,132
|
|
|
$
|
|
|
|
$
|
|
|
International drilling
|
|
|
1,504
|
|
|
|
|
|
|
|
|
|
Directional drilling services
|
|
|
4,168
|
|
|
|
4,168
|
|
|
|
4,168
|
|
Casing and tubing services
|
|
|
6,464
|
|
|
|
3,673
|
|
|
|
3,673
|
|
Compressed air drilling services
|
|
|
3,950
|
|
|
|
3,950
|
|
|
|
3,510
|
|
Production services
|
|
|
3,617
|
|
|
|
626
|
|
|
|
425
|
|
General corporate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total goodwill
|
|
$
|
125,835
|
|
|
$
|
12,417
|
|
|
$
|
11,776
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
88
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental tools
|
|
$
|
453,802
|
|
|
$
|
8,034
|
|
|
$
|
1,291
|
|
International drilling
|
|
|
185,677
|
|
|
|
|
|
|
|
|
|
Directional drilling services
|
|
|
28,585
|
|
|
|
20,960
|
|
|
|
14,166
|
|
Casing and tubing services
|
|
|
74,372
|
|
|
|
45,351
|
|
|
|
21,197
|
|
Compressed air drilling services
|
|
|
54,288
|
|
|
|
46,045
|
|
|
|
29,147
|
|
Production services
|
|
|
57,954
|
|
|
|
12,282
|
|
|
|
5,806
|
|
General corporate
|
|
|
53,648
|
|
|
|
4,683
|
|
|
|
8,585
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
908,326
|
|
|
$
|
137,355
|
|
|
$
|
80,192
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
228,192
|
|
|
$
|
98,583
|
|
|
$
|
42,466
|
|
International
|
|
|
79,112
|
|
|
|
6,761
|
|
|
|
5,260
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
307,304
|
|
|
$
|
105,344
|
|
|
$
|
47,726
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Long Lived Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
574,302
|
|
|
$
|
97,390
|
|
|
$
|
55,340
|
|
International
|
|
|
153,262
|
|
|
|
4,313
|
|
|
|
474
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long lived assets
|
|
$
|
727,564
|
|
|
$
|
101,703
|
|
|
$
|
55,814
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
89
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
NOTE 17
SUPPLEMENTAL CASH FLOWS INFORMATION (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
(Restated)
|
|
|
Interest paid
|
|
$
|
8,571
|
|
|
$
|
3,924
|
|
|
$
|
2,159
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes paid
|
|
$
|
5,796
|
|
|
$
|
676
|
|
|
$
|
514
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other non-cash investing and
financing transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Insurance premiums financed
|
|
|
2,871
|
|
|
|
|
|
|
|
|
|
Purchase of equipment financed
through assumption of debt or accounts payable
|
|
|
|
|
|
|
592
|
|
|
|
|
|
Non-cash investing and
financing transactions in connection with
acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of net assets acquired
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(4,867
|
)
|
Goodwill and other intangibles
|
|
|
(4,010
|
)
|
|
|
|
|
|
|
(3,839
|
)
|
Value of common stock, issued
|
|
|
94,980
|
|
|
|
1,750
|
|
|
|
2,177
|
|
Seller financed note
|
|
|
750
|
|
|
|
|
|
|
|
|
|
Deferred tax liability
|
|
|
17,662
|
|
|
|
|
|
|
|
|
|
Accrued expenses
|
|
|
250
|
|
|
|
|
|
|
|
|
|
Value of minority interest
contribution
|
|
|
|
|
|
|
|
|
|
|
2,070
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
109,632
|
|
|
$
|
1,750
|
|
|
$
|
(4,459
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of the remaining
19% of Jens:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of net assets acquired
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(813
|
)
|
Goodwill and other intangibles
|
|
|
|
|
|
|
|
|
|
|
(3,676
|
)
|
Value of common stock issued
|
|
|
|
|
|
|
|
|
|
|
6,434
|
|
Value of minority interest
retirement
|
|
|
|
|
|
|
|
|
|
|
(1,945
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 18
LEGAL MATTERS
We are named from time to time in legal proceedings related to
our activities prior to our bankruptcy in 1988; however, we
believe that we were discharged from liability for all such
claims in the bankruptcy and believe the likelihood of a
material loss relating to any such legal proceeding is remote.
We are involved in various other legal proceedings in the
ordinary course of business. The legal proceedings are at
different stages; however, we believe that the likelihood of
material loss relating to any such legal proceeding is remote.
NOTE 19
SUBSEQUENT EVENTS
In January 2007, we closed on a private offering, to qualified
institutional buyers pursuant to Rule 144A under the
Securities Act, of $255.0 million principal amount of our
8.5% senior notes due 2017. The proceeds of the senior
notes offering, together with a portion of the proceeds of our
concurrent common stock offering, were used to repay the debt
outstanding under our $300.0 million bridge loan facility,
which we incurred to finance our acquisition of substantially
all the assets of OGR.
90
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial
Statements (Continued)
In January 2007, we closed on a public offering of
6.0 million shares of our common stock at $17.65 per
share. The proceeds of the common stock offering, together with
the proceeds of our concurrent senior notes offering, were used
to repay the debt outstanding under our $300.0 million
bridge loan facility, which we incurred to finance our
acquisition of substantially all the assets of OGR and for
general corporate purposes.
|
|
NOTE 20
|
SUMMARIZED
QUARTERLY FINANCIAL DATA (UNAUDITED) (in thousands, except per
share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Year 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
47,028
|
|
|
$
|
60,470
|
|
|
$
|
85,738
|
|
|
$
|
114,068
|
|
Operating income
|
|
|
8,633
|
|
|
|
15,871
|
|
|
|
19,054
|
|
|
|
23,098
|
|
Net income
|
|
$
|
4,423
|
|
|
$
|
9,594
|
|
|
$
|
11,252
|
|
|
$
|
10,356
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.26
|
|
|
$
|
0.53
|
|
|
$
|
0.52
|
|
|
$
|
0.41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.23
|
|
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
$
|
0.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
|
(Restated)
|
|
|
|
|
|
|
|
|
|
|
|
Year 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
19,334
|
|
|
$
|
23,588
|
|
|
$
|
28,908
|
|
|
$
|
33,514
|
|
Operating income
|
|
|
2,247
|
|
|
|
2,914
|
|
|
|
3,524
|
|
|
|
4,533
|
|
Net income
|
|
$
|
1,567
|
|
|
$
|
1,769
|
|
|
$
|
1,293
|
|
|
$
|
2,546
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.12
|
|
|
$
|
0.13
|
|
|
$
|
0.09
|
|
|
$
|
0.15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.11
|
|
|
$
|
0.12
|
|
|
$
|
0.08
|
|
|
$
|
0.14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91
|
|
ITEM 9.
|
CHANGES
AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
|
None.
|
|
ITEM 9A.
|
CONTROLS
AND PROCEDURES
|
|
|
(a)
|
Evaluation
Of Disclosure Controls And Procedures
|
Our management is responsible for establishing and maintaining
adequate internal control over financial reporting as that term
is defined in Exchange Act
Rule 13a-15(f).
Our internal control over financial reporting is a process
designed to provide reasonable assurance regarding the
reliability of our financial reporting and the preparation of
our financial statements for external purposes in accordance
with U.S. generally accepted accounting principles. Our
control environment is the foundation for our system of internal
control over financial reporting and is an integral part of our
Code of Ethics for the Chief Executive Officer, Chief Financial
Officer and Chief Accounting Officer, which sets the tone of our
company. Our internal control over financial reporting includes
those policies and procedures that (i) pertain to the
maintenance of records that, in reasonable detail, accurately
and fairly reflect our transactions and dispositions of our
assets; (ii) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of our financial
statements in accordance with generally accepted accounting
principles, and that our receipts and expenditures are being
made only in accordance with authorizations of our management
and 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 financial statements. Our evaluation did
not include companies which were acquired during fiscal year
2006, except for Specialty Rental Tools, Inc., since, under SEC
guidelines, acquisitions do not have to evaluated until twelve
months after the acquisition date.
In order to evaluate the effectiveness of our internal control
over financial reporting as of December 31, 2006, as
required by Section 404 of the Sarbanes-Oxley Act of 2002,
our management conducted an assessment, including testing, based
on the criteria set forth in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO
Framework). Because of its inherent limitations, internal
control over financial reporting may not prevent or detect
misstatements. In addition, 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.
Under the supervision and with the participation of our
management, including our Chief Executive Officer and Chief
Financial Officer, we conducted an evaluation of the
effectiveness of our internal control over financial reporting
and, based on that assessment, and concluded that, as of
December 31, 2006, our internal controls over financial
reporting are effective based on these criteria.
|
|
(b)
|
Change in
Internal Control Over Financial Reporting.
|
During the most recent fiscal quarter, there have been no
changes in our internal control over financial reporting that
have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.
Management
Report on Internal Control Over Financial
Reporting.
Our Management Report on Internal Controls Over Financial
Reporting can be found in Item 8 of this report. UHY LLP,
the Independent Registered Public Accounting Firms
attestation report on managements assessment of the
effectiveness of our internal control over financial reporting
can also be found in Item 8 of this report.
|
|
ITEM 9B.
|
OTHER
INFORMATION
|
None.
92
PART III
|
|
ITEM 10.
|
DIRECTORS
AND EXECUTIVE OFFICERS OF THE REGISTRANT
|
Pursuant to General Instructions G(3), information on
directors and executive officers of Allis-Chalmers will be filed
in an amendment to this Annual Report on
Form 10-K
or incorporated by reference from Allis-Chalmers
Definitive Proxy Statement for the 2007 annual meeting of
stockholders within 120 days of the end of our fiscal year
ending December 31, 2006.
|
|
ITEM 11.
|
EXECUTIVE
COMPENSATION
|
Pursuant to General Instructions G(3), information on
executive compensation will be filed in an amendment to this
Annual Report on
Form 10-K
or incorporated by reference from Allis-Chalmers
Definitive Proxy Statement for the 2007 annual meeting of
stockholders within 120 days of the end of our fiscal year
ending December 31, 2006.
|
|
ITEM 12.
|
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
|
Pursuant to General Instruction G(3), information on
security ownership of certain beneficial owners and management
will be filed in an amendment to this Annual Report on
Form 10-K
or incorporated by reference from Allis-Chalmers
Definitive Proxy Statement for the 2007 annual meeting of
stockholders within 120 days of the end of our fiscal year
ending December 31, 2006.
|
|
ITEM 13.
|
CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS
|
Pursuant to General Instruction G(3), information on
security ownership of certain beneficial owners and management
will be filed in an amendment to this Annual Report on
Form 10-K
or incorporated by reference from the Companys Definitive
Proxy Statement for the 2007 annual meeting of stockholders
within 120 days of the end of our fiscal year ending
December 31, 2006.
|
|
ITEM 14.
|
PRINCIPAL
ACCOUNTANT FEES AND SERVICES
|
Pursuant to General Instruction G(3), information on
principal accountant fees and services will be filed in an
amendment to this Annual Report on
Form 10-K
or incorporated by reference from the Companys Definitive
Proxy Statement for the 2007 annual meeting of stockholders
within 120 days of the end of our fiscal year ending
December 31, 2006.
PART IV
|
|
ITEM 15.
|
EXHIBITS AND
FINANCIAL STATEMENT SCHEDULES
|
(a)(1) Financial Statements
All financial statements of the Registrant as set forth under
Item 8 of this Annual Report on
Form 10-K.
(2) Financial Statement Schedules
Schedule II Valuation and Qualifying Accounts
(3) Exhibits
The exhibits listed on the Exhibit index located on page 96
of this Annual report are filed as part of this
10-K.
93
(2) Financial
Statement Schedule:
Schedule II
Valuation and Qualifying Accounts
Allis-Chalmers
Energy Inc.
Valuation
and Qualifying Accounts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions
|
|
|
|
|
|
|
Balance at
|
|
Charged to
|
|
|
|
Balance at
|
|
|
Beginning
|
|
Costs and
|
|
|
|
End of
|
Description
|
|
of Period
|
|
Expense
|
|
Deductions
|
|
Period
|
|
|
(In thousands)
|
|
Year Ended December 31,
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
|
383
|
|
|
|
781
|
|
|
|
(338
|
)
|
|
|
826
|
|
Deferred tax assets valuation
allowance
|
|
|
27,131
|
|
|
|
|
|
|
|
(27,131
|
)
|
|
|
|
|
Year Ended December 31,
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
|
265
|
|
|
|
219
|
|
|
|
(101
|
)
|
|
|
383
|
|
Deferred tax assets valuation
allowance
|
|
|
30,367
|
|
|
|
|
|
|
|
(3,236
|
)
|
|
|
27,131
|
|
Year Ended December 31,
2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
|
168
|
|
|
|
104
|
|
|
|
(7
|
)
|
|
|
265
|
|
Deferred tax assets valuation
allowance
|
|
|
38,475
|
|
|
|
|
|
|
|
(8,108
|
)
|
|
|
30,367
|
|
94
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, as amended, the registrant has
duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized on March 14, 2007.
/s/ MUNAWAR
H. HIDAYATALLAH
Munawar H. Hidayatallah
Chief Executive Officer and Chairman
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, as amended, this report has
been signed on the date indicated by the following persons on
behalf of the registrant and in the capacities indicated.
|
|
|
|
|
|
|
Name
|
|
Title
|
|
Date
|
|
/s/ MUNAWAR
H. HIDAYATALLAH
Munawar
H. Hidayatallah
|
|
Chairman and Chief Executive
Officer (Principle Executive Officer)
|
|
March 14, 2007
|
|
|
|
|
|
/s/ VICTOR
M. PEREZ
Victor
M. Perez
|
|
Chief Financial Officer
(Principal Financial Officer)
|
|
March 14, 2007
|
|
|
|
|
|
/s/ BRUCE
SAUERS
Bruce
Sauers
|
|
Chief Accounting Officer
(Principal Accounting Officer)
|
|
March 14, 2007
|
|
|
|
|
|
/s/ BURT
A. ADAMS
Burt
A. Adams
|
|
Vice Chairman, President and Chief
Operating Officer
|
|
March 14, 2007
|
|
|
|
|
|
/s/ ALI
H. M. AFDHAL
Ali
H. M. Afdhal
|
|
Director
|
|
March 14, 2007
|
|
|
|
|
|
Alejandro
P. Bulgheroni
|
|
Director
|
|
March 14, 2007
|
|
|
|
|
|
Carlos
A. Bulgheroni
|
|
Director
|
|
March 14, 2007
|
|
|
|
|
|
/s/ JEFFREY
R. FREEDMAN
Jeffrey
R. Freedman
|
|
Director
|
|
March 14, 2007
|
|
|
|
|
|
/s/ VICTOR
F. GERMACK
Victor
F. Germack
|
|
Director
|
|
March 14, 2007
|
|
|
|
|
|
/s/ JOHN
E. MCCONNAUGHY,
JR.
John
E. McConnaughy, Jr.
|
|
Director
|
|
March 14, 2007
|
|
|
|
|
|
/s/ ROBERT
E. NEDERLANDER
Robert
E. Nederlander
|
|
Director
|
|
March 14, 2007
|
|
|
|
|
|
/s/ ZANE
TANKEL
Zane
Tankel
|
|
Director
|
|
March 14, 2007
|
|
|
|
|
|
/s/ LEONARD
TOBOROFF
Leonard
Toboroff
|
|
Director
|
|
March 14, 2007
|
95
EXHIBIT INDEX
|
|
|
|
|
Exhibit
|
|
Description
|
|
|
2
|
.1
|
|
First Amended Disclosure Statement
pursuant to Section 1125 of the Bankruptcy Code, dated
September 14, 1988, which includes the First Amended and
Restated Joint Plan of Reorganization dated September 14,
1988 (incorporated by reference to Registrants Current
Report on
Form 8-K
dated December 1, 1988).
|
|
2
|
.2
|
|
Reorganization
Trust Agreement dated September 14, 1988 by and
between Registrant and John T. Grigsby, Jr., Trustee
(incorporated by reference to Exhibit D of the First
Amended and Restated Joint Plan of Reorganization dated
September 14, 1988 included in Registrants Current
Report on
Form 8-K
dated December 1, 1988).
|
|
2
|
.3
|
|
Agreement and Plan of Merger dated
as of May 9, 2001 by and among Registrant, Allis-Chalmers
Acquisition Corp. and OilQuip Rentals, Inc. (incorporated by
reference to Exhibit 2.1 to the Registrants Current
Report on
Form 8-K
filed May 15, 2001).
|
|
2
|
.4
|
|
Stock Purchase Agreement dated
February 1, 2002 by and between Registrant and Jens H.
Mortensen, Jr. (incorporated by reference to
Exhibit 10.1 to the Registrants Current Report on
Form 8-K
filed February 21, 2002).
|
|
2
|
.5
|
|
Stock Purchase Agreement dated
February 1, 2002 by and among Registrant, Energy Spectrum
Partners LP, and Strata Directional Technology, Inc.
(incorporated by reference to Exhibit 2.10 to the
Registrants Annual Report on
Form 10-K
for the year ended December 31, 2001).
|
|
2
|
.6
|
|
Stock Purchase Agreement dated
August 10, 2004 by and among Allis-Chalmers Corporation and
the investors named thereto (incorporated by reference to
Exhibit 10.37 to the Registration Statement on
Form S-1
(Registration No. 118916) filed on September 10,
2004).
|
|
2
|
.7
|
|
Amendment to Stock Purchase
Agreement dated August 10, 2004 (incorporated by reference
to Exhibit 10.38 to the Registration Statement on
Form S-1
(Registration No. 118916) filed on September 10,
2004).
|
|
2
|
.8
|
|
Addendum to Stock Purchase
Agreement dated September 24, 2004 (incorporated by
reference to Exhibit 10.55 to Registrants Current
Report on
Form 8-K
filed on September 30, 2004).
|
|
2
|
.9
|
|
Asset Purchase Agreement dated
November 10, 2004 by and among AirComp LLC, a Delaware
limited liability company, Diamond Air Drilling Services, Inc.,
a Texas corporation, and Marquis Bit Co., L.L.C., a New Mexico
limited liability company, Greg Hawley and Tammy Hawley,
residents of Texas and Clay Wilson and Linda Wilson, residents
of New Mexico (incorporated by reference to the Current Report
on
Form 8-K
filed on November 15, 2004).
|
|
2
|
.10
|
|
Purchase Agreement and related
Agreements by and among Allis-Chalmers Corporation, Chevron USA,
Inc., Dale Redman and others dated December 10, 2004
(incorporated by reference to Exhibit 10.63 to the
Registrants Current Report on
Form 8-K
filed on December 16, 2004).
|
|
2
|
.11
|
|
Stock Purchase Agreement dated
April 1, 2005, by and among Allis-Chalmers Energy Inc.,
Thomas Whittington, Sr., Werlyn R. Bourgeois and SAM and D,
LLC. (incorporated by reference to Exhibit 10.51 to the
Registrants Current Report on
Form 8-K
filed on April 5, 2005).
|
|
2
|
.12
|
|
Stock Purchase Agreement effective
May 1, 2005, by and among Allis-Chalmers Energy Inc.,
Wesley J. Mahone, Mike T. Wilhite, Andrew D. Mills and Tim
Williams (incorporated by reference to Exhibit 10.51 to the
Registrants Current Report on
Form 8-K
filed on May 6, 2005).
|
|
2
|
.13
|
|
Purchase Agreement dated
July 11, 2005 among Allis-Chalmers Energy Inc., Mountain
Compressed Air, Inc. and M-I, L.L.C. (incorporated by reference
to Exhibit 10.42 to the Registrants Current Report on
Form 8-K
filed on July 15, 2005).
|
|
2
|
.14
|
|
Asset Purchase Agreement dated
July 11, 2005 between AirComp LLC, W.T. Enterprises, Inc.
and William M. Watts (incorporated by reference to
Exhibit 10.43 to the Registrants Current Report on
Form 8-K
filed on July 15, 2005).
|
|
2
|
.15
|
|
Asset Purchase Agreement by and
between Patterson Services, Inc. and Allis-Chalmers Tubular
Services, Inc. (incorporated by reference to Exhibit 10.44
to the Registrants Current Report on
Form 8-K
filed on September 8, 2005).
|
96
|
|
|
|
|
Exhibit
|
|
Description
|
|
|
2
|
.16
|
|
Stock Purchase Agreement dated as
of December 20, 2005 between the Registrant and Joe Van
Matre (incorporated by reference to Exhibit 10.33 to the
Registrants Annual Report on
Form 10-K
for the year ended December 31, 2005).
|
|
2
|
.17
|
|
Stock Purchase Agreement, dated as
of April 27, 2006, by and among Bridas International
Holdings Ltd., Bridas Central Company Ltd., Associated Petroleum
Investors Limited, and the Registrant. (incorporated by
reference to Exhibit 2.3 to the Registrants Quarterly
Report on
Form 10-Q
for the quarter ended March 31, 2006)
|
|
2
|
.18
|
|
Stock Purchase Agreement, dated as
of October 17, 2006, by and between Allis-Chalmers
Production Services, Inc. and Randolph J. Hebert (incorporated
by reference to Exhibit 10.1 to the Registrants
Current Report on
Form 8-K
filed on October 19, 2006).
|
|
2
|
.19
|
|
Asset Purchase Agreement, dated as
of October 25, 2006, by and between Allis-Chalmers Energy
Inc. and Oil & Gas Rental Services, Inc. (incorporated
by reference to Exhibit 10.1 to the Registrants
Current Report on
Form 8-K
filed on October 26, 2006).
|
|
3
|
.1
|
|
Amended and Restated Certificate
of Incorporation of Registrant (incorporated by reference to
Exhibit 3.1 to the Registrants Annual Report on
Form 10-K
for the year ended December 31, 2001).
|
|
3
|
.2
|
|
Certificate of Designation,
Preferences and Rights of the Series A 10% Cumulative
Convertible Preferred Stock ($.01 Par Value) of
Registrant (incorporated by reference to Exhibit 3.1 to the
Registrants Current Report on
Form 8-K
filed February 21, 2002).
|
|
3
|
.3
|
|
Amended and Restated By-laws of
Registrant (incorporated by reference to Exhibit 3.3. to
the Registrants Annual Report of
Form 10-K
for the year ended December 31, 2001).
|
|
3
|
.4
|
|
Certificate of Amendment of
Certificate of Incorporation filed with the Delaware Secretary
of State on June 9, 2004 (incorporated by reference to
Exhibit 3.3 to the Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2004).
|
|
3
|
.5
|
|
Certificate of Amendment of
Certificate of Incorporation filed with the Delaware Secretary
of State on January 5, 2005 (incorporated by reference to
Exhibit 3.5 to the Registrants Current Report on
Form 8-K
filed January 11, 2005).
|
|
3
|
.6
|
|
Certificate of Amendment of
Certificate of Incorporation filed with the Delaware Secretary
of State on August 16, 2005 (incorporated by reference to
Exhibit 3.5 to the Registrants Current Report on
Form 8-K
filed August 17, 2005).
|
|
4
|
.1
|
|
Specimen Stock Certificate of
Common Stock of Registrant (incorporated by reference to
Exhibit 4.1 to the Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2004).
|
|
4
|
.2
|
|
Registration Rights Agreement
dated as of March 31, 1999, by and between Allis-Chalmers
Corporation and the Pension Benefit Guaranty Corporation
(incorporated by reference to Exhibit 10.3 to the
Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 1999).
|
|
4
|
.3
|
|
Registration Rights Agreement
dated April 2, 2004 by and between Registrant and the
Stockholder signatories thereto (incorporated by reference to
Exhibit 10.43 to Amendment No. 1 to the
Registrants Annual Report on
Form 10-K
for the year ended December 31, 2003).
|
|
4
|
.4
|
|
Registration Rights Agreement
dated as of January 29, 2007 by and among Allis-Chalmers
Energy Inc., the Guarantors named therein and the Initial
Purchasers named therein (incorporated by reference to
Exhibit 10.2 to the Registrants Current Report on
Form 8-K
filed on January 29, 2007).
|
|
4
|
.5
|
|
Registration Rights Agreement
dated as of January 18, 2006 by and among Allis-Chalmers
Energy Inc., the Guarantors named therein and the Initial
Purchasers named therein (incorporated by reference to
Exhibit 10.2 to the Registrants Current Report on
Form 8-K
filed on January 24, 2006).
|
|
4
|
.6
|
|
Registration Rights Agreement
dated as of August 14, 2006 by and among the Registrant,
the guarantors listed on Schedule A thereto and RBC Capital
Markets Corporation (incorporated by reference to
Exhibit 10.1 to the Registrants
Form 8-K
filed on August 14, 2006).
|
|
4
|
.7
|
|
Indenture dated as of
January 18, 2006 by and among the Registrant, the
Guarantors named therein and Wells Fargo Bank, N.A., as trustee
(incorporated by reference to Exhibit 4.1 to the
Registrants Current Report on
Form 8-K
filed on January 24, 2006).
|
97
|
|
|
|
|
Exhibit
|
|
Description
|
|
|
4
|
.8
|
|
First Supplemental Indenture dated
as of August 11, 2006 by and among Allis-Chalmers GP, LLC,
Allis-Chalmers LP, LLC, Allis-Chalmers Management, LP, Rogers
Oil Tool Services, Inc., the Registrant, the other Guarantors
(as defined in the Indenture referred to therein) and Wells
Fargo Bank, N.A (incorporated by reference to Exhibit 4.2
to the Registrants
Form 8-K
filed on August 14, 2006).
|
|
4
|
.9
|
|
Second Supplemental Indenture
dated as of January 23, 2007 by and among Petro-Rentals,
Incorporated, the Registrant, the other Guarantor parties
thereto and Wells Fargo Bank, N.A., as trustee (incorporated by
reference to Exhibit 10.1 to the Registrants Current
Report on
Form 8-K
filed on January 24, 2007).
|
|
4
|
.10
|
|
Indenture, dated as of
January 29, 2007, by and among the Registrant, the
Guarantors named therein and Wells Fargo Bank, N.A.
(incorporated by reference to Exhibit 4.1 to the
Registrants Current Report on
Form 8-K
filed on January 29, 2007).
|
|
4
|
.11
|
|
Form of 9.0% Senior Note due
2014 (incorporated by reference to Exhibit A to
Exhibit 4.1 to the Registrants Current Report on
Form 8-K
filed on January 24, 2006).
|
|
4
|
.12
|
|
Form of 8.5% Senior Note due
2017 (incorporated by reference to Exhibit A to
Exhibit 4.1 to the Registrants Current Report on
Form 8-K
filed on January 29, 2007).
|
|
9
|
.1
|
|
Shareholders Agreement dated
February 1, 2002 by and among Registrant and the
stockholder and warrant holder signatories thereto (incorporated
by reference to Exhibit 2.12 to the Registrants
Annual Report on
Form 10-K
for the year ended December 31, 2001).
|
|
10
|
.1
|
|
Amended and Restated Retiree
Health Trust Agreement dated September 14, 1988 by and
between Registrant and Wells Fargo Bank (incorporated by
reference to
Exhibit C-1
of the First Amended and Restated Joint Plan of Reorganization
dated September 14, 1988 included in Registrants
Current Report on
Form 8-K
dated December 1, 1988).
|
|
10
|
.2
|
|
Amended and Restated Retiree
Health Trust Agreement dated September 18, 1988 by and
between Registrant and Firstar Trust Company (incorporated by
reference to
Exhibit C-2
of the First Amended and Restated Joint Plan of Reorganization
dated September 14, 1988 included in Registrants
Current Report on
Form 8-K
dated December 1, 1988).
|
|
10
|
.3
|
|
Product Liability
Trust Agreement dated September 14, 1988 by and
between Registrant and Bruce W. Strausberg, Trustee
(incorporated by reference to Exhibit E of the First
Amended and Restated Joint Plan of Reorganization dated
September 14, 1988 included in Registrants Current
Report on
Form 8-K
dated December 1, 1988).
|
|
10
|
.4*
|
|
Allis-Chalmers Savings Plan
(incorporated by reference to Registrants Annual Report on
Form 10-K
for the year ended December 31, 1988).
|
|
10
|
.5*
|
|
Allis-Chalmers Consolidated
Pension Plan (incorporated by reference to Registrants
Annual Report on
Form 10-K
for the year ended December 31, 1988).
|
|
10
|
.6
|
|
Agreement dated as of
March 31, 1999 by and between Registrant and the Pension
Benefit Guaranty Corporation (incorporated by reference to
Exhibit 10.1 to the Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 1999).
|
|
10
|
.7
|
|
Shareholders Agreement dated
February 1, 2002 by and among Jens Oilfield Service,
Inc., a Texas corporation, Jens H. Mortensen, Jr., and
Registrant (incorporated by reference to Exhibit 2.9 to the
Registrants Annual Report on
Form 10-K
for the year ended December 31, 2001).
|
|
10
|
.8
|
|
Letter Agreement dated May 9,
2001 by and between Registrant and the Pension Benefit Guarantee
Corporation (incorporated by reference to Registrants
Quarterly Report on
Form 10-Q
for the quarter ended March 31, 2002).
|
|
10
|
.9
|
|
Termination Agreement dated
May 9, 2001 by and between Registrant, the Pension Benefit
Guarantee Corporation and others (incorporated by reference to
Registrants Current Report on
Form 8-K
filed on May 15, 2002).
|
|
10
|
.10*
|
|
Employment Agreement dated
July 1, 2003 by and between AirComp LLC and Terry Keane
(incorporated by reference to Exhibit 10.37 to the
Registrants Current Report on
Form 8-K
filed July 16, 2003).
|
98
|
|
|
|
|
Exhibit
|
|
Description
|
|
|
10
|
.11*
|
|
Employment Agreement dated as of
April 1, 2004 between Registrant and Munawar H.
Hidayatallah (incorporated by reference to Exhibit 10.47 to
the Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2004).
|
|
10
|
.12*
|
|
Employment Agreement dated as of
April 1, 2004 between Registrant and David Wilde
(incorporated by reference to Exhibit 10.48 to the
Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2004).
|
|
10
|
.13*
|
|
Employment Agreement dated
July 26, 2004 by and between the Registrant and Victor M.
Perez (incorporated by reference to Exhibit 10.36 to the
Registration Statement on
Form S-1
(Registration No. 118916) filed on September 10,
2004).
|
|
10
|
.14*
|
|
Employment Agreement dated
October 11, 2004, between the Registrant and Theodore F.
Pound III (incorporated by reference to Exhibit 10.60
to the Registrants Current Report on
Form 8-K
filed on October 15, 2004).
|
|
10
|
.15*
|
|
Employment Agreement, dated
December 18, 2006, by and between the Registrant and Burt
A. Adams (incorporated by reference to Exhibit 10.3 to the
Registrants Current Report on
Form 8-K
filed on December 19, 2006).
|
|
10
|
.16
|
|
Fifth Amendment to Credit
Agreement dated as of April 6, 2004 by and between Strata
Directional Technology, Inc., and Wells Fargo Credit Inc.
(incorporated by reference to Exhibit 10.53 to the
Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2004).
|
|
10
|
.17
|
|
Third Amendment to Credit
Agreement dated as of April 6, 2004 by and between
Jens Oilfield Service, Inc. and Wells Fargo Credit Inc.
(incorporated by reference to Exhibit 10.54 to the
Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2004).
|
|
10
|
.18
|
|
Letter Agreement dated
February 13, 2004 by and between Registrant and Morgan
Joseph & Co., Inc. (incorporated by reference to
Exhibit 10.26 to the Registration Statement on
Form S-1
(Registration No. 118916) filed on September 10,
2004).
|
|
10
|
.19
|
|
Letter Agreement dated
June 8, 2004 by and between the Registrant and Morgan
Keegan & Company, Inc. (incorporated by reference to
Exhibit 10.35 to the Registration Statement on
Form S-1
(Registration No. 118916) filed on September 10,
2004).
|
|
10
|
.20
|
|
Letter Agreement relating to Stock
Purchase Agreement dated August 5, 2004 (incorporated by
reference to Exhibit 10.39 to the Registration Statement on
Form S-1
(Registration No. 118916) filed on September 10,
2004).
|
|
10
|
.21
|
|
Amended and Restated Credit
Agreement dated as of December 7, 2004, between AirComp LLC
and Wells Fargo Bank, NA (incorporated by reference to
Exhibit 10.62 to the Registrants Current Report on
Form 8-K
filed on December 13, 2004).
|
|
10
|
.22
|
|
First Amendment to Stockholder
Agreement by and among Allis-Chalmers Energy Inc. and the
Stockholders named therein (incorporated by reference to
Exhibit 10.44 to the Registrants Current Report on
Form 8-K
filed on August 5, 2005).
|
|
10
|
.23
|
|
Purchase Agreement dated as of
January 12, 2006 by and among Allis-Chalmers Energy Inc,
the Guarantors named therein and the Initial Purchasers named
therein (incorporated by reference to Exhibit 10.1 to the
Registrants Current Report on
Form 8-K
filed on January 24, 2006).
|
|
10
|
.24
|
|
Purchase Agreement dated as of
August 8, 2006 by and between the Registrant, the
guarantors listed on Schedule B thereto and RBC Capital
Markets Corporation (incorporated by reference to
Exhibit 10.4 to the Registrants
Form 8-K
filed on August 14, 2006).
|
|
10
|
.25
|
|
Purchase Agreement dated as of
January 24, 2007 by and among Allis-Chalmers Energy Inc.,
the Guarantors named therein and the Initial Purchasers named
therein (incorporated by reference to Exhibit 10.1 to the
Registrants Current Report on
Form 8-K
filed on January 29, 2007).
|
|
10
|
.26
|
|
Amended and Restated Credit
Agreement dated as of January 18, 2006 by and among
Allis-Chalmers Energy Inc., as borrower, Royal bank of Canada,
as administrative agent and Collateral Agent, RBC Capital
Markets, as lead arranger and sole bookrunner, and the lenders
party thereto (incorporated by reference to Exhibit 10.3 to
the Registrants Current Report on
Form 8-K
filed on January 24, 2006).
|
|
10
|
.27
|
|
First Amendment to Amended and
Restated Credit Agreement dated as of August 8, 2006, by
and among the Registrant, the guarantors named thereto and Royal
Bank of Canada (incorporated by reference to Exhibit 10.3
to the Registrants
Form 8-K
filed on August 14, 2006).
|
99
|
|
|
|
|
Exhibit
|
|
Description
|
|
|
10
|
.28
|
|
Senior Unsecured Bridge Loan
Agreement, dated December 18, 2006, by and among the
Registrant, Royal Bank of Canada, as administrative agent, RBC
Capital Markets Corporation, as exclusive lead arranger and sole
bookrunner, and the guarantors and institutional lenders named
thereto (incorporated by reference to Exhibit 10.1 to the
Registrants Current Report on
Form 8-K
filed on December 19, 2006).
|
|
10
|
.29
|
|
Strategic Agreement dated
July 1, 2003 between Pan American Energy LLC Sucursal
Argentina and DLS Argentina Limited Sucursal Argentina
(incorporated by reference to Exhibit 10.13 to the
Registrants Quarterly Report on
Form 10-Q
filed on December 29, 2006).
|
|
10
|
.30
|
|
Amendment No. 1 dated
May 18, 2005 to Strategic Agreement between Pan American
Energy LLC Sucursal Argentina and DLS Argentina Limited Sucursal
Argentina (incorporated by reference to Exhibit 10.14 to
the Registrants Quarterly Report on
Form 10-Q
filed on December 29, 2006).
|
|
10
|
.31
|
|
Amendment No. 2 dated
January 1, 2006 between Pan American Energy LLC Sucursal
Argentina and DLS Argentina Limited Sucursal Argentina
(incorporated by reference to Exhibit 10.15 to the
Registrants Quarterly Report on
Form 10-Q
filed on December 29, 2006).
|
|
10
|
.32
|
|
Investor Rights Agreement, dated
December 18, 2006, by and between the Registrant and
Oil & Gas Rental Services, Inc. (incorporated by
reference to Exhibit 10.2 to the Registrants Current
Report on
Form 8-K
filed on December 19, 2006).
|
|
10
|
.33
|
|
Investors Rights Agreement dated
as of August 18, 2006 by and among the Registrant and the
investors named on Exhibit A thereto (incorporated by
reference to Exhibit 10.1 to the Registrants
Form 8-K
filed on August 14, 2006).
|
|
10
|
.34*
|
|
2003 Incentive Stock Plan
(incorporated by reference to Exhibit 4.12 to the
Registrants Current Report on
Form 8-K
filed August 17, 2005).
|
|
10
|
.35*
|
|
Form of Option Certificate issued
pursuant to 2003 Incentive Stock Plan (incorporated by reference
to Exhibit 10.41 to the Registrants Annual Report on
Form 10-K
for the year ended December 31, 2003).
|
|
10
|
.36*
|
|
2006 Incentive Plan (incorporated
by reference to Exhibit 10.1 to the Registrants
Form 8-K
filed on September 18, 2006).
|
|
10
|
.37*
|
|
Form of Employee Restricted Stock
Agreement (incorporated by reference to Exhibit 10.2 to the
Registrants
Form 8-K
filed on September 18, 2006).
|
|
10
|
.38*
|
|
Form of Employee Nonqualified
Stock Option Agreement (incorporated by reference to
Exhibit 10.3 to the Registrants
Form 8-K
filed on September 18, 2006).
|
|
10
|
.39*
|
|
Form of Employee Incentive Stock
Option Agreement (incorporated by reference to Exhibit 10.4
to the Registrants
Form 8-K
filed on September 18, 2006).
|
|
10
|
.40*
|
|
Form of Non-Employee Director
Restricted Stock Agreement (incorporated by reference to
Exhibit 10.5 to the Registrants
Form 8-K
filed on September 18, 2006).
|
|
10
|
.41*
|
|
Form of Non-Employee Director
Nonqualified Stock Option Agreement (incorporated by reference
to Exhibit 10.6 to the Registrants
Form 8-K
filed on September 18, 2006).
|
|
14
|
.1
|
|
Code of Ethics (incorporated by
reference to the
Form 8-K
filed on December 1, 2004).
|
|
16
|
.1
|
|
Letter from Gordon
Hughes & Banks LLP dated October 5, 2004, to the
Securities and Exchange Commission (incorporated by reference to
Registrants Current Report on
Form 8-K
filed on October 6, 2004).
|
|
21
|
.1
|
|
Subsidiaries of Registrant.
|
|
23
|
.1
|
|
Consent of UHY LLP.
|
|
31
|
.1
|
|
Certification of Chief Executive
Officer pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
|
|
31
|
.2
|
|
Certification of Chief Financial
Officer pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
|
|
32
|
.1
|
|
Certification of the Chief
Executive Officer and Chief Financial Officer pursuant to
18 U.S.C. 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.
|
|
|
|
* |
|
Compensation Plan or Agreement |
100