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, 2007
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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
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77056
(Zip code)
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(Address of principal executive
offices)
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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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New York 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, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
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Large
accelerated
filer o
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Accelerated
filer þ
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Non-accelerated
filer o
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Smaller
reporting
company o
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(Do not check if a smaller
reporting
company)
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
The aggregate market value of the common equity held by
non-affiliates of the registrant, computed using the closing
price of the common stock of $22.99 per share on June 30,
2007, as reported on the New York Stock Exchange, was
approximately $462,009,706 (affiliates included for this
computation only: directors, executive officers and holders of
more than 5% of the registrants common stock).
As of February 29, 2008 there were 35,130,914 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 2008 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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foam unit |
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A compressor, a booster, a mist pump and a fuel tank all mounted
together on one flat bed trailer to be used for completion,
workover and/or shallow drilling operations. Foam units are
designed to provide a small footprint and easy transport. |
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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
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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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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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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. |
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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 14
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.
ITEM 1. BUSINESS
We provide services and equipment to oil and natural gas
exploration and production companies throughout the United
States including Texas, Louisiana, New Mexico, Colorado,
Oklahoma, Mississippi, Wyoming, Arkansas, 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 Services; International
Drilling; Directional Drilling; Tubular Services; Underbalanced
Drilling 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
strategic acquisitions and organic growth. 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. Since 2001, we have completed 23 acquisitions,
including six in 2005, six in 2006 and four in 2007.
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 14.
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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 Oil Quip Rentals, Inc., or Oil Quip, and its
wholly-owned subsidiary, Mountain Compressed Air, Inc., or MCA.
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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 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 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 June 2007, we acquired Coker Directional, Inc., or Coker and
merged it with Strata.
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In July 2007, we acquired Diggar Tools, LLC, or Diggar and
merged it with Strata.
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In October 2007, we acquired Rebel Rentals, Inc. or Rebel.
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In November 2007, we acquired substantially all the assets
Diamondback Oilfield Services, Inc. or Diamondback.
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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.
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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. Current industry forecasts
suggest an increasing demand for oil and natural gas coupled
with 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 0.8% and 0.3% through 2030, respectively.
The EIA estimates that U.S. oil and natural gas production
will increase at an average annual rate of 0.4% and 0.3%
respectively.
We anticipate that oil and natural exploration and production
companies will continue to increase capital spending for their
exploration and drilling programs. According to Lehman Bros.
Survey of E&P Spending, U.S. spending in 2008 will
increase by 3.5% to $78.5 billion while international
spending will increase by 16.16% to $230.24 billion. Baker
Hughes rig count data indicates that the average total rig count
in the United States increased 92% from an average of 918 in
2000 to 1,763 as of February 29, 2008, while the average
natural gas rig count increased 97% from an average of 720 in
2000 to 1,418 as of February 29, 2008. While the number of
rigs drilling for natural gas has increased significantly since
the beginning of 1996, natural gas production has remained
relatively flat over the same period of time. This is largely a
function of increasing decline rates for natural gas wells in
the United States. The offshore Gulf of Mexico rig count,
however, decreased to 58 rigs at February 29, 2008 from 90
rigs in the comparable 2007 period due to the relocation of rigs
to the more attractive international markets. We believe that a
continued increase in capital expenditure 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, underbalanced drilling and rental services. We employ
approximately 105 full-time directional drillers, own 30
measurement-while-drilling tools and a fleet of 300 downhole
motors. 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 underbalanced drillers based on amount of
air drilling equipment with approximately 260 compressors,
boosters and foam units enabling us to provide customized
packages. 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, the Arkoma, Woodford
Shale and Anadarko Basins in Oklahoma, the Fayetteville Shale in
Arkansas, 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 Pan American Energy, Repsol-YPF, Apache Corporation, BP,
Anadarko Petroleum, Oxy, ConocoPhilips, Chesapeake Energy,
Newfield Exploration, Nexen Petroleum, XTO Energy, El Paso
Corporation, Materiales y Equipo Petroleo, or Matyep and Devon
Energy. Since 2002, we have broadened our customer base as a
result of our acquisitions, technical
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expertise and reputation for quality customer service and by
providing customers with technologically advanced equipment and
highly skilled operating personnel.
Successful execution of growth strategy. Over
the past six years, we have grown both organically and through
successful acquisitions of competing businesses. Since 2001, we
have completed 23 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.
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 in August 2006
increased our international presence and provides stable
long-term contracts. Our acquisition of Petro Rentals in October
2006 significantly enhanced our production-related services and
equipment, and our acquisition of substantially all the assets
of OGR in December 2006 expanded our Rental Services segment and
increased 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. Part of our strategy is to
further increase our international operations because they
increase our exposure to crude oil and provide opportunities for
long-term contracts.
Expand geographically to provide greater access and service
to key customer segments. We have locations in
Texas, New Mexico, Colorado, Wyoming, Arkansas, 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 and Bolivia. We
plan to continue to establish new locations in the United States
and internationally. In 2007, we expanded our presence
domestically into non-traditional geographic regions
experiencing strong growth and new drilling activity.
Prudently pursue strategic acquisitions. To
complement our organic growth, we have pursued strategic
acquisitions which we believe are accretive to earnings,
complement our products and services, provide new equipment and
technology, 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 $175.2 million in capital
expenditures to grow our business organically by investing in
new, technologically advanced equipment and by expanding our
product and service offerings. This strategy is consistent with
our belief that our customers favor modern equipment emphasizing
efficiency and safety and 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 increasing 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
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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 Services. 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 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 Services segment was established with the acquisition
of Safco in September 2004 and Delta in April 2005. We
significantly expanded our Rental Services 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. 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. Our Rental Services segment currently
operates through our subsidiary, Allis-Chalmers Rental Services
LLC.
International Drilling. We provide drilling,
completion, workover and related services for oil and natural
gas wells. Headquartered in Buenos Aires, Argentina, we operate
out of the San Jorge, Cuyan, Neuquen, Austral and Noroeste
basins of Argentina. We also offer a wide variety of other
oilfield services such as drilling fluids and completion fluids
and engineering and logistics to complement our customers
field organization.
Our International Drilling segment was established with
acquisition of DLS in August 2006 for approximately
$117.9 million. We operate a fleet of 56 rigs, including 20
drilling rigs and 35 service rigs (workover and pulling units)
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. In
2007, we placed orders for four drilling rigs and 16 service
rigs. Four of the service rigs were delivered in the fourth
quarter of 2007, while the remaining rigs are expected to be
delivered throughout the first three quarters of 2008. As of
February 29, 2008, all of our rig fleet was actively
marketed, except for one drilling rig that is presently inactive
and would require approximately $6.4 million in capital
expenditures to become operational.
Directional Drilling. 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 (MWD)
services. In 2007, we expanded our capability by completing
three acquisitions for approximately $37.3 million in
total. These were Coker (June 2007), Diggar (July 2007) and
Diamondback (November 2007). These acquisitions provided
additional directional drillers, downhole motors, and MWD tools
and enabled us to expand our presence in the Northern Rockies
and the Mid-Continent areas. We now have a team of approximately
105 full-time directional drillers and maintain an
inventory of approximately 300 drilling motors. Our
straight-hole motors offer an opportunity to capture additional
market share. We currently provide our directional drilling
services in Texas, Louisiana, Oklahoma, Colorado, Wyoming and
West Virginia.
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According to Baker Hughes, as of February 29, 2008, 46% 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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Tubular 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 tubular 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 tubular services
primarily in Texas, Louisiana and both onshore and offshore in
the Gulf of Mexico and Mexico.
We expanded our Tubular 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 tubular 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.
In April 2006 we acquired 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
expanded this segment again in October 2007 with the acquisition
of Rebel Rentals, Inc. for $7.3 million. Rebel owns an
inventory of equipment used primarily for tubing installation
services in the South Louisiana and Gulf Coast regions.
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 offshore
in the Bay of Campeche, 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, 2007, 2006 and 2005, our
Mexico operations accounted for approximately $7.9 million,
$6.5 million and $6.4 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
$2.8 million at December 31, 2007 and approximately
$3.2 million at December 31, 2006. Tubular has been
providing services to Pemex in association with Matyep since
1997.
Underbalanced Drilling. We provide compressed
air equipment, chemicals and other specialized products for
underbalanced drilling and production applications. With a
combined fleet of approximately 260 compressors, boosters and
foam units, we believe we are one of the worlds largest
providers of 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.
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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. 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.
On June 29, 2007, we sold our capillary tubing units and
related equipment for approximately $16.3 million. We
reported a gain of approximately $8.9 million. The assets
sold represented a small portion of our Production Services
segment.
We have an inventory of specialized equipment consisting of coil
tubing units in various sizes ranging from 1/4 to 2
along with nitrogen pumping and transportation equipment. We
purchased 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 was delivered at the end
of the second quarter of 2007. We also maintain a full range of
stainless and carbon steel coiled tubing and related supplies
used in the installation of the tubing. We currently provide
production services in Texas, Louisiana, Arkansas and Oklahoma.
We have ordered six additional coil tubing units ranging in size
from 1 1/4 to 2. The units are expected to be
delivered in the third and fourth quarters of 2008.
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. The market in 2007 was generally positive with some
areas of weakness and some areas of growth. Certain customers
slowed their drilling activity in 2007 in response to increased
availability of drilling rigs and volatility of natural gas
prices, while others remained very active. Activity in the
U.S. Gulf of Mexico decreased in the second half of 2007
due to the hurricane season and relocation of rigs to more
attractive international markets. Management believes demand
will generally remain stable in 2008 due to high oil and natural
gas prices and the capital expenditure plans of the exploration
and production companies, however, activity in the
U.S. Gulf of Mexico may remain low for the next year.
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 and developments in the
U.S. economy.
Customers
In 2007 and 2006, one of our customers, Pan American Energy LLC
Sucursal Argentina, or Pan American Energy, represented
approximately 20.7% and 11.7% of our consolidated revenues,
respectively. Pan America Energy is a joint venture that is
owned 60% by British Petroleum and 40% by Bridas Corporation.
Alejandro P. Bulgheroni and Carlos A. Bulgheroni, two of our
directors, may be deemed to indirectly
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beneficially own all of the outstanding capital stock of Bridas
Corporation and are members of the Management Committee of Pan
American Energy. 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. 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.
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, 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 tubular 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 underbalanced 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.
In the production 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 International Drilling 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 February 29, 2008, we had
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approximately 3,050 employees. Almost all of our
International Drilling operations are subject to collective
bargaining agreements. We believe that we maintain a
satisfactory relationship with the unions to which our
International Drilling 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. We
are responsible for the first $250,000 of claims under our
workers compensation policy and the first $100,000 of claims
under our general liability and medical insurance policies.
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.
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. Additionally, in August to October of
2007 we witnessed a decline in offshore drilling rig operations
in the Gulf of Mexico in anticipation of the hurricane season.
Many of those rigs have not returned to the U.S. Gulf and
have been relocated to the international markets. 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.
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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 or are unable to finance such
acquisitions, 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.
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.
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 are complex and time
consuming, 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 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. Furthermore, we will depend on these
entities continued performance as a source of cash flow to
service our debt obligations.
Our
acquisition of DLS has substantially changed the nature of our
operations and business.
Our acquisition of DLS, which established our International
Drilling segment, has substantially changed the nature and
geographic location of our operations and business as a result
of the character and location of our International Drilling
operations, which have substantially different operating
characteristics and are in different geographic locations from
our other businesses. Prior to the establishment of our
International Drilling segment, 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. We had no
significant operations in South America prior to acquiring DLS.
Accordingly, this acquisition has subjected and will continue to
subject us to risks inherent in operating in a foreign country
where we did not have significant prior experience. Our
International Drilling segments business consists of
14
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.
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.
Likewise, during the course of our integration of any acquired
business, 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 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 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 internal control over financial
reporting is fairly stated, 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.
15
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 2007 and 2006, one of
our customers, Pan American Energy represented 20.7% and 11.7%
of our consolidated revenues, respectively. In 2005, no single
customer generated over 10% of our revenues. Our International
Drilling segment currently relies on one customer for a majority
of its revenue. In 2007 and 2006, Pan American Energy
represented 51.0% and 45.6% of our international revenues,
respectively. 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.
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 and funded 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.
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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 our Chief Executive Officer and Chairman
Munawar H. Hidayatallah.
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.
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. With the exception of certain contracts in Argentina
and Mexico, 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.
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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.
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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For example, oil and natural gas operations of our customers
located offshore and onshore in the Gulf of Mexico and in Mexico
have been adversely affected by floods, 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 customers 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.
18
Risks
Associated With Our International Drilling 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 our International Drilling services and substantially
reduce our revenues, profitability, cash flows and/or
liquidity.
The profitability of our International Drilling 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 our
control, including:
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oil and natural gas prices and expectations about future prices;
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the demand for oil and natural 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 natural 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 our
rigs. Any significant decrease in daily rates or utilization of
our rigs could materially reduce our revenues, profitability,
cash flows
and/or
liquidity.
A
majority of our International Drilling segments revenues
are derived from one customer. The termination of the contract
with this customer could have a significant negative effect on
the revenue and results of operations from our International
Drilling segment.
A majority of our International Drilling revenues are currently
received pursuant to a strategic agreement with Pan American
Energy. Additionally, in 2007 we placed orders for 16 new
service rigs and 4 drilling rigs which will be added to this
agreement. 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 currently has an expiration date of June 30,
2011. 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 us if such breach is not cured within 20 days of notice
of the breach.
Because a majority of our International Drilling revenues are
currently generated under this agreement, our International
Drilling revenues and earnings will be materially adversely
affected if this agreement is terminated unless we are able to
enter into a satisfactory substitute arrangement. We cannot
assure you that in the event of such a termination we would be
able to enter into a substitute arrangement on terms similar to
those contained in the current agreement with Pan American
Energy.
Our
International Drillings operations and financial condition
could be affected by union activity and general labor unrest.
Additionally, our International Drillings 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 our International Drilling segment will
19
not face labor disruptions in the future or that any such
disruptions will not have a material adverse effect on our
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 our International Drilling segment to
provide additional benefits, which would increase our costs and
potentially reduce our International Drilling segments
profitability and cash flow.
Rig
upgrade, refurbishment and construction projects are subject to
risks, including delays and cost overruns, which could have an
adverse effect on our International Drilling segments
results of operations and cash flows.
Our International Drilling segment often has to make upgrade and
refurbishment expenditures for its rig fleet to comply with our
quality management and preventive maintenance system or
contractual requirements or when repairs are required in
response to an inspection by a governmental authority. We may
also make significant expenditures when rigs are moved from one
location to another. Additionally, we may make substantial
expenditures for the construction of new rigs. In 2007, we
placed orders for 16 new service rigs and 4 drilling rigs to be
placed in service during the first three quarters of 2008. 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 our
financial condition and results of operations. Additionally,
capital expenditures for rig upgrade, refurbishment or
construction projects could exceed our planned capital
expenditures, impairing our ability to service its debt
obligations.
An
oversupply of comparable rigs in the geographic markets in which
we compete could depress the utilization rates and dayrates for
our rigs and materially reduce our 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 we compete. Improvements in demand in a geographic
market may cause our 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 our rigs and materially
reduce our International Drilling segments revenues and
profitability.
20
Worldwide
political and economic developments may hurt our operations
materially.
Currently, we derive substantially all of our International
Drilling segment revenues from operations in Argentina. From
time to time, we also generate revenues from operations in
Bolivia. Our International Drilling 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 we operate;
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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
we operate; and
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acts of terrorism.
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We attempt 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 indexed to the U.S. dollar exchange rate. To the
extent possible, we seek to limit our exposure to local
currencies by matching the acceptance of local currencies to our
local expense requirements in those currencies. Although we have
done this in the past, we may not be able to take these actions
in the future, thereby exposing us to foreign currency
fluctuations that could cause our results of operations,
financial condition and cash flows to deteriorate materially.
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.
Our operations are also subject to other risks, including
foreign monetary and tax policies, expropriation,
nationalization and nullification or modification of contracts.
Additionally, our 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, we may face
governmentally imposed restrictions from time to time on its
ability to transfer funds.
Devaluation
of the Argentine peso will adversely affect our International
Drilling segments 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 our financial results, but there
is a risk that our 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 our
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
21
unemployment and greater social unrest. If instability persists,
there could be a material adverse effect on our 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.
An
increase in inflation could have a material adverse effect on
our 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 our results of operations and financial condition.
Some
of our customers may seek to cancel or renegotiate some of our
International Drilling contracts during periods of depressed
market conditions or if we experience operational
difficulties.
Substantially all of our International Drilling segments
contracts with major customers are dayrate contracts, where we
charge 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, our customers
may have the right to terminate existing contracts if we
experience 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 our drilling contracts could materially reduce our
revenues and profitability.
We are
subject to numerous governmental laws and regulations, including
those that may impose significant liability on us for
environmental and natural resource damages.
Many aspects of our International Drilling segments
operations are subject to laws and regulations that may relate
directly or indirectly to the contract drilling and well
servicing industries, including those requiring us to control
the discharge of oil and other contaminants into the environment
or otherwise relating to environmental protection. The countries
where our International Drilling segment 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 our operations. Laws and regulations protecting the
environment have become more stringent in recent years and may
in certain circumstances impose strict liability, rendering us
liable for environmental and natural resource damages without
regard to negligence or fault on our part. These laws and
regulations may expose us 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 our costs or both.
22
We are
subject to hazards customary for drilling operations, which
could adversely affect our financial performance if we are not
adequately indemnified or insured.
Substantially all of our International Drilling segments
operations are subject to hazards that are customary for oil and
natural 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 we generally obtain indemnification from 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 we are
unable to transfer such risks to customers by contract or
indemnification agreements, we generally seek protection through
insurance. However, we have a significant amount of self-insured
retention or deductible 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
us 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 we are 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 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 3,311,300 shares of our
common stock, representing approximately 9.4% of our issued and
outstanding shares as of February 29, 2008. 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.
The stockholders of OGR hold 3.2 million shares of our
common stock, representing approximately 9.1% of our issued and
outstanding shares as of February 29, 2008. Under the
investor rights agreement that we entered into in connection
with the OGR acquisition, the stockholders of OGR have the right
to designate one nominee for election to our board of directors.
As a result, the DLS sellers and OGR stockholders 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
stockholders, 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 stockholders 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.
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 securities
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 and the indentures 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 35,130,914 shares outstanding as of
February 29, 2008. At December 31, 2007, we had
reserved an additional 2,323,728 shares of common stock for
issuance under our equity compensation plans, of which
982,763 shares were issuable upon the exercise of
outstanding options with a weighted average exercise price of
$10.77 per share and 710,000 shares were issuable under
restricted stock award grants subject to performance based
vesting. 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.
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
3,311,300 shares of our common stock as of
February 29, 2008. In connection with our acquisition of
substantially all the assets of OGR, we entered into an investor
rights agreement with the stockholders of OGR, who hold
3.2 million shares of our common stock. Under these
agreements, the DLS sellers and the OGR stockholders 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.
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.
24
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, 2007, we had approximately
$514.7 million of consolidated total indebtedness
outstanding and approximately $81.6 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.
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.
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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;
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sell assets, including capital stock of our restricted
subsidiaries;
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restrict dividends or other payments by restricted subsidiaries;
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create liens;
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enter into transactions with affiliates; and
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merge or consolidate with another company.
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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.
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ITEM 1B.
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UNRESOLVED
STAFF COMMENTS
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None.
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The following table describes the location and general character
of the principal physical properties used in each of our
companys businesses as of February 29, 2008. 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.
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Business Segment
|
|
Location
|
|
Owned/Leased
|
|
Rental Services
|
|
Houston, Texas
|
|
Leased 2 locations
|
|
|
Victoria, Texas
|
|
Owned
|
|
|
Broussard, Louisiana
|
|
Leased
|
|
|
Lafayette, Louisiana
|
|
Leased
|
|
|
Morgan City, Louisiana
|
|
Owned
|
International Drilling
|
|
Buenos Aires, Argentina
|
|
Leased
|
|
|
Comodoro Rivadavia, Argentina
|
|
Owned
|
|
|
Neuquen, Argentina
|
|
Owned
|
|
|
Rincon de los Sauces, Argentina
|
|
Owned
|
|
|
Tartagal, Argentina
|
|
Owned
|
|
|
Santa Cruz, Bolivia
|
|
Leased
|
Directional Drilling
|
|
Conroe, Texas
|
|
Leased
|
|
|
Houston, Texas
|
|
Leased 2 locations
|
|
|
Oklahoma City, Oklahoma
|
|
Leased
|
|
|
Denver, Colorado
|
|
Leased
|
|
|
Casper, Wyoming
|
|
Leased
|
Tubular Services
|
|
Corpus Christi, Texas
|
|
Leased
|
|
|
Edinburg, Texas
|
|
Owned
|
|
|
Kilgore, Texas
|
|
Leased
|
|
|
Pearsall, Texas
|
|
Leased
|
|
|
Broussard, Louisiana
|
|
Leased 2 locations
|
|
|
Houma, Louisiana
|
|
Leased
|
|
|
Youngsville, Louisiana
|
|
Owned
|
|
|
Elk City, Oklahoma
|
|
Leased
|
Underbalanced Drilling
|
|
Fort Stockton, Texas
|
|
Leased
|
|
|
Grandbury, Texas
|
|
Leased
|
|
|
Houston, Texas
|
|
Leased
|
|
|
Midland, Texas
|
|
Leased
|
|
|
San Angelo, Texas
|
|
Leased
|
|
|
Sonora, Texas
|
|
Leased
|
|
|
Carlsbad, New Mexico
|
|
Leased
|
|
|
Farmington, New Mexico
|
|
Leased
|
|
|
Mt Morris, Pennsylvania
|
|
Leased
|
|
|
Grand Junction, Colorado
|
|
Leased
|
|
|
Wilburton, Oklahoma
|
|
Leased
|
Production Services
|
|
Searcy, Arkansas
|
|
Leased
|
|
|
Alvin, Texas
|
|
Leased
|
|
|
Corpus Christi, Texas
|
|
Leased
|
|
|
Longview, Texas
|
|
Leased
|
|
|
Broussard, Louisiana
|
|
1 Owned & 1 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.
27
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 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.
The A-C Reorganization Trust is being dissolved, 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 or
that the products liability trust will continue to have funds to
pay any such claims.
We have been named as a defendant in three lawsuits in
connection with our proposed merger with Bronco Drilling, Inc.
We do not believe that the suits have any merit.
28
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.
|
|
ITEM 4.
|
SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS
|
None
PART II
|
|
ITEM 5.
|
MARKET
FOR REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
|
MARKET
PRICE INFORMATION
Our common stock is traded on the New York Stock Exchange under
the symbol ALY. Prior to March 22, 2007, our
common stock was traded on the American Stock Exchange. The
following table sets forth, for periods prior to March 22,
2007, high and low sales prices from our common stock, as
reported on the American Stock Exchange and for periods since
March 22, 2007, high and low sale prices of our common
stock reported on the New York Stock Exchange.
|
|
|
|
|
|
|
|
|
Calendar Quarter
|
|
High
|
|
|
Low
|
|
|
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
|
|
2007
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
23.61
|
|
|
$
|
14.10
|
|
Second Quarter
|
|
|
24.39
|
|
|
|
15.83
|
|
Third Quarter
|
|
|
28.10
|
|
|
|
18.35
|
|
Fourth Quarter
|
|
|
19.49
|
|
|
|
14.09
|
|
Holders
As of February 29, 2008, there were approximately 1,275
holders of record of our common stock. On February 29,
2008, the closing price for our common stock reported on the New
York Stock Exchange was $12.62 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.
29
EQUITY
COMPENSATION PLAN INFORMATION
The following table provides information as of December 31,
2007 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
|
|
|
1,696,763
|
|
|
$
|
10.76
|
|
|
|
527,131
|
|
Equity compensation plans not approved by security holders
|
|
|
4,000
|
|
|
$
|
13.75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,700,763
|
|
|
$
|
10.77
|
|
|
|
527,131
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2007, 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 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 Russell 2000 and
the CoreData Services Oil and Gas Equipment and Services Index
for the period commencing January 1, 2002 and ending on
December 31, 2007. Our common stock was a component of the
Russell 2000 during the year ended December 31, 2007. 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, 2002
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 CUMULATIVE TOTAL RETURN
OF ONE OR MORE COMPANIES, PEER GROUPS, INDUSTRY INDEXES
AND/OR BROAD MARKETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ending
|
Company/Index/Market
|
|
12/31/2002
|
|
12/31/2003
|
|
12/31/2004
|
|
12/30/2005
|
|
12/29/2006
|
|
12/31/2007
|
Allis-Chalmers Energy Inc.
|
|
|
100.00
|
|
|
|
101.96
|
|
|
|
192.16
|
|
|
|
489.02
|
|
|
|
903.53
|
|
|
|
578.43
|
|
|
Oil & Gas Equipment/Svcs
|
|
|
100.00
|
|
|
|
121.99
|
|
|
|
167.42
|
|
|
|
253.03
|
|
|
|
298.70
|
|
|
|
425.38
|
|
|
Russell 2000 Index
|
|
|
100.00
|
|
|
|
145.37
|
|
|
|
170.81
|
|
|
|
176.48
|
|
|
|
206.61
|
|
|
|
196.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31
|
|
ITEM 6.
|
SELECTED
FINANCIAL DATA.
|
The following selected historical financial information for each
of the five years ended December 31, 2007, has been derived
from our audited consolidated financial statements and related
notes. Certain reclassifications have been made to the prior
years selected financial data to conform with the current
period presentation. 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,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
Statement of Operations Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
570,967
|
|
|
$
|
310,964
|
|
|
$
|
108,022
|
|
|
$
|
49,307
|
|
|
$
|
33,278
|
|
Income from operations
|
|
$
|
124,782
|
|
|
$
|
67,730
|
|
|
$
|
13,518
|
|
|
$
|
4,291
|
|
|
$
|
2,981
|
|
Net income from continuing operations
|
|
$
|
50,440
|
|
|
$
|
35,626
|
|
|
$
|
7,175
|
|
|
$
|
888
|
|
|
$
|
2,927
|
|
Net income attributed to common stockholders
|
|
$
|
50,440
|
|
|
$
|
35,626
|
|
|
$
|
7,175
|
|
|
$
|
764
|
|
|
$
|
2,271
|
|
Per Share Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.48
|
|
|
$
|
1.73
|
|
|
$
|
0.48
|
|
|
$
|
0.10
|
|
|
$
|
0.58
|
|
Diluted
|
|
$
|
1.45
|
|
|
$
|
1.66
|
|
|
$
|
0.44
|
|
|
$
|
0.09
|
|
|
$
|
0.50
|
|
Weighted average number of common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
34,158
|
|
|
|
20,548
|
|
|
|
14,832
|
|
|
|
7,930
|
|
|
|
3,927
|
|
Diluted
|
|
|
34,701
|
|
|
|
21,410
|
|
|
|
16,238
|
|
|
|
9,510
|
|
|
|
5,850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
Balance Sheet Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,053,585
|
|
|
$
|
908,326
|
|
|
$
|
137,355
|
|
|
$
|
80,192
|
|
|
$
|
53,662
|
|
Long-term debt classified as:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
$
|
6,434
|
|
|
$
|
6,999
|
|
|
$
|
5,632
|
|
|
$
|
5,541
|
|
|
$
|
3,992
|
|
Long-term
|
|
$
|
508,300
|
|
|
$
|
561,446
|
|
|
$
|
54,937
|
|
|
$
|
24,932
|
|
|
$
|
28,241
|
|
Redeemable convertible Preferred stock
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
4,171
|
|
Stockholders equity
|
|
$
|
414,329
|
|
|
$
|
253,933
|
|
|
$
|
60,875
|
|
|
$
|
35,109
|
|
|
$
|
4,541
|
|
Book value per share
|
|
$
|
11.80
|
|
|
$
|
8.99
|
|
|
$
|
3.61
|
|
|
$
|
2.58
|
|
|
$
|
1.30
|
|
|
|
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 throughout the United States, including
Texas, Louisiana, New Mexico, Colorado, Oklahoma, Mississippi,
Wyoming, Arkansas, 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 Services; International Drilling; Directional
Drilling; Tubular Services; Underbalanced Drilling 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
1,763 as of February 29, 2008, according to the Baker
Hughes rig count. Furthermore, directional and horizontal rig
counts increased from 283 as of December 31, 2002 to 817 as
of February 29, 2008, which accounted for 33% and 46% of
the total U.S. rig count, respectively. The offshore Gulf
of Mexico rig count, however, decreased to 58 rigs at
February 29, 2008 from 90 rigs one year earlier. We believe
this is due to the relocation of rigs to international markets
as a result of the high oil prices.
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.
Results
of Operations
In April 2005, we acquired all of the outstanding stock of Delta
and, in May 2005, we acquired all of the outstanding stock of
Capcoil. We report the operations of Downhole and Capcoil in our
Production Services segment and the operations of Safco and
Delta in our Rental Services segment. In July 2005, we acquired
the 45% interest of M-I in our Underbalanced Drilling
subsidiary, AirComp, making us the 100% owner of AirComp. In
addition, in July 2005, we acquired the underbalanced drilling
assets of W. T. On August 1, 2005, we acquired all of the
outstanding capital stock of Target. We included Target results
in our Directional Drilling segment because Targets
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 Services segment. In April 2006, we acquired all
of the outstanding stock of Rogers. We report the operations of
Rogers in our Tubular 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.
In June 2007, we acquired all of the outstanding stock of Coker
and in July 2007, we acquired all of the outstanding stock of
Diggar and in November 2007, we acquired substantially all of
the assets of Diamondback. We report the operations of Coker,
Diggar and Diamondback in our Directional Drilling segment. In
October 2007, we acquired all of the outstanding stock of Rebel.
We report the operations of
33
Rebel in our Tubular 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, 2007 and December 31,
2006
Our revenues for the year ended December 31, 2007 were
$571.0 million, an increase of 83.6% compared to
$311.0 million for the year ended December 31, 2006.
Revenues increased in all of our business segments due
principally to the acquisitions completed during the two year
period ended December 31, 2007, the investment in new
equipment and the opening of new operating locations. The most
significant increase in revenues was due to the acquisition of
DLS on August 14, 2006 which established our International
Drilling segment. Revenues also increased significantly at our
Rental Services segment due to the acquisition of the OGR assets
on December 18, 2006. Our Directional Drilling segment
revenues increased in the 2007 period compared to the 2006
period due to acquisitions completed in the third and fourth
quarters of 2007 which added downhole motors,
measurement-while-drilling, or MWD, tools, and directional
drilling personnel resulting in increased capacity and increased
market penetration. Revenues increased at our Underbalanced
Drilling segment due to the purchase of additional equipment,
principally new compressor packages, and expansion of operations
into new geographic regions.
Our gross margin for the year ended December 31, 2007
increased 69.9% to $178.6 million, or 31.3% of revenues,
compared to $105.1 million, or 33.8%, of revenues for the
year ended December 31, 2006. The increase in gross profit
is due to the increase in revenues in all of our business
segments. The decrease in gross profit as a percentage of
revenues is primarily due to the 151.3% increase in depreciation
expense to $50.9 million in 2007 from $20.3 million in
2006. The increase in depreciation expense is due to the
acquisition of the OGR assets, the acquisition of DLS and our
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 $58.6 million for
the year ended December 31, 2007 compared to
$35.5 million for the year ended December 31, 2006.
General and administrative expense increased due to the
acquisitions, and the hiring of additional sales, operations,
accounting and administrative personnel. As a percentage of
revenues, general and administrative expenses were 10.3% in 2007
compared to 11.4% in 2006. General and administrative expense
includes share-based compensation expense of $4.7 million
in 2007 and $3.0 million in 2006.
On June 29, 2007, we sold our capillary tubing assets that
were part of our Production Services segment. The total
consideration was approximately $16.3 million in cash. We
recognized a gain of $8.9 million related to the sale of
these assets.
Amortization expense was $4.1 million for the year ended
December 31, 2007 compared to $1.9 million for the
year ended December 31, 2006. The increase in amortization
expense is due to the amortization of intangible assets in
connection with our acquisitions.
Income from operations for the year ended December 31, 2007
totaled $124.8 million, an 84.2% increase over the
$67.7 million in income from operations for the year ended
December 31, 2006, reflecting the increase in our revenues
and gross profit, offset in part by increased general and
administrative expense and amortization expense. Our income from
operations as a percentage of revenues increased slightly to
21.9% in 2007 from 21.8% in 2006. Income from operations in the
2007 period includes an $8.9 million gain from the sale of
our capillary tubing assets in the second quarter of 2007.
Our net interest expense was $46.3 million for the year
ended December 31, 2007, compared to $20.3 million for
the year ended December 31, 2006. Interest expense
increased in 2007 due to our increased debt. In August 2006 we
issued $95.0 million of senior notes bearing interest at
9.0% to fund a portion of the acquisition of DLS. In January
2007 we issued $250.0 million of senior notes bearing
interest at 8.5% to pay off, in part, the $300.0 million
bridge loan utilized to complete the OGR acquisition and for
working capital. This bridge loan was repaid on January 29,
2007. The average interest rate on the bridge loan was
34
approximately 10.6%. Interest expense for 2007 includes the
write-off of deferred financing fees of $1.2 million
related to the repayment of the bridge loan. Interest expense
includes amortization expense of deferred financing costs of
$1.9 million and $1.5 million for 2007 and 2006,
respectively.
Our provision for income taxes for the year ended
December 31, 2007 was $28.8 million, or 36.4% of our
net income before income taxes, compared to $11.4 million,
or 24.3% of our net income before income taxes for 2006. The
increase in our provision for income taxes is attributable to
the increase in our operating income and a higher effective tax
rate. The effective tax rate in 2006 was favorably impacted by
the reversal of our valuation allowance on our deferred tax
assets. The valuation allowance was reversed due to operating
results that allowed for the realization of our deferred tax
assets.
We had net income attributed to common stockholders of
$50.4 million for the year ended December 31, 2007, an
increase of 41.6%, compared to net income attributed to common
stockholders of $35.6 million for the year ended
December 31, 2006.
The following table compares revenues and income from operations
for each of our business segments for the years ended
December 31, 2007 and December 31, 2006. Income from
operations consists of our revenues less cost of revenues,
general and administrative expenses, and depreciation and
amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
Income (Loss) from Operations
|
|
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Rental Services
|
|
$
|
121,186
|
|
|
$
|
51,521
|
|
|
$
|
69,665
|
|
|
$
|
49,139
|
|
|
$
|
26,293
|
|
|
$
|
22,846
|
|
International Drilling
|
|
|
215,795
|
|
|
|
69,490
|
|
|
|
146,305
|
|
|
|
38,839
|
|
|
|
12,233
|
|
|
|
26,606
|
|
Directional Drilling
|
|
|
96,080
|
|
|
|
76,471
|
|
|
|
19,609
|
|
|
|
18,848
|
|
|
|
17,666
|
|
|
|
1,182
|
|
Tubular Services
|
|
|
53,524
|
|
|
|
50,887
|
|
|
|
2,637
|
|
|
|
10,744
|
|
|
|
12,544
|
|
|
|
(1,800
|
)
|
Underbalanced Drilling
|
|
|
50,959
|
|
|
|
43,045
|
|
|
|
7,914
|
|
|
|
13,091
|
|
|
|
10,810
|
|
|
|
2,281
|
|
Production Services
|
|
|
33,423
|
|
|
|
19,550
|
|
|
|
13,873
|
|
|
|
10,535
|
|
|
|
2,137
|
|
|
|
8,398
|
|
General Corporate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16,414
|
)
|
|
|
(13,953
|
)
|
|
|
(2,461
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
570,967
|
|
|
$
|
310,964
|
|
|
$
|
260,003
|
|
|
$
|
124,782
|
|
|
$
|
67,730
|
|
|
$
|
57,052
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental Services. Our Rental Services revenues
were $121.2 million for the year ended December 31,
2007, an increase of 135.2% from the $51.5 million in
revenues for the year ended December 31, 2006. Income from
operations increased 86.9% to $49.1 million in 2007
compared to $26.3 million in 2006. The increase in revenue
and operating income is primarily attributable to the
acquisition of the OGR assets in December 2006. Income from
operations as a percentage of revenues decreased to 40.5% for
2007 compared to 51.0% for the prior year as a result of higher
depreciation expense associated with the OGR acquisition and
capital expenditures. Rental Services revenues and operating
income was impacted by a more competitive market environment due
to the decreased U.S. Gulf of Mexico drilling activity in
the last half of 2007 due to the hurricane season and the
departure of drilling rigs in favor of the international markets.
International Drilling. On August 14,
2006, we acquired DLS which established our International
Drilling segment. Our international drilling revenues were
$215.8 million for the year ended December 31, 2007,
an increase from the $69.5 million in revenues for the year
ended December 31, 2006. Income from operations increased
to $38.8 million in 2007 compared to $12.2 million in
2006. Income from operations as percentage of revenue increased
to 18.0% for 2007 compared to 17.6% for 2006. During 2007 we
placed orders for 16 service rigs (workover rigs and pulling
rigs) and four drilling rigs. Four of the service rigs were
delivered in the fourth quarter of 2007. We expect all the rigs
to be placed in service during the first three quarters of 2008.
Directional Drilling. Revenues for the year
ended December 31, 2007 for our Directional Drilling
segment were $96.1 million, an increase of 25.6% from the
$76.5 million in revenues for the year ended
December 31, 2006. The increase in revenues is due to the
purchase of additional MWD tools and the benefit of acquisitions
completed in the last half of 2007 which added downhole motors,
MWDs, and directional drillers. The additional equipment and
personnel enabled us to strengthen our presence in new
geographic markets and increase our market penetration. Income
from operations increased 6.7% to $18.8 million for
35
2007 from $17.7 million for 2006. Income from operations as
a percentage of revenues decreased to 19.6% for 2007 compared to
23.1% for the prior year. The decrease in our operating margin a
percentage of revenues is due to increased expenses for downhole
motor rentals and repairs, experienced primarily in the first
three quarters of 2007 prior to the recent additions to our
downhole motor fleet, increased personnel costs and increased
depreciation expense.
Tubular Services. Revenues for the year ended
December 31, 2007 for the Tubular Services segment were
$53.5 million, an increase of 5.2% from the
$50.9 million in revenues for the year ended
December 31, 2006. Revenues from domestic operations
increased to $45.6 million in 2007 from $44.4 million
in 2006 as a result of the investment in new equipment and the
acquisition of Rogers in April 2006. Revenues from Mexican
operations increased to $7.9 million in 2007 from
$6.5 million in 2006. Income from operations decreased
14.3% to $10.7 million in 2007 from $12.5 million in
2006. Income from operations as a percentage of revenues
decreased to 20.1% for 2007 compared to 24.7% for the prior
year. The results of our Tubular Services segment were impacted
by an increasingly competitive environment domestically for
casing and tubing services, exacerbated by the decline in
drilling activity in the U.S. Gulf of Mexico in the last
half of 2007, and decreased sales of power tongs in 2007
compared to 2006. While revenues from Mexican operations
increased 21.5% in 2007 compared to 2006, they were impacted in
the fourth quarter of 2007, by severe weather and flooding in
Mexico.
Underbalanced Drilling. Our Underbalanced
Drilling revenues were $51.0 million for the year ended
December 31, 2007, an increase of 18.4% compared to
$43.0 million in revenues for the year ended
December 31, 2006. Income from operations increased 21.1%
to $13.1 million in 2007 compared to income from operations
of $10.8 million in 2006. Income from operations as a
percentage of revenues increased slightly to 25.7% in 2007 from
25.1% in 2006. Our Underbalanced Drilling revenues and operating
income for the 2007 period increased compared to the 2006 period
due in part to our investment in additional equipment,
principally new compressors and new foam units.
During 2007 Underbalanced Drilling was affected by a decrease in
drilling activity in certain geographic areas by some of our
customers, offset by an increased market presence and growth in
drilling activity in other, more attractive geographic areas.
Production Services Segment. Our Production
Services revenues were $33.4 million for the year ended
December 31, 2007, compared to $19.6 million in
revenues for the year ended December 31, 2006. Income from
operations was $10.5 million in 2007 compared to income
from operations of $2.1 million in 2006. Revenues for 2007
increased compared to 2006 due primarily to our acquisition of
Petro Rentals on October 17, 2006, the addition of two coil
tubing units in the fourth quarter of 2006, one unit in the
first quarter of 2007 and one additional unit delivered at the
end of the second quarter of 2007, offset in part by the sale of
our capillary tubing assets in June 2007. The increase in income
from operations can be attributed to an $8.9 million gain
on sale of our capillary tubing assets. During 2007 our
Production Services segment experienced delays in the delivery
and activation of new coil tubing units. As a result, we
experienced low utilization for our coil tubing units and
increases in personnel expenses, including increased lodging,
relocation and training expenses for the crews without the
benefit of corresponding increases in revenues.
Comparison
of Years Ended December 31, 2006 and December 31,
2005
Our revenues for the year ended December 31, 2006 was
$311.0 million, an increase of 187.9% compared to
$108.0 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 Services
segment due to the acquisition of Specialty effective
January 1, 2006. Our Tubular 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 Underbalanced Drilling segment due to the purchase of
additional equipment and improved pricing for our services. Our
Directional Drilling segment revenues
36
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 MWD tools and the
purchase of additional down-hole motors and MWDs which increased
our capacity and market presence.
Our gross margin for the year ended December 31, 2006
increased 243.8% to $105.1 million, or 33.8% of revenues,
compared to $30.6 million, or 28.3%, 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 11.4% in 2006 compared to 14.4% 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 $1.9 million for the year ended
December 31, 2006 compared to $1.5 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.
Income from operations for the year ended December 31, 2006
totaled $67.7 million, a 401.0% increase over the
$13.5 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 21.8% 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 $20.3 million for the year
ended December 31, 2006, compared to $4.7 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
37
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 January 29, 2007 and
the remaining $1.2 million of financing fees were 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 Services
|
|
$
|
51,521
|
|
|
$
|
5,059
|
|
|
$
|
46,462
|
|
|
$
|
26,293
|
|
|
$
|
1,300
|
|
|
$
|
24,993
|
|
International Drilling
|
|
|
69,490
|
|
|
|
|
|
|
|
69,490
|
|
|
|
12,233
|
|
|
|
|
|
|
|
12,233
|
|
Directional Drilling
|
|
|
76,471
|
|
|
|
46,579
|
|
|
|
29,892
|
|
|
|
17,666
|
|
|
|
7,389
|
|
|
|
10,277
|
|
Tubular Services
|
|
|
50,887
|
|
|
|
20,932
|
|
|
|
29,955
|
|
|
|
12,544
|
|
|
|
4,994
|
|
|
|
7,550
|
|
Underbalanced Drilling
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13,953
|
)
|
|
|
(5,678
|
)
|
|
|
(8,275
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
310,964
|
|
|
$
|
108,022
|
|
|
$
|
202,942
|
|
|
$
|
67,730
|
|
|
$
|
13,518
|
|
|
$
|
54,212
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental Services Segment. Our rental services
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.
Directional Drilling Segment. Revenues for the
year ended December 31, 2006 for our Directional Drilling
segment were $76.5 million, an increase of 64.2% from the
$46.6 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 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
38
Tubular Services Segment. Revenues for the
year ended December 31, 2006 for the Tubular 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.
Underbalanced Drilling Segment. Our
underbalanced 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 underbalanced 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-Rental and the addition of two coil tubing units in the
fourth quarter of 2006.
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 $43.7 million at
December 31, 2007 compared to $39.7 million at
December 31, 2006.
Operating
Activities
In the year ended December 31, 2007, we generated
$103.5 million in cash from operating activities. Net
income for the year ended December 31, 2007 was
$50.4 million. Non-cash additions to net income totaled
$60.6 million in the 2007 period consisting primarily of
$55.0 million of depreciation and amortization,
$4.9 million related to the expensing of stock options as
required under SFAS No. 123R, $8.0 million of
deferred income tax, $730,000 for a provision for bad debts and
$3.2 million of amortization and write-off of deferred
financing fees, partially offset by $2.3 million of gain
from the disposition of equipment and a $8.9 million gain
from the sale of capillary assets.
During the year ended December 31, 2007, changes in working
capital used $7.6 million in cash, principally due to an
increase of $30.8 million in accounts receivable, an
increase of $4.5 million in other assets and an increase in
inventories of $5.4 million, offset by a decrease of
$8.2 million in other current assets, an increase of
$10.7 million in accounts payable, an increase of
$6.0 million in accrued interest, an increase of
$4.0 million in accrued employee benefits and payroll
taxes, an increase of $1.5 million in accrued expenses and
an increase in other long-term liabilities of $2.7 million.
Our accounts receivables increased at December 31, 2007
primarily due to the increase in our revenues in 2007. Other
assets increase primarily due to the contract costs related to
the deployment of new rigs for our International Drilling
segment. The decrease in other current assets is principally due
to the collection of the working capital adjustment from the OGR
acquisition for approximately $7.1 million in the first
quarter of 2007. Accrued interest increased at December 31,
2007 due principally to interest accrued on our 8.5% senior
notes issued in January 2007 and our 9.0% senior notes
issued in August 2006 which are both payable semi-annually. Our
accounts payable, accrued employee benefits and payroll taxes
and other accrued expenses increased primarily due to the
39
increase in costs due to our growth in revenues and acquisition
completed in 2007. Other long-term liabilities increased
primarily due to the deferral of contract revenue related to our
new rigs being constructed in the International drilling segment.
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
$27.6 million in the 2006 period consisting primarily of
$22.1 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
$1.5 million for amortization of finance fees, including
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, an
increase of $2.6 million in inventories, a decrease of
$2.3 million in accounts payable, offset in part by a
decrease in other current assets of $2.5 million, 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 are
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 $6.4 million of
depreciation and amortization, $488,000 of minority interest in
the income of a subsidiary, $962,000 in amortization and
write-off of financing fees in conjunction with a refinancing
and $219,000 for a provision for bad debts, partially offset by
$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 $3.1 million in inventories, 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 a decrease in other current assets of $929,000, 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. 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.
Investing
Activities
During the year ended December 31, 2007, we used
$137.1 million in investing activities consisting of four
acquisitions and our capital expenditures. During the year ended
December 31, 2007, we completed the following acquisitions
for a total net cash outlay of $41.0 million, consisting of
the purchase price and acquisition costs less cash acquired:
|
|
|
|
|
In June 2007, we acquired Coker for a purchase price of
approximately $3.6 million in cash and a promissory note
for $350,000.
|
|
|
|
In July 2007, we acquired Diggar for a purchase price of
approximately $6.7 million in cash, the payment of
approximately $2.8 million of debt and a promissory note
for $750,000.
|
|
|
|
In October 2007, we acquired Rebel for a purchase price of
approximately $5.0 million in cash, the payment of
approximately $1.8 million of debt and escrow and
promissory notes for an aggregate of $500,000.
|
|
|
|
In November 2007, we acquired substantially all of the assets of
Diamondback for a purchase price of approximately
$23.1 million in cash.
|
40
In addition we made capital expenditures of approximately
$113.2 million during the year ended December 31,
2007, including $34.9 million to increase our inventory of
equipment and replace
lost-in-hole
equipment in the Rental Services segment, $28.9 million to
purchase, improve and replace equipment in our International
Drilling segment, $11.2 million to purchase equipment for
our Directional Drilling segment, $17.4 million to purchase
and improve equipment in our Underbalanced Drilling segment,
$9.3 million to purchase and improve our Tubular Services
equipment and approximately $10.7 million to expand our
Production Services segment. We received proceeds of
$16.3 million from the sale of our capillary assets. We
also received $12.8 million from the sale of assets during
the year ended December 31, 2007, comprised mostly from
equipment
lost-in-hole
from our Rental Services segment ($11.0 million) and our
Directional Drilling segment ($1.4 million). We also made
advance payments of $11.5 million on the purchase of new
drilling and service rigs to be delivered in 2008 for our
International Drilling segment.
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:
|
|
|
|
|
Effective January 1, 2006, we acquired Specialty for a
purchase price of approximately $95.3 million in cash.
|
|
|
|
Effective April 1, 2006, we acquired Rogers for a purchase
price of approximately $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
approximately $93.7 million in cash, 2.5 million
shares of our common stock and the assumption of
$9.1 million of indebtedness.
|
|
|
|
On October 16, 2006, we acquired Petro Rentals for a
purchase price of approximately $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 Services 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 segment, $7.7 million to purchase and improve
equipment in our Underbalanced Drilling segment,
$11.0 million to purchase and improve our tubular services
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 Services 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
approximately $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
approximately $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.
|
41
|
|
|
|
|
Effective August 1, 2005, we acquired Target for a purchase
price of approximately $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 segment, $7.0 million to purchase and
improve equipment in our Underbalanced Drilling segment,
$5.2 million to purchase and improve our tubular services
equipment and approximately $1.5 million to expand our
Production 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
Services segment ($408,000).
Financing
Activities
During the year ended December 31, 2007, financing
activities provided a net of $37.6 million in cash. We
received $250.0 million in borrowings from the issuance of
our 8.5% senior notes due 2017. We also received
$100.1 million in net proceeds from the issuance of
6,000,000 shares of our common stock, $1.7 million on
the tax benefit of stock compensation plans and
$3.3 million from the proceeds of warrant and option
exercises for 882,624 shares of our common stock. The
proceeds were used to repay long-term debt totaling
$309.7 million and to pay $7.8 million in debt
issuance costs. The repayment of long-term debt consisted
primarily of the repayment of our $300.0 million bridge
loan which was used to fund the acquisition of the OGR assets.
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 the OGR assets. 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.
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 December 18, 2006, we closed on a $300.0 million
senior unsecured bridge loan. The bridge loan was due
18 months after closing and had 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.
In January 2007, we closed on a private offering, to qualified
institutional buyers pursuant to Rule 144A under the
Securities Act, of $250.0 million principal amount of
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,
42
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.
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 agreement are secured by
substantially all of our assets excluding the DLS assets, but
including 2/3 of our shares of DLS. On April 26, 2007, we
entered into a Second Amended and Restated Credit Agreement,
which increased our revolving line of credit to
$62.0 million, and has a final maturity date of
April 26, 2012. On December 3, 2007, we entered into a
First Amendment to Second Amended and Restated Credit Agreement,
which increased our revolving line of credit to
$90.0 million. The amended and restated credit 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 amended
and restated credit agreement are secured by substantially all
of our assets located in the United States. At December 31,
2007 and 2006, no amounts were borrowed on the facility but
availability is reduced by outstanding letters of credit of
$8.4 million and $9.7 million, respectively.
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 6.7% and 7.0% at
December 31, 2007 and 2006, respectively. The bank loans
are denominated in U.S. dollars and the outstanding amount
due as of December 31, 2007 and 2006 was $4.9 million
and $7.3 million, respectively.
As part of the acquisition of MCA in 2001, we issued a note to
the sellers of MCA 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, 2007 and 2006 the outstanding amounts due were
$0 and $150,000, 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. 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 Coker, we
issued to the seller a note in the amount of $350,000. The note
bears interest at 8.25% and is due June 29, 2008. In
connection with the purchase of Diggar, we issued to the seller
a note in the amount of $750,000. The note bears interest at
6.0% and is due July 26, 2008. In connection with the
purchase of Rebel, we issued to the sellers notes in the amount
of $500,000. The notes bear interest at 5.0% and are due
October 23, 2008.
In connection with the purchase of Tubular, we agreed to pay a
total of $1.2 million to the seller in exchange for a
non-compete agreement. Monthly payments of $20,576 were due
under this agreement through January 31, 2007. In
connection with the purchase of Safco-Oil Field Products, Inc.,
or Safco, we also agreed to pay a total of $150,000 to the
sellers in exchange for a non-compete agreement. We were
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, 2007 and 2006 were $110,000 and $270,000,
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, 2007 and
2006, the principal and accrued interest on these notes totaled
approximately $32,000.
We have various rig and equipment financing loans with interest
rates ranging from 7.8% to 8.7% and terms of 2 to 5 years.
As of December 31, 2007 and 2006, the outstanding balances
for rig and equipment
43
financing loans were $595,000 and $3.5 million,
respectively. In January 2006, we prepaid $350,000 of the
outstanding equipment loans with proceeds from our senior notes
offering.
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. In April 2007
and August 2007, we obtained insurance premium financings in the
amount of $3.2 million and $1.3 with fixed interest rates
of 5.9% and 5.7%, respectively. Under terms of the agreements,
amounts outstanding are paid over 11 month repayment
schedules. The outstanding balance of these notes was
approximately $1.7 million as of December 31, 2007.
We also have various capital leases with terms that expire in
2008. As of December 31, 2007 and 2006, amounts outstanding
under capital leases were $14,000 and $414,000, respectively.
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, 2007.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments by Period
|
|
|
|
|
|
|
Less Than
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1 Year
|
|
|
1-3 Years
|
|
|
3-5 Years
|
|
|
After 5 Years
|
|
|
|
(In thousands)
|
|
|
Contractual Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
514,720
|
|
|
$
|
6,420
|
|
|
$
|
2,950
|
|
|
$
|
350
|
|
|
$
|
505,000
|
|
Capital leases
|
|
|
14
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest payments on long-term debt
|
|
|
334,018
|
|
|
|
44,588
|
|
|
|
88,577
|
|
|
|
88,406
|
|
|
|
112,447
|
|
Operating leases
|
|
|
5,941
|
|
|
|
2,618
|
|
|
|
2,354
|
|
|
|
593
|
|
|
|
376
|
|
Employment contracts
|
|
|
7,511
|
|
|
|
3,543
|
|
|
|
3,968
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual cash obligations
|
|
$
|
862,204
|
|
|
$
|
57,183
|
|
|
$
|
97,849
|
|
|
$
|
89,349
|
|
|
$
|
617,823
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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We have identified capital expenditure projects that will
require up to approximately $140.0 million in 2008,
exclusive of any acquisitions, of which $82.7 million is
committed as of December 31, 2007. 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
On January 23, 2008, we entered into an Agreement and Plan
of Merger with Bronco Drilling Company, Inc., or Bronco, whereby
Bronco will become a wholly-owned subsidiary of Allis-Chalmers.
The merger agreement, which was approved by our Board of
Directors and the Board of Directors of Bronco, provides that
the Bronco stockholders will receive aggregate merger
consideration with a value of approximately $437.8 million,
consisting of (a) $280.0 million in cash and
(b) shares of our common stock, par value $0.01 per share,
having an aggregate value of approximately $157.8 million.
The number of shares of our common stock to be issued will be
based on the average closing price of our common stock for the
ten-trading day period ending
44
two days prior to the closing. Completion of the merger is
conditioned upon, among other things, adoption of the merger
agreement by Broncos stockholders and approval by our
stockholders of the issuance of shares of our common stock to be
used as merger consideration.
In order to finance some or all of the cash component of the
merger consideration, the repayment of outstanding Bronco debt
and transaction expenses, we expect to incur debt of up to
$350.0 million. We intend to obtain up to
$350.0 million from either (1) a permanent debt
financing of up to $350.0 million or (2) if the
permanent debt financing cannot be consummated prior to the
closing date of the merger, the draw down under a senior
unsecured bridge loan facility in an aggregate principal amount
of up to $350.0 million to be arranged by RBC Capital
Markets Corporation and Goldman Sachs Credit Partners L.P.,
acting as joint lead arrangers and joint bookrunners. We
executed a commitment letter, dated January 28, 2008, with
Royal Bank of Canada and Goldman Sachs who have each, subject to
certain conditions, severally committed to provide 50% of the
loans under the senior unsecured bridge facility to us. This
commitment for the bridge loan facility will terminate on
July 31, 2008, if we have not drawn the bridge facility by
such date and the merger is not consummated by such date. The
commitment may also terminate prior to July 31, 2008, if
the merger is abandoned or a material condition to the merger is
not satisfied or we breach our obligations under the commitment
letter. We may use the proceeds of the bridge facility to
finance the cash component of the merger consideration, repay
outstanding Bronco debt and pay transaction expenses.
On January 29, 2008, Burt A. Adams resigned as our
President and Chief Operating Officer, effective
February 28, 2008. Mr. Adams will remain as a member
of our Board of Directors. On January 29, 2008, Mark C.
Patterson was elected our Senior Vice-President Rental
Services. On January 29, 2008, Terrence P. Keane was
elected our Senior Vice-President Oilfield Services.
On January 31, 2008, we entered into an agreement with BCH
Ltd., or BCH, to invest $40.0 million in cash in BCH in the
form of a 15% Convertible Subordinated Secured debenture.
The debenture is convertible, at any time, at our option into
49% of the common equity of BCH. At the end of two years, we
have the option to acquire the remaining 51% of BCH from its
parent, BrazAlta Resources Corp., or BrazAlta, based on an
independent valuation from a mutually acceptable investment
bank. BCH is a Canadian-based oilfield services company engaged
in contract drilling operations exclusively in Brazil.
On February 15, 2008, through our DLS subsidiary in
Argentina, we entered into a $25.0 million import finance
facility with a bank. Borrowings under this facility will be
used to fund a portion of the purchase price of the new drilling
and service rigs ordered for our international drilling
operation. The facility is available for borrowings until
December 31, 2008. Each drawdown shall be repaid over four
years in equal semi-annual instalments beginning one year after
each disbursement with the final principal payment due not later
than March 15, 2013. Interest is payable every six months.
The import finance facility is unsecured and contains customary
events of default and financial covenants and limits DLS
ability to incur additional indebtedness, make capital
expenditures, create liens and sell assets.
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 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
45
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, or
daywork, and per job contractual rates and recognize the
drilling related revenue as the work progresses and when
collectibility is reasonably assured. Revenue from daywork
contracts is recognized when it is realized or realizable and
earned. On daywork contracts, revenue is recognized based on the
number of days completed at fixed rates stipulated by the
contract. For certain contracts, we receive lump-sum and other
fees for equipment and other mobilization costs. Mobilization
fees and the related costs are deferred and amortized over the
contract terms when material. 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, 2007, we have recorded approximately
$138.4 million of goodwill and $35.2 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. 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
46
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. We provide for uncertain tax
positions pursuant to FASB Interpretation No. 48,
Accounting for Uncertainty in Income Taxes an
Interpretation of FASB Statement No. 109.
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 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. Subsequently, the FASB provided for a
one-year deferral of the provisions of Statement No. 157
for non-financial assets and liabilities that are recognized or
disclosed at fair value in the consolidated financial statements
on a non-recurring basis. 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 December 2007, the FASB issued SFAS No. 141(R),
Business Combinations. This statement retains the
fundamental requirements in SFAS No. 141,
Business Combinations that the acquisition method of
accounting be used for all business combinations and expands the
same method of accounting to all transactions and other events
in which one entity obtains control over one or more other
businesses or assets at the acquisition date and in subsequent
periods. This statement replaces SFAS No. 141 by
requiring measurement at the acquisition date of the fair value
of assets acquired, liabilities assumed and any non-controlling
interest. Additionally, SFAS No. 141(R) requires that
acquisition-related costs, including restructuring costs, be
recognized as expense separately from the acquisition.
SFAS No. 141(R) applies prospectively to business
combinations for fiscal years beginning after December 15,
2008. We will adopt SFAS No. 141(R) beginning
January 1, 2009 and apply to future acquisitions.
In February 2007, the FASB issued Statement No. 159, The
Fair Value Option for Financial Assets and Financial
Liabilities, which permits entities to elect to measure many
financial instruments and certain other items at fair value.
Upon adoption of SFAS No. 159, an entity may elect the
fair value option for eligible items that exist at the adoption
date. Subsequent to the initial adoption, the election of the
fair value option should only be made at the initial recognition
of the asset or liability or upon a re-measurement event that
gives rise to the new-basis of accounting. All subsequent
changes in fair value for that instrument are reported in
earnings. SFAS No. 159 does not affect any existing
accounting literature that requires certain assets and
liabilities to be recorded at fair value nor does it eliminate
disclosure requirements included in other accounting standards.
SFAS No. 159 is effective as of the beginning of each
reporting entitys first fiscal year that begins after
November 15, 2007. We are currently evaluating the
provisions of SFAS No. 159 and have not yet determined
the impact, if any, on our financial statements.
In December 2007, the FASB issued SFAS No. 160,
Non-controlling Interests in Consolidated Financial
Statements an amendment of ARB No. 51.
SFAS No. 160 requires (i) that non-controlling
(minority) interests be reported as a component of
shareholders equity, (ii) that net income
attributable to the parent and to the non-controlling interest
be separately identified in the consolidated statement of
operations, (iii) that changes in a parents ownership
interest while the parent retains its controlling interest be
accounted for as
47
equity transactions, (iv) that any retained non-controlling
equity investment upon the deconsolidation of a subsidiary be
initially measured at fair value, and (v) that sufficient
disclosures are provided that clearly identify and distinguish
between the interests of the parent and the interests of the
non-controlling owners. SFAS No. 160 is effective for
annual periods beginning after December 15, 2008 and should
be applied prospectively. The presentation and disclosure
requirements of the statement shall be applied retrospectively
for all periods presented. We believe the adoption of
SFAS No. 160 will not have a material impact on our
financial position or results of operations.
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 $90.0 million revolving line
of credit with a maturity of January 2010. At December 31,
2007, no amounts were borrowed on the facility but availability
is reduced by outstanding letters of credit of
$8.4 million. We do not guarantee obligations of any
unconsolidated entities.
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ITEM 7A.
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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, 2007, we were exposed to interest rate
fluctuations on approximately $4.9 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
$49,000. 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, 2007, we had $31.1 million invested in
short-term maturing investments.
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 years ended
December 31, 2007 and 2006, we had a net foreign exchange
loss of $128,000 and $515,000, respectively 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.
48
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ITEM 8.
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FINANCIAL
STATEMENTS.
|
INDEX TO
FINANCIAL STATEMENTS
ALLIS-CHALMERS
ENERGY INC. AND SUBSIDIARIES
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Page
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50
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51
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53
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54
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55
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56
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57
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92
|
|
49
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, 2007, based on criteria in Internal
Control-Integrated Framework issued by the COSO. The
effectiveness of Allis-Chalmers internal control over financial
reporting as of December 31, 2007 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.
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By:
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/s/ Munawar H. Hidayatallah
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By:
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/s/ Victor M. Perez
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Munawar H. Hidayatallah
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Victor Perez
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Chief Executive Officer
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Chief Financial Officer
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50
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, 2007 and 2006, and
the related consolidated statements of operations,
stockholders equity and cash flows for each of the three
years in the period ended December 31, 2007. These
consolidated financial statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these consolidated financial statements and financial
statement schedule based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the 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 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, 2007 and 2006, and the
consolidated results of their operations and their cash flows
for each of the three years in the period ended
December 31, 2007, in conformity with accounting principles
generally accepted in the United States of America. Also, in our
opinion, the related financial statement schedule, when
considered in relation to the basic financial statements taken
as a whole, presents fairly in all material respects the
information set forth therein.
As discussed in Note 6 to the consolidated financial
statements, effective January 1, 2007, the Company adopted
FASB Interpretations No. 48: Accounting for Uncertainty
in Income Taxes an Interpretation of FASB Statement
No. 109 and, as discussed in Note 1, effective
January 1, 2006, the Company adopted Statement of Financial
Accounting Standards No. 123 (Revised 2004): Share Based
Payment.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States),
Allis-Chalmers Energy Inc.s internal control over
financial reporting as of December 31, 2007, based on
criteria established in Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO), and our report dated March 6,
2008 expressed an unqualified opinion thereon.
/s/ UHY LLP
Houston, Texas
March 6, 2008
51
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and
Stockholders of Allis-Chalmers Energy Inc.:
We have audited Allis-Chalmers Energy Inc.s internal
control over financial reporting as of December 31, 2007,
based on criteria established in Internal Control-Integrated
Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO criteria).
Allis-Chalmers Energy Inc.s management is responsible for
maintaining effective internal control over financial reporting,
and for its assessment of the effectiveness of internal control
over financial reporting included in the accompanying
Managements Report on Internal Control Over Financial
Reporting. Our responsibility is to express an opinion on 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, assessing the risk
that a material weakness exists, testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk, and performing such other procedures as we
considered necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles and that receipts and expenditures of the company are
being made only in accordance with authorizations of management
and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, Allis-Chalmers Energy Inc. and subsidiaries
maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2007, based on
the COSO criteria.
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, 2007 and 2006, and the
related consolidated statements of operations,
stockholders equity, and cash flows for each of the three
years in the period ended December 31, 2007, and our report
dated March 6, 2008 expressed an unqualified opinion
thereon.
/s/ UHY LLP
Houston, Texas
March 6, 2008
52
ALLIS-CHALMERS
ENERGY INC.
CONSOLIDATED
BALANCE SHEETS
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December 31,
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2007
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2006
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(In thousands, except
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for share and per share
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amounts)
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ASSETS
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Cash and cash equivalents
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$
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43,693
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$
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39,745
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Trade receivables, net of allowance for doubtful accounts of
$1,924 and
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|
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$826 at December 31, 2007 and 2006, respectively
|
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130,094
|
|
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95,766
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Inventories
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32,209
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28,615
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Prepaid expenses and other
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11,898
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16,636
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|
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|
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Total current assets
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217,894
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180,762
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Property and equipment, at cost net of accumulated depreciation
of $77,008 and $29,743 at December 31, 2007 and 2006,
respectively
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626,668
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554,258
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Goodwill
|
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138,398
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|
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125,835
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|
Other intangible assets, net of accumulated amortization of
$6,218 and $4,475 at December 31, 2007 and 2006,
respectively
|
|
|
35,180
|
|
|
|
32,840
|
|
Debt issuance costs, net of accumulated amortization of $2,718
and $1,501 at December 31, 2007 and 2006, respectively
|
|
|
14,228
|
|
|
|
9,633
|
|
Other assets
|
|
|
21,217
|
|
|
|
4,998
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,053,585
|
|
|
$
|
908,326
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current maturities of long-term debt
|
|
$
|
6,434
|
|
|
$
|
6,999
|
|
Trade accounts payable
|
|
|
37,464
|
|
|
|
25,666
|
|
Accrued salaries, benefits and payroll taxes
|
|
|
15,283
|
|
|
|
10,888
|
|
Accrued interest
|
|
|
17,817
|
|
|
|
11,867
|
|
Accrued expenses
|
|
|
20,545
|
|
|
|
16,951
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
97,543
|
|
|
|
72,371
|
|
Deferred income tax liability
|
|
|
30,090
|
|
|
|
19,953
|
|
Long-term debt, net of current maturities
|
|
|
508,300
|
|
|
|
561,446
|
|
Other long-term liabilities
|
|
|
3,323
|
|
|
|
623
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
639,256
|
|
|
|
654,393
|
|
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; 35,116,035 issued and outstanding at
December 31, 2007 and 28,233,411 issued and outstanding at
December 31, 2006)
|
|
|
351
|
|
|
|
282
|
|
Capital in excess of par value
|
|
|
326,095
|
|
|
|
216,208
|
|
Retained earnings
|
|
|
87,883
|
|
|
|
37,443
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
414,329
|
|
|
|
253,933
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
1,053,585
|
|
|
$
|
908,326
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated
Financial Statements.
53
ALLIS-CHALMERS
ENERGY INC.
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except per
|
|
|
|
share amounts)
|
|
|
Revenues
|
|
$
|
570,967
|
|
|
$
|
310,964
|
|
|
$
|
108,022
|
|
Cost of revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs
|
|
|
341,450
|
|
|
|
185,579
|
|
|
|
72,567
|
|
Depreciation
|
|
|
50,914
|
|
|
|
20,261
|
|
|
|
4,874
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin
|
|
|
178,603
|
|
|
|
105,124
|
|
|
|
30,581
|
|
General and administrative expenses
|
|
|
58,622
|
|
|
|
35,536
|
|
|
|
15,576
|
|
Gain on capillary asset sale
|
|
|
(8,868
|
)
|
|
|
|
|
|
|
|
|
Amortization
|
|
|
4,067
|
|
|
|
1,858
|
|
|
|
1,487
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
124,782
|
|
|
|
67,730
|
|
|
|
13,518
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(49,534
|
)
|
|
|
(21,309
|
)
|
|
|
(4,746
|
)
|
Interest income
|
|
|
3,259
|
|
|
|
972
|
|
|
|
49
|
|
Other
|
|
|
776
|
|
|
|
(347
|
)
|
|
|
186
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(45,499
|
)
|
|
|
(20,684
|
)
|
|
|
(4,511
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before minority interest and income taxes
|
|
|
79,283
|
|
|
|
47,046
|
|
|
|
9,007
|
|
Minority interest in income of subsidiaries
|
|
|
|
|
|
|
|
|
|
|
(488
|
)
|
Provision for income taxes
|
|
|
(28,843
|
)
|
|
|
(11,420
|
)
|
|
|
(1,344
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
50,440
|
|
|
$
|
35,626
|
|
|
$
|
7,175
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.48
|
|
|
$
|
1.73
|
|
|
$
|
0.48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
1.45
|
|
|
$
|
1.66
|
|
|
$
|
0.44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
34,158
|
|
|
|
20,548
|
|
|
|
14,832
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
34,701
|
|
|
|
21,410
|
|
|
|
16,238
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated
Financial Statements.
54
ALLIS-CHALMERS
ENERGY INC.
CONSOLIDATED
STATEMENT OF STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital in
|
|
|
Retained
|
|
|
Total
|
|
|
|
Common Stock
|
|
|
Excess of
|
|
|
Earnings
|
|
|
Stockholders
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Par Value
|
|
|
(Deficit)
|
|
|
Equity
|
|
|
|
(In thousands, except share amounts)
|
|
|
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
|
|
Issuance under stock plans
|
|
|
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
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50,440
|
|
|
|
50,440
|
|
Issuance of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Secondary public offering, net of offering costs
|
|
|
6,000,000
|
|
|
|
60
|
|
|
|
99,995
|
|
|
|
|
|
|
|
100,055
|
|
Issuance under stock plans
|
|
|
882,624
|
|
|
|
9
|
|
|
|
3,310
|
|
|
|
|
|
|
|
3,319
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
4,863
|
|
|
|
|
|
|
|
4,863
|
|
Tax benefits on stock plans
|
|
|
|
|
|
|
|
|
|
|
1,719
|
|
|
|
|
|
|
|
1,719
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2007
|
|
|
35,116,035
|
|
|
$
|
351
|
|
|
$
|
326,095
|
|
|
$
|
87,883
|
|
|
$
|
414,329
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated
Financial Statements.
55
ALLIS-CHALMERS
ENERGY INC.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Cash Flows from Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
50,440
|
|
|
$
|
35,626
|
|
|
$
|
7,175
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
54,981
|
|
|
|
22,119
|
|
|
|
6,361
|
|
Amortization and write-off of deferred financing fees
|
|
|
3,197
|
|
|
|
1,527
|
|
|
|
962
|
|
Stock-based compensation
|
|
|
4,863
|
|
|
|
3,394
|
|
|
|
|
|
Allowance for bad debts
|
|
|
730
|
|
|
|
781
|
|
|
|
219
|
|
Imputed interest
|
|
|
|
|
|
|
355
|
|
|
|
|
|
Deferred taxes
|
|
|
8,017
|
|
|
|
2,215
|
|
|
|
|
|
Minority interest in income of subsidiaries
|
|
|
|
|
|
|
|
|
|
|
488
|
|
Gain on sale of property and equipment
|
|
|
(2,323
|
)
|
|
|
(2,444
|
)
|
|
|
(669
|
)
|
Gain on capillary asset sale
|
|
|
(8,868
|
)
|
|
|
|
|
|
|
|
|
Changes in operating assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in accounts receivable
|
|
|
(30,825
|
)
|
|
|
(23,175
|
)
|
|
|
(10,656
|
)
|
Increase in inventories
|
|
|
(5,375
|
)
|
|
|
(2,637
|
)
|
|
|
(3,072
|
)
|
Decrease in prepaid expenses and other assets
|
|
|
8,202
|
|
|
|
2,505
|
|
|
|
929
|
|
Increase (decrease) in other assets
|
|
|
(4,492
|
)
|
|
|
308
|
|
|
|
(936
|
)
|
Increase (decrease) in trade accounts payable
|
|
|
10,732
|
|
|
|
(2,337
|
)
|
|
|
2,373
|
|
Increase in accrued interest
|
|
|
5,950
|
|
|
|
11,382
|
|
|
|
324
|
|
Increase (decrease) in accrued expenses
|
|
|
1,508
|
|
|
|
872
|
|
|
|
(97
|
)
|
Increase (decrease) in other liabilities
|
|
|
2,700
|
|
|
|
(224
|
)
|
|
|
(266
|
)
|
Increase in accrued salaries, benefits and payroll taxes
|
|
|
4,031
|
|
|
|
3,392
|
|
|
|
443
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
103,468
|
|
|
|
53,659
|
|
|
|
3,578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions, net of cash acquired
|
|
|
(41,000
|
)
|
|
|
(526,572
|
)
|
|
|
(36,888
|
)
|
Purchase of investment interests
|
|
|
(498
|
)
|
|
|
|
|
|
|
|
|
Purchase of property and equipment
|
|
|
(113,151
|
)
|
|
|
(39,697
|
)
|
|
|
(17,767
|
)
|
Deposits on asset commitments
|
|
|
(11,488
|
)
|
|
|
|
|
|
|
|
|
Proceeds from sale of capillary assets
|
|
|
16,250
|
|
|
|
|
|
|
|
|
|
Proceeds from sale of property and equipment
|
|
|
12,811
|
|
|
|
6,881
|
|
|
|
1,579
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(137,076
|
)
|
|
|
(559,388
|
)
|
|
|
(53,076
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of long-term debt
|
|
|
250,000
|
|
|
|
557,820
|
|
|
|
56,251
|
|
Payments on long-term debt
|
|
|
(309,745
|
)
|
|
|
(54,030
|
)
|
|
|
(28,202
|
)
|
Payments on related party debt
|
|
|
|
|
|
|
(3,031
|
)
|
|
|
(1,522
|
)
|
Net (repayments) borrowings on lines of credit
|
|
|
|
|
|
|
(6,400
|
)
|
|
|
2,527
|
|
Proceeds from issuance of common stock, net of offering costs
|
|
|
100,055
|
|
|
|
46,297
|
|
|
|
15,459
|
|
Proceeds from exercise of options and warrants
|
|
|
3,319
|
|
|
|
6,321
|
|
|
|
1,382
|
|
Tax benefit on stock plans
|
|
|
1,719
|
|
|
|
6,440
|
|
|
|
|
|
Debt issuance costs
|
|
|
(7,792
|
)
|
|
|
(9,863
|
)
|
|
|
(1,821
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
37,556
|
|
|
|
543,554
|
|
|
|
44,074
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
3,948
|
|
|
|
37,825
|
|
|
|
(5,424
|
)
|
Cash and cash equivalents at beginning of year
|
|
|
39,745
|
|
|
|
1,920
|
|
|
|
7,344
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
43,693
|
|
|
$
|
39,745
|
|
|
$
|
1,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated
Financial Statements.
56
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial Statements
|
|
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 provide services and
equipment to oil and natural gas exploration and production
companies throughout the United States including Texas,
Louisiana, New Mexico, Colorado, Oklahoma, Mississippi, Wyoming,
Arkansas, 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 Services; International Drilling; Directional Drilling;
Tubular Services; Underbalanced Drilling 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, 2007 are AirComp LLC (AirComp),
Allis-Chalmers Tubular Services LLC (Tubular),
Strata Directional Technology LLC (Strata),
Allis-Chalmers Rental Services LLC (Rental),
Allis-Chalmers Production Services LLC (Production),
Allis-Chalmers Management LLC, Allis-Chalmers Holdings Inc., DLS
Drilling, Logistics & Services Corporation
(DLS), DLS Argentina Limited, Tanus Argentina S.A.
(Tanus), Petro-Rentals LLC
(Petro-Rental) and Rebel Rentals LLC
(Rebel). All significant inter-company transactions
have been eliminated.
Revenue
Recognition
We provide rental equipment and drilling services to our
customers at per day, or daywork, and per job contractual rates
and recognize the drilling related revenue as the work
progresses and when collectibility is reasonably assured.
Revenue from daywork contracts is recognized when it is realized
or realizable and earned. On daywork contracts, revenue is
recognized based on the number of days completed at fixed rates
stipulated by the contract. For certain contracts, we receive
lump-sum and other fees for equipment and other mobilization
costs. Mobilization fees and the related costs are deferred and
amortized over the contract terms when material. We recognize
reimbursements received for out-of-pocket expenses incurred as
revenues and account for out-of-pocket expenses as direct costs.
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 $12.6 million, $2.4 million and $970,000
for the years ended December 31, 2007, 2006 and 2005,
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
57
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
recognition issues. Our revenue recognition policy is in
accordance with generally accepted accounting principles and
SAB No. 104.
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, 2007 and 2006, we
had recorded an allowance for doubtful accounts of
$1.9 million and $826,000 respectively. Bad debt expense
was $1.3 million, $781,000 and $219,000 for the years ended
December 31, 2007, 2006 and 2005, 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 $50.9 million,
$20.3 million and $4.9 million for the years ended
December 31, 2007, 2006 and 2005, 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-
58
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 write-down 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, 2007 and 2006, 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, 2007 and 2006.
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, 2007, we have approximately $2.5 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, 2007 by a
total of $13.2 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 2007 and 2006, one
of our customers, Pan American Energy LLC Sucursal Argentina, or
Pan American Energy, represented 20.7% and 11.7% of our
consolidated revenues, respectively. In 2005 none of our
customers accounted for more than 10% of our consolidated
revenues. Revenues from Materiales y Equipo Petroleo, or Matyep,
represented 3.4%, 8.3% and 94.5% of our international revenues
in 2007, 2006 and 2005, respectively. Revenues from Pan American
Energy represented 51.0% and 45.6% of our international revenues
in 2007 and 2006, respectively.
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.
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
59
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
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. We provide for
uncertain tax positions pursuant to FASB Interpretation
No. 48, Accounting for Uncertainty in Income
Taxes an Interpretation of FASB Statement
No. 109 (FIN 48). Our policy is that
we recognize interest and penalties accrued on any unrecognized
tax benefits as a component of income tax expense. As of the
date of adoption of FIN 48, we did not have any accrued
interest or penalties associated with any unrecognized tax
benefits. For United States federal tax purposes, our tax
returns for the tax years 2001 through 2006 remain open for
examination by the tax authorities. Our foreign tax returns
remain open for examination for the tax years 2001 through 2006.
Generally, for state tax purposes, our 2002 through 2006 tax
years remain open for examination by the tax authorities under a
four year statute of limitations, however, certain states may
keep their statute open for six to ten years.
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 2007 and 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.
60
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
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 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 years ended December 31, 2007 and 2006
includes approximately $4.9 million and $3.4 million
of compensation costs related to share-based payments,
respectively. The tax benefit recorded in association with the
share-based payments was $1.7 million and $6.4 million
for the years-ended December 31, 2007 and 2006,
respectively. As of December 31, 2007 there is
$16.3 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
and net income per common share for the year ended
December 31, 2005 would have been decreased to the pro
forma amounts indicated below (in thousands, except per share
amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended
|
|
|
|
|
|
|
December 31, 2005
|
|
|
Net income attributed to common stockholders as reported:
|
|
|
|
|
|
$
|
7,175
|
|
Less total stock based employee compensation expense determined
under fair value based method for all awards net of tax related
effects
|
|
|
|
|
|
|
(4,284
|
)
|
|
|
|
|
|
|
|
|
|
Pro-forma net income attributed to common stockholders
|
|
|
|
|
|
$
|
2,891
|
|
|
|
|
|
|
|
|
|
|
Net income per common share:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
As reported
|
|
|
$
|
0.48
|
|
|
|
|
Pro forma
|
|
|
$
|
0.19
|
|
Diluted
|
|
|
As reported
|
|
|
$
|
0.44
|
|
|
|
|
Pro forma
|
|
|
$
|
0.18
|
|
Options were granted in 2007, 2006 and 2005. See Note 10
for further disclosures regarding stock options. The following
assumptions were applied in determining the compensation costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Expected dividend yield
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected price volatility
|
|
|
66.21
|
%
|
|
|
72.28
|
%
|
|
|
84.28
|
%
|
Risk-free interest rate
|
|
|
4.8
|
%
|
|
|
5.1
|
%
|
|
|
5.6
|
%
|
Expected life of options
|
|
|
5 years
|
|
|
|
7 years
|
|
|
|
7 years
|
|
Weighted average fair value of options granted at market value
|
|
$
|
12.86
|
|
|
$
|
10.58
|
|
|
$
|
5.02
|
|
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 14 for further disclosure
of segment information in accordance with SFAS No. 131.
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
61
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
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. 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. Restricted stock grants are
legally considered issued and outstanding, but are included in
basic and diluted earnings per share only to the extent that
they are vested. Unvested restricted stock is included in the
computation of diluted earnings per share using the treasury
stock method. 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,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
50,440
|
|
|
$
|
35,626
|
|
|
$
|
7,175
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding excluding nonvested
restricted stock
|
|
|
34,158
|
|
|
|
20,548
|
|
|
|
14,832
|
|
Effect of potentially dilutive common shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants and employee and director stock options and restricted
shares
|
|
|
543
|
|
|
|
862
|
|
|
|
1,406
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding and assumed
conversions
|
|
|
34,701
|
|
|
|
21,410
|
|
|
|
16,238
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.48
|
|
|
$
|
1.73
|
|
|
$
|
0.48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
1.45
|
|
|
$
|
1.66
|
|
|
$
|
0.44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Potentially dilutive securities excluded as anti-dilutive
|
|
|
1,108
|
|
|
|
53
|
|
|
|
599
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification
Certain prior period balances have been reclassified to conform
to current year presentation.
New
Accounting Pronouncements
In September 2006, the FASB issued SFAS No. 157,
Fair Value Measurements (SFAS 157).
SFAS 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 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. Subsequently, the FASB provided for a
one-year deferral of the provisions of SFAS 157 for
non-financial assets and liabilities that are recognized or
disclosed at fair value in the consolidated financial statements
on a non-recurring basis. We believe that the adoption of
SFAS 157 will not have a material impact on our financial
position, results of operations or cash flows.
In December 2007, the FASB issued SFAS No. 141(R),
Business Combinations (SFAS 141(R)).
This statement retains the fundamental requirements in
SFAS No. 141, Business Combinations that
the acquisition method of accounting be used for all business
combinations and expands the same method of accounting to all
transactions and other events in which one entity obtains
control over one or more other businesses or assets at
62
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
the acquisition date and in subsequent periods. This statement
replaces SFAS No. 141 by requiring measurement at the
acquisition date of the fair value of assets acquired,
liabilities assumed and any non-controlling interest.
Additionally, SFAS 141(R) requires that acquisition-related
costs, including restructuring costs, be recognized as expense
separately from the acquisition. SFAS 141(R) applies
prospectively to business combinations for fiscal years
beginning after December 15, 2008. We will adopt
SFAS 141(R) beginning January 1, 2009 and apply to
future acquisitions.
In February 2007, the FASB issued Statement No. 159, The
Fair Value Option for Financial Assets and Financial Liabilities
(SFAS 159), which permits entities to elect to
measure many financial instruments and certain other items at
fair value. Upon adoption of SFAS 159, an entity may elect
the fair value option for eligible items that exist at the
adoption date. Subsequent to the initial adoption, the election
of the fair value option should only be made at the initial
recognition of the asset or liability or upon a re-measurement
event that gives rise to the new-basis of accounting. All
subsequent changes in fair value for that instrument are
reported in earnings. SFAS 159 does not affect any existing
accounting literature that requires certain assets and
liabilities to be recorded at fair value nor does it eliminate
disclosure requirements included in other accounting standards.
SFAS 159 is effective as of the beginning of each reporting
entitys first fiscal year that begins after
November 15, 2007. We are currently evaluating the
provisions of SFAS 159 and have not yet determined the
impact, if any, on our financial statements.
In December 2007, the FASB issued SFAS No. 160,
Non-controlling Interests in Consolidated Financial
Statements an amendment of ARB No. 51
(SFAS 160). SFAS 160 requires
(i) that non-controlling (minority) interests be reported
as a component of shareholders equity, (ii) that net
income attributable to the parent and to the non-controlling
interest be separately identified in the consolidated statement
of operations, (iii) that changes in a parents
ownership interest while the parent retains its controlling
interest be accounted for as equity transactions, (iv) that
any retained non-controlling equity investment upon the
deconsolidation of a subsidiary be initially measured at fair
value, and (v) that sufficient disclosures are provided
that clearly identify and distinguish between the interests of
the parent and the interests of the non-controlling owners.
SFAS 160 is effective for annual periods beginning after
December 15, 2008 and should be applied prospectively. The
presentation and disclosure requirements of the statement shall
be applied retrospectively for all periods presented. We believe
the adoption of SFAS 160 will not have a material impact on
our financial position or results of operations.
|
|
NOTE 2
|
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, 2007
and 2006, we have post-retirement benefit obligations of $31,000
and $304,000, 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
63
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
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 three-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 $1.8 million,
$735,000 and $114,000 were paid in 2007, 2006 and 2005,
respectively.
|
|
NOTE 3
|
ACQUISITIONS
AND SALE OF CAPILLARY ASSETS
|
On April 1, 2005, we acquired 100% of the outstanding stock
of Delta Rental Service, Inc., or Delta, for approximately
$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. The results of Delta since the
acquisition are included in our Rental Services segment.
On May 1, 2005, we acquired 100% of the outstanding capital
stock of Capcoil Tubing Services, Inc., or Capcoil, for
approximately $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. The results of Capcoil since the acquisition are
included in our Production Services segment.
On July 11, 2005, we acquired the compressed air drilling
assets of W.T Enterprises, Inc., or W.T., 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. The results of the W.T. assets since their
acquisition are included in our Underbalanced Drilling segment.
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. The results of AirComp are included in our
Underbalanced Drilling segment.
Effective August 1, 2005, we acquired 100% of the
outstanding capital stock of Target Energy Inc., or Target, for
approximately $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.
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. The results of these assets since their acquisition
are included in our Tubular Services segment.
Effective January 1, 2006, we acquired 100% of the
outstanding stock of Specialty Rental Tools, Inc., or Specialty,
for approximately $95.3 million in cash. In addition,
approximately $588,000 of costs were incurred in relation to the
Specialty acquisition. 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
64
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
summarizes the allocation of the purchase price and related
acquisition costs 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
|
|
|
|
|
|
|
Specialtys historical property and equipment values were
increased by approximately $71.6 million based on
third-party valuations. The results of Specialty since the
acquisition are included in our Rental Services segment.
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 approximately
$11.3 million in cash, $1.6 million in our common
stock and a $750,000 three-year promissory note. In addition,
approximately $380,000 of costs were incurred in relation to the
Rogers acquisition. 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 and related acquisition costs
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, including goodwill
|
|
|
4,941
|
|
|
|
|
|
|
Total assets acquired
|
|
|
19,327
|
|
|
|
|
|
|
Current liabilities
|
|
|
1,376
|
|
Deferred income tax liabilities
|
|
|
3,760
|
|
Other long-term liabilities
|
|
|
150
|
|
|
|
|
|
|
Total liabilities assumed
|
|
|
5,286
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
14,041
|
|
|
|
|
|
|
Rogers historical property and equipment values were
increased by approximately $8.4 million based on
third-party valuations. Intangible assets include approximately
$2.4 million assigned to goodwill, $1.2 million
assigned to patents, $1.1 million assigned to customer list
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 10.5 years. The
results of Rogers since the acquisition are included in our
Tubular Services segment.
Effective August 14, 2006, we acquired 100% of the
outstanding stock of DLS, based in Argentina, for a total
consideration of approximately $114.5 million, which
includes approximately $93.7 million in cash,
$38.1 million in our common stock, less approximately
$17.3 million of debt assigned to us. In addition,
approximately $3.4 million of costs were incurred in
relation to the DLS acquisition. 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
65
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
Bolivia. The following table summarizes the allocation of the
purchase price and related acquisition costs 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
|
|
|
|
|
|
|
DLS historical property and equipment values were
increased by approximately $22.7 million based on
third-party valuations. The results of DLS since the acquisition
are included in our International Drilling segment.
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 approximately $20.2 million in cash,
$3.8 million in our common stock and repaid
$9.6 million of existing Petro Rental debt. In addition,
approximately $82,000 of costs were incurred in relation to the
Petro-Rental acquisition. 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 allocation of the purchase price and related
acquisition costs 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, including goodwill
|
|
|
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
|
|
|
|
|
|
|
Petro Rentals historical property and equipment values
were increased by approximately $13.4 million based on
third-party valuations. Intangible assets include approximately
$3.6 million assigned to goodwill and $2.2 million
assigned to customer relationships based on third-party
valuations. The amortizable intangibles have a weighted-average
useful life of 10 years. The results of Petro-Rental since
the acquisition are included in our Production Services segment.
Effective December 1, 2006, we acquired 100% of the
outstanding stock of Tanus, based in Argentina, for a total
consideration of $2.5 million. In addition, approximately
$17,000 of costs were incurred in relation to the Tanus
acquisition. Tanus is engaged in the research and manufacturing
of additives for the oil, natural gas and water well drilling
and completion fluids in Argentina. The following table
summarizes the allocation
66
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
of the purchase price and related acquisition costs 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
|
|
|
|
|
|
|
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 approximately
$291.0 million in cash, and $51.4 million in our
common stock. In addition, approximately $3.0 million of
costs were incurred in relation to the acquisition of the assets
of OGR The following table summarizes the allocation of the
purchase price and related acquisition costs 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, including goodwill
|
|
|
128,976
|
|
|
|
|
|
|
Total assets acquired
|
|
$
|
345,344
|
|
|
|
|
|
|
OGRs historical property and equipment values were
increased by approximately $168.9 million based on
third-party valuations. Intangible assets include approximately
$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 results of the OGR assets since their
acquisition are included in our Rental Services segment.
On June 29 2007, we acquired Coker Directional, Inc., or Coker,
for a total consideration of approximately $3.9 million,
which includes approximately $3.6 million in cash and a
promissory note for $350,000. In addition, approximately $5,000
of costs were incurred in relation to the Coker acquisition. The
following table summarizes the preliminary allocation of the
purchase price and related acquisition costs to the estimated
fair value of the assets acquired and liabilities assumed at the
date of the acquisition (in thousands):
|
|
|
|
|
Property and equipment
|
|
|
3
|
|
Intangible assets, including goodwill
|
|
|
3,902
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
3,905
|
|
|
|
|
|
|
Intangible assets include approximately $1.8 million
assigned to goodwill and $2.1 million assigned to customer
relationships and non-compete. The amortizable intangibles have
a weighted-average useful life of 9.4 years. The results of
Coker since the acquisition are included in our Directional
Drilling segment. We do not expect any material differences from
the preliminary allocation of the purchase price and the final
purchase price allocations.
On July 26, 2007, we acquired Diggar Tools, LLC, or Diggar,
for a total consideration of approximately $10.3 million,
which includes approximately $6.7 million in cash, a
promissory note for $750,000 and payment of approximately
$2.8 million of existing Diggar debt. In addition,
approximately $29,000 of costs were incurred in relation to the
Diggar acquisition. The following table summarizes the
preliminary allocation
67
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
of the purchase price and related acquisition costs to the
estimated fair value of the assets acquired at the date of
acquisition (in thousands):
|
|
|
|
|
Current assets
|
|
$
|
1,113
|
|
Property and equipment
|
|
|
7,204
|
|
Intangible assets, including goodwill
|
|
|
2,675
|
|
|
|
|
|
|
Total assets acquired
|
|
|
10,992
|
|
|
|
|
|
|
Current liabilities
|
|
|
622
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
10,370
|
|
|
|
|
|
|
Diggars historical property and equipment values were
increased by approximately $3.4 million based on
third-party valuations. Intangible assets include approximately
$2.7 million assigned to goodwill. The results of Diggar
since the acquisition are included in our Directional Drilling
segment. We do not expect any material differences from the
preliminary allocation of the purchase price and the final
purchase price allocations.
On October 23, 2007, we acquired Rebel for a total
consideration of approximately $7.3 million, which includes
approximately $5.0 million in cash, promissory notes for an
aggregate of $500,000, payment of approximately
$1.5 million of existing Rebel debt and the deposit of
$305,000 in escrow to cover distributions owed under the Rebel
Defined Benefit Pension Plan & Trust. In addition,
approximately $214,000 of costs were incurred in relation to the
Rebel acquisition. The following table summarizes the
preliminary allocation of the purchase price and related
acquisition costs to the estimated fair value of the assets
acquired at the date of acquisition (in thousands):
|
|
|
|
|
Current assets
|
|
$
|
944
|
|
Land, Property and equipment
|
|
|
8,736
|
|
Intangible assets, including goodwill
|
|
|
1,144
|
|
|
|
|
|
|
Total assets acquired
|
|
|
10,824
|
|
|
|
|
|
|
Current liabilities
|
|
|
218
|
|
Deferred tax liabilities
|
|
|
3,095
|
|
|
|
|
|
|
Total liabilities assumed
|
|
|
3,313
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
7,511
|
|
|
|
|
|
|
Rebels historical property and equipment values were
increased by approximately $8.5 million based on
third-party valuations. Intangible assets include approximately
$461,000 assigned to goodwill and $683,000 assigned to customer
relations. The amortizable intangibles have a useful life of
15 years. The results of Rebel since the acquisition are
included in our Tubular services segment. We do not expect any
material differences from the preliminary allocation of the
purchase price and the final purchase price allocations.
On November 1, 2007, we acquired substantially all the
assets Diamondback Oilfield Services, Inc. or Diamondback, for a
total consideration of approximately $23.1 million in cash.
Approximately $89,000 of costs were incurred in relation to the
Diamondback acquisition. The following table summarizes the
68
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
preliminary allocation of the purchase price and related
acquisition costs to the estimated fair value of the assets
acquired at the date of acquisition (in thousands):
|
|
|
|
|
Current assets
|
|
$
|
3,350
|
|
Property and equipment
|
|
|
8,701
|
|
Intangible assets, including goodwill
|
|
|
12,232
|
|
Other noncurrent assets
|
|
|
10
|
|
|
|
|
|
|
Total assets acquired
|
|
|
24,293
|
|
|
|
|
|
|
Current liabilities
|
|
|
1,160
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
23,133
|
|
|
|
|
|
|
Diamondbacks historical property and equipment values were
increased by approximately $2.0 million based on
third-party valuations. Intangible assets include approximately
$7.6 million assigned to goodwill, $650,000 assigned to
non-compete, $620,000 assigned to trade name and
$3.4 million assigned to customer relations based on
third-party valuations. The amortizable intangibles have a
weighted-average useful life of 13.3 years. The sellers are
entitled to a future cash earn-out payment upon the business
attaining certain earning objectives. The results of the
Diamondback assets since their acquisition are included in our
Directional Drilling segment. We do not expect any material
differences from the preliminary allocation of the purchase
price and the final purchase price allocations.
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.
On June 29, 2007, we sold our capillary tubing units and
related equipment for approximately $16.3 million. We
reported a gain of approximately $8.9 million. The assets
sold represented a small portion of our Production Services
segment.
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-Rental 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-Rental and OGR as if the
acquisitions had occurred as of January 1, 2005, based on
the historical results of the acquisitions. 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
|
|
|
Revenues
|
|
$
|
502,418
|
|
|
$
|
346,230
|
|
Operating income
|
|
$
|
93,082
|
|
|
$
|
49,868
|
|
Net income
|
|
$
|
32,358
|
|
|
$
|
1,264
|
|
Net income per common share
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.96
|
|
|
$
|
0.04
|
|
Diluted
|
|
$
|
0.94
|
|
|
$
|
0.04
|
|
69
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
Inventories are comprised of the following as of December 31 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Manufactured
|
|
|
|
|
|
|
|
|
Finished goods
|
|
$
|
2,198
|
|
|
$
|
1,476
|
|
Work in process
|
|
|
1,781
|
|
|
|
2,266
|
|
Raw materials
|
|
|
4,464
|
|
|
|
2,638
|
|
|
|
|
|
|
|
|
|
|
Total manufactured
|
|
|
8,443
|
|
|
|
6,380
|
|
Hammers
|
|
|
1,434
|
|
|
|
1,016
|
|
Drive pipe
|
|
|
420
|
|
|
|
716
|
|
Rental supplies
|
|
|
2,261
|
|
|
|
1,845
|
|
Chemicals and drilling fluids
|
|
|
3,236
|
|
|
|
2,673
|
|
Rig parts and related inventory
|
|
|
9,985
|
|
|
|
9,762
|
|
Coiled tubing and related inventory
|
|
|
1,014
|
|
|
|
1,627
|
|
Shop supplies and related inventory
|
|
|
5,416
|
|
|
|
4,596
|
|
|
|
|
|
|
|
|
|
|
Total inventories
|
|
$
|
32,209
|
|
|
$
|
28,615
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 5
|
PROPERTY
AND OTHER INTANGIBLE ASSETS
|
Property and equipment is comprised of the following as of
December 31 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
|
|
|
|
|
|
Period
|
|
2007
|
|
|
2006
|
|
|
Land
|
|
|
|
$
|
2,040
|
|
|
$
|
1,810
|
|
Building and improvements
|
|
15-20 years
|
|
|
6,986
|
|
|
|
5,392
|
|
Transportation equipment
|
|
3-10 years
|
|
|
26,132
|
|
|
|
22,744
|
|
Drill pipe and rental equipment
|
|
3-20 years
|
|
|
350,202
|
|
|
|
321,821
|
|
Drilling, workover and pulling rigs
|
|
20 years
|
|
|
127,725
|
|
|
|
120,517
|
|
Machinery and equipment
|
|
3-20 years
|
|
|
157,626
|
|
|
|
105,926
|
|
Furniture, computers, software and leasehold improvements
|
|
3-10 years
|
|
|
5,817
|
|
|
|
3,522
|
|
Construction in progress equipment
|
|
N/A
|
|
|
27,148
|
|
|
|
2,269
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
703,676
|
|
|
|
584,001
|
|
Less: accumulated depreciation
|
|
|
|
|
(77,008
|
)
|
|
|
(29,743
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
|
|
$
|
626,668
|
|
|
$
|
554,258
|
|
|
|
|
|
|
|
|
|
|
|
|
The net book value of equipment recorded under capital leases
was $285,000 and $1.0 million as of December 31, 2007
and 2006, respectively.
70
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
Other intangible assets are as follows as of December 31 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization
|
|
|
|
|
|
|
|
|
Period
|
|
2007
|
|
|
2006
|
|
|
Intellectual property
|
|
10-20 years
|
|
$
|
1,629
|
|
|
$
|
1,009
|
|
Non-compete agreements
|
|
3-5 years
|
|
|
2,852
|
|
|
|
4,580
|
|
Customer relationships
|
|
10-15 years
|
|
|
33,528
|
|
|
|
27,552
|
|
Patents
|
|
12-15 years
|
|
|
2,560
|
|
|
|
3,327
|
|
Other intangible assets
|
|
2-10 years
|
|
|
829
|
|
|
|
847
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
41,398
|
|
|
|
37,315
|
|
Less: accumulated amortization
|
|
|
|
|
(6,218
|
)
|
|
|
(4,475
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Other intangibles assets, net
|
|
|
|
$
|
35,180
|
|
|
$
|
32,840
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
Gross
|
|
|
Accumulated
|
|
|
Gross
|
|
|
Accumulated
|
|
|
|
Value
|
|
|
Amortization
|
|
|
Value
|
|
|
Amortization
|
|
|
Intellectual property
|
|
$
|
1,629
|
|
|
$
|
410
|
|
|
$
|
1,009
|
|
|
$
|
349
|
|
Non-compete agreements
|
|
|
2,852
|
|
|
|
1,367
|
|
|
|
4,580
|
|
|
|
2,707
|
|
Customer relationships
|
|
|
33,528
|
|
|
|
3,497
|
|
|
|
27,552
|
|
|
|
789
|
|
Patents
|
|
|
2,560
|
|
|
|
423
|
|
|
|
3,327
|
|
|
|
203
|
|
Other intangible assets
|
|
|
829
|
|
|
|
521
|
|
|
|
847
|
|
|
|
427
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
41,398
|
|
|
$
|
6,218
|
|
|
$
|
37,315
|
|
|
$
|
4,475
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization expense related to other intangibles was
$4.1 million, $1.9 million and $1.5 million for
the years ended December 31, 2007, 2006 and 2005,
respectively. Future amortization of intangible assets at
December 31, 2007 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible Amortization by Period
|
|
|
|
Years Ended December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012 and
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
Thereafter
|
|
|
Intellectual property
|
|
$
|
96
|
|
|
$
|
96
|
|
|
$
|
96
|
|
|
$
|
96
|
|
|
$
|
835
|
|
Non-compete agreements
|
|
|
627
|
|
|
|
494
|
|
|
|
291
|
|
|
|
48
|
|
|
|
25
|
|
Customer relationships
|
|
|
3,227
|
|
|
|
3,227
|
|
|
|
3,227
|
|
|
|
3,227
|
|
|
|
17,123
|
|
Patents
|
|
|
202
|
|
|
|
202
|
|
|
|
202
|
|
|
|
202
|
|
|
|
1,329
|
|
Other intangible assets
|
|
|
107
|
|
|
|
90
|
|
|
|
79
|
|
|
|
30
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Intangible Amortization
|
|
$
|
4,259
|
|
|
$
|
4,109
|
|
|
$
|
3,895
|
|
|
$
|
3,603
|
|
|
$
|
19,314
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We had income before income taxes of $41.7 million,
$35.9 million and $8.5 million for U.S. tax
purposes for the years ended December 31, 2007, 2006 and
2005, respectively. We also had income before income taxes of
$37.6 million and $11.1 million reported in
non-U.S. countries
for the years ended December 31, 2007 and 2006,
respectively. We treat the withholding taxes incurred by our
U.S. subsidiaries in foreign countries as foreign tax, and
we anticipate using those tax payments to offset U.S. tax.
71
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
The income tax provision consists of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Current income tax expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
6,814
|
|
|
$
|
5,865
|
|
|
$
|
123
|
|
State
|
|
|
1,053
|
|
|
|
898
|
|
|
|
595
|
|
Foreign
|
|
|
12,959
|
|
|
|
2,442
|
|
|
|
626
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,826
|
|
|
|
9,205
|
|
|
|
1,344
|
|
Deferred income tax expense (benefit):
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
7,081
|
|
|
|
(946
|
)
|
|
|
|
|
State
|
|
|
349
|
|
|
|
573
|
|
|
|
|
|
Foreign
|
|
|
587
|
|
|
|
2,588
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,017
|
|
|
|
2,215
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
28,843
|
|
|
$
|
11,420
|
|
|
$
|
1,344
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We are required to file a consolidated U.S. federal income
tax return. We pay foreign income taxes in Argentina related to
our International Drillings operations and in Mexico
related to Tubulars revenues from Matyep.
The following table reconciles the U.S. statutory tax rate
to our actual tax rate:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Statutory income tax rate
|
|
|
35.0
|
%
|
|
|
35.0
|
%
|
|
|
34.0
|
%
|
State taxes, net of federal benefit
|
|
|
1.8
|
|
|
|
2.1
|
|
|
|
6.1
|
|
Valuation allowances
|
|
|
|
|
|
|
(57.7
|
)
|
|
|
(98.7
|
)
|
Nondeductible items, permanent differences and other
|
|
|
(0.4
|
)
|
|
|
44.9
|
|
|
|
74.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate
|
|
|
36.4
|
%
|
|
|
24.3
|
%
|
|
|
15.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Significant components of deferred income tax assets as of
December 31, were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Deferred income tax assets:
|
|
|
|
|
|
|
|
|
Net future (taxable) deductible items
|
|
$
|
874
|
|
|
$
|
899
|
|
Share-based compensation
|
|
|
1,898
|
|
|
|
578
|
|
Net operating loss carryforwards
|
|
|
2,681
|
|
|
|
1,698
|
|
Foreign tax credits
|
|
|
|
|
|
|
2,420
|
|
A-C Reorganization Trust and Product Liability Trust
|
|
|
4,099
|
|
|
|
5,500
|
|
|
|
|
|
|
|
|
|
|
Total deferred income tax assets
|
|
|
9,552
|
|
|
|
11,095
|
|
Deferred income tax liabilities
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
(37,795
|
)
|
|
|
(28,226
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred income tax liabilities
|
|
$
|
(28,243
|
)
|
|
$
|
(17,131
|
)
|
|
|
|
|
|
|
|
|
|
Net current deferred income tax asset
|
|
$
|
1,847
|
|
|
$
|
2,822
|
|
Net noncurrent deferred income tax liability
|
|
|
(30,090
|
)
|
|
|
(19,953
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred income tax liabilities
|
|
$
|
(28,243
|
)
|
|
$
|
(17,131
|
)
|
|
|
|
|
|
|
|
|
|
72
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
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 carryforwards, 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. Net operating loss
carryforwards for tax purposes at December 31, 2007 and
2006 were $7.7 million and $4.9 million, respectively,
expiring through 2024.
Prior to 2006, we did not record an asset for the
U.S. foreign tax credits as we believed they would not be
recoverable based on our taxable income. We now project that all
of the U.S. foreign tax credits will be utilized against
U.S. income tax.
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 and for
administrative expenses. 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 generates deductions for us as the Product
Liability Trust makes payments to liquidate claims or incurs
administrative 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. 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. As of December 31, 2007 and 2006, the valuation
allowance was zero.
Approximately $9.7 million and $5.5 million of
ad valorem, franchise, income, sales and other tax accruals
are included in our accrued expense balances of
$20.5 million and $17.0 million as of
December 31, 2007 and 2006, respectively.
We adopted the provisions of FIN 48 on January 1,
2007. This interpretation clarifies the accounting for uncertain
tax positions and requires companies to recognize the impact of
a tax position in their financial statements, if that position
is more likely than not of being sustained on audit, based on
the technical merits of the position. The adoption of
FIN 48 did not have any impact on the total liabilities or
stockholders equity.
73
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
Our long-term debt consists of the following as of December 31
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Senior notes
|
|
$
|
505,000
|
|
|
$
|
255,000
|
|
Bridge loan
|
|
|
|
|
|
|
300,000
|
|
Bank term loans
|
|
|
4,926
|
|
|
|
7,302
|
|
Revolving line of credit
|
|
|
|
|
|
|
|
|
Seller notes
|
|
|
2,350
|
|
|
|
900
|
|
Notes payable to former directors
|
|
|
32
|
|
|
|
32
|
|
Equipment & vehicle installment notes
|
|
|
595
|
|
|
|
3,502
|
|
Insurance premium financing notes
|
|
|
1,707
|
|
|
|
1,025
|
|
Obligations under non-compete agreements
|
|
|
110
|
|
|
|
270
|
|
Capital lease obligations
|
|
|
14
|
|
|
|
414
|
|
|
|
|
|
|
|
|
|
|
Total debt
|
|
|
514,734
|
|
|
|
568,445
|
|
Less: current maturities of long-term debt
|
|
|
6,434
|
|
|
|
6,999
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
508,300
|
|
|
$
|
561,446
|
|
|
|
|
|
|
|
|
|
|
Our weighted average interest rate for all of our outstanding
debt was approximately 8.7% as of December 31, 2007 and
9.8% as of December 31, 2006.
Maturities of debt obligations as of December 31, 2007 are
as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt
|
|
|
Capital Leases
|
|
|
Total
|
|
|
Year Ending:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
$
|
6,420
|
|
|
$
|
14
|
|
|
$
|
6,434
|
|
December 31, 2009
|
|
|
2,250
|
|
|
|
|
|
|
|
2,250
|
|
December 31, 2010
|
|
|
700
|
|
|
|
|
|
|
|
700
|
|
December 31, 2011
|
|
|
350
|
|
|
|
|
|
|
|
350
|
|
December 31, 2012
|
|
|
|
|
|
|
|
|
|
|
|
|
Thereafter
|
|
|
505,000
|
|
|
|
|
|
|
|
505,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
514,720
|
|
|
$
|
14
|
|
|
$
|
514,734
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
In January 2007, we closed on a private offering, to qualified
institutional buyers pursuant to Rule 144A under the
Securities Act, of $250.0 million principal amount of
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.
74
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
On December 18, 2006, we closed on a $300.0 million
senior unsecured bridge loan. The bridge loan was due
18 months after closing and had 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.
On January 18, 2006, we also executed an amended and
restated credit agreement which provided for a
$25.0 million revolving line of credit with a maturity of
January 2010. Our January 2006 amended and restated credit
agreement contained 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 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. On April 26, 2007, we entered into a
Second Amended and Restated Credit Agreement, which increased
our revolving line of credit to $62.0 million, and had a
final maturity date of April 26, 2012. On December 3,
2007, we entered into a First Amendment to Second Amended and
Restated Credit Agreement, which increased our revolving line of
credit to $90.0 million. The amended and restated credit
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 amended and restated credit agreement are
secured by substantially all of our assets located in the United
States. As of December 31, 2007 and 2006, no amounts were
borrowed on the facility but availability is reduced by
outstanding letters of credit of $8.4 million and
$9.7 million, respectively.
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 6.7% and 7.0% as of
December 31, 2007 and 2006, respectively. The bank loans
are denominated in U.S. dollars and the outstanding amount
due as of December 31, 2007 and 2006 was $4.9 million
and $7.3 million, respectively.
Notes
payable
As part of the acquisition of Mountain Compressed Air, Inc., or
MCA, in 2001, we issued a note to the sellers of MCA 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. As
of December 31, 2007 and 2006 the outstanding amounts due
were $0 and $150,000, respectively.
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 Coker, we issued to the seller a note in the amount
of $350,000. The note bears interest at 8.25% and is due June,
29, 2008. In connection with the purchase of Diggar, we issued
to the seller a note in the amount of $750,000. The note bears
interest at 6.0% and is due July 26, 2008. In connection
with the purchase of Rebel, we issued to the sellers notes in
the amount of $500,000. The notes bear interest at 5.0% and are
due October 23, 2008
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%. As of December 31, 2007 and
2006, the principal and accrued interest on these notes totaled
approximately $32,000.
We have various rig and equipment financing loans with interest
rates ranging from 7.8% to 8.7% and terms of 2 to 5 years.
As of December 31, 2007 and 2006, the outstanding balances
for rig and equipment financing loans were $595,000 and
$3.5 million, respectively.
75
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
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. In April 2007
and August 2007, we obtained insurance premium financings in the
amount of $3.2 million and $1.3 with fixed interest rates
of 5.9% and 5.7%, respectively. Under terms of the agreements,
amounts outstanding are paid over 11 month repayment
schedules. The outstanding balance of these notes was
approximately $1.7 million as of December 31, 2007.
Other
debt
In connection with the purchase of Tubular, we agreed to pay a
total of $1.2 million to the seller in exchange for a
non-compete agreement. Monthly payments of $20,576 were due
under this agreement through January 31, 2007. In
connection with the purchase of Safco-Oil Field Products, Inc.,
or Safco, we also agreed to pay a total of $150,000 to the
sellers in exchange for a non-compete agreement. We were
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 as of
December 31, 2007 and 2006 were $110,000 and $270,000,
respectively.
We also have various capital leases with terms that expire in
2008. As of December 31, 2007 and 2006, amounts outstanding
under capital leases were $14,000 and $414,000, respectively.
|
|
NOTE 8
|
COMMITMENTS
AND CONTINGENCIES
|
We have placed orders for capital equipment totaling
$82.7 million to be received and paid for through 2008.
Approximately $46.2 million is for drilling and service
rigs for our International Drilling segment, $26.0 million
is for six new coiled tubing units and related equipment for our
Production Services segment, $5.3 million is for rental
equipment, principally drill pipe, for our Rental Services
segment and $5.2 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 and certain other facilities and shop yards
for equipment storage and maintenance. Facility rent expense for
the years ended December 31, 2007, 2006 and 2005 was
$2.7 million, $1.6 million and $987,000, respectively.
At December 31, 2007, future minimum rental commitments for
all operating leases are as follows (in thousands):
|
|
|
|
|
Years Ending:
|
|
|
|
|
December 31, 2008
|
|
$
|
2,618
|
|
December 31, 2009
|
|
|
1,633
|
|
December 31, 2010
|
|
|
721
|
|
December 31, 2011
|
|
|
437
|
|
December 31, 2012
|
|
|
156
|
|
Thereafter
|
|
|
376
|
|
|
|
|
|
|
Total
|
|
$
|
5,941
|
|
|
|
|
|
|
|
|
NOTE 9
|
STOCKHOLDERS
EQUITY
|
As of January 1, 2005, in relation to the acquisition of
Downhole Injection Services, LLC, or 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
76
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
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 have been issued.
During 2005, we issued 223,114 and 168,161 shares of our
common stock in relation to the Delta and Capcoil acquisitions,
respectively (see Note 3).
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 approximately $1.4 million.
During 2006, 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 asset acquisitions,
respectively (see Note 3).
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 approximately $46.3 million were used to fund a portion
of our acquisition of DLS.
During 2006, we 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.
In January 2007 we closed on a public offering of
6.0 million shares of our common stock at a public offering
price of $17.65 per share. Net proceeds from the public
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 the OGR acquisition and for general corporate
purposes.
We also had restricted stock award grants, and options and
warrants exercised during 2007, which resulted in
882,624 shares of our common stock being issued for
approximately $3.3 million. We recognized approximately
$4.9 million of compensation expense related to share based
payments that was recorded as capital in excess of par value
(see Note 1). We also recorded approximately
$1.7 million of tax benefit related to our stock
compensation plans.
In 2000, we issued stock options and promissory notes to certain
current and former directors as compensation for services as
directors (See Note 7), 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, 2010. As of December 31, 2007, 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 Oil Quip Rentals,
Inc., or Oil Quip, prior to the merger, including providing
financial advisory services, assisting in Oil Quips
capital structure and assisting Oil Quip 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, 2007, all of the
stock options have been exercised.
77
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
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, 2007
|
|
|
December 31, 2006
|
|
|
December 31, 2005
|
|
|
|
Shares
|
|
|
Weighted Ave.
|
|
|
Shares
|
|
|
Weighted Ave.
|
|
|
Shares
|
|
|
Weighted Avg.
|
|
|
|
Under
|
|
|
Exercise
|
|
|
Under
|
|
|
Exercise
|
|
|
Under
|
|
|
Exercise
|
|
|
|
Option
|
|
|
Price
|
|
|
Option
|
|
|
Price
|
|
|
Option
|
|
|
Price
|
|
|
Beginning balance
|
|
|
1,350,365
|
|
|
$
|
6.88
|
|
|
|
2,860,867
|
|
|
$
|
5.10
|
|
|
|
1,215,000
|
|
|
$
|
3.20
|
|
Granted
|
|
|
220,000
|
|
|
|
21.83
|
|
|
|
15,000
|
|
|
|
14.74
|
|
|
|
1,695,000
|
|
|
|
6.44
|
|
Canceled
|
|
|
(17,334
|
)
|
|
|
8.45
|
|
|
|
(54,567
|
)
|
|
|
5.97
|
|
|
|
(15,300
|
)
|
|
|
3.33
|
|
Exercised
|
|
|
(566,268
|
)
|
|
|
5.86
|
|
|
|
(1,470,935
|
)
|
|
|
3.54
|
|
|
|
(33,833
|
)
|
|
|
2.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
|
986,763
|
|
|
$
|
10.77
|
|
|
|
1,350,365
|
|
|
$
|
6.88
|
|
|
|
2,860,867
|
|
|
$
|
5.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The total intrinsic value of stock options (the amount by which
the market price of the underlying stock on the date of exercise
exceeds the exercise price of the option) exercised was
approximately $6.6 million, $18.8 million and $343,000
during the years ended December 31, 2007, 2006 and 2005,
respectively. As of December 31, 2007, there was
approximately $2.4 million of total unrecognized
compensation cost related to stock option, with $939,000,
$918,000 and $532,000 to be recognized during the years ended
December 31, 2008, 2009 and 2010, respectively.
The following table summarizes additional information about our
stock options outstanding as of December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
|
Options Exercisable
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
Weighted
|
|
|
|
|
|
Weighted Average
|
|
|
Weighted
|
|
Range of
|
|
|
|
|
|
Remaining
|
|
|
Average
|
|
|
|
|
|
Remaining
|
|
|
Average
|
|
Exercise
|
|
|
Number of
|
|
|
Contractual Life
|
|
|
Exercise
|
|
|
Number of
|
|
|
Contractual Life
|
|
|
Exercise
|
|
Prices
|
|
|
options
|
|
|
(in Years)
|
|
|
Price
|
|
|
options
|
|
|
(in Years)
|
|
|
Price
|
|
|
$
|
2.75-4.87
|
|
|
|
380,699
|
|
|
|
7.02
|
|
|
$
|
4.14
|
|
|
|
380,699
|
|
|
|
7.02
|
|
|
$
|
4.14
|
|
|
10.85-14.74
|
|
|
|
386,064
|
|
|
|
7.92
|
|
|
|
11.01
|
|
|
|
381,069
|
|
|
|
7.92
|
|
|
|
10.96
|
|
|
16.50-21.95
|
|
|
|
220,000
|
|
|
|
9.59
|
|
|
|
21.83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.75-21.95
|
|
|
|
986,763
|
|
|
|
7.95
|
|
|
$
|
10.77
|
|
|
|
761,768
|
|
|
|
7.47
|
|
|
$
|
7.55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
78
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
The aggregate pretax intrinsic value of stock options
outstanding and exercisable was approximately $5.5 million
at December 31, 2007. The amount represents the value that
would have been received by the option holders had the
respective options been exercised on December 31, 2007.
Restricted
Stock Awards
In addition to stock options, our 2003 and 2006 Plans allow for
the grant of restricted stock awards (RSA). A
time-lapse RSA is an award of common stock, 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 time-lapse 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. A
performance-based RSA is an award of common stock, where each
unit represents the right to receive one unrestricted share of
stock with no exercise price at the attainment of established
performance criteria. During 2007, we granted 710,000
performance based RSAs with market conditions. The
performance-based RSAs are granted, but not earned and issued
until certain annual total shareholder return criteria are
attained over the next 3 years. The fair value of the
performance-based RSAs were based on third-party valuations.
The following table summarizes activity in our nonvested
restricted stock awards:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
December 31, 2006
|
|
|
|
Number
|
|
|
Weighted Ave.
|
|
|
Number
|
|
|
Weighted Ave.
|
|
|
|
of
|
|
|
Grant Date Fair
|
|
|
of
|
|
|
Grant Date Fair
|
|
|
|
Shares
|
|
|
Value Per Share
|
|
|
Shares
|
|
|
Value Per Share
|
|
|
Beginning balance
|
|
|
27,000
|
|
|
$
|
18.30
|
|
|
|
|
|
|
$
|
|
|
Granted
|
|
|
996,203
|
|
|
|
17.44
|
|
|
|
27,000
|
|
|
|
18.30
|
|
Vested
|
|
|
(30,000
|
)
|
|
|
18.01
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
|
993,203
|
|
|
$
|
17.45
|
|
|
|
27,000
|
|
|
$
|
18.30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The total fair value of RSA shares that vested during 2007 was
approximately $577,000. As of December 31, 2007, there was
approximately $13.9 million of total unrecognized
compensation cost related to nonvested RSAs, with
$6.6 million, $5.0 million, $1.8 million,
$278,000 and $208,000 to be recognized during the years ended
December 31, 2008, 2009, 2010, 2011 and 2012, respectively.
|
|
NOTE 11
|
STOCK
PURCHASE WARRANTS
|
In conjunction with the MCA purchase by Oil Quip in February of
2001, MCA 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 MCA assets. The warrant
entitles the holder to acquire up to 620,000 shares of
common stock of MCA at an exercise price of $.01 per share over
a nine-year period commencing on February 7, 2001.
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 MCA 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.
79
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
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 a
consultant in consideration of financial advisory services to be
provided pursuant to a consulting agreement. The warrants were
exercised in May 2004. This consultant 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 to this consultant in May 2004 and were
exercised in January 2007.
|
|
NOTE 12
|
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.
80
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
CONDENSED
CONSOLIDATING BALANCE SHEETS
December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chalmers
|
|
|
|
|
|
Subsidiary
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors
|
|
|
Adjustments
|
|
|
Total
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
|
|
|
$
|
41,176
|
|
|
$
|
2,517
|
|
|
$
|
|
|
|
$
|
43,693
|
|
Trade receivables, net
|
|
|
|
|
|
|
83,126
|
|
|
|
46,973
|
|
|
|
(5
|
)
|
|
|
130,094
|
|
Inventories
|
|
|
|
|
|
|
15,699
|
|
|
|
16,510
|
|
|
|
|
|
|
|
32,209
|
|
Intercompany receivables
|
|
|
76,583
|
|
|
|
|
|
|
|
|
|
|
|
(76,583
|
)
|
|
|
|
|
Note receivable from affiliate
|
|
|
8,270
|
|
|
|
|
|
|
|
|
|
|
|
(8,270
|
)
|
|
|
|
|
Prepaid expenses and other
|
|
|
7,731
|
|
|
|
2,564
|
|
|
|
1,603
|
|
|
|
|
|
|
|
11,898
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
92,584
|
|
|
|
142,565
|
|
|
|
67,603
|
|
|
|
(84,858
|
)
|
|
|
217,894
|
|
Property and equipment, net
|
|
|
|
|
|
|
477,055
|
|
|
|
149,613
|
|
|
|
|
|
|
|
626,668
|
|
Goodwill
|
|
|
|
|
|
|
136,875
|
|
|
|
1,523
|
|
|
|
|
|
|
|
138,398
|
|
Other intangible assets, net
|
|
|
552
|
|
|
|
34,572
|
|
|
|
56
|
|
|
|
|
|
|
|
35,180
|
|
Debt issuance costs, net
|
|
|
14,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,228
|
|
Note receivable from affiliates
|
|
|
16,380
|
|
|
|
|
|
|
|
|
|
|
|
(16,380
|
)
|
|
|
|
|
Investments in affiliates
|
|
|
824,410
|
|
|
|
|
|
|
|
|
|
|
|
(824,410
|
)
|
|
|
|
|
Other assets
|
|
|
15
|
|
|
|
4,977
|
|
|
|
16,225
|
|
|
|
|
|
|
|
21,217
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
948,169
|
|
|
$
|
796,044
|
|
|
$
|
235,020
|
|
|
$
|
(925,648
|
)
|
|
$
|
1,053,585
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
$
|
32
|
|
|
$
|
4,026
|
|
|
$
|
2,376
|
|
|
$
|
|
|
|
$
|
6,434
|
|
Trade accounts payable
|
|
|
|
|
|
|
16,815
|
|
|
|
20,654
|
|
|
|
(5
|
)
|
|
|
37,464
|
|
Accrued salaries, benefits and payroll taxes
|
|
|
|
|
|
|
3,712
|
|
|
|
11,571
|
|
|
|
|
|
|
|
15,283
|
|
Accrued interest
|
|
|
17,709
|
|
|
|
33
|
|
|
|
75
|
|
|
|
|
|
|
|
17,817
|
|
Accrued expenses
|
|
|
1,660
|
|
|
|
7,127
|
|
|
|
11,758
|
|
|
|
|
|
|
|
20,545
|
|
Intercompany payables
|
|
|
|
|
|
|
433,116
|
|
|
|
1,185
|
|
|
|
(434,301
|
)
|
|
|
|
|
Note payable to affiliate
|
|
|
|
|
|
|
|
|
|
|
8,270
|
|
|
|
(8,270
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
19,401
|
|
|
|
464,829
|
|
|
|
55,889
|
|
|
|
(442,576
|
)
|
|
|
97,543
|
|
Long-term debt, net of current maturities
|
|
|
505,750
|
|
|
|
|
|
|
|
2,550
|
|
|
|
|
|
|
|
508,300
|
|
Note payable to affiliate
|
|
|
|
|
|
|
|
|
|
|
16,380
|
|
|
|
(16,380
|
)
|
|
|
|
|
Deferred income tax liability
|
|
|
8,658
|
|
|
|
13,809
|
|
|
|
7,623
|
|
|
|
|
|
|
|
30,090
|
|
Other long-term liabilities
|
|
|
31
|
|
|
|
242
|
|
|
|
3,050
|
|
|
|
|
|
|
|
3,323
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
533,840
|
|
|
|
478,880
|
|
|
|
85,492
|
|
|
|
(458,956
|
)
|
|
|
639,256
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock
|
|
|
351
|
|
|
|
3,526
|
|
|
|
42,963
|
|
|
|
(46,489
|
)
|
|
|
351
|
|
Capital in excess of par value
|
|
|
326,095
|
|
|
|
167,508
|
|
|
|
74,969
|
|
|
|
(242,477
|
)
|
|
|
326,095
|
|
Retained earnings
|
|
|
87,883
|
|
|
|
146,130
|
|
|
|
31,596
|
|
|
|
(177,726
|
)
|
|
|
87,883
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
414,329
|
|
|
|
317,164
|
|
|
|
149,528
|
|
|
|
(466,692
|
)
|
|
|
414,329
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stock holders equity
|
|
$
|
948,169
|
|
|
$
|
796,044
|
|
|
$
|
235,020
|
|
|
$
|
(925,648
|
)
|
|
$
|
1,053,585
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
81
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
CONDENSED
CONSOLIDATING INCOME STATEMENTS
For the Year Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers
|
|
|
|
|
|
Subsidiary
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors
|
|
|
Adjustments
|
|
|
Total
|
|
|
Revenues
|
|
$
|
|
|
|
$
|
355,172
|
|
|
$
|
215,795
|
|
|
$
|
|
|
|
$
|
570,967
|
|
Cost of revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs
|
|
|
|
|
|
|
185,617
|
|
|
|
155,833
|
|
|
|
|
|
|
|
341,450
|
|
Depreciation
|
|
|
|
|
|
|
39,659
|
|
|
|
11,255
|
|
|
|
|
|
|
|
50,914
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin
|
|
|
|
|
|
|
129,896
|
|
|
|
48,707
|
|
|
|
|
|
|
|
178,603
|
|
General and administrative
|
|
|
4,349
|
|
|
|
44,439
|
|
|
|
9,834
|
|
|
|
|
|
|
|
58,622
|
|
Gain on capillary asset sale
|
|
|
|
|
|
|
(8,868
|
)
|
|
|
|
|
|
|
|
|
|
|
(8,868
|
)
|
Amortization
|
|
|
46
|
|
|
|
3,988
|
|
|
|
33
|
|
|
|
|
|
|
|
4,067
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(4,395
|
)
|
|
|
90,337
|
|
|
|
38,840
|
|
|
|
|
|
|
|
124,782
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in affiliates, net of tax
|
|
|
102,208
|
|
|
|
|
|
|
|
|
|
|
|
(102,208
|
)
|
|
|
|
|
Interest, net
|
|
|
(47,677
|
)
|
|
|
2,796
|
|
|
|
(1,394
|
)
|
|
|
|
|
|
|
(46,275
|
)
|
Other
|
|
|
304
|
|
|
|
336
|
|
|
|
136
|
|
|
|
|
|
|
|
776
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
54,835
|
|
|
|
3,132
|
|
|
|
(1,258
|
)
|
|
|
(102,208
|
)
|
|
|
(45,499
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
50,440
|
|
|
|
93,469
|
|
|
|
37,582
|
|
|
|
(102,208
|
)
|
|
|
79,283
|
|
Provision for income taxes
|
|
|
|
|
|
|
(16,085
|
)
|
|
|
(12,758
|
)
|
|
|
|
|
|
|
(28,843
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
50,440
|
|
|
$
|
77,384
|
|
|
$
|
24,824
|
|
|
$
|
(102,208
|
)
|
|
$
|
50,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
82
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOW
For the Year Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Chalmers
|
|
|
|
|
|
Subsidiaries
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
(Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors)
|
|
|
Adjustments
|
|
|
Total
|
|
|
Cash Flows from Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
50,440
|
|
|
$
|
77,384
|
|
|
$
|
24,824
|
|
|
$
|
(102,208
|
)
|
|
$
|
50,440
|
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation & amortization
|
|
|
46
|
|
|
|
43,647
|
|
|
|
11,288
|
|
|
|
|
|
|
|
54,981
|
|
Amortization and write-off of deferred financing fees
|
|
|
3,197
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,197
|
|
Stock based compensation
|
|
|
4,863
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,863
|
|
Allowance for bad debts
|
|
|
|
|
|
|
730
|
|
|
|
|
|
|
|
|
|
|
|
730
|
|
Equity earnings in affiliates
|
|
|
(102,208
|
)
|
|
|
|
|
|
|
|
|
|
|
102,208
|
|
|
|
|
|
Deferred taxes
|
|
|
7,430
|
|
|
|
|
|
|
|
587
|
|
|
|
|
|
|
|
8,017
|
|
Gain on sale of equipment
|
|
|
|
|
|
|
(2,182
|
)
|
|
|
(141
|
)
|
|
|
|
|
|
|
(2,323
|
)
|
Gain on capillary asset sale
|
|
|
|
|
|
|
(8,868
|
)
|
|
|
|
|
|
|
|
|
|
|
(8,868
|
)
|
Changes in operating assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in accounts receivables
|
|
|
|
|
|
|
(17,823
|
)
|
|
|
(13,002
|
)
|
|
|
|
|
|
|
(30,825
|
)
|
Increase in inventories
|
|
|
|
|
|
|
(4,286
|
)
|
|
|
(1,089
|
)
|
|
|
|
|
|
|
(5,375
|
)
|
(Increase) Decrease in other current assets
|
|
|
(3,003
|
)
|
|
|
12,075
|
|
|
|
(870
|
)
|
|
|
|
|
|
|
8,202
|
|
(Increase) decrease in other assets
|
|
|
242
|
|
|
|
|
|
|
|
(4,734
|
)
|
|
|
|
|
|
|
(4,492
|
)
|
(Decrease) increase in accounts payable
|
|
|
(31
|
)
|
|
|
2,234
|
|
|
|
8,529
|
|
|
|
|
|
|
|
10,732
|
|
(Decrease) increase in accrued interest
|
|
|
5,954
|
|
|
|
33
|
|
|
|
(37
|
)
|
|
|
|
|
|
|
5,950
|
|
(Decrease) increase in accrued expenses
|
|
|
1,525
|
|
|
|
(3,912
|
)
|
|
|
3,895
|
|
|
|
|
|
|
|
1,508
|
|
(Decrease) increase in other liabilities
|
|
|
(273
|
)
|
|
|
(77
|
)
|
|
|
3,050
|
|
|
|
|
|
|
|
2,700
|
|
Increase in accrued salaries, benefits and payroll taxes
|
|
|
|
|
|
|
355
|
|
|
|
3,676
|
|
|
|
|
|
|
|
4,031
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by operating activities
|
|
|
(31,818
|
)
|
|
|
99,310
|
|
|
|
35,976
|
|
|
|
|
|
|
|
103,468
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions, net of cash acquired
|
|
|
|
|
|
|
(41,000
|
)
|
|
|
|
|
|
|
|
|
|
|
(41,000
|
)
|
83
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 investment interests
|
|
|
|
|
|
|
(498
|
)
|
|
|
|
|
|
|
|
|
|
|
(498
|
)
|
Purchase of property and equipment
|
|
|
|
|
|
|
(84,240
|
)
|
|
|
(28,911
|
)
|
|
|
|
|
|
|
(113,151
|
)
|
Deposits on asset commitments
|
|
|
|
|
|
|
|
|
|
|
(11,488
|
)
|
|
|
|
|
|
|
(11,488
|
)
|
Notes receivable from affiliates
|
|
|
(6,809
|
)
|
|
|
|
|
|
|
|
|
|
|
6,809
|
|
|
|
|
|
Proceeds from sale of capillary assets
|
|
|
|
|
|
|
16,250
|
|
|
|
|
|
|
|
|
|
|
|
16,250
|
|
Proceeds from sale of property and equipment
|
|
|
|
|
|
|
12,666
|
|
|
|
145
|
|
|
|
|
|
|
|
12,811
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) in investing activities
|
|
|
(6,809
|
)
|
|
|
(96,822
|
)
|
|
|
(40,254
|
)
|
|
|
6,809
|
|
|
|
(137,076
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of long-term debt
|
|
|
250,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
250,000
|
|
Payments on long-term debt
|
|
|
(300,000
|
)
|
|
|
(6,587
|
)
|
|
|
(3,158
|
)
|
|
|
|
|
|
|
(309,745
|
)
|
Accounts receivable from affiliates
|
|
|
(8,674
|
)
|
|
|
|
|
|
|
|
|
|
|
8,674
|
|
|
|
|
|
Accounts payable to affiliates
|
|
|
|
|
|
|
7,506
|
|
|
|
1,168
|
|
|
|
(8,674
|
)
|
|
|
|
|
Note payable to affiliate
|
|
|
|
|
|
|
|
|
|
|
6,809
|
|
|
|
(6,809
|
)
|
|
|
|
|
Proceeds from issuance of common stock, net of offering costs
|
|
|
100,055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100,055
|
|
Proceeds from exercise of options and warrants
|
|
|
3,319
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,319
|
|
Tax benefit on stock plans
|
|
|
1,719
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,719
|
|
Debt issuance costs
|
|
|
(7,792
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,792
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by financing activities
|
|
|
38,627
|
|
|
|
919
|
|
|
|
4,819
|
|
|
|
(6,809
|
)
|
|
|
37,556
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
|
|
|
|
3,407
|
|
|
|
541
|
|
|
|
|
|
|
|
3,948
|
|
Cash and cash equivalents at beginning of year
|
|
|
|
|
|
|
37,769
|
|
|
|
1,976
|
|
|
|
|
|
|
|
39,745
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
|
|
|
$
|
41,176
|
|
|
$
|
2,517
|
|
|
$
|
|
|
|
$
|
43,693
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
84
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
85
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
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
|
|
$
|
|
|
|
$
|
241,474
|
|
|
$
|
69,490
|
|
|
$
|
|
|
|
$
|
310,964
|
|
Cost of revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs
|
|
|
|
|
|
|
134,638
|
|
|
|
50,941
|
|
|
|
|
|
|
|
185,579
|
|
Depreciation
|
|
|
|
|
|
|
16,198
|
|
|
|
4,063
|
|
|
|
|
|
|
|
20,261
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin
|
|
|
|
|
|
|
90,638
|
|
|
|
14,486
|
|
|
|
|
|
|
|
105,124
|
|
General and administrative
|
|
|
2,643
|
|
|
|
30,651
|
|
|
|
2,242
|
|
|
|
|
|
|
|
35,536
|
|
Amortization
|
|
|
46
|
|
|
|
1,801
|
|
|
|
11
|
|
|
|
|
|
|
|
1,858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(2,689
|
)
|
|
|
58,186
|
|
|
|
12,233
|
|
|
|
|
|
|
|
67,730
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in affiliates, net of tax
|
|
|
58,077
|
|
|
|
|
|
|
|
|
|
|
|
(58,077
|
)
|
|
|
|
|
Interest, net
|
|
|
(19,807
|
)
|
|
|
67
|
|
|
|
(597
|
)
|
|
|
|
|
|
|
(20,337
|
)
|
Other
|
|
|
45
|
|
|
|
97
|
|
|
|
(489
|
)
|
|
|
|
|
|
|
(347
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
38,315
|
|
|
|
164
|
|
|
|
(1,086
|
)
|
|
|
(58,077
|
)
|
|
|
(20,684
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) 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 (loss)
|
|
$
|
35,626
|
|
|
$
|
51,305
|
|
|
$
|
6,772
|
|
|
$
|
(58,077
|
)
|
|
$
|
35,626
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
86
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 (loss)
|
|
$
|
35,626
|
|
|
$
|
51,305
|
|
|
$
|
6,772
|
|
|
$
|
(58,077
|
)
|
|
$
|
35,626
|
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation & amortization
|
|
|
46
|
|
|
|
17,999
|
|
|
|
4,074
|
|
|
|
|
|
|
|
22,119
|
|
Amortization & write-off of deferred financing fees
|
|
|
1,527
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,527
|
|
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 inventories
|
|
|
|
|
|
|
(2,989
|
)
|
|
|
352
|
|
|
|
|
|
|
|
(2,637
|
)
|
(Increase) decrease in other current assets
|
|
|
(2,482
|
)
|
|
|
4,120
|
|
|
|
867
|
|
|
|
|
|
|
|
2,505
|
|
(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) in other liabilities
|
|
|
(31
|
)
|
|
|
(193
|
)
|
|
|
|
|
|
|
|
|
|
|
(224
|
)
|
(Decrease) increase in accrued salaries, benefits and payroll
taxes
|
|
|
(1,951
|
)
|
|
|
2,780
|
|
|
|
2,563
|
|
|
|
|
|
|
|
3,392
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by operating activities
|
|
|
(11,235
|
)
|
|
|
54,109
|
|
|
|
10,785
|
|
|
|
|
|
|
|
53,659
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions, net of cash acquired
|
|
|
(528,167
|
)
|
|
|
3,649
|
|
|
|
(2,054
|
)
|
|
|
|
|
|
|
(526,572
|
)
|
Notes receivable from affiliates
|
|
|
(585
|
)
|
|
|
|
|
|
|
|
|
|
|
585
|
|
|
|
|
|
Purchase of property and equipment
|
|
|
|
|
|
|
(33,930
|
)
|
|
|
(5,767
|
)
|
|
|
|
|
|
|
(39,697
|
)
|
87
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Chalmers
|
|
|
|
|
|
Subsidiaries
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
(Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors)
|
|
|
Adjustments
|
|
|
Total
|
|
|
Proceeds from sale of property and 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, net of offering costs
|
|
|
46,297
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
46,297
|
|
Proceeds from exercise of options and warrants
|
|
|
6,321
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,321
|
|
Tax benefit on stock plans
|
|
|
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 13
|
RELATED
PARTY TRANSACTIONS
|
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.
We purchased approximately $3.5 million of general oilfield
supplies and materials from Ralow Services, Inc., or Ralow in
2007 for our Rental Services segment. Ralow is owned by Brad A.
Adams and Bruce A. Adams who are brothers of Burt A. Adams, one
of our directors and our former President and Chief Operating
Officer. In addition, Brad A. Adams and Bruce A. Adams were
employed as officers of Rental during 2007.
88
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
NOTE 14
|
SEGMENT
INFORMATION
|
At December 31, 2007, we had six operating segments
including: Rental Services, International Drilling, Directional
Drilling, Tubular Services, Underbalanced Drilling 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,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental Services
|
|
$
|
121,186
|
|
|
$
|
51,521
|
|
|
$
|
5,059
|
|
International Drilling
|
|
|
215,795
|
|
|
|
69,490
|
|
|
|
|
|
Directional Drilling
|
|
|
96,080
|
|
|
|
76,471
|
|
|
|
46,579
|
|
Tubular Services
|
|
|
53,524
|
|
|
|
50,887
|
|
|
|
20,932
|
|
Underbalanced Drilling
|
|
|
50,959
|
|
|
|
43,045
|
|
|
|
25,662
|
|
Production Services
|
|
|
33,423
|
|
|
|
19,550
|
|
|
|
9,790
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
570,967
|
|
|
$
|
310,964
|
|
|
$
|
108,022
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental Services
|
|
$
|
49,139
|
|
|
$
|
26,293
|
|
|
$
|
1,300
|
|
International Drilling
|
|
|
38,839
|
|
|
|
12,233
|
|
|
|
|
|
Directional Drilling
|
|
|
18,848
|
|
|
|
17,666
|
|
|
|
7,389
|
|
Tubular Services
|
|
|
10,744
|
|
|
|
12,544
|
|
|
|
4,994
|
|
Underbalanced Drilling
|
|
|
13,091
|
|
|
|
10,810
|
|
|
|
5,612
|
|
Production Services
|
|
|
10,535
|
|
|
|
2,137
|
|
|
|
(99
|
)
|
General corporate
|
|
|
(16,414
|
)
|
|
|
(13,953
|
)
|
|
|
(5,678
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income from operations
|
|
$
|
124,782
|
|
|
$
|
67,730
|
|
|
$
|
13,518
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and Amortization Expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental Services
|
|
$
|
26,353
|
|
|
$
|
7,268
|
|
|
$
|
492
|
|
International Drilling
|
|
|
11,288
|
|
|
|
4,074
|
|
|
|
|
|
Directional Drilling
|
|
|
3,063
|
|
|
|
1,464
|
|
|
|
887
|
|
Tubular Services
|
|
|
5,164
|
|
|
|
3,908
|
|
|
|
2,006
|
|
Underbalanced Drilling
|
|
|
3,692
|
|
|
|
3,057
|
|
|
|
1,946
|
|
Production Services
|
|
|
4,919
|
|
|
|
2,005
|
|
|
|
912
|
|
General corporate
|
|
|
502
|
|
|
|
343
|
|
|
|
118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depreciation and amortization expense
|
|
$
|
54,981
|
|
|
$
|
22,119
|
|
|
$
|
6,361
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental Services
|
|
$
|
34,883
|
|
|
$
|
4,538
|
|
|
$
|
435
|
|
International Drilling
|
|
|
28,911
|
|
|
|
5,770
|
|
|
|
|
|
Directional Drilling
|
|
|
11,177
|
|
|
|
5,128
|
|
|
|
2,922
|
|
Tubular Services
|
|
|
9,250
|
|
|
|
10,980
|
|
|
|
5,207
|
|
Underbalanced Drilling
|
|
|
17,443
|
|
|
|
7,716
|
|
|
|
7,008
|
|
Production Services
|
|
|
10,740
|
|
|
|
5,253
|
|
|
|
1,514
|
|
General corporate
|
|
|
747
|
|
|
|
312
|
|
|
|
681
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures
|
|
$
|
113,151
|
|
|
$
|
39,697
|
|
|
$
|
17,767
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
89
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Goodwill:
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental Services
|
|
$
|
106,382
|
|
|
$
|
106,132
|
|
|
$
|
|
|
International Drilling
|
|
|
1,523
|
|
|
|
1,504
|
|
|
|
|
|
Directional Drilling
|
|
|
16,300
|
|
|
|
4,168
|
|
|
|
4,168
|
|
Tubular Services
|
|
|
6,564
|
|
|
|
6,464
|
|
|
|
3,673
|
|
Underbalanced Drilling
|
|
|
3,950
|
|
|
|
3,950
|
|
|
|
3,950
|
|
Production Services
|
|
|
3,679
|
|
|
|
3,617
|
|
|
|
626
|
|
General corporate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total goodwill
|
|
$
|
138,398
|
|
|
$
|
125,835
|
|
|
$
|
12,417
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental Services
|
|
$
|
454,216
|
|
|
$
|
453,802
|
|
|
$
|
8,034
|
|
International Drilling
|
|
|
235,020
|
|
|
|
185,677
|
|
|
|
|
|
Directional Drilling
|
|
|
82,532
|
|
|
|
28,585
|
|
|
|
20,960
|
|
Tubular Services
|
|
|
88,014
|
|
|
|
74,372
|
|
|
|
45,351
|
|
Underbalanced Drilling
|
|
|
72,401
|
|
|
|
54,288
|
|
|
|
46,045
|
|
Production Services
|
|
|
56,353
|
|
|
|
57,954
|
|
|
|
12,282
|
|
General corporate
|
|
|
65,049
|
|
|
|
53,648
|
|
|
|
4,683
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,053,585
|
|
|
$
|
908,326
|
|
|
$
|
137,355
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
339,476
|
|
|
$
|
231,852
|
|
|
$
|
101,261
|
|
International
|
|
|
231,491
|
|
|
|
79,112
|
|
|
|
6,761
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
570,967
|
|
|
$
|
310,964
|
|
|
$
|
108,022
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Long Lived Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
655,513
|
|
|
$
|
574,302
|
|
|
$
|
97,390
|
|
International
|
|
|
180,178
|
|
|
|
153,262
|
|
|
|
4,313
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long lived assets
|
|
$
|
835,691
|
|
|
$
|
727,564
|
|
|
$
|
101,703
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
90
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
NOTE 15
|
SUPPLEMENTAL
CASH FLOWS INFORMATION (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Interest paid
|
|
$
|
40,363
|
|
|
$
|
8,571
|
|
|
$
|
3,924
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes paid
|
|
$
|
17,272
|
|
|
$
|
5,796
|
|
|
$
|
676
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other non-cash investing and financing transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Insurance premiums financed
|
|
|
4,434
|
|
|
|
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 Property and equipment
|
|
$
|
4,345
|
|
|
$
|
109,632
|
|
|
$
|
1,750
|
|
Fair value of goodwill and other intangibles
|
|
|
350
|
|
|
|
4,010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
4,695
|
|
|
$
|
113,642
|
|
|
$
|
1,750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Value of common stock, issued
|
|
$
|
|
|
|
$
|
94,980
|
|
|
$
|
1,750
|
|
Seller financed note
|
|
|
1,600
|
|
|
|
750
|
|
|
|
|
|
Deferred tax liability
|
|
|
3,095
|
|
|
|
17,662
|
|
|
|
|
|
Accrued expenses
|
|
|
|
|
|
|
250
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
4,695
|
|
|
$
|
113,642
|
|
|
$
|
1,750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 17
|
SUBSEQUENT
EVENTS
|
On January 23, 2008, we entered into an Agreement and Plan
of Merger with Bronco Drilling Company, Inc., or Bronco, whereby
Bronco will become a wholly-owned subsidiary of Allis-Chalmers.
The merger agreement, which was approved by our Board of
Directors and the Board of Directors of Bronco, provides that
the Bronco stockholders will receive aggregate merger
consideration with a value of approximately $437.8 million,
consisting of (a) $280.0 million in cash and
(b) shares of our common stock, par value $0.01 per share,
having an aggregate value of approximately $157.8 million.
The number of shares of our common stock to be issued will be
based on the average closing price of our common stock for the
ten-trading day period ending two days prior to the closing.
Completion of the merger is conditioned upon, among other
things, adoption of the merger agreement by Broncos
stockholders and approval by our stockholders of the issuance of
shares of our common stock to be used as merger consideration.
In order to finance some or all of the cash component of the
merger consideration, the repayment of outstanding Bronco debt
and transaction expenses, we expect to incur debt of up to
$350.0 million. We intend to obtain up to
$350.0 million from either (1) a permanent debt
financing of up to $350.0 million or (2) if the
permanent debt financing cannot be consummated prior to the
closing date of the merger, the draw down under a senior
unsecured bridge loan facility in an aggregate principal amount
of up to $350.0 million to be arranged by RBC Capital
Markets Corporation and Goldman Sachs Credit Partners L.P.,
acting as joint lead arrangers and joint bookrunners. We
executed a commitment letter, dated January 28, 2008, with
Royal Bank of Canada and Goldman Sachs who have each, subject to
certain conditions, severally committed to provide
91
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
50% of the loans under the senior unsecured bridge facility to
us. This commitment for the bridge loan facility will terminate
on July 31, 2008, if we have not drawn the bridge facility
by such date and the merger is not consummated by such date. The
commitment may also terminate prior to July 31, 2008, if
the merger is abandoned or a material condition to the merger is
not satisfied or we breach our obligations under the commitment
letter. We may use the proceeds of the bridge facility to
finance the cash component of the merger consideration, repay
outstanding Bronco debt and pay transaction expenses.
On January 29, 2008, Burt A. Adams resigned as our
President and Chief Operating Officer, effective
February 28, 2008. Mr. Adams will remain as a member
of our Board of Directors. On January 29, 2008, Mark C.
Patterson was elected our Senior Vice-President
Rental Services. On January 29, 2008, Terrence P. Keane was
elected our Senior Vice-President Oilfield Services.
On January 31, 2008, we entered into an agreement with BCH
Ltd., or BCH, to invest $40.0 million in cash in BCH in the
form of a 15% Convertible Subordinated Secured debenture.
The debenture is convertible, at any time, at our option into
49% of the common equity of BCH. At the end of two years, we
have the option to acquire the remaining 51% of BCH from its
parent, BrazAlta Resources Corp., or BrazAlta, based on an
independent valuation from a mutually acceptable investment
bank. BCH is a Canadian-based oilfield services company engaged
in contract drilling operations exclusively in Brazil.
On February 15, 2008, through our DLS subsidiary in
Argentina, we entered into a $25.0 million import finance
facility with a bank. Borrowings under this facility will be
used to fund a portion of the purchase price of the new drilling
and service rigs ordered for our international drilling
operation. The facility is available for borrowings until
December 31, 2008. Each drawdown shall be repaid over four
years in equal semi-annual instalments beginning one year after
each disbursement with the final principal payment due not later
than March 15, 2013. Interest is payable every six months.
The import finance facility is unsecured and contains customary
events of default and financial covenants and limits DLS
ability to incur additional indebtedness, make capital
expenditures, create liens and sell assets.
|
|
NOTE 18
|
SUMMARIZED
QUARTERLY FINANCIAL DATA (UNAUDITED) (in thousands, except per
share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
Year 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
135,900
|
|
|
$
|
143,362
|
|
|
$
|
147,881
|
|
|
$
|
143,824
|
|
Operating income
|
|
|
31,470
|
|
|
|
41,474
|
|
|
|
31,148
|
|
|
|
20,690
|
|
Net income
|
|
$
|
12,165
|
|
|
$
|
19,504
|
|
|
$
|
12,987
|
|
|
$
|
5,784
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.38
|
|
|
$
|
0.56
|
|
|
$
|
0.37
|
|
|
$
|
0.17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.37
|
|
|
$
|
0.55
|
|
|
$
|
0.37
|
|
|
$
|
0.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
Year 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
47,911
|
|
|
$
|
61,383
|
|
|
$
|
86,772
|
|
|
$
|
114,898
|
|
Operating income
|
|
|
8,856
|
|
|
|
16,108
|
|
|
|
19,336
|
|
|
|
23,430
|
|
Net income
|
|
$
|
4,423
|
|
|
$
|
9,594
|
|
|
$
|
11,253
|
|
|
$
|
10,356
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.26
|
|
|
$
|
0.53
|
|
|
$
|
0.52
|
|
|
$
|
0.41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.23
|
|
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
$
|
0.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
92
|
|
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, with the participation of our Chief Executive
Officer and Chief Financial Officer, evaluated the effectiveness
of our disclosure controls and procedures (as
defined in Exchange Act
Rules 13a-15(e)
and
15d-15(e)),
as of December 31, 2007. Based on their evaluation, they
have concluded that our disclosure controls and procedures as of
the end of the period covered by this report were adequate to
ensure that (1) information required to be disclosed by us
in the reports filed or furnished by us under the Securities
Exchange Act of 1934, as amended, is recorded, processed,
summarized and reported within the time periods specified in the
rules and forms of the SEC and (2) such information is
accumulated and communicated to our management, including our
Chief Executive Officer and Chief Financial Officer, to allow
timely decisions regarding required disclosure. Based on that
evaluation, our Chief Executive Officer and Chief Financial
Officer have concluded that our disclosure controls and
procedures as of December 31, 2007 were effective at
reaching a reasonable level of assurance of achieving the
desired objective.
|
|
(b)
|
Managements
Report on Internal Control Over Financial Reporting
|
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
2007, 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, 2007, 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, 2007, our internal controls over financial
reporting are effective based on these criteria.
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,
an independent registered public accounting firm, has issued a
report on our internal control over financial reporting as of
December 31, 2007, which can be found in Item 8 of
this report.
93
|
|
(c)
|
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.
|
|
ITEM 9B.
|
OTHER
INFORMATION
|
None.
PART III
|
|
ITEM 10.
|
DIRECTORS,
EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
|
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 our Definitive Proxy Statement
for the 2008 annual meeting of stockholders within 120 days
of the end of our fiscal year ending December 31, 2007.
|
|
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 our Definitive Proxy Statement
for the 2008 annual meeting of stockholders within 120 days
of the end of our fiscal year ending December 31, 2007.
|
|
ITEM 12.
|
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTER
|
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 our Definitive Proxy Statement
for the 2008 annual meeting of stockholders within 120 days
of the end of our fiscal year ending December 31, 2007.
|
|
ITEM 13.
|
CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
|
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 our Definitive Proxy Statement
for the 2008 annual meeting of stockholders within 120 days
of the end of our fiscal year ending December 31, 2007.
|
|
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 our Definitive Proxy Statement
for the 2008 annual meeting of stockholders within 120 days
of the end of our fiscal year ending December 31, 2007.
94
PART IV
|
|
ITEM 15.
|
EXHIBITS AND
FINANCIAL STATEMENT SCHEDULES
|
(a)(1) Financial Statements
Consolidated Balance Sheets as of December 31, 2007 and
2006.
Consolidated Statements of Operations as of December 31,
2007, 2006 and 2005.
Consolidated Statement of Stockholders Equity as of
December 31, 2007, 2006, 2005 and 2004.
Consolidated Statements of Cash Flows as of December 31,
2007, 2006 and 2005.
Notes to Consolidated Financial Statements.
(2) Financial Statement Schedules
Schedule II Valuation and Qualifying Accounts
(3) Exhibits
The exhibits listed on the accompanying Exhibit Index or
incorporated by reference into this annual report on
Form 10-K.
|
|
(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, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
|
826
|
|
|
|
1,309
|
|
|
|
(211
|
)
|
|
|
1,924
|
|
Deferred tax assets valuation allowance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
95
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 6, 2008.
/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. Hidayatalla
|
|
Chairman and Chief Executive Officer (Principal Executive
Officer)
|
|
March 6, 2008
|
|
|
|
|
|
/s/ VICTOR
M. PEREZ
Victor
M. Perez
|
|
Chief Financial Officer
(Principal Financial Officer)
|
|
March 6, 2008
|
|
|
|
|
|
/s/ BRUCE
SAUERS
Bruce
Sauers
|
|
Chief Accounting Officer
(Principal Accounting Officer)
|
|
March 6, 2008
|
|
|
|
|
|
/s/ BURT
A. ADAMS
Burt
A. Adams
|
|
Director
|
|
March 6, 2008
|
|
|
|
|
|
Ali
H. M. Afdhal
|
|
Director
|
|
March 6, 2008
|
|
|
|
|
|
/s/ ALEJANDRO
P. BULGHERONI
Alejandro
P. Bulgheroni
|
|
Director
|
|
March 6, 2008
|
|
|
|
|
|
Carlos
A. Bulgheroni
|
|
Director
|
|
March 6, 2008
|
|
|
|
|
|
/s/ VICTOR
F. GERMACK
Victor
F. Germack
|
|
Director
|
|
March 6, 2008
|
|
|
|
|
|
/s/ JAMES
M. HENNESSY
James
M. Hennessy
|
|
Director
|
|
March 6, 2008
|
|
|
|
|
|
/s/ JOHN
E. MCCONNAUGHY, JR.
John
E. McConnaughy, Jr.
|
|
Director
|
|
March 6, 2008
|
|
|
|
|
|
/s/ ROBERT
E. NEDERLANDER
Robert
E. Nederlander
|
|
Director
|
|
March 6, 2008
|
|
|
|
|
|
Zane
Tankel
|
|
Director
|
|
March 6, 2008
|
|
|
|
|
|
/s/ LEONARD
TOBOROFF
Leonard
Toboroff
|
|
Director
|
|
March 6, 2008
|
96
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 Oil Quip
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).
|
97
|
|
|
|
|
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).
|
|
2
|
.20
|
|
Agreement and Plan of Merger by and among the Registrant, Bronco
Drilling Company, Inc. and Elway Merger Sub, Inc., dated as of
January 23, 2008 (incorporated by reference to
Exhibit 2.1 to the Registrants
Form 8-K
filed on January 24, 2008).
|
|
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).
|
98
|
|
|
|
|
Exhibit
|
|
Description
|
|
|
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).
|
|
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).
|
|
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
|
|
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
|
.8
|
|
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
|
.9*
|
|
Executive Employment Agreement, dated April 1, 2007, by and
between the Registrant and Munawar H. Hidayatallah (incorporated
by reference to Exhibit 10.3 to the Registrants
Form 8-K
filed on November 6, 2007).
|
|
10
|
.10*
|
|
Executive Employment Agreement, effective April 3, 2007, by
and between the Registrant and Victor M. Perez (incorporated by
reference to Exhibit 10.4 to the Registrants
Form 8-K
filed on November 6, 2007).
|
99
|
|
|
|
|
Exhibit
|
|
Description
|
|
|
10
|
.11*
|
|
Executive Employment Agreement, effective July 1, 2007, by
and between the Registrant and Terrence P. Keane (incorporated
by reference to Exhibit 10.1 to the Registrants
Form 8-K
filed on July 24, 2007).
|
|
10
|
.12*
|
|
Executive Employment Agreement, dated December 3, 2007, by
and between the Registrant and Theodore F. Pound III
(incorporated by reference to Exhibit 10.2 to the
Registrants
Form 8-K
filed on December 6, 2007).
|
|
10
|
.13*
|
|
Executive Employment Agreement, effective July 1, 2007, by
and between the Registrant and David K. Bryan (incorporated by
reference to Exhibit 10.1 to the Registrants
Form 8-K
filed on July 13, 2007).
|
|
10
|
.14*
|
|
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
|
.15*
|
|
Executive Employment Agreement, effective January 1, 2008,
by and between the Registrant and Mark C. Patterson
(incorporated by reference to Exhibit 10.1 to the
Registrants
Form 8-K
filed on February 25, 2008).
|
|
10
|
.16
|
|
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
|
.17
|
|
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
|
.18
|
|
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
|
.19
|
|
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
|
.20
|
|
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).
|
|
10
|
.21
|
|
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
|
.22
|
|
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
|
.23
|
|
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
|
.24
|
|
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
|
.25
|
|
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).
|
100
|
|
|
|
|
Exhibit
|
|
Description
|
|
|
10
|
.26
|
|
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
|
.27*
|
|
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
|
.28*
|
|
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
|
.29*
|
|
2006 Incentive Plan (incorporated by reference to
Exhibit 10.1 to the Registrants
Form 8-K
filed on September 18, 2006).
|
|
10
|
.30*
|
|
Form of Employee Restricted Stock Agreement pursuant to the
Registrants 2006 Incentive Plan (incorporated by reference
to Exhibit 10.2 to the Registrants
Form 8-K
filed on September 18, 2006).
|
|
10
|
.31*
|
|
Form of Employee Nonqualified Stock Option Agreement pursuant to
the Registrants 2006 Incentive Plan (incorporated by
reference to Exhibit 10.3 to the Registrants
Form 8-K
filed on September 18, 2006).
|
|
10
|
.32*
|
|
Form of Employee Incentive Stock Option Agreement pursuant to
the Registrants 2006 Incentive Plan (incorporated by
reference to Exhibit 10.4 to the Registrants
Form 8-K
filed on September 18, 2006).
|
|
10
|
.33*
|
|
Form of Non-Employee Director Restricted Stock Agreement
pursuant to the Registrants 2006 Incentive Plan
(incorporated by reference to Exhibit 10.5 to the
Registrants
Form 8-K
filed on September 18, 2006).
|
|
10
|
.34*
|
|
Form of Non-Employee Director Nonqualified Stock Option
Agreement pursuant to the Registrants 2006 Incentive Plan
(incorporated by reference to Exhibit 10.6 to the
Registrants
Form 8-K
filed on September 18, 2006).
|
|
10
|
.35*
|
|
Form of Performance Award Agreement pursuant to the
Registrants 2006 Incentive Plan (incorporated by reference
to Exhibit 10.5 to the Registrants
Form 8-K
filed on November 6, 2007).
|
|
10
|
.36
|
|
Second Amended and Restated Credit Agreement, dated as of
April 26, 2007, by and among the Registrant, 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 10.1 to the Registrants
Form 8-K
filed on May 10, 2007).
|
|
10
|
.37
|
|
First Amendment to Second Amended and Restated Credit Agreement,
dated as of December 3, 2007, by and among the Registrant,
the guarantors named thereto, Royal Bank of Canada and the
lenders named thereto (incorporated by reference to
Exhibit 10.1 to the Registrants
Form 8-K
filed on December 6, 2007).
|
|
10
|
.38
|
|
Amended and Restated Guaranty, dated April 26, 2007, by
each of the guarantors named thereto in favor of Royal Bank of
Canada, as administrative agent and collateral agent
(incorporated by reference to Exhibit 10.2 to the
Registrants
Form 8-K
filed on May 10, 2007).
|
|
10
|
.39
|
|
Amended and Restated Pledge and Security Agreement, dated
April 26, 2007, by the Registrant in favor of Royal Bank of
Canada, as administrative agent and collateral agent
(incorporated by reference to Exhibit 10.3 to the
Registrants
Form 8-K
filed on May 10, 2007).
|
|
10
|
.40
|
|
Credit Agreement, dated January 31, 2008, among the
Registrant, as lender, BCH Ltd., as borrower, and BCH Energy do
Brasil Servicos de Petroleo Ltda., as guarantor (incorporated by
reference to Exhibit 10.1 to the Registrants
Form 8-K
filed on February 6, 2008).
|
|
10
|
.41
|
|
Option to Purchase and Governance Agreement, dated
January 31, 2008, among the Registrant, BrazAlta Resources
Corp. and BCH Ltd. (incorporated by reference to
Exhibit 10.2 to the Registrants
Form 8-K
filed on February 6, 2008).
|
|
10
|
.42
|
|
Subordination Agreement, dated January 31, 2008, among the
Registrant, Standard Bank PLC, BCH Ltd., BCH Energy do Brasil
Servicos de Petroleo Ltda. and BrazAlta Resources Corp.
(incorporated by reference to Exhibit 10.3 to the
Registrants
Form 8-K
filed on February 6, 2008).
|
101
|
|
|
|
|
Exhibit
|
|
Description
|
|
|
10
|
.43
|
|
Form of Convertible Subordinated Secured Debenture (incorporate
by reference to Schedule E to Exhibit 10.1 to the
Registrants
Form 8-K
filed on February 6, 2008).
|
|
10
|
.44*
|
|
Agreement, dated April 1, 2007, by and between the
Registrant and David Wilde (incorporated by reference to
Exhibit 99.1 to the Registrants
Form 8-K
filed on April 3, 2007).
|
|
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 |
102