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, 2009
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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
(State or other jurisdiction
of
incorporation or organization)
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39-0126090
(I.R.S. Employer
Identification No.)
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5075 WESTHEIMER, SUITE 890,
HOUSTON, TEXAS
(Address of principal
executive offices)
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77056
(Zip
code)
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(713) 369-0550
Registrants telephone
number, including area code
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE
ACT:
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Title of Security:
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Name of Exchange:
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Common Stock, par value $0.01 per share
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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) of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted
electronically and posted on it corporate Website, if any, every
Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§ 232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files). Yes o No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
(§ 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrants
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this
Form 10-K
or any amendment to this
Form 10-K. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Rule
12b-2 of the
Exchange Act. (Check one):
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Large
accelerated
filer 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
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 $2.31 per share on June 30,
2009, as reported on the New York Stock Exchange, was
approximately $94,383,251.
As of February 26, 2010 there were 71,459,876 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 2010 annual meeting of
stockholders.
DEFINITIONS
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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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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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measurement-while-drilling |
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The technique used to measure direction and angle while drilling
a well. |
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mist pump |
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A drilling pump that uses mist as the circulation medium for
injecting small amounts of foaming agent, corrosion agent and
other chemical solutions into the well. |
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pulling rig |
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A type of well-servicing rig used to pull downhole equipment,
such as tubing, rods or the pumps from a well, and replace them
when necessary. A pulling rig is also used to set downhole tools
and perform lighter jobs. |
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service rig |
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A type of well-servicing rig which can function as either a
workover or as a pulling rig. |
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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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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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underbalanced 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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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. These
factors include, but are not limited to, the following:
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the impact of the weak economic conditions and the future impact
of such conditions on the oil and natural gas industry and
demand for our services;
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unexpected future capital expenditures (including the amount and
nature thereof);
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unexpected difficulties in integrating our operations as a
result of any significant acquisitions;
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adverse weather conditions in certain regions;
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the impact of political disturbances, war, or terrorist attacks
and changes in global trade policies;
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the availability (or lack thereof) of capital to fund our
business strategy
and/or
operations;
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the potential impact of the loss of one or more key employees;
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the effect of environmental liabilities that are not covered by
an effective indemnity or insurance;
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the impact of current and future laws;
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the impact of customer defaults and related bad debt expense;
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the potential impairment in the carrying value of goodwill and
other acquired intangible assets;
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the risks associated with doing business outside the U.S.,
including currency exchange rates;
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the effects of competition; and
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the effects of our indebtedness, which could adversely restrict
our ability to operate, could make us vulnerable to general
adverse economic and industry conditions, could place us at a
competitive disadvantage compared to competitors that have less
debt, and could have other adverse consequences
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Further information about the risks and uncertainties that may
impact us are described in Risk Factors beginning on
page 12 of this annual report. You
should read those sections carefully. You should not place undue
reliance on forward-looking statements, which speak only as of
the date of this annual report. We undertake no obligation to
update publicly any forward-looking statements in order to
reflect any event or circumstance occurring after the date of
this annual report or currently unknown facts or conditions or
the occurrence of unanticipated events.
PART I.
We provide services and equipment to oil and natural gas
exploration and production companies throughout the
U.S. including Texas, Louisiana, Arkansas, Pennsylvania,
Oklahoma, New Mexico, offshore in the Gulf of Mexico, and
internationally primarily in Argentina, Brazil, Bolivia and
Mexico. 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.
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Our growth strategy is focused on identifying and pursuing
opportunities in markets, products and services we believe will
grow faster than the overall oilfield services industry and
opportunities which we believe help us to mitigate cyclical risk
by diversifying our cash flow, both domestically and
internationally. 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 by expanding our geographic scope,
acquiring complementary property and equipment, hiring personnel
to service new regions and cross-selling our products and
services. Currently, as part of our strategic plan, we are
focusing on international growth opportunities. We also
continually assess the strategic fit of our existing businesses
and may divest businesses that are deemed not to fit with our
strategic plan or are not achieving the desired return on
investment.
Our
History
We were incorporated in 1913 under Delaware law. 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, which was sold in December 2001.
In May 2001, under new management, we embarked on a new course
of direction into the oilfield service industry. Since 2001, we
have completed 24 acquisitions, including six in 2005, six in
2006, four in 2007 and one in 2008. Our first series of
acquisitions became the backbone of our Oilfield Services
segment. In May 2001 we entered the underbalanced drilling
market and then in February of 2002 we entered the directional
drilling business and the tubular services business. In December
2004, we entered the production services business. We have
improved our product line offerings by completing additional
acquisitions for all product lines. We also disposed of some
nonstrategic assets in our production services business in June
2007 and in our tubular services business in August 2008.
In September 2004, we entered the Rental Services market which
we subsequently expanded with acquisitions in April 2005 and
January and December 2006. As a result of these acquisitions, we
are now a major provider of oilfield rental tools primarily in
the Gulf Coast region of the U.S.
In August 2006, we entered the Drilling and Completion business
with the acquisition of DLS Drilling, Logistics &
Services Corporation, or DLS, in Argentina. Subsequently, in
December 2008 we increased our business in this segment with the
acquisition of BCH Ltd, or BCH, in Brazil. In addition, we are
building a drilling presence in the U.S. by building new
drilling rigs.
As a result of these transactions, our prior results may not be
indicative of current or future operations. Segment and
geographic financial information appears in Item 8.
Financial Information Notes to Consolidated
Financial Statements Note 15.
Our
Industry
The oilfield 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 industry is 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 generally increased from 2004 through
2007. Activity in the U.S. Gulf of Mexico, however
decreased in the second half of 2007 due to the hurricane season
and relocation of offshore rigs to more attractive international
markets. Demand for our services for most of 2008 was generally
stable due to high oil and natural gas prices and the capital
expenditures of the exploration and production companies. As a
result, the number of active rigs drilling, or rig count, in the
U.S., according to Baker Hughes, peaked at 2,031 in August
of 2008 compared to 1,782 at the end of 2007. In the last
quarter of 2008, the rig count in the U.S. began to drop
due to the weakening U.S. economy, the decrease in oil and
natural gas
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prices and the turmoil in the financial markets which affected
the availability of capital for our customers. The Baker
Hughes U.S. rig count decreased to 876 in June 2009
and then gradually began to improve in response to increased
prices and more stable natural gas prices. As of
February 26, 2010, the Baker Hughes U.S. rig
count stood at 1,373.
Business
Segments
We conduct our operations through three principal segments:
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Oilfield Services. This segment includes the following oilfield
service divisions: directional drilling services, casing and
tubular services, underbalanced drilling services and production
services.
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Drilling and Completion. This segment includes drilling,
completion, workover and related services.
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Rental Services. This segment includes the rental of specialized
oilfield equipment.
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Oilfield Services. We utilize
state-of-the-art
equipment to provide well planning and engineering services,
directional drilling packages, downhole motor technology, well
site directional supervision, exploratory and development
re-entry drilling, downhole guidance services and other drilling
services to our customers, including measurement-while-drilling
(MWD) services. We provide compressed air equipment, chemicals
and other specialized products for underbalanced drilling and
production applications. We also 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. In addition, we provide a variety of quality
production-related rental tools and equipment and services,
including wire line support services and coiled tubing.
According to Baker Hughes, as of February 26, 2010, 67% of
the active drilling rigs in the U.S. were drilling
directionally
and/or
horizontally. We believe directional drilling offers several
advantages over conventional drilling including:
1) improvement of total cumulative recoverable reserves;
2) improved reservoir production performance beyond
conventional vertical wells; and 3) reduction of the number
of field development wells.
In 2007, we expanded our directional drilling capability by
completing three acquisitions for a total of approximately
$37.3 million. These were Coker Directional, Inc. (June
2007), Diggar Tools, LLC (July 2007) and substantially all
of the assets of Diamondback Oilfield Services, Inc. (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 currently maintain an inventory of
approximately 315 drilling motors. Our straight-hole motors
offer an opportunity to capture additional market share. We
currently provide directional drilling services primarily in
Texas, Pennsylvania, Louisiana, Oklahoma and offshore in the
Gulf of Mexico.
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 October 2007 by acquiring
Rebel Rentals, Inc., or Rebel, for a purchase price of
approximately $7.3 million. Rebel owns an inventory of
equipment used primarily for tubing installation services in the
South Louisiana and Gulf Coast regions. In August 2008, we sold
our drill pipe tong manufacturing assets for approximately
$7.5 million.
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. We currently have a
combined fleet of approximately 185 compressors, boosters
and foam units and we believe we are one of the 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. We currently
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provide underbalanced drilling services primarily in Arkansas,
Pennsylvania, New Mexico, Texas, Oklahoma and California.
Our production services product line is focused on coiled tubing
services and rental of various tools used in the production
process. We sold our capillary tubing units and related
equipment for approximately $16.3 million and reported a
gain of approximately $8.9 million in June 2007. The assets
sold represented a small portion of our Oilfield Services
segment. We currently provide production services primarily in
Texas, Arkansas, Louisiana and West Virginia.
Drilling and Completion. We provide drilling,
completion, workover and related services for oil and natural
gas wells. We operate out of the San Jorge, Cuyan, Neuquen,
Austral and Noroeste basins of Argentina and the Espirito Santo,
Potiguar, Reconcavo and Sergipe basins of Brazil and in Bolivia.
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.
We provide the rigs and drilling crews and we also provide rig
management services on a variety of rigs, consisting of
technical drilling assistance, personnel, repair and maintenance
services and drilling operation management services.
Our Drilling and Completion segment was established with the
acquisition of DLS in August 2006 for a purchase price of
approximately $114.5 million. We expanded our Drilling and
Completion segment with the acquisition of BCH, which operates
in Brazil. In 2008, we invested $40.0 million into BCH via
a 15% convertible subordinated secured debenture and we acquired
the common stock of BCH for a total purchase price of
$56.1 million. We currently operate a fleet of 76 land
rigs, including 17 drilling rigs and 47 service rigs (workover
and pulling units) in Argentina, eight drilling rigs and one
service rig in Brazil and three drilling rigs in Bolivia. In
2007, we placed orders for four drilling rigs and 16 service
rigs. All of the service rigs and one of the drilling rigs were
placed into service in Argentina at various dates in 2008. A
second drilling rig was activated in Argentina in March 2009.
The remaining two drilling rigs were substantially completed
during 2009. However, currently both of the drilling rigs are at
the original manufacturers facility for modification or
improvements and we are uncertain as to when these rigs will be
available for service. Additionally in 2008 we placed orders for
two 1600 horsepower drilling rigs for the U.S. market from
a different manufacturer. As a result of industry market
conditions in late 2008 and 2009, completion and delivery of
these rigs was suspended. It is currently expected that these
rigs will be delivered in the second and fourth quarters of 2010.
Rental Services. We provide specialized
oilfield 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 primarily in Texas,
Louisiana, Oklahoma, offshore in the Gulf of Mexico and
internationally in Mexico, Columbia and Egypt.
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, products and services 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, casing and tubing,
underbalanced drilling, drilling and completion and rental
services. We also have an established presence in certain
international markets which provide additional opportunities for
growth and diversification of cash flow.
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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, Arkansas, Pennsylvania,
Oklahoma, New Mexico, offshore in the Gulf of Mexico, Argentina,
Brazil, Bolivia and Mexico. Our largest customers include Pan
American Energy LLC Sucursal Argentina, or Pan American Energy,
Petroleo Brasileiro S.A, or Petrobras, Repsol-YPF, Chesapeake
Energy, Apache Corporation, Anadarko Petroleum, Occidental
Petroleum, BP, Devon Energy, and Materiales y Equipo Petroleo.
Since 2002, we have broadened our customer base as a result of
our acquisitions, technical expertise and reputation for quality
customer service and by providing customers with technologically
advanced equipment and highly skilled operating personnel.
Successful execution of growth strategy. Over
the past seven years, we have grown both organically and through
successful acquisitions of competing businesses. Since 2001, we
have completed 24 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, through our capital
expenditures program, 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 three business segments. We believe
that our product and service offerings and geographical presence
through our three business segments provide us with diverse
sources of cash flow. Our acquisition of DLS in Argentina in
August 2006 and our acquisition of BCH in Brazil at the end of
2008, increased our international presence and we believe,
provides more stable long-term contracts and revenue streams
when compared to the volatility in the U.S. domestic
market. Additionally, the international markets are primarily
driven by oil prices compared to the natural gas focus of the
U.S. domestic market.
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.
Business
Strategy
The key elements of our long-term strategy include:
Mitigate cyclical risk through balanced
operations. We strive to mitigate cyclical risk
across our lines of business 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. A key part of our strategy has been to
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, Arkansas, Louisiana and Pennsylvania in order
to enhance our proximity to customers and more efficiently serve
their needs. We have redeployed our assets to the growing land
shale plays such as the Marcellus (principally in Pennsylvania),
the Haynesville (Louisiana), the Bakken (North Dakota) and the
Eagleford in South Texas. Internationally, our acquisition of
DLS expanded our geographic footprint into Argentina and Bolivia
and our acquisition of BCH expanded our geographic footprint
into Brazil. We expect to increase our international presence
principally in South America, Mexico, the Middle East and North
Africa. We will continue to evaluate locations to conveniently
serve our customers and exploit emerging markets.
Prudently pursue strategic acquisitions. To
complement our organic growth, we have historically 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. As
part of our long-term growth strategy, we continue to review
complementary acquisitions, as well as capital expenditures to
enhance our ability to increase cash flows
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from our existing assets. Future acquisitions will be subject to
an improved outlook for our products and services and improved
availability of capital on reasonable terms.
Expand products and services provided in existing operating
locations. Since the beginning of 2005, we have
invested approximately $403.2 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 range of products and services in many geographic
locations. Recent economic conditions have led us to reduce our
capital spending and operating expenses consistent with the
decline in demand for our services as producers curtailed their
drilling activity in 2009.
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.
Customers
In 2009, 2008 and 2007, one of our customers, Pan American
Energy, represented approximately 35.5%, 28.5% and 20.7% 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, one of our
directors, may be deemed to indirectly beneficially own 50% of
the outstanding capital stock of Bridas Corporation and is a
member of the Management Committee of Pan American Energy. 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. However, the cost of
acquiring new equipment to expand our business could increase as
demand for equipment in the industry increases.
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.
We believe that there are five major directional drilling
companies, Schlumberger, Halliburton, Baker Hughes, Smith
International (Pathfinder) and Weatherford, that market both
worldwide and in the U.S. 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 U.S. 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.
Our five largest competitors in the Drilling and Completion
segment, which operate primarily in Argentina, are Servicios
WellTech, Ensign Energy Services, Nabors and
Helmerich & Payne, and San Antonia Global Ltd in
Brazil.
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The Rental Services business is highly fragmented with hundreds
of companies offering various rental tool services. Our largest
competitors include Weatherford, Quail Rental Tools, Knight
Rental Tools, Superior Energy Services (Workstrings) and Smith
International (Thomas Tools).
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 Drilling and Completion 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 26, 2010, we had
approximately 3,174 employees. Almost all of our Drilling
and Completion operations located in Argentina and Brazil are
subject to collective bargaining agreements. We believe that we
maintain a satisfactory relationship with the unions to which
our Drilling and Completion 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 U.S. Gulf of Mexico and in Mexico may be
adversely affected by hurricanes and tropical storms, resulting
in reduced demand for our services. For example, from 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 2008, Hurricanes Gustav and Ike disrupted our
operations along the Texas and Louisiana Gulf Coast and the East
Texas/West Louisiana corridor. In addition, our customers
operations in the Mid-Continent and Rocky Mountain regions of
the U.S. 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
11
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.
Available
Information
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 web site at www.alchenergy.com as soon
as reasonably practicable after we electronically file or
furnish them to the Securities and Exchange Commission, or SEC.
Our Board of Directors has documented its governance practices
by adopting several corporate governance policies. These
governance policies, including our corporate governance
principles and our code of business ethics and conduct, as well
as the charters for the committees of our Board (Audit
Committee, Compensation Committee, Corporate Governance and
Nominating and Finance Committee) may be viewed on the investor
relations section of our website. Copies of such documents will
be sent to stockholders free of charge upon written request of
the corporate secretary at the address shown on the cover page
of this
Form 10-K.
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.
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 Industry
Global
political, economic and market conditions could negatively
impact our business.
Our operations are affected by global political, economic and
market conditions and the condition of the oil and natural gas
industry. Our operating results and the forward-looking
information we provide are based on our current assumptions
about oil and natural gas supply and demand, oil and natural gas
prices, rig count and other market trends. Our assumptions on
these matters are in turn based on currently available
information, which is subject to change. The oil and natural gas
industry is extremely volatile and subject to change based on
political and economic factors outside our control. This
volatility caused oil and natural gas companies and drilling
contractors to change their strategies and expenditure levels
late in 2008 and in 2009. We have experienced in the past, and
expect to experience in 2010, significant fluctuations in
operating results based on these changes.
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 mergers among oil and natural gas
companies have reduced the number of available customers. The
competitive environment has also intensified, late in 2008 and
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2009, due to the decrease in the U.S. rig count and the
demand for our services. 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.
Risks
Associated With Our Company
Our
business depends on spending by the oil and natural gas
industry, and this spending and our business may be adversely
affected by industry and financial market conditions that are
beyond our control.
Demand for our products and services is dependent upon the level
of oil and natural gas exploration and development activities
of, and the corresponding capital spending by, oil and natural
gas companies. The industrys willingness to explore,
develop and produce depends largely upon the availability of
attractive drilling prospects, the price of oil and natural gas,
and the prevailing view of future product prices. Oil and
natural gas prices have been extremely volatile and have
declined significantly from their historic highs in mid-2008.
Any prolonged reduction in oil and natural gas prices will
depress levels of exploration, development, and production
activity. Such price declines reduce drilling activity and
demand for our services, which could lead to lower pricing for
our products and services. Accordingly, prolonged periods of
lower drilling activity and the reduction in our customers
expenditures could have a materially adverse effect on our
financial condition, results of operations and cash flows.
Oil and natural gas prices depend on many factors beyond our
control, including the following:
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economic conditions in the U.S. 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;
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advances in exploration, development and production
technologies; and
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the availability of capital for exploration and production
companies.
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Limitations on the availability of capital, or higher costs of
capital, for financing expenditures may cause these and other
oil and natural gas producers to make additional reductions to
capital budgets in the future even if commodity prices remain at
historically high levels.
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 exploration
business in the U.S., Argentina, Brazil, Mexico and elsewhere.
Historically, we have been dependent upon a few customers for a
significant portion of our revenues. In 2009, 2008 and 2007, one
of our customers, Pan American Energy represented 35.5%, 28.5%
and 20.7% of our consolidated revenues, respectively. Pan
American Energy also contributes a majority of the revenue
derived from our Drilling and Completion operations. In 2009,
2008 and 2007, Pan American Energy represented 59.2%, 66.0% and
51.0% of our Drilling and Completion revenues, respectively.
13
The strategic agreement with Pan American Energy 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 the revenues of our Drilling and Completion operations are
currently generated under this agreement, the revenues and
earnings of our Drilling and Completion operations 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. In addition, our results of
operations could be materially adversely affected if any of our
major customers terminates its contracts with us, fails to renew
its existing contracts or refuses to award new contracts to us
and we are unable to enter into contracts with new customers at
comparable rates.
This concentration of customers may increase our overall
exposure to credit risk. Our 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
customers may seek to cancel or renegotiate some of our Drilling
and Completion contracts during periods of depressed market
conditions or if we experience operational
difficulties.
Substantially all of our Drilling and Completion business
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.
If we
are unable to renew or obtain new and favorable contracts for
rigs whose contracts are expiring or are terminated, our
revenues and profitability could be materially
reduced.
We have a number of contracts that will expire in 2010 and 2011.
Our ability to renew these contracts or obtain new contracts and
the terms of any such contracts will depend on market
conditions. We may be unable to renew our expiring contracts or
obtain new contracts for the rigs under contracts that have
expired or been terminated, and the dayrates under any new
contracts may be substantially below the existing dayrates,
which could materially reduce our revenues and profitability.
Failure
to secure a drilling contract prior to deployment of a rig under
construction or any other rigs we may construct in the future
prior to their deployment could adversely affect our future
results of operations.
We have two rigs being constructed that are scheduled for
delivery in second and fourth quarters of 2010. We have not yet
obtained a drilling contract for these rigs. Our failure to
secure a drilling contract for any rig under construction prior
to its deployment could adversely affect our results of
operations and financial condition.
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
14
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 revenues and profitability.
The
loss of the services of key executives or our failure to attract
and retain skilled workers and key personnel could hurt our
operations.
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 of
the Board, Munawar H. Hidayatallah. We do not maintain key man
insurance on any of our personnel.
In addition, companies in our industry, including us, are
dependent upon the available labor pool of skilled employees.
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. 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, increases in wage rates 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.
The
operations and financial condition of our Drilling and
Completion business could be affected by union activity and
general labor unrest. Additionally, the labor expenses of our
Drilling and Completion business could increase as a result of
governmental regulation of payments to employees.
In Argentina and Brazil, labor organizations have substantial
support and have considerable political influence. The demands
of labor organizations in Argentina 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
Drilling and Completion business will 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. It is possible the government will adopt
measures that will increase salaries or require our Drilling and
Completion business to provide additional benefits, which would
increase our costs and potentially reduce our profitability,
cash flow
and/or
liquidity. In addition, in many of the countries in which we
operate, our workforce has certain compensation and other rights
arising from our various collective bargaining agreements and
from statutory requirements of those countries relating to
involuntary terminations. If we choose to cease operations in
one of those countries or if market conditions reduce the demand
for our drilling services in such a country, we could incur
costs, which may be material, associated with workforce
reductions.
Rig
upgrade, refurbishment and construction projects are subject to
risks, including delays and cost overruns, which could have an
adverse effect on our results of operations and cash
flows.
Our Drilling and Completion business 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
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make substantial expenditures for the construction of new rigs.
Rig upgrade, refurbishment and construction projects are subject
to the risks of delay or cost overruns inherent in any large
construction project.
We have two land drilling rigs that were substantially completed
in 2009. One of these rigs worked for a limited period before
encountering certain operational malfunctions. Currently both
rigs are at the original manufacturers facility undergoing
modifications or improvements. At this time we cannot be assured
that these rigs will not require significant expenditures to
bring them to satisfactory operational standards and we are
uncertain as to when these rigs will be available for service.
We have two additional drilling rigs scheduled to be delivered
in 2010 by a different manufacturer.
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 our debt
obligations.
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 from time to time been adversely affected by floods,
hurricanes and tropical storms, resulting in reduced demand for
our services. In 2008, Hurricanes Gustav and Ike disrupted our
operations along the Texas and Louisiana Gulf Coast and the East
Texas/West Louisiana corridor. Further, our customers
operations in the Mid-Continent and Rocky Mountain regions of
the U.S. 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.
We
have recorded substantial goodwill as the result of our
acquisitive nature and as such goodwill is subject to periodic
reviews of impairment.
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. We conduct periodic reviews of goodwill for
impairment in value. Any impairments would result in a non-cash
charge against earnings in the period reviewed, which may or may
not create a tax benefit, and would have a corresponding
decrease in stockholders equity.
We reviewed goodwill at December 31, 2009 and recorded no
impairment but based on our review of goodwill at
December 31, 2008 we recorded an impairment of
$115.8 million, which was all of our goodwill for the
Rental Services segment as well as the impairment of goodwill
associated with our Tubular Services and Production Services
businesses within our Oilfield Services segment. In the event
that market conditions deteriorate or we have a prolonged
downturn, we may be required to record an additional impairment
of goodwill and such impairment could be material.
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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 may make additional strategic
acquisitions of privately held businesses. 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. 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 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:
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could harm our business and operating results,
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cause investors to lose confidence in the accuracy and
completeness of our financial reports,
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have a material adverse effect on the trading price of our
common stock or
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adversely affect our ability to timely file our periodic reports
with the SEC.
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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, which we refer to
as our 9.0% senior notes, our outstanding 8.5% senior
notes due 2017, which we refer to as our 8.5% 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 9.0% senior notes, our 8.5% senior notes or our
other debt were to occur, we cannot assure you that we would
have sufficient funds to repay such obligations.
Our
strategic plan may not achieve the intended
results.
In 2009, we filed a five-year plan outlining our strategic
decision to focus our geographical expansion in the
international markets, particularly Columbia, Mexico, Saudi
Arabia, Libya, Egypt and the MENA region. As part of this plan,
we have begun to transfer idle assets overseas. We may not be
successful in executing our strategy. We may not be able to find
suitable international acquisitions. In addition, engaging in
any international acquisition will incur a variety of costs, and
we may never realize the anticipated benefits of any such
acquisition. We may need additional financing in order to fund
additional acquisitions. Acquisition efforts can consume
significant management attention and require substantial
expenditures, which could detract from our other businesses. In
addition, we may devote resources to potential acquisitions that
are never completed. If not successful in achieving our
strategic plan may have a material adverse effect on our
financial condition, liquidity and results of operations.
We do
business in international jurisdictions whose political and
regulatory environments and compliance regimes differ from those
in the U.S:
A significant amount of our revenue is attributable to
operations in foreign countries. These activities accounted for
approximately 62.8% of our consolidated revenue in the year
ended December 31, 2009. Risks associated with our
operations in foreign areas include, but are not limited to:
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political instability, terrorist acts, war and civil
disturbances;
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changes in laws or policies regarding the award of contracts;
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the inability to collect or repatriate currency, income, capital
or assets;
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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; and
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new economic and tax policies.
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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.
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.
Additionally, in some jurisdictions we are subject to foreign
governmental regulations favoring or requiring the awarding of
contracts to local contractors or requiring foreign contractors
to employ citizens of, or purchase supplies from, a particular
jurisdiction. These regulations may adversely affect our ability
to compete.
Our international business operations also include projects in
countries where governmental corruption has been known to exist.
We are subject to the anti-bribery restrictions of the Foreign
Corrupt Practices Act, which make it illegal to give anything of
value to foreign officials or employees or agents of nationally
owned oil companies in order to obtain or retain any business or
other advantage.
Violations of these laws could result in monetary and criminal
penalties against us or our subsidiaries and could damage our
reputation and, therefore, our ability to do business.
Devaluation
of the Argentine Peso, the Mexican Peso or the Brazilian Real
could adversely affect our results of operations.
These currencies have been subject to significant devaluation in
the past and may be subject to significant fluctuations in the
future. Given the economic and political uncertainties which
have historically existed 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. Similar economic and political turmoil in
Mexico and Brazil could also expose us to unpredictable currency
exchange rates in these countries that may result in 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
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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.
An
increase in inflation in Argentina could have a material adverse
effect on our results of operations.
Historically, the devaluation of the Argentine Peso has created
pressures on the domestic price system that generated high rates
of inflation. We cannot assure you that inflation rates will
remain stable in the future. Significant inflation in Argentina
could have a material adverse effect on our results of
operations and financial condition.
We are
subject to numerous governmental laws and regulations, including
those that may impose significant liability on us for
environmental and natural resource damages.
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. For example, many aspects of our
Drilling and Completion 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 Drilling and
Completion business 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.
Environmental
liabilities relating to discontinued operations 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, or EPA, 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. This product liability trust
is in the process of being dissolved. We believe that product
liability claims relating to our business prior to bankruptcy
are barred by applicable bankruptcy law. 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
19
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.
Substantially all of our Drilling and Completion 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
Our
common stock price has been volatile, which could adversely
affect our business and cause our stockholders to suffer
significant losses
The trading price of our common stock has historically
fluctuated significantly. For example, during the twelve months
ended December 31, 2009, the high sales price per share of
our common stock as reported on the New York Stock Exchange was
$6.07 and the low sales price per share was $0.71. The
volatility of our stock price depends upon many factors
including:
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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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illiquidity of the market for our common stock;
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developments specifically affecting the economies in Latin
America;
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sales of common stock by existing stockholders;
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our substantial indebtedness; and
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other developments affecting us or the financial markets.
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20
A reduced stock price will result in a loss to investors and
will adversely affect our ability to issue stock to fund our
activities.
Substantial
sales of our common stock could adversely affect our stock
price.
Sales of a substantial number of shares of our common stock, or
the perception that such sales could occur, could adversely
affect the market price of our common stock.
We had 71,459,876 shares of common stock outstanding as of
February 26, 2010 and 14,202,146 shares reserved for
issuance upon conversion of our convertible preferred stock. At
February 26, 2010, we had reserved an additional
8,552,387 shares of common stock for issuance under our
equity compensation plans, of which 701,732 shares were
issuable upon the exercise of outstanding options with a
weighted average exercise price of $6.31 per share. As of the
same date, there were a total of 433,960 shares of
non-performance-based restricted stock and 481,666 shares
of performance-based restricted stock outstanding under our
equity compensation plans.
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 over 15% of our
common stock as of February 26, 2010 In addition, in
connection with our backstopped rights offering, we entered into
a registration rights agreement with Lime Rock who hold
19,889,044 shares of our common stock and
36,393 shares of our preferred stock as of
February 26, 2010, which are convertible into
14,202,146 shares of our common stock. Pursuant to those
agreements, the DLS sellers and Lime Rock are entitled to
certain rights with respect to the registration of the sale of
such common 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.
The
DLS sellers and Lime Rock control substantial ownership stakes
in us and have board nomination rights, and they are therefore
able to exert significant influence on our affairs and actions,
including matters submitted for a stockholder
vote.
The DLS sellers collectively hold over 15% of our issued and
outstanding common stock as of February 26, 2010. 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.
Lime Rock currently holds 19,889,044 shares of our common
stock, representing approximately 27.8% of our issued and
outstanding shares as of February 26, 2010. In addition,
Lime Rock owns 36,393 shares of preferred stock which are
convertible into 14,202,146 shares of our common stock.
Through its ownership of common and preferred stock, Lime Rock
controls, in the aggregate, 35% of our stockholders voting
power. Pursuant to the investment agreement we entered into with
Lime Rock, Lime Rock has the right to designate up to four
people to serve on our board of directors based upon the amount
of our common stock Lime Rock and its affiliates beneficially
own (counting the preferred stock on an as converted basis).
Lime Rock has the right to designate four nominees for election
to our board of directors and have designated two directors at
this time. As a result, the DLS sellers and Lime Rock each have
considerable influence over the composition of our board of
directors, our future operations and strategy and our future
corporate actions, including matters submitted for a stockholder
vote.
Following the earlier of June 26, 2012 and the date on
which the transfer restrictions set forth in the Investment
Agreement expire, Lime Rock will not be prohibited from
acquiring additional shares of our common stock or converting
its shares of preferred stock, even if such conversion will
result in its control of more than 35% of our stockholders
voting power. As a result, Lime Rocks influence over us
may increase in the future.
21
Conflicts of interest between the DLS sellers and Lime Rock, 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 Lime Rock or other matters. In
addition, the interests of the DLS sellers or Lime Rock
regarding any proposed merger or sale may differ from the
interests of other holders of our securities.
The board designation rights described above could 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.
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.
Risks
Associated With Our Indebtedness
We are
a holding company, and as a result we are dependent on dividends
from our subsidiaries to meet our obligations, including with
respect to the notes.
We are a holding company and do not conduct any business
operations of our own. Our principal assets are the equity
interests we own in our operating subsidiaries, either directly
or indirectly. As a result, we are dependent upon cash
dividends, distributions or other transfers we receive from our
subsidiaries to repay any debt we may incur, and to meet our
other obligations. The ability of our subsidiaries to pay
dividends and make payments to us will depend on their operating
results and may be restricted by, among other things, applicable
corporate, tax and other laws and regulations and agreements of
those subsidiaries. For example, the corporate laws of some
jurisdictions prohibit the payment of dividends by any
subsidiary unless the subsidiary has a capital surplus or net
profits in the current or immediately preceding fiscal year.
Payments or distributions from our subsidiaries also could be
subject to restrictions on dividends or repatriation of earnings
under applicable local law, and monetary transfer restrictions
in the jurisdictions in which our subsidiaries operate. Our
subsidiaries are separate and distinct legal entities. Any right
that we have to receive any assets of/or distributions from any
subsidiary upon its bankruptcy, dissolution, liquidation or
reorganization, or to realize proceeds from the sale of the
assets of any subsidiary, will be junior to the claims of that
subsidiarys creditors, including trade creditors.
We
have a substantial amount of debt, which could adversely affect
our financial health and prevent us from making principal and
interest payments on the notes and our other debt.
At December 31, 2009, we have approximately
$492.2 million of consolidated total indebtedness
outstanding and approximately $85.8 million of additional
secured borrowing capacity available under our credit agreement.
In addition, we may incur substantial additional debt in the
future. Each of the indentures governing our 9.0% senior
notes and our 8.5% senior notes permits 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 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
22
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 9.0% senior notes, our 8.5% 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.
The turmoil in the financial markets since mid-2008 and its
impact on the financial condition of the banking sector and
other lenders, has significantly reduced access to the capital
markets. It is uncertain to what extent capital will be
available to us in the future and at what cost. If we are unable
to obtain financing, we will be unable to acquire additional
businesses and may be unable to meet our obligations under our
credit agreement, our 9.0% senior notes, our
8.5% senior notes or any other debt securities we may offer.
The
indenture governing our 9.0% senior notes, the indenture
governing our 8.5% senior notes and our credit agreement
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 indenture governing our 9.0% senior notes, the
indenture governing our 8.5% senior notes and our credit
agreement 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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Our revolving credit agreement requires us to maintain specified
financial ratios. If we fail to comply with the financial ratio
covenants, it could limit or eliminate the availability under
our revolving credit agreement. Our ability to maintain such
financial ratios 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. The
decrease in demand for our services experienced in 2009
adversely impacts our ability to maintain or meet such financial
ratios.
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. A
breach of these covenants could result in a default under the
indentures governing our 9.0% senior notes, our
8.5% senior notes and any other debt securities we may
offer and/or
the
23
credit agreement. If there were an event of default under any of
the indentures 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.
|
UNRESOLVED
STAFF COMMENTS
|
None.
The following table describes the location and general character
of the principal physical properties used in each of our
companys businesses as of February 26, 2010. Our
principal executive office is rented and located in Houston,
Texas and the table below presents all of our material operating
locations and whether the property is owned or leased.
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Business Segment
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Location
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Owned/Leased
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Oilfield Services
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Searcy, Arkansas
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Leased
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Broussard, Louisiana
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Owned
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Youngsville, Louisiana
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Owned
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Carlsbad, New Mexico
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Leased
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Farmington, New Mexico
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Leased
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Elk City, Oklahoma
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Leased
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McAlester, Oklahoma
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Leased
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Oklahoma City, Oklahoma
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Leased
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Mt Morris, Pennsylvania
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Leased
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Conroe, Texas
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Leased
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Corpus Christi, Texas
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Leased 2 locations
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Fort Stockton, Texas
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Leased
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Houston, Texas
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Leased
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Kilgore, Texas
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Leased
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Longview, Texas
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Leased
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San Angelo, Texas
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Leased
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Drilling and Completion
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Buenos Aires, Argentina
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Leased
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Comodoro Rivadavia, Argentina
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Owned
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Neuquen, Argentina
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Owned
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Rincon de los Sauces, Argentina
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Owned
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Tartagal, Argentina
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Owned
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Santa Cruz, Bolivia
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Leased
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Catu, Bahia, Brazil
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Owned
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Aracuja, Sergipe, Brazil
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Leased
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Macae, Rio de Janeiro, Brazil
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Leased
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Mossoro, Rio Grande de Norte, Brazil
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Leased
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Rio de Janeiro, Rio de Janeiro, Brazil
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Leased
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Sao Mateus, Espirito Santo, Brazil
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Leased
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Rental Services
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Victoria, Texas
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Owned
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Broussard, Louisiana
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Leased
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Morgan City, Louisiana
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Owned
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24
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ITEM 3.
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LEGAL
PROCEEDINGS
|
On June 29, 1987, we filed for reorganization under
Chapter 11 of the U.S. Bankruptcy Code. Our plan of
reorganization was confirmed by the Bankruptcy Court after
acceptance by our creditors and stockholders, and was
consummated on December 2, 1988.
At confirmation of our plan of reorganization, the
U.S. 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, some of
which have been dissolved, and retain no responsibility for the
assets transferred to or distributions made or to be made by
such trusts pursuant to our plan of reorganization.
As part of our plan of reorganization, we settled with the EPA
on 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, had responded to
such claims, generally, by informing claimants that our
liabilities were discharged in the bankruptcy. Each of such
claims have 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.
We have assumed 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 had previously been referred to and handled by a special
products liability trust formed to be responsible for such
claims in connection with our reorganization. Such products
liability trust is in the process of being dissolved. As with
environmental claims, we do not believe we are liable for
product liability claims relating to our business prior to our
bankruptcy. However, there can be no assurance that we will not
be subject to material product liability claims in the future.
25
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.
PART II
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ITEM 5.
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MARKET
FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES.
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MARKET
PRICE INFORMATION
Our common stock is traded on the New York Stock Exchange under
the symbol ALY. The following table sets forth high
and low sale prices of our common stock reported on the New York
Stock Exchange.
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Calendar Quarter
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High
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Low
|
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2009
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First Quarter
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$
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6.07
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$
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0.71
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Second Quarter
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4.53
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1.80
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Third Quarter
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4.94
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2.01
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Fourth Quarter
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4.87
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3.06
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2008
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First Quarter
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$
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15.21
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$
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9.56
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Second Quarter
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18.50
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13.01
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Third Quarter
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18.00
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9.76
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Fourth Quarter
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12.68
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3.69
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Holders
As of February 26, 2010, there were approximately 878
holders of record of our common stock. On February 26,
2010, the closing price for our common stock reported on the New
York Stock Exchange was $3.78 per share.
Dividends
No dividends were declared or paid on our common stock during
the past two years, and no dividends are anticipated to be
declared or paid in the foreseeable future on such common stock.
Our credit facilities and the indentures governing our senior
notes restrict our ability to pay dividends on our common stock.
26
EQUITY
COMPENSATION PLAN INFORMATION
The following table provides information as of December 31,
2009 with respect to the shares of our common stock that may be
issued under our existing equity compensation plans.
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|
|
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|
|
|
Number of Securities
|
|
|
|
|
|
|
|
|
|
Remaining Available
|
|
|
|
Number of
|
|
|
|
|
|
for Future Issuance
|
|
|
|
Securities to be
|
|
|
Weighted
|
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|
Under Equity
|
|
|
|
Issued Upon
|
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|
Average Exercise
|
|
|
Compensation Plans
|
|
|
|
Exercise of
|
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|
Price of
|
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|
(excluding
|
|
|
|
Outstanding
|
|
|
Outstanding
|
|
|
securities
|
|
|
|
Options, Warrants
|
|
|
Options, Warrants
|
|
|
reflected in first
|
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Plan Category
|
|
And Rights
|
|
|
and Rights
|
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column)
|
|
|
Equity compensation plans approved by security holders
|
|
|
1,179,398
|
|
|
$
|
6.27
|
|
|
|
7,454,989
|
|
Equity compensation plans not approved by security holders
|
|
|
4,000
|
|
|
$
|
13.75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,183,398
|
|
|
$
|
6.31
|
|
|
|
7,454,989
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
Compensation Plans Not Approved By Security Holders
These plans comprise the following:
In 1999 and 2000, the Board compensated 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, 2009, 4,000 of these options
remain outstanding.
27
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 last five years. Our common stock was a component of the
Russell 2000 during the year ended December 31, 2009. 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 December 31,
2004 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.
*$100 invested on 12/31/04 in stock or index, including
reinvestment of dividends.
Fiscal year ending December 31.
COMPARISON
OF CUMULATIVE TOTAL RETURN OF ONE OR MORE
COMPANIES, PEER GROUPS, INDUSTRY INDEXES AND/OR BROAD
MARKETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ending
|
|
Company/Index/Market
|
|
12/31/2004
|
|
|
12/31/2005
|
|
|
12/30/2006
|
|
|
12/29/2007
|
|
|
12/31/2008
|
|
|
12/31/2009
|
|
Allis-Chalmers Energy Inc.
|
|
|
100.00
|
|
|
|
254.49
|
|
|
|
470.20
|
|
|
|
301.02
|
|
|
|
112.24
|
|
|
|
80.18
|
|
|
Russell 2000 Index
|
|
|
100.00
|
|
|
|
104.55
|
|
|
|
123.76
|
|
|
|
121.82
|
|
|
|
80.66
|
|
|
|
102.58
|
|
|
Oil & Gas Equipment/Svcs
|
|
|
100.00
|
|
|
|
151.13
|
|
|
|
177.92
|
|
|
|
254.37
|
|
|
|
102.83
|
|
|
|
166.75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28
|
|
ITEM 6.
|
SELECTED
FINANCIAL DATA.
|
The following selected historical financial information for each
of the five years ended December 31, 2009, 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,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Statement of Operations Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
506,253
|
|
|
$
|
675,948
|
|
|
$
|
570,967
|
|
|
$
|
310,964
|
|
|
$
|
108,022
|
|
Impairment of goodwill
|
|
$
|
|
|
|
$
|
115,774
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Income (loss) from operations
|
|
$
|
(8,547
|
)
|
|
$
|
(13,520
|
)
|
|
$
|
124,782
|
|
|
$
|
67,730
|
|
|
$
|
13,518
|
|
Net income (loss) from continuing operations
|
|
$
|
(21,190
|
)
|
|
$
|
(39,464
|
)
|
|
$
|
50,440
|
|
|
$
|
35,626
|
|
|
$
|
7,175
|
|
Net income (loss) attributed to common stockholders
|
|
$
|
(22,492
|
)
|
|
$
|
(39,464
|
)
|
|
$
|
50,440
|
|
|
$
|
35,626
|
|
|
$
|
7,175
|
|
Per Share Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.42
|
)
|
|
$
|
(1.13
|
)
|
|
$
|
1.48
|
|
|
$
|
1.73
|
|
|
$
|
0.48
|
|
Diluted
|
|
$
|
(0.42
|
)
|
|
$
|
(1.13
|
)
|
|
$
|
1.45
|
|
|
$
|
1.66
|
|
|
$
|
0.44
|
|
Weighted average number of common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
53,669
|
|
|
|
35,052
|
|
|
|
34,158
|
|
|
|
20,548
|
|
|
|
14,832
|
|
Diluted
|
|
|
53,669
|
|
|
|
35,052
|
|
|
|
34,701
|
|
|
|
21,410
|
|
|
|
16,238
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Balance Sheet Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,080,620
|
|
|
$
|
1,115,051
|
|
|
$
|
1,053,585
|
|
|
$
|
908,326
|
|
|
$
|
137,355
|
|
Long-term debt classified as:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
$
|
17,027
|
|
|
$
|
14,617
|
|
|
$
|
6,434
|
|
|
$
|
6,999
|
|
|
$
|
5,632
|
|
Long-term
|
|
$
|
475,206
|
|
|
$
|
579,044
|
|
|
$
|
508,300
|
|
|
$
|
561,446
|
|
|
$
|
54,937
|
|
Redeemable convertible
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock
|
|
$
|
34,183
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Stockholders equity
|
|
$
|
483,647
|
|
|
$
|
383,409
|
|
|
$
|
414,329
|
|
|
$
|
253,933
|
|
|
$
|
60,875
|
|
Book value per common share
|
|
$
|
6.78
|
|
|
$
|
10.75
|
|
|
$
|
11.80
|
|
|
$
|
8.99
|
|
|
$
|
3.61
|
|
|
|
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
29
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.
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 U.S., including Texas,
Louisiana, Arkansas, Pennsylvania, Oklahoma, New Mexico,
offshore in the Gulf of Mexico, and internationally, primarily
in Argentina, Brazil, Bolivia and Mexico. We operate in three
sectors of the oil and natural gas service industry: Oilfield
Services; Drilling and Completion and Rental 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 rig count is an important indicator of activity levels in
the oil and natural gas industry. According to the Baker Hughes
rig count, the rig count in the U.S. increased from 862 as
of December 27, 2002 to a peak of 2,031 in August 2008.
However the rig count began to decline in the fourth quarter of
2008 and continued to decline in 2009 reaching a low of 876 rigs
in June 2009. The rapid decline in the U.S. rig count
experienced in 2009 was due to the economic slowdown in the
U.S. and the decrease in natural gas and oil prices which
impacted the capital expenditures of our customers. The turmoil
in the financial markets and its impact on the availability of
capital for our customers also affected drilling activity in the
U.S. The rig count has since increased to 1,373 as of
February 26, 2010 due to the recovery of oil prices and the
stabilization of natural gas prices. The directional and
horizontal rig count in the U.S., according to Baker Hughes, was
914 as of February 26, 2010 compared to 692 one year
earlier. According to Baker Hughes, the offshore Gulf of Mexico
rig count was 44 rigs at February 26, 2010 from 51 at
February 27, 2009.
While our revenue can be correlated to the rig count, our
operating costs do not fluctuate in direct proportion to changes
in revenues. Our operating expenses consist 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 operating income as a
percentage of revenues is generally affected by our level of
revenues.
Company
Outlook
We believe that our revenue and operating income for all of our
operating segments will improve in 2010. Our Oilfield Service
segment is heavily based on oil and natural gas activity in the
U.S. and a good indicator of that activity is the
U.S. rig count. The Baker Hughes rig count in the
U.S. for the first eight weeks of 2010 decreased to an
average of 1,308 compared to an average of 1,428 for the first
eight weeks of 2009, but has increased when compared to the
average rig count for the fourth quarter of 2009 of 1,115 or the
average rig count of 1,079 for all of 2009. That favorable trend
in rig count should result in improved demand and pricing for
our Oilfield Services segment. Our Rental Services segment has
historically been very dependent on drilling activity in the
Gulf of Mexico. The Baker Hughes average rig count in the Gulf
of Mexico for the first eight weeks of 2010 decreased to 42 rigs
compared to an average of 60 rigs for the first eight weeks of
2009, but increased when compared to 34 rigs for the last
quarter of 2009. We believe this favorable trend since the
fourth quarter, and our strategy of moving rental assets to new
markets, will result in increased utilization and pricing for
our Rental Services segment. We anticipate our Drilling and
Completion segment will exceed 2009 results for both revenue and
operating income as drilling activity in Argentina is improving
and we have relocated underutilized rigs to Brazil. We have also
signed two new contracts in Bolivia to commence drilling
30
operations in February and April of 2010. Our Drilling and
Completion segment currently operates in Argentina, Brazil and
Bolivia, but we have two rigs scheduled to be delivered in the
U.S. in 2010. Currently, we have no firm commitments of
work for the two U.S. rigs, so the impact of revenue and
operating income from these rigs may have a negative impact on
our Drilling and Completion segments operating results.
We expect our general and administrative expenses in 2010 to be
relatively flat as we realize a full year benefit from
reductions of our administrative staffs made in 2009 to reflect
the decline in activity, offset by additional administrative
positions created to handled our growing international
activities and costs related to investigation of new operational
and financial reporting tools to improve our operating
performance. We also anticipate an increase in compensation for
existing administrative positions in response to market
conditions. Our net interest expense is dependent upon our level
of debt and cash on hand, which are principally dependent on
acquisitions we complete, our capital expenditures and our cash
flows from operations. Due to the shortage of liquidity and
credit in the U.S. financial markets, we may see an
increase in our effective interest rate in 2010. We do not
anticipate the ability to record a gain on debt extinguishment
in 2010 as our senior notes are trading close to face value. We
anticipate that our effective tax rate will increase in 2010 due
to a projected domestic tax loss at lower tax rate than the tax
rate applied to our international operations which are expected
to generate taxable income.
Our operating income is principally dependent on our level of
revenues and the pricing environment of our services. In
addition, demand for our services is dependent upon our
customers capital spending plans, which are largely driven
by current commodity prices and their expectations of future
commodity prices.
We believe that 2010 will be a challenging year for our
operations although increased oil and natural gas prices and the
resulting increased rig count should increase the utilization
and pricing for our equipment and services. We believe our cost
cuts and our strategy of international growth, by offering new
equipment and technology to our customers and our focus on the
U.S. land shale plays, will improve our operating results
in 2010.
Results
of Operations
In June 2007, we acquired all of the outstanding stock of Coker,
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. In October 2007, we acquired all of the
outstanding stock of Rebel. In June 2007, we sold our capillary
assets. We report the operations of these four acquisitions and
one disposition in our Oilfield Services segment.
In December 2008, we acquired all of the outstanding stock of
BCH, which is reported as part of our Drilling and Completion
segment. In August 2008, we sold our drill pipe tong
manufacturing assets, which were reported in our Oilfield
Services segment.
We consolidated the results of all of these acquisitions from
the day they were acquired.
The foregoing acquisitions and dispositions 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, 2009 and December 31,
2008
Our revenues for the year ended December 31, 2009 were
$506.3 million, a decrease of 25.1% compared to
$675.9 million for the year ended December 31, 2008.
The decrease in revenues is due to the decrease in revenues in
our Oilfield Services and Rental Services segments, offset in
part by a slight increase in revenues in our Drilling and
Completion segment. Both our Oilfield Services and Rental
Services segments have a strong concentration in the
U.S. domestic oil and natural gas market. Due to the
decline in oil and natural gas prices and drilling activity in
the U.S. compared to 2008, we experienced significant
deterioration in both equipment utilization and pricing. This
resulted in a decline in revenues of our Oilfield Services
segment to $143.6 million for the year ended
December 31, 2009 compared to revenues of
$280.8 million for the year ended December 31, 2008.
Our Rental Services segment had a decline in revenues to
$58.7 million for the year ended December 31, 2009
compared to revenues of $103.8 million for the year ended
December 31,
31
2008. The increase in revenues in our Drilling and Completion
segment was due to the acquisition of BCH in Brazil offset by
lower rig utilization and pricing in our Argentina operations.
The Drilling and Completion segment generated
$304.0 million in revenues for the year ended
December 31, 2009 compared to revenues of
$291.3 million for the year ended December 31, 2008.
BCH, which was acquired on December 31, 2008, generated
$43.6 million in revenues for the year ended
December 31, 2009.
Our direct costs for the year ended December 31, 2009
decreased 14.4% to $379.4 million, or 75.0% of revenues,
compared to $443.4 million, or 65.6%, of revenues for the
year ended December 31, 2008. The increase in the
percentage of direct costs to revenue between periods is
primarily due to the change in our revenue mix and the fact that
not all of our direct costs are variable and therefore do not
fluctuate with revenues. For the year ended December 31,
2009, our higher margin Rental Services segment only comprised
11.6% of our total revenues compared to 15.4% of our total
revenues for the year ended December 31, 2008. Our direct
costs in our Oilfield Services and Rental Services segments
decreased in absolute dollars for the year ended
December 31, 2009 compared to the year ended
December 31, 2008, but our revenues in our Oilfield
Services and Rental Services segments decreased more during that
same period than the reduction in direct costs. Our Oilfield
Services segment direct costs for the year ended
December 31, 2009 decreased 39.4% from direct costs for the
year ended December 31, 2008, while the revenues decreased
48.9% over that same period. In addition, our Oilfield Services
segment had $1.2 million of expenses recorded during the
year ended December 31, 2009 related to severance payments,
the closing of unprofitable locations and downsizing other
locations. Our Oilfield Services segment has also been impacted
by pricing pressure that decreases revenues but has no impact on
direct costs. Our Rental Services segment direct costs for the
year ended December 31, 2009 decreased 36.4% from direct
costs for the year ended December 31, 2008, while the
revenues decreased 43.4% over that same period. Our direct costs
for the Rental Services segment are largely fixed because they
primarily relate to yard expenses to maintain the rental
inventory. In addition, pricing pressure has reduced our Rental
Services revenues but had no impact on our direct costs. Direct
costs in our Drilling and Completion segment increased
$20.6 million for the year ended December 31, 2009
compared to the year ended December 31, 2008. Direct costs
related to our December 2008 acquisition of BCH were
$29.6 million during the year ended December 31, 2009.
Our Drilling and Completion segment direct costs for the year
ended December 31, 2009 increased 9.1% from direct costs
for the year ended December 31, 2008, while the revenues
increased 4.3% over that same period. This unfavorable variance
is primarily attributed to lower utilization of our drilling and
service rigs during the year ended December 31, 2009
compared to the same period of the prior year and labor and
other cost increases due to the inflationary environment in
Argentina. Additionally, workforce reductions in response to
market conditions are difficult and costly to implement in the
labor environment in Argentina. We incurred $1.7 million in
severance costs in Argentina during the year ended
December 31, 2009.
Depreciation expense increased 23.3% to $78.3 million for
the year ended December 31, 2009 from $63.5 million
for the year ended December 31, 2008. The primary increase
in depreciation expense is due to the acquisitions completed in
the second half of 2008 and the acquisition of BCH in December
2008. Depreciation expense for BCH was $3.3 million for the
year ended December 31, 2009.
General and administrative expense was $50.8 million for
the year ended December 31, 2009 compared to
$62.8 million for the year ended December 31, 2008.
General and administrative expense decreased primarily due to
the amortization of share-based compensation arrangements,
reduced management, accounting and administrative staffs and
reductions in provided benefits. General and administrative
expense includes share-based compensation expense of
$4.8 million in 2009 and $7.9 million in 2008. As a
percentage of revenues, general and administrative expenses were
10.0% in 2009 compared to 9.3% in 2008.
During the year ended December 31, 2009, we recorded a
$1.6 million loss on an asset disposition from the total
loss of a rig from a blow-out in our Drilling and Completion
segment. The insurance proceeds for the loss were not sufficient
to cover the book value of the rig and related assets. Effective
August 1, 2008, we sold our drill pipe tong manufacturing
assets that were part of our Oilfield Services segment. The
total consideration was approximately $7.5 million. We
recognized a gain of $166,000 related to the transaction.
32
We recorded an impairment of goodwill of $115.8 million as
of December 31, 2008. In light of adverse market conditions
affecting our stock price and market conditions at that time, we
determined that impairment was necessary on all of our goodwill
associated with our Rental Services segment as well as on our
Tubular Services and Production Services reporting units
included in our Oilfield Services segment. We performed the same
annual impairment test as of December 31, 2009 and recorded
no impairment.
Amortization expense was $4.7 million for the year ended
December 31, 2009 compared to $4.2 million for the
year ended December 31, 2008. The increase was primarily
attributable to intangible assets associated with our
acquisition of BCH in December 2008.
Our loss from operations for the year ended December 31,
2009 totaled $8.5 million, compared to $13.5 million
loss for the year ended December 31, 2008, for an
improvement of $5.0 million. The improvement is primarily
related to the $115.8 million goodwill impairment in the
year ended December 31, 2008 compared to no impairment for
the year ended December 31, 2009, offset by decreased
revenues and increased depreciation and amortization expense of
$15.3 million from the year ended December 31, 2009
compared to year ended December 31, 2008.
Our interest expense was $48.1 million for the year ended
December 31, 2009, compared to $48.4 million for the
year ended December 31, 2008. On June 29, 2009 we
purchased $74.8 million of our senior notes with proceeds
from our $125.6 million in equity issuances on that same
date. We also prepaid the then $35.0 million outstanding
loan balance under our revolving credit facility on
June 29, 2009 from those same equity proceeds. This
compared to an outstanding balance of $36.5 million at
December 31, 2008 under our revolving credit facility. In
2008, through DLS, we entered into a new $25.0 million
import finance facility with a bank to fund a portion of the
purchase price of new drilling and service rigs. Interest
expense increased due to the acquisition of BCH at the end of
2008. BCH had a $22.1 million term loan facility at
December 31, 2008 which was reduced to $16.2 million
at December 31, 2009. Interest expense includes
amortization expense of debt issuance costs of $2.2 million
and $2.1 million for the years ended December 31, 2009
and 2008, respectively.
Our interest income was $72,000 for the year ended
December 31, 2009, compared to $5.6 million for the
year ended December 31, 2008. In January 2008, we invested
$40.0 million into a 15% convertible subordinated secured
debenture with BCH. We earned interest on this note up until
December 28, 2008, when we acquired all of the outstanding
stock of BCH.
During the year ended December 31, 2009, we recorded a gain
of $26.4 million as a result of a tender offer that we
completed on June 29, 2009. We purchased $30.6 million
aggregate principal of our 9.0% senior notes and
$44.2 million aggregate principal of 8.5% senior notes
for approximately $46.4 million. Included in the
computation of the gain is the write-off of $1.5 million of
debt issuance costs related to the retired notes and we incurred
approximately $466,000 in expenses related to the transactions.
Our benefit for income taxes for the year ended
December 31, 2009 was $9.9 million, or 31.8% of our
net loss before income taxes, compared to an income tax benefit
of $17.4 million, or 30.6% of our net income before income
taxes for 2008. Our effective tax rate in the U.S. was
35.5% in 2009 compared to 31.1% in 2008, while our effective tax
rate for international activities increased to 44.4% in 2009
compared to 31.7% in 2008. The increase in the U.S. tax
rate was primarily attributable to higher nondeductible items
during the 2008 year including intangible disposals and
meals and entertainment. The increase in the international tax
rate is primarily due to our BCH operations which generate a
loss in Brazil which has a valuation allowance of
$2.1 million against its benefit. For the year ended
December 31, 2009, the U.S. operations generated a
$43.9 million book loss before income taxes, while the
international activities generated $12.9 million of income
before income taxes, resulting in the U.S. operations
having a higher influence on our consolidated effective tax rate
in 2009.
We had a net loss of $21.2 million for the year ended
December 31, 2009, compared to a net loss of
$39.5 million for the year ended December 31, 2008.
The net loss attributed to common stockholders was
$22.5 million after $1.3 million in preferred stock
dividends. The preferred stock dividend relates to
36,393 shares of $1,000 par value preferred shares at
7.0%.
33
The following table compares revenues and income (loss) from
operations for each of our business segments for the years ended
December 31, 2009 and December 31, 2008. Income (loss)
from operations consists of our revenues and the gain (loss) on
asset dispositions less direct costs, general and administrative
expenses, goodwill impairment, depreciation and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
Income (Loss) from Operations
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Oilfield Services
|
|
$
|
143,564
|
|
|
$
|
280,835
|
|
|
$
|
(137,271
|
)
|
|
$
|
(14,691
|
)
|
|
$
|
38,643
|
|
|
$
|
(53,334
|
)
|
Drilling & Completion
|
|
|
303,975
|
|
|
|
291,335
|
|
|
|
12,640
|
|
|
|
19,222
|
|
|
|
40,226
|
|
|
|
(21,004
|
)
|
Rental Services
|
|
|
58,714
|
|
|
|
103,778
|
|
|
|
(45,064
|
)
|
|
|
140
|
|
|
|
(74,361
|
)
|
|
|
74,501
|
|
General Corporate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13,218
|
)
|
|
|
(18,028
|
)
|
|
|
4,810
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
506,253
|
|
|
$
|
675,948
|
|
|
$
|
(169,695
|
)
|
|
$
|
(8,547
|
)
|
|
$
|
(13,520
|
)
|
|
$
|
4,973
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services. Revenues for the year ended
December 31, 2009 for our Oilfield Services segment were
$143.6 million, a decrease of 48.9% from the
$280.8 million in revenues for the year ended
December 31, 2008. Income from operations for our Oilfield
Services segment decreased $53.3 million and resulted in a
loss from operations of $14.7 million for the year ended
December 31, 2009 compared to income from operations of
$38.6 million for the year ended December 31, 2008.
The operating income for the year ended December 31, 2008
included a $9.4 million non-cash charge for the impairment
of goodwill. Our Oilfield Services segment revenues and
operating income for the year ended December 31, 2009
decreased compared to the year ended December 31, 2008 due
to weak market conditions that resulted in reduced demand and
pricing for our services. During the year ended
December 31, 2009, we incurred $1.2 million of costs
related to severance payments, the closing of unprofitable
locations and downsizing other locations in our Oilfield
Services segment. Depreciation and amortization expense for the
Oilfield Services segment increased by $5.9 million or
23.7% for the year ended December 31, 2009 compared to the
prior year, due to capital expenditures completed during 2008,
including six coiled tubing units delivered in the last half of
2008. We have not realized the benefits of these capital
expenditures due to decreased utilization and pricing of our
equipment as a result of the decline in U.S. drilling
activity.
Drilling and Completion. Our Drilling and
Completion revenues were $304.0 million for the year ended
December 31, 2009, an increase of 4.3% from the
$291.3 million in revenues for the year ended
December 31, 2008. Our Drilling and Completion revenues
increased in 2009 primarily due to $43.6 million in
revenues generated by BCH, which we acquired in December 2008,
offset by a decrease in revenues in Argentina. Income from
operations decreased to $19.2 million in 2009 compared to
$40.2 million for the year ended December 31, 2008.
Income from operations as percentage of revenue decreased to
6.3% for 2009 compared to 13.8% for 2008. This reduction was due
to: (1) reduced rig utilization and rig rates in Argentina
during the year ended December 31, 2009; (2) increased
labor and other costs in Argentina during the year ended
December 31, 2009 (3) an increase of
$8.0 million, or 55.9%, in depreciation and amortization in
the year ended December 31, 2009; (4) a
$1.6 million non-cash loss recorded in the year ended
December 31, 2009 on a rig destroyed in a blow-out;
(5) $1.7 million of severance costs during the year
ended December 31, 2009 related to workforce reductions in
Argentina as a result of lower activity and (6) $329,000 of
costs incurred to consolidate operating locations in Brazil
during the year ended December 31, 2009. The increase in
depreciation and amortization expense was the result of the
addition of new rigs in Argentina and the acquisition of BCH.
Rental Services. Our Rental Services revenues
were $58.7 million for the year ended December 31,
2009, a decrease of 43.4% from the $103.8 million in
revenues for the year ended December 31, 2008. Income from
operations for our Rental Services segment increased to $140,000
for the year ended December 31, 2009 compared to a loss of
$74.4 million for the year ended December 31, 2008.
The operating income for the year ended December 31, 2008
included a $106.4 million non-cash charge for impairment of
goodwill, without this charge our operating income for the year
ended December 31, 2008 would have been $32.0 million.
Our Rental Services segment revenues and operating income as
adjusted for goodwill impairment for the year ended
December 31, 2009 decreased compared to the prior year due
primarily to the decrease in utilization of
34
our rental equipment and a more competitive pricing environment
due to the decrease in drilling activity in the United States.
The decrease in income from operations for the year ended
December 31, 2009 is also due to a $306,000 increase to the
bad debt expense for Rental Services segment customers who are
facing financial difficulties, and $237,000 of costs related to
closing a rental yard and reducing our workforce. Our bad debt
expense recorded in our Rental Services segment for the year
ended December 31, 2009 was $1.5 million compared to
$1.2 million for the year ended December 31, 2008. In
addition, depreciation and amortization expense for our Rental
Services segment increased $1.7 million or 5.9%, for the
year ending December 31, 2009 compared to the prior year
due to capital expenditures made during 2008.
General Corporate. General corporate expenses
decreased $4.8 million to $13.2 million for the year
ended December 31, 2009 compared to $18.0 million for
the year ended December 31, 2008. The decrease was
primarily due to the decrease in share-based compensation
expense and the decrease in payroll costs and benefits due to
reduced management and accounting and administrative staff.
Share-based compensation expense included in general corporate
was $3.7 million for the year ended December 31, 2009
compared to $6.7 million for the year ended
December 31, 2008.
Comparison
of Years Ended December 31, 2008 and December 31,
2007
Our revenues for the year ended December 31, 2008 were
$675.9 million, an increase of 18.4% compared to
$571.0 million for the year ended December 31, 2007.
The increase in revenues is due to the increase in revenues in
our Drilling and Completion and our Oilfield Services segments,
offset in part by a decrease in revenues in our Rental Services
segment. The most significant increase in revenues was in our
Drilling and Completion segment due to additional drilling and
service rigs placed in service in 2008 and price increases. The
Drilling and Completion segment generated $291.3 million in
revenues for the year ended December 31, 2008 compared to
$215.8 million for the year ended December 31, 2007.
Our Oilfield Services segment revenues increased to
$280.8 million in 2008 compared to $234.0 million in
2007 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 also increased at our Oilfield
Services segment due to the purchase of additional equipment,
principally new compressor packages for our underbalanced
operations, coiled tubing equipment and expansion of operations
into new geographic regions. The impact of the additional MWD
tools, downhole motors and the acquisitions of Diggar and Coker
completed in the last half of 2007 are not easily identifiable
as they were quickly integrated with our pre-existing
operations. The acquisition of the Diamondback assets provided
$30.3 million in revenues for the year ended
December 31, 2008 compared to $3.1 million in revenues
from the date of acquisition to December 31, 2007. The
additional coiled tubing equipment provided an additional
$11.8 million in revenues for the year ended
December 31, 2008 compared to 2007. These increases in
revenue were partially offset by a significant decrease in
revenues at our Rental Services segment due to the reduction of
drilling activity in the U.S. Gulf of Mexico beginning in
the last half of 2007, as rigs departed the U.S. Gulf in
favor of the international markets and the impact of hurricanes
in 2008. These factors also caused the pricing for our Rental
Services segment to become more competitive. Also impacting
revenues was a $5.5 million decrease in revenues from our
capillary tubing assets compared to 2007 as those assets were
sold on June 29, 2007.
Our direct costs for the year ended December 31, 2008
increased 30.9% to $443.4 million, or 65.6% of revenues,
compared to $338.8 million, or 59.3%, of revenues for the
year ended December 31, 2007. On a percentage basis, direct
costs in our Oilfield Services segment outpaced the growth in
revenue for that segment. Oilfield Services revenue for the year
ended December 31, 2008 increased 20.0% from revenue in the
Oilfield Services segment for the year ended December 31,
2007, while the direct costs increased 24.7% over that same
period. This unfavorable variance was primarily associated with
costs incurred in the deployment of our new coiled tubing rigs.
On a percentage basis, direct costs in our Drilling and
Completion segment outpaced the growth in our revenue for that
segment. Drilling and Completion revenue for the year ended
December 31, 2008 increased 35.0% from revenue in the
Drilling and Completion segment for the year ended
December 31, 2007, while the direct costs increased 45.1%
over that same period. This unfavorable variance is primarily
attributed to higher labor costs in our Drilling and Completion
segment relating to labor
35
concessions in Argentina granted by the oil industry in the last
half of 2007 and a significant increase in our labor force and
labor-related expenses in connection with the delivery of new
rigs prior to their activation. Our direct costs in our Rental
Services segment did not decrease on the same percentage as the
drop in our revenue for that segment. Rental Services revenue
for the year ended December 31, 2008 decreased 14.4% from
revenue in the Rental Services segment for the year ended
December 31, 2007, while the direct costs decreased 5.9%
over that same period. Our direct costs for the Rental Services
segment are largely fixed because they primarily relate to yard
expenses to maintain the rental inventory. In addition, the
change in the service mix from the longer-term Gulf of Mexico
rentals, which we benefited from in 2007, to the shorter term
land-drilling rental work in 2008, requires more handling on our
part which increases costs.
Depreciation expense increased 24.6% to $63.5 million for
the year ended December 31, 2008 from $50.9 million
for the year ended December 31, 2007. The primary increase
in depreciation expense is due to the acquisitions completed in
the second half of 2007 and our capital expenditures,
principally the addition of new service rigs and one drilling
rig in Argentina.
General and administrative expense was $62.8 million for
the year ended December 31, 2008 compared to
$61.2 million for the year ended December 31, 2007.
General and administrative expense increased primarily due to
the amortization of share-based compensation arrangements.
General and administrative expense includes share-based
compensation expense of $7.9 million in 2008 and
$4.7 million in 2007. As a percentage of revenues, general
and administrative expenses were 9.3% in 2008 compared to 10.7%
in 2007.
Effective August 1, 2008, we sold our drill pipe tong
manufacturing assets that were part of our Oilfield Services
segment. The total consideration was approximately
$7.5 million. We recognized a gain of $166,000 related to
the transaction. On June 29, 2007, we sold our capillary
tubing assets that were part of our Oilfield 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.
We recorded an impairment of goodwill of $115.8 million as
of December 31, 2008. In light of adverse market conditions
affecting our stock price and market conditions, we determined
that impairment was necessary on all of our goodwill associated
with our Rental Services segment as well as on our Tubular
Services and Production Services reporting units included in our
Oilfield Services segment. We performed the same annual
impairment test as of December 31, 2007 and recorded no
impairment.
Amortization expense was $4.2 million for the year ended
December 31, 2008 compared to $4.1 million for the
year ended December 31, 2007.
Our loss from operations for the year ended December 31,
2008 totaled $13.5 million, compared to $124.8 million
in income from operations for the year ended December 31,
2007, for a total decrease of $138.3 million. The decrease
is primarily related to the $115.8 million goodwill
impairment, increased depreciation and amortization expense of
$12.7 million from the year ended December 31, 2008
compared to year ended December 31, 2007 and the
$8.9 million gain related to the sale of our capillary
tubing assets in 2007.
Our interest expense was $48.4 million for the year ended
December 31, 2008, compared to $49.5 million for the
year ended December 31, 2007. During 2008, we borrowed
against our revolving credit facility and as of
December 31, 2008, we had an outstanding balance of
$36.5 million. In 2008, through our DLS subsidiary in
Argentina, we also entered into a new $25.0 million import
finance facility with a bank to fund a portion of the purchase
price of new drilling and service rigs. 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 acquisition of substantially all of the
assets of Oil & Gas Rental Services, Inc., or OGR, and
for working capital. This bridge loan was repaid on
January 29, 2007. The average interest rate on the bridge
loan was 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
also includes amortization expense of deferred financing costs
of $2.1 million and $1.9 million for 2008 and 2007,
respectively.
Our interest income was $5.6 million for the year ended
December 31, 2008, compared to $3.3 million for the
year ended December 31, 2007. In January 2008, we invested
$40.0 million into a 15% convertible
36
subordinated secured debenture with BCH. We earned interest on
this note up until December 28, 2008, when we acquired all
of the outstanding stock of BCH. In 2007, we had excess cash as
the result of a senior note financing and an equity offering and
we were able to generate interest income during this period.
Our benefit for income taxes for the year ended
December 31, 2008 was $17.4 million, or 30.6% of our
net loss before income taxes, compared to an income tax expense
of $28.8 million, or 36.4% of our net income before income
taxes for 2007. The income tax benefit recorded in 2008 was the
result of net loss before income taxes compared to net income
before income taxes in the previous year and a lower effective
tax rate. The lower effective tax rate in 2008 is attributable
to the impact of foreign currency losses on the foreign income
tax as well a lower benefit from the loss generated on our
U.S. operations due to nondeductible expenses and state
income taxes.
We had a net loss of $39.5 million for the year ended
December 31, 2008, compared to net income of
$50.4 million for the year ended December 31, 2007.
The following table compares revenues and income (loss) from
operations for each of our business segments for the years ended
December 31, 2008 and December 31, 2007. Income (loss)
from operations consists of our revenues and the gain on asset
dispositions less direct costs, general and administrative
expenses, goodwill impairment, depreciation and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
Income (Loss) from Operations
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Oilfield Services
|
|
$
|
280,835
|
|
|
$
|
233,986
|
|
|
$
|
46,849
|
|
|
$
|
38,643
|
|
|
$
|
53,218
|
|
|
$
|
(14,575
|
)
|
Drilling & Completion
|
|
|
291,335
|
|
|
|
215,795
|
|
|
|
75,540
|
|
|
|
40,226
|
|
|
|
38,839
|
|
|
|
1,387
|
|
Rental Services
|
|
|
103,778
|
|
|
|
121,186
|
|
|
|
(17,408
|
)
|
|
|
(74,361
|
)
|
|
|
49,139
|
|
|
|
(123,500
|
)
|
General Corporate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(18,028
|
)
|
|
|
(16,414
|
)
|
|
|
(1,614
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
675,948
|
|
|
$
|
570,967
|
|
|
$
|
104,981
|
|
|
$
|
(13,520
|
)
|
|
$
|
124,782
|
|
|
$
|
(138,302
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services. Revenues for the year ended
December 31, 2008 for our Oilfield Services segment were
$280.8 million, an increase of 20.0% from the
$234.0 million in revenues for the year ended
December 31, 2007. The increase in revenues is due to the
purchase of additional MWD tools, new compressors and new
foam units for our underbalanced drilling
operations, new coiled tubing units 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. The
impact of the acquisitions of Diggar and Coker completed in the
last half of 2007 and of the additional MWD tools are not easily
identifiable as they were quickly integrated with our
pre-existing operations. The acquisition of Diamondback provided
$30.3 million in 2008 compared to $3.1 million of
revenues from the date of acquisition to December 31, 2007.
Income from operations decreased 27.4% to $38.6 million for
2008 from $53.2 million for 2007 because income from
operations for the year ended December 31, 2008 includes a
goodwill impairment charge of $9.4 million while the year
ended December 31, 2007 included an $8.9 million gain
on sale of our capillary tubing assets. Depreciation and
amortization expense increased 46.8% to $24.7 million for
the year ended December 31, 2008 compared to
$16.8 million in 2007. The increase is depreciation expense
was due to our capital expenditures, principally the new coiled
tubing units which were delivered in the second half of 2008.
Drilling and Completion. Our Drilling and
Completion revenues were $291.3 million for the year ended
December 31, 2008, an increase of 35.0% from the
$215.8 million in revenues for the year ended
December 31, 2007. Our Drilling and Completion revenues
increased in 2008 primarily due to 16 new service rigs and one
drilling rig which were placed in service at various dates in
2008 and increased prices for our services. Income from
operations increased to $40.2 million in 2008 compared to
$38.8 million for the year ended December 31, 2007.
Income from operations as percentage of revenue decreased to
13.8% for 2008 compared to 18.0% for 2007. This was due
primarily to higher wages, which included other payroll
expenses, and the increase in administrative costs all relating
to labor concessions in Argentina granted by the oil industry in
the last half of 2007 and a significant increase in our labor
force and labor-related expenses in connection with the delivery
of
37
new rigs prior to their activation. Depreciation expense
increased $3.0 million for the year ended December 31,
2008 compared to the prior year due to capital expenditures for
the Drilling and Completion segment in 2008 and 2007.
Rental Services. Our Rental Services revenues
were $103.8 million for the year ended December 31,
2008, a decrease of 14.4% from the $121.2 million in
revenues for the year ended December 31, 2007. The decrease
in revenue is primarily attributable to a more competitive
market environment due to the decreased U.S. Gulf of Mexico
drilling activity beginning in the last half of 2007 stemming
from the departure of drilling rigs in favor of the
international markets and the impact of hurricanes in the
U.S. Gulf of Mexico in 2008. Income from operations
decreased $123.5 million to a loss of $74.4 million in
2008 compared to income of $49.1 million in 2007. The
decrease in operating income is primarily attributable to a
$106.4 million non-cash charge for impairment of goodwill
recorded in the year ending December 31, 2008 and due to
the decrease in revenue.
General Corporate. General corporate expenses
increased $1.6 million to $18.0 million for the year
ended December 31, 2008 compared to $16.4 million for
the year ended December 31, 2007. The increase was
primarily due to the increase in share-based compensation
expense.
Liquidity
and Capital Resources
In June 2009, we strengthened our balance sheet by raising
approximately $125.6 million in gross proceeds from the
sale of common stock and a newly issued series of preferred
stock. The transactions were effected through a common stock
rights offering to our existing stockholders, the sale of common
stock to Lime Rock through its backstop commitment of the rights
offering, and the sale of convertible perpetual preferred stock
to Lime Rock. Approximately $46.4 million of the proceeds
were used to purchase an aggregate of $74.8 million
principal amount of our existing senior notes, approximately
$35.0 million was used to repay all the borrowings under
our revolving bank credit facility due 2012, except for
outstanding letters of credit, and the remainder for general
corporate purposes.
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.
Our amended and restated revolving credit facility permits
borrowings of up to $90.0 million in principal amount. As
of December 31, 2009, we had $85.8 million available
for borrowing under our amended and restated revolving credit
facility. Cash flows from operations are expected to be our
primary source of liquidity in fiscal 2010. We had cash and cash
equivalents of $41.1 million at December 31, 2009
compared to $6.9 million at December 31, 2008.
Our revolving credit agreement requires us to maintain specified
financial ratios. If we fail to comply with the financial ratio
covenants, it could limit or eliminate the availability under
our revolving credit agreement. Our ability to maintain such
financial ratios 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. The
decrease in the U.S. rig count experienced late in 2008 and
2009 and the resulting decrease in demand for our services
adversely impacts our ability to maintain or meet such financial
ratios. We believe that the $125.6 million in gross equity
proceeds received in June 2009 has significantly improved our
liquidity and decreased our reliance on our revolving credit
facility. We utilized a portion of the equity proceeds to prepay
all borrowings under our revolving credit agreement.
Exclusive of any acquisitions, we currently expect our capital
spending to be between $60.0 million and $85.0 million
in 2010 depending upon the market demand we experience, our
operating performance during the year and expenditures which may
be associated with potential new contracts. These amounts are
net of equipment deposits paid in 2009. As of December 31,
2009, we had capital expenditure commitments of
$19.2 million, net of equipment deposits. The majority of
these commitments are due to $12.1 million remaining to be
paid on two new 1600 horsepower drilling rigs expected to be
completed in the second and fourth quarters of 2010. We believe
that our cash generated from operations, cash on hand and cash
available
38
under our credit facilities will provide sufficient funds for
our identified projects. Our ability to obtain capital for
opportunistic acquisitions or additional projects to implement
our growth strategy over the longer term will depend upon our
future operating performance and financial condition, which will
be dependent upon the prevailing conditions in our industry and
the global market, including the availability of equity and debt
financing.
Operating
Activities
In the year ended December 31, 2009, we generated
$55.5 million in cash from operating activities. Our net
loss for the year ended December 31, 2009 was
$21.2 million. Non-cash additions to net loss totaled
$49.3 million in the 2009 period consisting primarily of
$83.0 million of depreciation and amortization,
$4.8 million related to the expensing of stock options,
$2.8 million for bad debts, $2.2 million of
amortization and write-off of deferred financing fees and
$1.6 million related to loss on rig destroyed by fire,
partially offset by $26.4 million from gain on debt
extinguishment, $17.9 million in deferred income taxes and
$0.9 million of gains from the dispositions of equipment.
During the year ended December 31, 2009, changes in working
capital provided $27.4 million in cash, principally due to
a decrease of $50.0 million in accounts receivable, a
decrease of $4.6 million in inventories, a decrease in
other current assets of $4.6 million and an increase of
$2.7 million in accrued employee benefits and payroll
taxes, offset by an decrease of $27.6 million in accounts
payable, a decrease of $4.6 million in accrued expenses and
a decrease in accrued interest of $2.8 million. Our
accounts receivables decreased at December 31, 2009
primarily due to the decrease in our revenues in 2009.
Inventories decreased at December 31, 2009 primarily due to
a slow down in our activity. Other current assets decreased
primarily due to tax refunds received in 2009. Our accounts
payable, and other accrued expenses decreased primarily due to
the decrease in costs due to our decrease in activity.
In the year ended December 31, 2008, we generated
$113.7 million in cash from operating activities. Our net
loss for the year ended December 31, 2008 was
$39.5 million. Non-cash additions to net loss totaled
$164.8 million in the 2008 period consisting primarily of
$115.8 million of impairment of goodwill,
$67.7 million of depreciation and amortization,
$7.9 million related to the expensing of stock options,
$3.3 million for bad debts and $2.1 million of
amortization and write-off of deferred financing fees, partially
offset by $29.9 million in deferred income taxes and
$1.9 million of gains from the dispositions of equipment.
During the year ended December 31, 2008, changes in working
capital used $11.7 million in cash, principally due to an
increase of $27.5 million in accounts receivable, an
increase of $9.7 million in inventories and an increase in
other current assets of $1.6 million, offset by an increase
of $21.9 million in accounts payable, an increase of
$3.5 million in accrued employee benefits and payroll
taxes, an increase of $1.2 million in accrued expenses and
an increase in accrued interest of $567,000. Our accounts
receivables increased at December 31, 2008 primarily due to
the increase in our revenues in 2008. Inventories increased at
December 31, 2008 primarily due to our larger rig fleet in
our Drilling and Completion segment. Other current assets
increased primarily due to estimated tax payments exceeding the
estimated tax liability as of December 31, 2008. Our
accounts payable, accrued employee benefits and payroll taxes
and other accrued expenses increased primarily due to the
increase in costs due to our growth in revenues.
In the year ended December 31, 2007, we generated
$103.5 million in cash from operating activities. Our net
income for the year ended December 31, 2007 was
$50.4 million. Non-cash additions to net income totaled
$61.2 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,
$8.0 million of deferred income tax, $1.3 million 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 $8.1 million in cash, principally due to an
increase of $31.4 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
39
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
Drilling and Completion 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 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
Drilling and Completion segment.
Investing
Activities
During the year ended December 31, 2009, we used
$64.0 million in investing activities, consisting of
$78.1 million for capital expenditures, $1.1 million
of additional investments, offset by a decrease of
$2.7 million in deposits on asset commitments,
$8.6 million of proceeds from equipment sales and
$3.9 million in insurance proceeds for a drilling rig
destroyed by a blow-out. Included in the $78.1 million for
capital expenditures was $11.4 million for our Oilfield
Services segment, $38.5 million for two domestic drilling
rigs and $19.9 million for additional equipment in our
Drilling and Completion segment and $8.2 million for drill
pipe and other equipment used in our Rental Services segment. We
invested $2.4 million of cash and cash expenditures for
equipment into our investment into our Saudi Arabia joint
venture and we received $1.3 million from insurance
proceeds related to a pre-acquisition contingency on BCH. The
decrease in other assets was due to the conversion of deposits
on equipment purchases into capital expenditures for the
drilling rigs and assets used in our directional drilling
services. We also received $8.6 million from the sale of
assets during the year ended December 31, 2009, comprised
mostly from equipment
lost-in-hole
from our Rental Services segment ($3.5 million) and our
Oilfield Services segment ($0.8 million) along with
$3.9 million from the sale a plane in our Rental Services
segment. We also transferred $1.6 million of rental assets
as part of our investment into our Saudi Arabia joint venture in
a non-cash transaction. In 2009, we reduced the carrying value
of goodwill on the BCH acquisition by $1.3 million due to
the utilization of a pre-acquisition tax asset.
During the year ended December 31, 2008, we used
$202.2 million in investing activities. During the year
ended December 31, 2008, we acquired BCH for a total net
cash outlay of $53.7 million, consisting of the purchase
price and acquisition costs less cash acquired. In addition we
made capital expenditures of approximately $154.5 million
during the year ended December 31, 2008, including
$73.4 million to expand our drilling fleet and to purchase,
improve and replace other equipment in our Drilling and
Completion segment, $58.4 million to purchase and upgrade
our equipment for our Oilfield Services segment and
$22.6 million to increase our inventory of equipment and
replace
lost-in-hole
equipment in the Rental Services segment. We received proceeds
of $3.0 million from the sale of our drill pipe tong
manufacturing assets. We also received $11.5 million from
the sale of assets during the year ended December 31, 2008,
comprised mostly from equipment
lost-in-hole
from our Rental Services segment ($8.3 million) and our
Oilfield Services segment ($2.3 million). We also made net
advance payments of $8.8 million on the purchase of new
drilling and service rigs to be delivered in 2009 for our
Drilling and Completion segment and advance payments of
$1.1 million on the purchase of new directional drilling
tools for our Oilfield Services segment.
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:
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In June 2007, we acquired Coker for a purchase price of
approximately $3.6 million in cash and a promissory note
for $350,000.
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40
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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.
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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.
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In November 2007, we acquired substantially all of the assets of
Diamondback for a purchase price of approximately
$23.1 million in cash.
|
In addition we made capital expenditures of approximately
$113.2 million during the year ended December 31,
2007, including $48.6 million to purchase and upgrade our
equipment for our Oilfield Services segment, $34.9 million
to increase our inventory of equipment and replace
lost-in-hole
equipment in the Rental Services segment and $28.9 million
to purchase, improve and replace equipment in our Drilling and
Completion 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
Oilfield Services 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
Drilling and Completion segment.
Financing
Activities
During the year ended December 31, 2009, financing
activities provided $42.7 million in cash. We raised
$120.2 million net of expenses from the issuance of common
and preferred stock, and borrowed $25.0 million under a
loan facility to acquire two drilling rigs, offset in part by
repayments of $64.8 million of long-term debt, a net
repayment on our revolving credit facility of $36.5 million
and $665,000 for preferred dividend payments. The repayments of
long-term debt consisted of $46.4 million on the senior
notes as a result of a tender offer and $18.4 million of
scheduled debt repayment including a prepayment on our BCH loan
facility. We also incurred $658,000 in debt issuance costs
consisting of $528,000 on the revolving credit facility,
primarily to modify our loan covenants, and $131,000 on the rig
financing agreement. In addition, we financed our renewal of
$3.2 million in insurance policy premiums in non-cash
transactions.
During the year ended December 31, 2008, financing
activities provided a net of $51.7 million in cash. We
received $25.0 million of proceeds of long-term debt which
was used to finance the expansion of our Drilling and Completion
segments rig fleet. During the year ended
December 31, 2008, we had a net draw on our revolving
credit facility of $36.5 million which was necessary due to
our investment in BCH and our capital expenditures. We also
received $633,000 from the proceeds of option exercises with
558,707 shares of our common stock being issued under our
equity compensation plans. Financing uses during the year ended
December 31, 2008 were the repayment of $9.9 million
of long-term debt and $525,000 in debt issuance costs.
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 with 882,624 shares of our common stock being
issued under our equity compensation plans. 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 substantially all the assets of OGR.
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 Rental Tools, Inc. and DLS, to
repay existing debt and for general corporate purposes. On
June 29, 2009, we closed on a tender offer in which we
purchased $30.6 million aggregate principal of our
9.0% senior notes for a total consideration of $650 per
$1,000 principal amount.
41
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 Oil & Gas Rental Services, Inc. On
June 29, 2009, we closed on a tender offer in which we
purchased $44.2 million aggregate principal of our
8.5% senior notes for a total consideration of $600 per
$1,000 principal amount.
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. 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. On April 9, 2009, we entered
into a Third Amendment to our existing Second Amended and
Restated Credit Agreement dated as of April 26, 2007 which
modified the leverage and interest coverage ratio covenants of
the Credit Agreement. In addition, permitted maximum capital
expenditures were reduced to $85.0 million for 2009
compared to the previous limit of $120.0 million. Effective
December 31, 2009, we amended the leverage and interest
coverage ratio covenants of the Credit Agreement. This amendment
relaxed the required financial ratios for the quarter ended
December 31, 2009 and for each of the quarters in 2010. Our
obligations under the amended and restated credit agreement are
secured by substantially all of our assets located in the
U.S. We were in compliance with all debt covenants as of
December 31, 2009 and 2008. As of December 31, 2009,
we had no borrowings under the facility except $4.2 million
in outstanding letters of credit. At December 31, 2008 we
had $36.5 million of borrowings outstanding and
$5.8 million in outstanding letters of credit. The credit
agreement loan rates are based on prime or LIBOR plus a margin.
The weighted average interest rate was 4.6% at December 31,
2008.
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 2.1% and 5.1% as of
December 31, 2009 and 2008, respectively. The bank loans
are denominated in U.S. dollars and the outstanding amount
due as of December 31, 2009 and 2008 was $1.1 million
and $2.5 million, respectively.
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 were used
to fund a portion of the purchase price of the new drilling and
service rigs ordered for our Drilling and Completion segment.
The loan is repayable over four years in equal semi-annual
installments beginning one year after each disbursement with the
final principal payment due not later than March 15, 2013.
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. We were in
compliance with all debt covenants as of December 31, 2009
and 2008. The bank loan rates are based on LIBOR plus a margin.
The weighted average interest rate was 4.4% and 6.9% at
December 31, 2009 and 2008, respectively. The bank loans
are denominated in U.S. dollars and the outstanding amount
as of December 31, 2009 and 2008 was $20.1 million and
$25.0 million, respectively.
As part of our acquisition of BCH, we assumed a
$23.6 million term loan credit facility with a bank. The
credit agreement is dated June 2007 and contains customary
events of default and financial covenants. Obligations under the
facility are secured by substantially all of the BCH assets. The
facility is repayable in quarterly principal installments plus
interest with the final payment due not later than August 2012.
We were in compliance with all debt covenants as of
December 31, 2009 and 2008. The credit facility loan is
denominated in U.S. dollars and interest rates are based on
LIBOR plus a margin. At December 31, 2009 and 2008, the
outstanding amount of the loan was $16.2 million and
$22.1 million and the interest rate was 3.5% and 6.0%,
respectively.
42
On May 22, 2009, we drew down $25.0 million on a new
term loan credit facility with a lending institution. The
facility was utilized to fund a portion of the purchase price of
two new drilling rigs. The loan is secured by the equipment. The
facility is repayable in quarterly installments of approximately
$1.4 million of principal and interest and matures in May
2015. The loan bears interest at a fixed rate of 9.0%. At
December 31, 2009, the outstanding amount of the loan was
$23.4 million.
In connection with the acquisition of Rogers Oil Tools, Inc., we
issued to the seller a note in the amount of $750,000. The note
bore interest at 5.0% and was paid in full in April 2009 in
accordance with its terms.
In 2000 we compensated directors 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, 2009 and
2008, the principal and accrued interest on these notes totaled
approximately $0 and $32,000, respectively.
In April 2008 and August 2008, we obtained insurance premium
financings in the aggregate amount of $3.0 million with a
fixed average weighted interest rate of 4.9%. Under terms of the
agreements, amounts outstanding are paid over 10 and
11 month repayment schedules. The outstanding balance of
these notes was approximately $0 and $991,000 at
December 31, 2009 and 2008, respectively. In 2009, we
obtained insurance premium financings in the aggregate amount of
$3.2 million with a fixed average weighted interest rate of
4.8%. Under terms of the agreements, the amount outstanding is
paid over 10 and 11 month repayment schedules. The
outstanding balance of these notes was approximately $997,000 as
of December 31, 2009.
As part of our acquisition of BCH, we assumed various capital
leases with terms of two to three years. The outstanding balance
under these capital leases was $254,000 and $779,000 at
December 31, 2009 and 2008, respectively.
The following table summarizes our obligations and commitments
to make future payments under our notes payable, operating
leases, employment contracts and consulting agreements for the
periods specified as of December 31, 2008.
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Payments by Period
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Less Than
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Total
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1 Year
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1-3 Years
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3-5 Years
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After 5 Years
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(In thousands)
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Contractual Obligations
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Long-term debt
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$
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491,979
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$
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16,778
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$
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30,033
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$
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236,738
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$
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208,430
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Capital leases(a)
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254
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249
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5
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Interest payments on long-term debt
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215,805
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40,931
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79,482
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57,450
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37,942
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Operating leases
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7,987
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2,670
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3,212
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1,504
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|
|
|
601
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Purchase obligations
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19,186
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19,186
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Employment contracts
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2,434
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2,104
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|
|
|
330
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Total contractual cash obligations
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$
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737,645
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$
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81,918
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$
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113,062
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$
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295,692
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$
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246,973
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(a) |
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These amounts represent our minimum capital lease obligations,
net of interest payments totaling $18,000. |
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
43
liabilities at the date of our financial statements, and the
reported amounts of revenue and expenses during the reporting
period. There can be no assurance that actual results will not
differ from those estimates.
Allowance For Doubtful Accounts. The
determination of the collectibility of amounts due from our
customers requires us to use estimates and make judgments
regarding future events and trends, including monitoring our
customer payment history and current credit worthiness to
determine that collectibility is reasonably assured, as well as
consideration of the overall business climate in which our
customers operate. Those uncertainties require us to make
frequent judgments and estimates regarding our customers
ability to pay amounts due us in order to determine the
appropriate amount of valuation allowances required for doubtful
accounts. Provisions for doubtful accounts are recorded when it
becomes evident that the customers will not be able to make the
required payments at either contractual due dates or in the
future.
Revenue Recognition. We provide rental
equipment, oilfield services 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.
Impairment Of Long-Lived Assets. Long-lived
assets, principally property, plant and equipment, 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
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, 2009 we have recorded approximately
$40.6 million of goodwill and $32.6 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. We make
judgments and estimates in conjunction with the carrying value
of these assets, including amounts to be capitalized and whether
the asset has a finite life for amortization purposes.
Our annual impairment tests involve the use of different
valuation techniques, including the income approach
and/or
market approach, to determine the fair value of our reporting
units. Determining the fair value of a reporting unit is a
matter of judgment and often involves the use of significant
estimates and assumptions. If the fair value of the reporting
unit is less than its carrying value, an impairment loss is
recorded to the extent that the implied fair value of the
reporting units goodwill is less than its carrying value.
We recorded an impairment charge of $115.8 million in 2008
as a result of our test. At December 31, 2009 and 2007, no
impairment was deeded necessary. Significant and unanticipated
changes to these assumptions could require an additional
provision for impairment in a future period.
Purchase Price Allocation of Acquired
Businesses. We allocate the purchase price of
acquired businesses to the identifiable assets and liabilities
of the businesses, post acquisition, based on estimated fair
values. The excess of the purchase price over the amount
allocated to the assets and liabilities, if any, is recorded as
goodwill. We engage third-party appraisal firms and valuation
experts to assist in the determination of identifiable assets
and liabilities. Our judgments and estimates for the allocation
of purchase price are based on information available during the
measurement period, these judgments and estimates can materially
impact our financial position as well as our results of
operations.
44
Income Taxes. The determination and evaluation
of our annual income tax provision involves the interpretation
of tax laws in various jurisdictions in which we operate and
requires significant judgment and the use of estimates and
assumptions regarding significant future events such as the
amount, timing and character of income, deductions and tax
credits. Changes in tax laws, regulations and our level of
operations or profitability in each jurisdiction may impact our
tax liability in any given year. While our annual tax provision
is based on the information available to us at the time, a
number of years may elapse before the ultimate tax liabilities
in certain tax jurisdictions are determined. Current income tax
expense (benefit) reflects an estimate of our income tax
liability for the current year, withholding taxes, changes in
tax rates and changes in prior year tax estimates as returns are
filed. Deferred tax assets and liabilities are recognized for
the anticipated future tax effects of temporary differences
between the financial statement basis and the tax basis of our
assets and liabilities using the enacted tax rates in effect at
year end. A valuation allowance for deferred tax assets is
recorded when it is more-likely-than-not that the benefit from
the deferred tax asset will not be realized.
It is our intention to permanently reinvest all of the
undistributed earnings of our
non-U.S. subsidiaries
in such subsidiaries. Accordingly, we have not provided for
U.S. deferred taxes on the undistributed earnings of our
non-U.S. subsidiaries.
If a distribution is made to us from the undistributed earnings
of these subsidiaries, we could be required to record additional
taxes. Because we cannot predict when, if at all, we will make a
distribution of these undistributed earnings, we are unable to
make a determination of the amount of unrecognized deferred tax
liability.
Recently
Issued Accounting Standards
For a discussion of new accounting standards, see the applicable
section in Note 1 to our Consolidated Financial Statements
included in Item 8. Financial Statements and
Supplementary Data.
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 credit
facility with a maturity of April 2012. At December 31,
2009, we had no borrowings on the facility, but availability is
reduced by outstanding letters of credit of $4.2 million.
We do not guarantee obligations of any unconsolidated entities.
|
|
ITEM 7A.
|
QUANTITATIVE
AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.
|
We are exposed to market risk primarily from changes in interest
rates and foreign currency exchange risks.
Interest
Rate Risk
Fluctuations in the general level of interest rates on our
current and future fixed and variable rate debt obligations
expose us to market risk. We are vulnerable to significant
fluctuations in interest rates on our variable rate debt and on
any future refinancing of our fixed rate debt and on future debt.
At December 31, 2009 we were exposed to interest rate
fluctuations on approximately $37.4 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
$374,000. 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
45
short-term nature. As of December 31, 2009, we had
approximately $24.0 million of 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, 2009, 2008 and 2007, we had a net foreign
exchange loss of $0.7 million, $1.2 million and
$128,000, respectively relating to our Drilling and Completion
operations. We also conduct international business through our
Rental Services and Oilfield Services segments and to control
the foreign exchange risk, we provide for payment in
U.S. dollars.
46
|
|
ITEM 8.
|
FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
|
INDEX TO
FINANCIAL STATEMENTS
ALLIS-CHALMERS
ENERGY INC. AND SUBSIDIARIES
|
|
|
|
|
|
|
Page
|
|
|
|
|
48
|
|
|
|
|
49
|
|
|
|
|
51
|
|
|
|
|
52
|
|
|
|
|
53
|
|
|
|
|
54
|
|
|
|
|
55
|
|
|
|
|
90
|
|
47
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, 2009, 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, 2009 has been audited by UHY
LLP, an independent registered public accounting firm, as stated
in their report, which is included herein.
Managements
Certifications
The certifications of Allis-Chalmers Chief Executive
Officer and Chief Financial Officer required by the
Sarbanes-Oxley Act of 2002 have been included as
Exhibits 31 and 32 in Allis-Chalmers
Form 10-K.
ALLIS-CHALMERS
ENERGY INC.
|
|
|
|
|
|
|
|
|
By:
|
|
/s/ Munawar H. Hidayatallah
|
|
|
|
By:
|
|
/s/ Victor M. Perez
|
|
|
Munawar H. Hidayatallah
|
|
|
|
|
|
Victor Perez
|
|
|
Chief Executive Officer
|
|
|
|
|
|
Chief Financial Officer
|
48
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Allis-Chalmers Energy Inc.:
We have audited the accompanying consolidated balance sheets of
Allis-Chalmers Energy Inc. and subsidiaries (the
Company) as of December 31, 2009 and 2008, and
the related consolidated statements of operations,
stockholders equity and cash flows for each of the three
years in the period ended December 31, 2009. Our audits
also included the financial statement schedule listed in the
Index at Item 15. These consolidated financial statements
and financial statement schedule are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these consolidated financial statements and financial
statement schedule based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the 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, 2009 and 2008, and the
consolidated results of their operations and their cash flows
for each of the three years in the period ended
December 31, 2009, 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.
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, 2009, 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 9,
2010 expressed an unqualified opinion thereon.
/s/ UHY LLP
Houston, Texas
March 9, 2010
49
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, 2009,
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 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, 2009, 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, 2009 and 2008, and the
related consolidated statements of operations,
stockholders equity, and cash flows for each of the three
years in the period ended December 31, 2009, and our report
dated March 9, 2010 expressed an unqualified opinion
thereon.
/s/ UHY LLP
Houston, Texas
March 9, 2010
50
ALLIS-CHALMERS
ENERGY INC.
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except
|
|
|
|
for share and per share amounts)
|
|
|
ASSETS
|
Cash and cash equivalents
|
|
$
|
41,072
|
|
|
$
|
6,866
|
|
Trade receivables, net of allowance for doubtful accounts of
$4,923 and $4,205 at December 31, 2009 and 2008,
respectively
|
|
|
105,059
|
|
|
|
157,871
|
|
Inventories
|
|
|
34,528
|
|
|
|
39,087
|
|
Deferred income tax asset
|
|
|
3,790
|
|
|
|
6,176
|
|
Prepaid expenses and other
|
|
|
13,799
|
|
|
|
15,238
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
198,248
|
|
|
|
225,238
|
|
Property and equipment, at cost net of accumulated depreciation
of $209,782 and $137,180 at December 31, 2009 and 2008,
respectively
|
|
|
746,478
|
|
|
|
760,990
|
|
Goodwill
|
|
|
40,639
|
|
|
|
43,273
|
|
Other intangible assets, net of accumulated amortization of
$13,973 and $9,251 at December 31, 2009 and 2008,
respectively
|
|
|
32,649
|
|
|
|
37,371
|
|
Debt issuance costs, net of accumulated amortization of $6,314
and $4,806 at December 31, 2009 and 2008, respectively
|
|
|
9,545
|
|
|
|
12,664
|
|
Deferred income tax asset
|
|
|
22,047
|
|
|
|
3,993
|
|
Other assets
|
|
|
31,014
|
|
|
|
31,522
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,080,620
|
|
|
$
|
1,115,051
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current maturities of long-term debt
|
|
$
|
17,027
|
|
|
$
|
14,617
|
|
Trade accounts payable
|
|
|
34,839
|
|
|
|
62,078
|
|
Accrued salaries, benefits and payroll taxes
|
|
|
22,854
|
|
|
|
20,192
|
|
Accrued interest
|
|
|
15,821
|
|
|
|
18,623
|
|
Accrued expenses
|
|
|
21,918
|
|
|
|
26,642
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
112,459
|
|
|
|
142,152
|
|
Deferred income tax liability
|
|
|
8,166
|
|
|
|
8,253
|
|
Long-term debt, net of current maturities
|
|
|
475,206
|
|
|
|
579,044
|
|
Other long-term liabilities
|
|
|
1,142
|
|
|
|
2,193
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
596,973
|
|
|
|
731,642
|
|
Commitments and Contingencies
|
|
|
|
|
|
|
|
|
Stockholders Equity
|
|
|
|
|
|
|
|
|
Preferred stock, $0.01 par value (25,000,000 shares
authorized, 36,393 shares issued and outstanding at
December 31, 2009 and no shares issued and outstanding at
December 31, 2008)
|
|
|
34,183
|
|
|
|
|
|
Common stock, $0.01 par value (200,000,000 shares
authorized; 71,378,529 issued and outstanding at
December 31, 2009 and 35,674,742 issued and outstanding at
December 31, 2008)
|
|
|
714
|
|
|
|
357
|
|
Capital in excess of par value
|
|
|
422,823
|
|
|
|
334,633
|
|
Retained earnings
|
|
|
25,927
|
|
|
|
48,419
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
483,647
|
|
|
|
383,409
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
1,080,620
|
|
|
$
|
1,115,051
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated
Financial Statements.
51
ALLIS-CHALMERS
ENERGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except per
|
|
|
|
share amounts)
|
|
|
Revenues
|
|
$
|
506,253
|
|
|
$
|
675,948
|
|
|
$
|
570,967
|
|
Operating costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs
|
|
|
379,437
|
|
|
|
443,414
|
|
|
|
338,835
|
|
Depreciation
|
|
|
78,276
|
|
|
|
63,460
|
|
|
|
50,914
|
|
Selling, general and administrative
|
|
|
50,763
|
|
|
|
62,774
|
|
|
|
61,237
|
|
Loss (gain) on asset dispositions
|
|
|
1,602
|
|
|
|
(166
|
)
|
|
|
(8,868
|
)
|
Impairment of goodwill
|
|
|
|
|
|
|
115,774
|
|
|
|
|
|
Amortization
|
|
|
4,722
|
|
|
|
4,212
|
|
|
|
4,067
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
514,800
|
|
|
|
689,468
|
|
|
|
446,185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(8,547
|
)
|
|
|
(13,520
|
)
|
|
|
124,782
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(48,145
|
)
|
|
|
(48,411
|
)
|
|
|
(49,534
|
)
|
Interest income
|
|
|
72
|
|
|
|
5,617
|
|
|
|
3,259
|
|
Gain on debt extinguishment
|
|
|
26,365
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
(798
|
)
|
|
|
(563
|
)
|
|
|
776
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(22,506
|
)
|
|
|
(43,357
|
)
|
|
|
(45,499
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(31,053
|
)
|
|
|
(56,877
|
)
|
|
|
79,283
|
|
Income tax benefit (expense)
|
|
|
9,863
|
|
|
|
17,413
|
|
|
|
(28,843
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
(21,190
|
)
|
|
|
(39,464
|
)
|
|
|
50,440
|
|
Preferred stock dividend
|
|
|
(1,302
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributed to common stockholders
|
|
$
|
(22,492
|
)
|
|
$
|
(39,464
|
)
|
|
$
|
50,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.42
|
)
|
|
$
|
(1.13
|
)
|
|
$
|
1.48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
(0.42
|
)
|
|
$
|
(1.13
|
)
|
|
$
|
1.45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
53,669
|
|
|
|
35,052
|
|
|
|
34,158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
53,669
|
|
|
|
35,052
|
|
|
|
34,701
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated
Financial Statements.
52
ALLIS-CHALMERS
ENERGY INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital in
|
|
|
Retained
|
|
|
Total
|
|
|
|
Preferred Stock
|
|
|
Common Stock
|
|
|
Excess of
|
|
|
Earnings
|
|
|
Stockholders
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Shares
|
|
|
Amount
|
|
|
Par Value
|
|
|
(Deficit)
|
|
|
Equity
|
|
|
|
(In thousands, except share amounts)
|
|
|
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
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(39,464
|
)
|
|
|
(39,464
|
)
|
Issuance of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance under stock plans
|
|
|
|
|
|
|
|
|
|
|
558,707
|
|
|
|
6
|
|
|
|
627
|
|
|
|
|
|
|
|
633
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,902
|
|
|
|
|
|
|
|
7,902
|
|
Tax benefits on stock plans
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
|
|
|
|
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
35,674,742
|
|
|
|
357
|
|
|
|
334,633
|
|
|
|
48,419
|
|
|
|
383,409
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21,190
|
)
|
|
|
(21,190
|
)
|
Preferred stock dividend
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,302
|
)
|
|
|
(1,302
|
)
|
Issuance of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rights offering, net of offering costs
|
|
|
36,393
|
|
|
|
34,183
|
|
|
|
35,683,688
|
|
|
|
357
|
|
|
|
85,683
|
|
|
|
|
|
|
|
120,223
|
|
Issuance under stock plans
|
|
|
|
|
|
|
|
|
|
|
20,099
|
|
|
|
|
|
|
|
43
|
|
|
|
|
|
|
|
43
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,799
|
|
|
|
|
|
|
|
4,799
|
|
Tax benefits on stock plans
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,335
|
)
|
|
|
|
|
|
|
(2,335
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2009
|
|
|
36,393
|
|
|
$
|
34,183
|
|
|
|
71,378,529
|
|
|
$
|
714
|
|
|
$
|
422,823
|
|
|
$
|
25,927
|
|
|
$
|
483,647
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated
Financial Statements.
53
ALLIS-CHALMERS
ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Cash Flows from Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(21,190
|
)
|
|
$
|
(39,464
|
)
|
|
$
|
50,440
|
|
Adjustments to reconcile net income (loss) to net cash provided
by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
82,998
|
|
|
|
67,672
|
|
|
|
54,981
|
|
Amortization and write-off of deferred issuance costs
|
|
|
2,231
|
|
|
|
2,089
|
|
|
|
3,197
|
|
Gain on debt extinguishment
|
|
|
(26,365
|
)
|
|
|
|
|
|
|
|
|
Impairment of goodwill
|
|
|
|
|
|
|
115,774
|
|
|
|
|
|
Stock-based compensation
|
|
|
4,799
|
|
|
|
7,902
|
|
|
|
4,863
|
|
Allowance for bad debts
|
|
|
2,835
|
|
|
|
3,283
|
|
|
|
1,309
|
|
Deferred income taxes
|
|
|
(17,883
|
)
|
|
|
(29,949
|
)
|
|
|
8,017
|
|
Gain on sale of property and equipment
|
|
|
(948
|
)
|
|
|
(1,762
|
)
|
|
|
(2,323
|
)
|
Loss (gain) on asset dispositions
|
|
|
1,602
|
|
|
|
(166
|
)
|
|
|
(8,868
|
)
|
Changes in operating assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease (increase) in trade receivable
|
|
|
49,977
|
|
|
|
(27,499
|
)
|
|
|
(31,404
|
)
|
Decrease (increase) in inventories
|
|
|
4,559
|
|
|
|
(9,719
|
)
|
|
|
(5,375
|
)
|
Decrease (increase) in prepaid expenses and other assets
|
|
|
4,628
|
|
|
|
(1,623
|
)
|
|
|
8,202
|
|
Decrease (increase) in other assets
|
|
|
1,648
|
|
|
|
1,224
|
|
|
|
(4,492
|
)
|
(Decrease) increase in trade accounts payable
|
|
|
(27,588
|
)
|
|
|
21,903
|
|
|
|
10,732
|
|
(Decrease) increase in accrued interest
|
|
|
(2,802
|
)
|
|
|
567
|
|
|
|
5,950
|
|
(Decrease) increase in accrued expenses
|
|
|
(4,607
|
)
|
|
|
1,131
|
|
|
|
1,508
|
|
(Decrease) increase in other liabilities
|
|
|
(1,051
|
)
|
|
|
(1,130
|
)
|
|
|
2,700
|
|
Increase in accrued salaries, benefits and payroll taxes
|
|
|
2,662
|
|
|
|
3,452
|
|
|
|
4,031
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
55,505
|
|
|
|
113,685
|
|
|
|
103,468
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions, net of cash acquired
|
|
|
|
|
|
|
(53,709
|
)
|
|
|
(41,000
|
)
|
Net sales (purchases) of investment interests
|
|
|
(1,102
|
)
|
|
|
1,374
|
|
|
|
(498
|
)
|
Purchases of property and equipment
|
|
|
(78,067
|
)
|
|
|
(154,468
|
)
|
|
|
(113,151
|
)
|
Deposits on asset commitments
|
|
|
2,685
|
|
|
|
(9,901
|
)
|
|
|
(11,488
|
)
|
Proceeds from asset dispositions
|
|
|
3,916
|
|
|
|
3,000
|
|
|
|
16,250
|
|
Proceeds from sale of property and equipment
|
|
|
8,581
|
|
|
|
11,480
|
|
|
|
12,811
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(63,987
|
)
|
|
|
(202,224
|
)
|
|
|
(137,076
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of long-term debt
|
|
|
25,000
|
|
|
|
25,000
|
|
|
|
250,000
|
|
Payments on long-term debt
|
|
|
(64,755
|
)
|
|
|
(9,905
|
)
|
|
|
(309,745
|
)
|
Net (repayments) borrowings on lines of credit
|
|
|
(36,500
|
)
|
|
|
36,500
|
|
|
|
|
|
Proceeds from issuance of stock, net of offering costs
|
|
|
120,223
|
|
|
|
|
|
|
|
100,055
|
|
Payment of preferred stock dividend
|
|
|
(665
|
)
|
|
|
|
|
|
|
|
|
Proceeds from exercise of options and warrants
|
|
|
43
|
|
|
|
633
|
|
|
|
3,319
|
|
Tax benefit on stock plans
|
|
|
|
|
|
|
9
|
|
|
|
1,719
|
|
Debt issuance costs
|
|
|
(658
|
)
|
|
|
(525
|
)
|
|
|
(7,792
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
42,688
|
|
|
|
51,712
|
|
|
|
37,556
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
34,206
|
|
|
|
(36,827
|
)
|
|
|
3,948
|
|
Cash and cash equivalents at beginning of year
|
|
|
6,866
|
|
|
|
43,693
|
|
|
|
39,745
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
41,072
|
|
|
$
|
6,866
|
|
|
$
|
43,693
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated
Financial Statements.
54
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 U.S. including Texas, Louisiana,
Arkansas, Pennsylvania, Oklahoma, New Mexico, offshore in the
Gulf of Mexico, and internationally, primarily in Argentina,
Brazil, Bolivia and Mexico. We operate in three sectors of the
oil and natural gas service industry: Oilfield Services;
Drilling and Completion and Rental 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, 2009 are AirComp LLC, Allis-Chalmers Tubular
Services LLC, Allis-Chalmers Directional Drilling Services LLC,
Allis-Chalmers Rental Services LLC, Allis-Chalmers Production
Services LLC, Allis-Chalmers Management LLC, Allis-Chalmers
Holdings Inc., DLS Drilling, Logistics & Services
Company (DLS), DLS Argentina Limited, Tanus
Argentina S.A., Petro-Rentals LLC, Rebel Rentals LLC
(Rebel), Allis-Chalmers Drilling LLC, BCH Ltd.
(BCH), ALY do Brasil Servicos do Petroleo Ltda,
Drilling Logistics and Services de Mexico and BCH Energy do
Brasil Servicos de Petroleo Ltda. All significant inter-company
transactions have been eliminated.
Revenue
Recognition
We provide rental equipment, oilfield services 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
55
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
from damaged or
lost-in-hole
equipment of $4.3 million, $10.6 million and
$12.6 million for the years ended December 31, 2009,
2008 and 2007, respectively.
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, 2009 and 2008, we
had recorded an allowance for doubtful accounts of
$4.9 million and $4.2 million respectively. Bad debt
expense was $2.8 million, $3.3 million and
$1.3 million for the years ended December 31, 2009,
2008 and 2007, 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.
Interest is capitalized on construction in progress at the
weighted average cost of debt outstanding during the
construction period or at the interest rate on debt incurred for
construction.
The cost of property and equipment currently in service is
depreciated over the estimated useful lives of the related
assets, which range from two 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 $78.3 million,
$63.5 million and $50.9 million for the years ended
December 31, 2009, 2008 and 2007, respectively.
56
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
Goodwill,
Intangible Assets and Amortization
Goodwill 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-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. Reporting units
are at a business unit level and is one level below our
operating segments. 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. Our
annual impairment tests involve the use of different valuation
techniques, including the income approach
and/or
market approach, to determine the fair value of our reporting
units. Determining the fair value of a reporting unit is a
matter of judgment and often involves the use of significant
estimates and assumptions. If the fair value of the reporting
unit is less than its carrying value, an impairment loss is
recorded to the extent that the implied fair value of the
reporting units goodwill is less than its carrying value.
As a result we recorded an impairment of $115.8 million at
December 31, 2008. At December 31, 2009 and 2007, no
impairment was deemed necessary. Significant and unanticipated
changes to these assumptions could require an additional
provision for impairment in a 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, accounts 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,
excluding the senior notes, would not be materially different
due to the instruments interest rates approximating market
rates for similar borrowings at December 31, 2009 and 2008.
Our senior notes, in the aggregate amount of $430.2 million
and $505.0 million at December 31, 2009 and 2008,
respectively, trade over the counter in limited
amounts and on an infrequent basis. Based on those trades we
estimate the fair value of our senior notes to be approximately
$394 million and $284 million at December 31,
2009 and 2008, respectively. The price at which our senior notes
trade is based on many factors such as the level of interest
rates, the economic environment, the outlook for the oilfield
services industry and the perceived credit risk. Additionally,
due to the turmoil in the financial markets of 2008 and 2009,
and its impact on investors of our senior notes, the price at
which our senior notes trade may be affected by the
investors financial distress and need for liquidity.
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, 2009, we have approximately $1.6 million
and $7.6 million of cash and cash equivalents residing in
Argentina and Brazil, respectively. Cash and cash equivalents of
$1.8 million are restricted in conjunction with financial
institution obligations in Brazil. We transact our business with
several financial institutions. However, the amount on deposit
in two financial institutions exceeded the $250,000 federally
insured limit at December 31, 2009 by a total of
57
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
$32.0 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 2009, 2008 and
2007, one of our customers, Pan American Energy LLC Sucursal
Argentina, or Pan American Energy, represented 35.5%, 28.5% and
20.7% of our consolidated revenues, respectively. Revenues from
Pan American Energy represented 56.6%, 62.0% and 51.0% of our
international revenues in 2009, 2008 and 2007, respectively (see
Note 14).
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. Interest expense related to debt
issuance costs were $2.2 million, $2.1 million and
$1.9 million for the years ended December 31, 2009,
2008 and 2007, respectively.
Income
Taxes
Our income tax expense is based on our income, statutory tax
rates and tax planning opportunities available to us in the
various jurisdictions in which we operate. We provide for income
taxes based on the tax laws and rates in effect in the countries
in which operations are conducted and income is earned. Our
income tax expense is expected to fluctuate from year to year as
our operations are conducted in different taxing jurisdictions
and the amount of pre-tax income fluctuates.
The determination and evaluation of our annual income tax
provision involves the interpretation of tax laws in various
jurisdictions in which we operate and requires significant
judgment and the use of estimates and assumptions regarding
significant future events such as the amount, timing and
character of income, deductions and tax credits. Changes in tax
laws, regulations and our level of operations or profitability
in each jurisdiction may impact our tax liability in any given
year. While our annual tax provision is based on the information
available to us at the time, a number of years may elapse before
the ultimate tax liabilities in certain tax jurisdictions are
determined.
Current income tax expense reflects an estimate of our income
tax liability for the current year, withholding taxes, changes
in tax rates and changes in prior year tax estimates as returns
are filed. Deferred tax assets and liabilities are recognized
for the anticipated future tax effects of temporary differences
between the financial statement basis and the tax basis of our
assets and liabilities using the enacted tax rates in effect at
year end. A valuation allowance for deferred tax assets is
recorded when it is more-likely-than-not that the benefit from
the deferred tax asset will not be realized. For
U.S. federal tax purposes, our tax returns for the tax
years 2001 through 2008 remain open for examination by the tax
authorities. Our foreign tax returns remain open for examination
for the tax years 2001 through 2008. Generally, for state tax
purposes, our 2003 through 2008 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 $65.0 million of
undistributed earnings of our
non-U.S. subsidiaries
as of December 31, 2009. 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.
58
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
Stock-Based
Compensation
We recognize all share-based payments to employees, including
grants of employee stock options, in the financial statements
based on their grant-date fair values. We utilize the
Black-Scholes model to determine fair value, which incorporates
assumptions to value stock-based awards. 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. The risk-free interest rate is
the related United States Treasury yield curve for periods
within the expected term of the option at the time of grant. We
estimate forfeiture rates based on our historical experience.
Our net income (loss) for the years ended December 31,
2009, 2008 and 2007 includes approximately $4.8 million,
$7.9 million and $4.9 million of compensation costs
related to share-based payments, respectively. The tax benefit
recorded in association with the share-based payments was $9,000
and $1.7 million for the years-ended December 31, 2008
and 2007, respectively. Due to expired unexercised nonqualified
stock options and restricted stock vesting at market prices
lower than the grant price, we adjusted $2.3 million of
excess tax asset against additional paid in capital. As of
December 31, 2009 there is $5.4 million of
unrecognized compensation expense related to non-vested stock
based compensation grants.
No options were granted in 2008. See Note 10 for further
disclosures regarding stock options. The following assumptions
were applied in determining the compensation costs for options
granted in 2009 and 2007:
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
|
|
2009
|
|
|
2007
|
|
|
Expected dividend yield
|
|
|
|
|
|
|
|
|
Expected price volatility
|
|
|
77.32
|
%
|
|
|
66.21
|
%
|
Risk-free interest rate
|
|
|
1.37
|
%
|
|
|
4.8
|
%
|
Expected life of options
|
|
|
5 years
|
|
|
|
5 years
|
|
Weighted average fair value of options granted at market value
|
|
$
|
0.77
|
|
|
$
|
12.86
|
|
Income
(Loss) Per Common 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 (deficit) per share.
59
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
The components of basic and diluted earnings (deficit) per share
are as follows (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(21,190
|
)
|
|
$
|
(39,464
|
)
|
|
$
|
50,440
|
|
Preferred stock dividend
|
|
|
(1,302
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributed to common stockholders
|
|
$
|
(22,492
|
)
|
|
$
|
(39,464
|
)
|
|
$
|
50,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding excluding nonvested
restricted stock
|
|
|
53,669
|
|
|
|
35,052
|
|
|
|
34,158
|
|
Effect of potentially dilutive common shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants and share based compensation shares
|
|
|
|
|
|
|
|
|
|
|
543
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding and assumed
conversions
|
|
|
53,669
|
|
|
|
35,052
|
|
|
|
34,701
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.42
|
)
|
|
$
|
(1.13
|
)
|
|
$
|
1.48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
(0.42
|
)
|
|
$
|
(1.13
|
)
|
|
$
|
1.45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Potentially dilutive securities excluded as anti-dilutive
|
|
|
15,059
|
|
|
|
1,041
|
|
|
|
1,108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Convertible preferred stock and share based compensation shares
of approximately 7.5 million and 332,000 were excluded in
the computation of diluted earnings per share for 2009 and 2008,
respectively as the effect would have been anti-dilutive due to
the net loss for the year.
Segments
of an Enterprise and Related Information
We designate the internal organization that is used by
management for allocating resources and assessing performance as
the source of our reportable segments. Please see Note 15
for further disclosure of segment information and disclosures by
geographic region.
Reclassification
Certain prior period balances have been reclassified to conform
to current year presentation.
New
Accounting Pronouncements
In September 2006, the Financial Accounting Standards Board, or
FASB, issued new accounting guidance related to fair value
measurements and related disclosures. This new guidance defines
fair value, establishes a framework for measuring fair value,
and expands disclosures about fair value measurements.
Subsequently, the FASB provided for a one-year deferral of the
provisions as it relates to fair value measurement requirements
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 adopted these provisions on
January 1, 2008, except as they relate to nonfinancial
assets and liabilities, which were adopted on January 1,
2009 and neither adoption had any impact on our financial
position or results of operations.
In December 2007, the FASB issued new accounting guidance
related to the accounting for business combinations and related
disclosures. This guidance changes the requirements for an
acquirers recognition
60
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
and measurement of the assets acquired and the liabilities
assumed in a business combination. Additionally, the guidance
requires that acquisition-related costs, including restructuring
costs, be recognized as expense separately from the acquisition.
We adopted this guidance on January 1, 2009 and the
guidance will be applied prospectively to all business
combinations subsequent to the effective date.
In April 2009, the FASB further updated the fair value
measurement standard to provide additional guidance for
estimating fair value when the volume and level of activity for
the asset or liability have significantly decreased. This update
re-emphasizes that regardless of market conditions the fair
value measurement is an exit price concept as defined in the
original standard. It clarifies and includes additional factors
to consider in determining whether there has been a significant
decrease in market activity for an asset or liability and
provides additional clarification on estimating fair value when
the market activity for an asset or liability has declined
significantly. We adopted this update on April 1, 2009 and
there was no impact on our financial position or results of
operations.
In April 2009, the FASB issued new accounting guidance related
to interim disclosures on the fair value of financial
instruments. This guidance requires disclosures about the fair
value of financial instruments whenever a public company issues
financial information for interim reporting periods. We adopted
the additional disclosure requirements in our June 30, 2009
financial statements and there was no impact on our financial
position or results of operations.
In May 2009, the FASB issued new accounting guidance that
establishes general standards of accounting for and disclosures
of events that occur after the balance sheet date but before the
financial statements are issued or are available to be issued.
It requires the disclosure of the date through which an entity
has evaluated subsequent events. We adopted this guidance for
the period ending June 30, 2009, which did not have an
impact on our financial position or results of operations.
In June 2009, the FASB issued new accounting guidance related to
variable interest entities and to provide more relevant and
reliable information to users of financial statements. The
guidance requires an analysis to determine whether an entity is
a variable interest entity and requires an enterprise to perform
an analysis to determine whether the enterprises variable
interest or interests give it a controlling financial interest.
The guidance also requires an ongoing reassessment and
eliminates the quantitative approach previously required for
determining whether an entity is the primary beneficiary. This
guidance is effective for annual reporting periods beginning
after November 15, 2009. We are currently evaluating the
impact the adoption of this guidance will have on our financial
position and operating results.
In August 2009, FASB further updated the fair value measurement
guidance to clarify how an entity should measure liabilities at
fair value. The update reaffirms fair value is based on an
orderly transaction between market participants, even though
liabilities are infrequently transferred due to contractual or
other legal restrictions. However, identical liabilities traded
in the active market should be used when available. When quoted
prices are not available, the quoted price of the identical
liability traded as an asset, quoted prices for similar
liabilities or similar liabilities traded as an asset, or
another valuation approach should be used. This update also
clarifies that restrictions preventing the transfer of a
liability should not be considered as a separate input or
adjustment in the measurement of fair value. We adopted this
guidance for the period ending December 31, 2009, which did
not have an impact on our financial position or results of
operations.
In October 2009, the FASB issued an update to existing guidance
on revenue recognition for arrangements with multiple
deliverables. This update will allow companies to allocate
consideration received for qualified separate deliverables using
estimated selling price for both delivered and undelivered items
when vendor-specific objective evidence or third-party evidence
is unavailable. This update requires expanded qualitative and
quantitative disclosures and is effective for fiscal years
beginning on or after June 15, 2010. However, companies may
elect to adopt as early as interim periods ended
September 30, 2009. This update may be applied either
prospectively from the beginning of the fiscal year for new or
materially modified
61
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
arrangements or retrospectively. We are currently evaluating
both the timing and impact of adopting this update on our
consolidated financial statements.
|
|
NOTE 2
|
EMPLOYEE
BENEFIT PLANS
|
401(k)
Savings Plan
On June 30, 2003, we adopted the 401(k) Profit Sharing Plan
(the Plan). The Plan is a defined contribution
savings plan designed to provide retirement income to our
eligible employees. The Plan is intended to be qualified under
Section 401(k) of the Internal Revenue Code of 1986, as
amended. It is funded by voluntary pre-tax contributions from
eligible employees who may contribute a percentage of their
eligible compensation, limited and subject to statutory limits.
The Plan is also funded by discretionary matching employer
contributions. 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 and our
matching contributions. Contributions are invested, as directed
by the participant, in investment funds available under the
Plan. Matching contributions of approximately $349,000,
$1.5 million and $1.8 million were paid in 2009, 2008
and 2007, respectively.
|
|
NOTE 3
|
ACQUISITIONS
AND ASSET DISPOSITIONS
|
On June 29 2007, we acquired Coker Directional, Inc., or Coker,
for a total consideration of approximately $3.9 million,
which included 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.
Coker was a directional drilling company operating in the Gulf
coast and Central Texas regions. 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 the acquisition (in
thousands):
|
|
|
|
|
Property and equipment
|
|
$
|
3
|
|
Intangible assets, including goodwill
|
|
|
3,902
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
3,905
|
|
|
|
|
|
|
Intangible assets included 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 Oilfield
Services segment.
On July 26, 2007, we acquired Diggar Tools, LLC, or Diggar,
for a total consideration of approximately $10.3 million,
which included 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. Diggar was a directional drilling company
operating in the Rocky Mountains with an inventory of 115
downhole motors. 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
|
|
$
|
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
|
|
|
|
|
|
|
62
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
Diggars historical property and equipment values were
increased by approximately $3.4 million based on
third-party valuations. Intangible assets included approximately
$2.7 million assigned to goodwill. The results of Diggar
since the acquisition are included in our Oilfield Services
segment.
On October 23, 2007, we acquired Rebel for a total
consideration of approximately $7.3 million, which included
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. Rebel is based in Lafayette, Louisiana and
had an extensive inventory of tubular services equipment and
primarily provided tubing installation services. 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
|
|
$
|
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 included 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 Oilfield Services segment.
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. Diamondback was a directional drilling
company based in Conroe, Texas with operations focused in the
Texas Panhandle and Oklahoma. Diamondback assets included 30
downhole motors, five measurement while drilling kits and eight
wireline steering vehicles. 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
|
|
$
|
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 included 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. Subsequent to
the date of acquisition, the sellers earned an additional
$3.0 million cash earn-out
63
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
payment as the business achieved certain earning objectives. The
earn-out increased goodwill and was accrued at December 31,
2008 and was paid in 2009. The results of the Diamondback assets
since their acquisition are included in our Oilfield Services
segment.
On December 31 2008, we completed the acquisition of all of the
outstanding stock of BCH for a total consideration of
approximately $56.1 million. Approximately $251,000 of
costs were incurred in relation to the BCH acquisition. BCH is a
land drilling contractor operating in Brazil. 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
|
|
$
|
7,622
|
|
Property and equipment
|
|
|
53,369
|
|
Intangible assets, including goodwill
|
|
|
26,199
|
|
|
|
|
|
|
Total assets acquired
|
|
|
87,190
|
|
|
|
|
|
|
Current liabilities
|
|
|
14,456
|
|
Long-term debt, less current portion
|
|
|
16,364
|
|
|
|
|
|
|
Total liabilities assumed
|
|
|
30,820
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
56,370
|
|
|
|
|
|
|
BCHs historical property and equipment values were
decreased by approximately $2.8 million based on
third-party valuations. Intangible assets included approximately
$18.5 million assigned to goodwill, $4.9 million to
customer contracts, $2.2 million assigned to trade name and
$600,000 to non-competes based on third-party valuations. The
amortizable intangibles have a weighted-average useful life of
12.6 years. Goodwill was subsequently reduced in 2009 by
$1.3 million of insurance proceeds that were received for a
rig loss that occurred prior to acquisition and by
$1.3 million for the utilization of pre acquisition tax
asset. The results of BCH since the acquisition are included in
our Drilling and Completion segment.
All of the aforementioned acquisitions were accounted for using
the purchase method of accounting.
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 Oilfield Services
segment.
Effective August 1, 2008, we sold our drill pipe tong
manufacturing assets for approximately $7.5 million. We
received cash of approximately $2.0 million at the time of
sale, a
90-day note
for $1.0 million and a
10-year
non-interest bearing note for $4.5 million. Repayment on
the 10-year
note is tied to various performance targets and we have assigned
a fair value of approximately $3.1 million to this note. We
reported a gain of approximately $166,000 on this transaction.
The assets sold represented a small portion of our Oilfield
Services segment.
During 2009, we recorded a $1.6 million loss on asset
disposition in our Drilling and Completion segment. The
insurance proceeds of $3.9 million related to damages
incurred on a blow-out which destroyed one of our drilling rigs
were not sufficient to cover the book value of the rig and
related assets.
64
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
Inventories are comprised of the following as of December 31 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Manufactured
|
|
|
|
|
|
|
|
|
Finished goods
|
|
$
|
2,983
|
|
|
$
|
2,821
|
|
Work in process
|
|
|
2,299
|
|
|
|
1,654
|
|
Raw materials
|
|
|
884
|
|
|
|
2,499
|
|
|
|
|
|
|
|
|
|
|
Total manufactured
|
|
|
6,166
|
|
|
|
6,974
|
|
Rig parts and related inventory
|
|
|
10,654
|
|
|
|
13,097
|
|
Shop supplies and related inventory
|
|
|
7,762
|
|
|
|
7,778
|
|
Chemicals and drilling fluids
|
|
|
4,381
|
|
|
|
3,698
|
|
Rental supplies
|
|
|
2,134
|
|
|
|
3,023
|
|
Hammers
|
|
|
2,257
|
|
|
|
2,257
|
|
Coiled tubing and related inventory
|
|
|
939
|
|
|
|
1,817
|
|
Drive pipe
|
|
|
235
|
|
|
|
443
|
|
|
|
|
|
|
|
|
|
|
Total inventories
|
|
$
|
34,528
|
|
|
$
|
39,087
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 5
|
PROPERTY
AND OTHER INTANGIBLE ASSETS
|
Property and equipment is comprised of the following as of
December 31 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
|
|
|
|
|
|
|
Period
|
|
|
2009
|
|
|
2008
|
|
|
Land
|
|
|
|
|
|
$
|
2,211
|
|
|
$
|
2,214
|
|
Building and improvements
|
|
|
15-20 years
|
|
|
|
8,611
|
|
|
|
8,387
|
|
Transportation equipment
|
|
|
2-10 years
|
|
|
|
33,353
|
|
|
|
34,493
|
|
Drill pipe and rental equipment
|
|
|
2-20 years
|
|
|
|
380,185
|
|
|
|
373,064
|
|
Drilling, workover and pulling rigs
|
|
|
20 years
|
|
|
|
248,780
|
|
|
|
228,857
|
|
Machinery and equipment
|
|
|
2-20 years
|
|
|
|
226,601
|
|
|
|
212,594
|
|
Furniture, computers, software and leasehold improvements
|
|
|
3-10 years
|
|
|
|
9,128
|
|
|
|
8,711
|
|
Construction in progress equipment
|
|
|
N/A
|
|
|
|
47,391
|
|
|
|
29,850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
956,260
|
|
|
|
898,170
|
|
Less: accumulated depreciation
|
|
|
|
|
|
|
(209,782
|
)
|
|
|
(137,180
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
|
|
|
|
$
|
746,478
|
|
|
$
|
760,990
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The net book value of equipment recorded under capital leases
was $1.0 million and $1.7 million as of
December 31, 2009 and 2008, respectively. Interest expense
capitalized to property and equipment was $2.2 million and
$1.9 million for the years ended December 31, 2009 and
2008, respectively.
65
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
Other intangible assets are as follows as of December 31 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization
|
|
|
|
|
|
|
|
|
|
Period
|
|
|
2009
|
|
|
2008
|
|
|
Intellectual property
|
|
|
10-20 years
|
|
|
$
|
3,829
|
|
|
$
|
3,829
|
|
Non-compete agreements
|
|
|
3-5 years
|
|
|
|
2,640
|
|
|
|
2,640
|
|
Customer relationships
|
|
|
10-15 years
|
|
|
|
38,033
|
|
|
|
38,033
|
|
Patents
|
|
|
12-15 years
|
|
|
|
1,327
|
|
|
|
1,327
|
|
Other intangible assets
|
|
|
2-10 years
|
|
|
|
793
|
|
|
|
793
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
46,622
|
|
|
|
46,622
|
|
Less: accumulated amortization
|
|
|
|
|
|
|
(13,973
|
)
|
|
|
(9,251
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other intangibles assets, net
|
|
|
|
|
|
$
|
32,649
|
|
|
$
|
37,371
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
|
Gross
|
|
|
Accumulated
|
|
|
Gross
|
|
|
Accumulated
|
|
|
|
Value
|
|
|
Amortization
|
|
|
Value
|
|
|
Amortization
|
|
|
Intellectual property
|
|
$
|
3,829
|
|
|
$
|
823
|
|
|
$
|
3,829
|
|
|
$
|
507
|
|
Non-compete agreements
|
|
|
2,640
|
|
|
|
1,879
|
|
|
|
2,640
|
|
|
|
1,198
|
|
Customer relationships
|
|
|
38,033
|
|
|
|
10,209
|
|
|
|
38,033
|
|
|
|
6,676
|
|
Patents
|
|
|
1,327
|
|
|
|
382
|
|
|
|
1,327
|
|
|
|
279
|
|
Other intangible assets
|
|
|
793
|
|
|
|
680
|
|
|
|
793
|
|
|
|
591
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
46,622
|
|
|
$
|
13,973
|
|
|
$
|
46,622
|
|
|
$
|
9,251
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization expense related to other intangibles was
$4.7 million, $4.2 million and $4.1 million for
the years ended December 31, 2009, 2008 and 2007,
respectively. Future amortization of intangible assets at
December 31, 2009 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible Amortization by Period
|
|
|
|
Years Ended December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014 and
|
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
Thereafter
|
|
|
Intellectual property
|
|
$
|
316
|
|
|
$
|
316
|
|
|
$
|
316
|
|
|
$
|
316
|
|
|
$
|
1,742
|
|
Non-compete agreements
|
|
|
489
|
|
|
|
248
|
|
|
|
24
|
|
|
|
|
|
|
|
|
|
Customer relationships
|
|
|
3,532
|
|
|
|
3,532
|
|
|
|
3,532
|
|
|
|
3,532
|
|
|
|
13,696
|
|
Patents
|
|
|
102
|
|
|
|
102
|
|
|
|
102
|
|
|
|
102
|
|
|
|
537
|
|
Other intangible assets
|
|
|
83
|
|
|
|
28
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total intangible amortization
|
|
$
|
4,522
|
|
|
$
|
4,226
|
|
|
$
|
3,976
|
|
|
$
|
3,950
|
|
|
$
|
15,975
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We had a loss before income taxes of $43.9 million and
$95.3 million for U.S. tax purposes for the years
ended December 31, 2009 and 2008, respectively. We had
income before income taxes of $41.7 million for
U.S. tax purposes for the year ended December 31,
2007. We also had income before income taxes of
$12.9 million, $38.4 million and $37.6 million
reported in
non-U.S. countries
for the years ended December 31, 2009, 2008 and 2007,
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.
We are required to file
66
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
a consolidated U.S. federal income tax return. We file
foreign income tax returns in Argentina, Brazil, Bolivia and
Canada related to our Drilling and Completion operations.
We recognize the impact of uncertain tax positions in our
financial statements, if a tax position is challenged by a
taxing authority and there is a more likely than not chance the
tax position will be disallowed, based on the technical merits
of the position. We recognize interest and penalties related to
uncertain tax positions as a component of income tax expense. We
identified no uncertain tax positions for the three years in the
period ended December 31, 2009.
The income tax provision consists of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Current income tax expense (benefit):
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
8
|
|
|
$
|
(1,525
|
)
|
|
$
|
6,814
|
|
State
|
|
|
324
|
|
|
|
471
|
|
|
|
1,053
|
|
Foreign
|
|
|
7,688
|
|
|
|
13,590
|
|
|
|
12,959
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,020
|
|
|
|
12,536
|
|
|
|
20,826
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax expense (benefit):
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(15,185
|
)
|
|
|
(28,462
|
)
|
|
|
7,081
|
|
State
|
|
|
(1,626
|
)
|
|
|
(1,149
|
)
|
|
|
349
|
|
Foreign
|
|
|
(1,072
|
)
|
|
|
(338
|
)
|
|
|
587
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(17,883
|
)
|
|
|
(29,949
|
)
|
|
|
8,017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(9,863
|
)
|
|
$
|
(17,413
|
)
|
|
$
|
28,843
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
67
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
Significant components of deferred income tax assets as of
December 31, were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Deferred income tax assets:
|
|
|
|
|
|
|
|
|
Amortization
|
|
$
|
30,902
|
|
|
$
|
32,081
|
|
Net operating loss carryforwards
|
|
|
40,752
|
|
|
|
15,552
|
|
Share-based compensation
|
|
|
2,199
|
|
|
|
2,691
|
|
Foreign tax credits
|
|
|
992
|
|
|
|
760
|
|
A-C Product Liability Trust
|
|
|
803
|
|
|
|
2,448
|
|
Other net future deductible items
|
|
|
3,083
|
|
|
|
3,303
|
|
Valuation allowance
|
|
|
(13,999
|
)
|
|
|
(13,265
|
)
|
|
|
|
|
|
|
|
|
|
Gross deferred income tax assets
|
|
|
64,732
|
|
|
|
43,570
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax liabilities
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
(46,050
|
)
|
|
|
(40,524
|
)
|
Other net future taxable items
|
|
|
(1,011
|
)
|
|
|
(1,130
|
)
|
|
|
|
|
|
|
|
|
|
Gross deferred income tax liabilities
|
|
|
(47,061
|
)
|
|
|
(41,654
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred income tax assets
|
|
$
|
17,671
|
|
|
$
|
1,916
|
|
|
|
|
|
|
|
|
|
|
Net current deferred income tax assets
|
|
$
|
3,790
|
|
|
$
|
6,176
|
|
Net noncurrent deferred income tax assets
|
|
|
22,047
|
|
|
|
3,993
|
|
Net noncurrent deferred income tax liabilities
|
|
|
(8,166
|
)
|
|
|
(8,253
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred income tax assets
|
|
$
|
17,671
|
|
|
$
|
1,916
|
|
|
|
|
|
|
|
|
|
|
The following table reconciles the statutory tax rates to our
actual tax rate:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Statutory income tax rate
|
|
|
34.0
|
%
|
|
|
34.0
|
%
|
|
|
35.0
|
%
|
State taxes, net of federal benefit
|
|
|
1.7
|
|
|
|
0.4
|
|
|
|
1.8
|
|
Foreign currency remeasurement
|
|
|
0.3
|
|
|
|
2.1
|
|
|
|
|
|
Nondeductible goodwill, permanent differences and other
|
|
|
(4.2
|
)
|
|
|
(5.9
|
)
|
|
|
(0.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate
|
|
|
31.8
|
%
|
|
|
30.6
|
%
|
|
|
36.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2009 and
2008 were $67.8 million and $6.7 million,
respectively, expiring through 2029.
68
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
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, 2009 and 2008, the valuation
allowance was $14.0 million and $13.3 million,
respectively. The valuation allowances relate to net operating
losses incurred by BCH, both pre and post acquisition, in which
we currently do not have a tax strategy to utilize.
Approximately $4.4 million and $4.7 million of ad
valorem, franchise, income, sales and other tax accruals are
included in our accrued expense balances of $21.9 million
and $26.6 million as of December 31, 2009 and 2008,
respectively.
Our long-term debt consists of the following as of December 31
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Senior notes
|
|
$
|
430,238
|
|
|
$
|
505,000
|
|
Revolving line of credit
|
|
|
|
|
|
|
36,500
|
|
Bank term loans
|
|
|
60,744
|
|
|
|
49,609
|
|
Seller notes
|
|
|
|
|
|
|
750
|
|
Notes payable to former directors
|
|
|
|
|
|
|
32
|
|
Insurance premium financing notes
|
|
|
997
|
|
|
|
991
|
|
Capital lease obligations
|
|
|
254
|
|
|
|
779
|
|
|
|
|
|
|
|
|
|
|
Total debt
|
|
|
492,233
|
|
|
|
593,661
|
|
Less: current maturities of long-term debt
|
|
|
17,027
|
|
|
|
14,617
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
475,206
|
|
|
$
|
579,044
|
|
|
|
|
|
|
|
|
|
|
Our weighted average interest rate for current and total debt
was approximately 5.0% and 8.4% as of December 31, 2009 and
6.4% and 8.3% as of December 31, 2008, respectively.
Maturities of debt obligations as of December 31, 2009 are
as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt
|
|
|
Capital Leases
|
|
|
Total
|
|
|
Year Ending:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
$
|
16,778
|
|
|
$
|
249
|
|
|
$
|
17,027
|
|
December 31, 2011
|
|
|
15,752
|
|
|
|
5
|
|
|
|
15,757
|
|
December 31, 2012
|
|
|
14,281
|
|
|
|
|
|
|
|
14,281
|
|
December 31, 2013
|
|
|
7,378
|
|
|
|
|
|
|
|
7,378
|
|
December 31, 2014
|
|
|
229,360
|
|
|
|
|
|
|
|
229,360
|
|
Thereafter
|
|
|
208,430
|
|
|
|
|
|
|
|
208,430
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
491,979
|
|
|
$
|
254
|
|
|
$
|
492,233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior
notes, term 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 Rental Tools, Inc. and DLS, to
repay existing debt and for general corporate purposes. On
June 29, 2009, we closed on a tender offer in which we
purchased
69
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
$30.6 million aggregate principal of our 9.0% senior
notes for a total consideration of $650 per $1,000 principal
amount.
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 Oil & Gas Rental Services, Inc, or
OGR. On June 29, 2009, we closed on a tender offer in which
we purchased $44.2 million aggregate principal of our
8.5% senior notes for a total consideration of $600 per
$1,000 principal amount.
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. 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. On April 9, 2009, we entered
into a Third Amendment to our existing Second Amended and
Restated Credit Agreement dated as of April 26, 2007 which
modified the leverage and interest coverage ratio covenants of
the Credit Agreement. In addition, permitted maximum capital
expenditures were reduced to $85.0 million for 2009
compared to the previous limit of $120.0 million. Effective
December 31, 2009, we amended the leverage and interest
coverage ratio covenants of the Credit Agreement. This amendment
relaxed the required financial ratios for the quarter ended
December 31, 2009 and for each of the quarters in 2010. Our
obligations under the amended and restated credit agreement are
secured by substantially all of our assets located in the
U.S. We were in compliance with all debt covenants as of
December 31, 2009 and 2008. As of December 31, 2009,
we had no borrowings under the facility except $4.2 million
in outstanding letters of credit. At December 31, 2008 we
had $36.5 million of borrowings outstanding and
$5.8 million in outstanding letters of credit. The credit
agreement loan rates are based on prime or LIBOR plus a margin.
The weighted average interest rate was 4.6% at December 31,
2008.
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 2.1% and 5.1% as of
December 31, 2009 and 2008, respectively. The bank loans
are denominated in U.S. dollars and the outstanding amount
due as of December 31, 2009 and 2008 was $1.1 million
and $2.5 million, respectively.
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 were used
to fund a portion of the purchase price of the new drilling and
service rigs ordered for our Drilling and Completion segment.
The loan is repayable over four years in equal semi-annual
installments beginning one year after each disbursement with the
final principal payment due not later than March 15, 2013.
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. We were in
compliance with all debt covenants as of December 31, 2009
and 2008. The bank loan rates are based on LIBOR plus a margin.
The weighted average interest rate was 4.4% and 6.9% at
December 31, 2009 and 2008, respectively. The bank loans
are denominated in U.S. dollars and the outstanding amount
as of December 31, 2009 and 2008 was $20.1 million and
$25.0 million, respectively.
As part of our acquisition of BCH, we assumed a
$23.6 million term loan credit facility with a bank. The
credit agreement is dated June 2007 and contains customary
events of default and financial covenants. Obligations under the
facility are secured by substantially all of the BCH assets. The
facility is repayable in
70
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
quarterly principal installments plus interest with the final
payment due not later than August 2012. We were in compliance
with all debt covenants as of December 31, 2009 and 2008.
The credit facility loan is denominated in U.S. dollars and
interest rates are based on LIBOR plus a margin. At
December 31, 2009 and 2008, the outstanding amount of the
loan was $16.2 million and $22.1 million and the
interest rate was 3.5% and 6.0%, respectively.
On May 22, 2009, we drew down $25.0 million on a new
term loan credit facility with a lending institution. The
facility was utilized to fund a portion of the purchase price of
two new drilling rigs. The loan is secured by the equipment. The
facility is repayable in quarterly installments of approximately
$1.4 million of principal and interest and matures in May
2015. The loan bears interest at a fixed rate of 9.0%. At
December 31, 2009, the outstanding amount of the loan was
$23.4 million.
Notes
payable
In connection with the acquisition of Rogers Oil Tools, Inc., we
issued to the seller a note in the amount of $750,000. The note
bore interest at 5.0% and was paid in full in April 2009 in
accordance with its terms.
In 2000 we compensated directors 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, 2009 and
2008, the principal and accrued interest on these notes totaled
approximately $0 and $32,000, respectively.
In April 2008 and August 2008, we obtained insurance premium
financings in the aggregate amount of $3.0 million with a
fixed average weighted interest rate of 4.9%. Under terms of the
agreements, amounts outstanding are paid over 10 and
11 month repayment schedules. The outstanding balance of
these notes was approximately $0 and $991,000 at
December 31, 2009 and 2008, respectively. In 2009, we
obtained insurance premium financings in the aggregate amount of
$3.2 million with a fixed average weighted interest rate of
4.8%. Under terms of the agreements, the amount outstanding is
paid over 10 and 11 month repayment schedules. The
outstanding balance of these notes was approximately $997,000 as
of December 31, 2009.
Other
debt
As part of our acquisition of BCH, we assumed various capital
leases with terms of two to three years. The outstanding balance
under these capital leases was $254,000 and $779,000 at
December 31, 2009 and 2008, respectively.
|
|
NOTE 8
|
COMMITMENTS
AND CONTINGENCIES
|
We have placed orders for capital equipment totaling
$19.2 million to be received and paid for through 2010.
Approximately $12.1 million is for drilling rigs for our
Drilling and Completion segment, $2.3 million is for drill
pipe for our Drilling and Completion segment and
$4.7 million is for various equipment to be utilized by our
Oilfield Services segment.
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, 2009, 2008 and 2007 was
$3.3 million, $2.8 million and $2.7 million,
respectively.
71
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
At December 31, 2009, future minimum rental commitments for
all operating leases are as follows (in thousands):
|
|
|
|
|
Years Ending:
|
|
|
|
|
December 31, 2010
|
|
$
|
2,670
|
|
December 31, 2011
|
|
|
2,016
|
|
December 31, 2012
|
|
|
1,196
|
|
December 31, 2013
|
|
|
872
|
|
December 31, 2014
|
|
|
632
|
|
Thereafter
|
|
|
601
|
|
|
|
|
|
|
Total
|
|
$
|
7,987
|
|
|
|
|
|
|
|
|
NOTE 9
|
STOCKHOLDERS
EQUITY
|
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.
During 2007, we also had restricted stock award grants, and
options and warrants exercised, 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.
During 2008, we had restricted stock award grants, and options
exercised, which resulted in 558,707 shares of our common
stock being issued for approximately $633,000. We recognized
approximately $7.9 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
$9,000 of tax benefit related to our stock compensation plans.
In June 2009, we closed our backstopped rights offering and
private placement of convertible preferred stock and received
proceeds of approximately $120.2 million net of
$5.4 million offering expenses. Pursuant to an Investment
Agreement, Lime Rock Partners V, L.P., or Lime Rock, agreed
to backstop the rights offering by purchasing, at the
subscription price, shares of common stock not purchased by our
existing stockholders. We sold 15,794,644 shares of our
common stock to existing stockholders who exercised their rights
through the rights offering and 19,889,044 shares of common
stock to Lime Rock, at a price of $2.50 per share. We issued
36,393 shares of 7.0% convertible perpetual preferred stock
to Lime Rock and received proceeds of approximately
$34.2 million net of $2.2 million offering expenses.
The preferred stock has an initial liquidation preference of
$1,000 per share and is adjusted to $3,000 per share upon
certain liquidation events. Dividends on the preferred stock are
declared quarterly if approved by our Board of Directors and
dividends accumulate if not paid. The preferred stock is, with
respect to dividend rights and rights upon liquidation,
winding-up,
or dissolution: (1) senior to common stock and any other
class or series of capital stock, the terms of which do not
expressly provide that such class or series ranks senior to or
on parity with the preferred stock; (2) on a parity with
any other class or series of capital stock, the terms of which
provide that it will rank on a parity with the preferred stock;
(3) junior to each class or series of capital stock (other
than common stock) established after the original issue date,
the terms of which expressly provide that it will rank senior to
the preferred stock; and (4) junior to all our existing and
future debt obligations and other liabilities, including claims
of trade creditors.
72
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
During the year ended December 31, 2009, we declared
$1.3 million in dividends on our preferred stock. Accrued
dividends of approximately $637,000 were included in our accrued
expense balance of $21.9 million as of December 31,
2009. The accrued dividends were paid in February 2010.
Each share of the preferred stock is convertible at the
holders option, at any time into 390.2439 shares of
our common stock under certain conditions, subject to specified
adjustments. This conversion rate represents an equivalent
conversion price of approximately $2.56 per share. Conversion is
limited to the earlier of June 26, 2012 or the date on
which the transfer restrictions included in the Investment
Agreement expire, unless immediately after giving effect to such
conversion, such person or group would not beneficially own a
number of shares of our common stock exceeding 35% of the total
number of issued and outstanding shares of common stock, unless
we have given prior written consent to such conversion. In
addition, we will be able to cause the preferred stock to be
converted into common stock five years after issuance if our
common stock is trading at a premium of 300% to the conversion
price for 30 consecutive trading days prior to our issuance of a
press release announcing the mandatory conversion. Generally,
holders of the preferred stock vote together with the common
stock on an as-converted basis, however, the preferred stock
voting rights held by any person or group when aggregated with
common stock is limited to 35% of all the votes to be cast by
all stockholders, including holders of common stock.
During 2009, we had restricted stock award grants, and options
exercised, which resulted in 20,099 shares of our common
stock being issued for approximately $43,000. We recognized
approximately $4.8 million of compensation expense related
to share based payments that was recorded as capital in excess
of par value (see Note 1). Due to expired unexercised
nonqualified stock options and restricted stock vesting at
market prices lower than the grant price, we adjusted
$2.3 million of excess tax asset against additional paid in
capital.
In 2000, we issued stock options and promissory notes to certain
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, 2009, 4,000 of the stock options remain
outstanding. No compensation expense has been recorded for these
options as they were issued with an exercise price equal to the
fair value of the common stock at the date of grant.
The 2003 Incentive Stock Plan, or 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 of our common
stock 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, or 2006 Plan, was approved and amended
by our stockholders in November 2006 and 2009. The 2006 Plan is
administered by the Compensation Committee of the Board. The
maximum number of shares of our common stock that may be issued
under the 2006 Plan is equal to 8,500,000 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 of our employees, consultants and
non-employee directors are eligible to participate in the 2006
Plan. The term of each Award
73
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
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 years from the date of its grant.
A summary of our stock option activity and related information
is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
December 31, 2008
|
|
|
December 31, 2007
|
|
|
|
Shares
|
|
|
Weighted Ave.
|
|
|
Shares
|
|
|
Weighted Ave.
|
|
|
Shares
|
|
|
Weighted Avg.
|
|
|
|
Under
|
|
|
Exercise
|
|
|
Under
|
|
|
Exercise
|
|
|
Under
|
|
|
Exercise
|
|
|
|
Option
|
|
|
Price
|
|
|
Option
|
|
|
Price
|
|
|
Option
|
|
|
Price
|
|
|
Beginning balance
|
|
|
901,732
|
|
|
$
|
10.95
|
|
|
|
986,763
|
|
|
$
|
10.77
|
|
|
|
1,350,365
|
|
|
$
|
6.88
|
|
Granted
|
|
|
125,000
|
|
|
|
1.23
|
|
|
|
|
|
|
|
|
|
|
|
220,000
|
|
|
|
21.83
|
|
Canceled
|
|
|
(305,000
|
)
|
|
|
18.18
|
|
|
|
(13,328
|
)
|
|
|
8.87
|
|
|
|
(17,334
|
)
|
|
|
8.45
|
|
Exercised
|
|
|
(20,000
|
)
|
|
|
2.75
|
|
|
|
(71,703
|
)
|
|
|
8.83
|
|
|
|
(566,268
|
)
|
|
|
5.86
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
|
701,732
|
|
|
$
|
6.31
|
|
|
|
901,732
|
|
|
$
|
10.95
|
|
|
|
986,763
|
|
|
$
|
10.77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 $36,000, $542,000 and $6.6 million during the
years ended December 31, 2009, 2008 and 2007, respectively.
As of December 31, 2009, there was approximately $572,000
of total unrecognized compensation cost related to stock
options, with $539,000, $28,000 and $5,000 to be recognized
during the years ended December 31, 2010, 2011 and 2012,
respectively.
The following table summarizes additional information about our
stock options outstanding as of December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
$
|
1.23-2.75
|
|
|
|
127,300
|
|
|
|
9.09
|
|
|
$
|
1.26
|
|
|
|
2,300
|
|
|
|
3.96
|
|
|
$
|
2.75
|
|
|
3.86-4.87
|
|
|
|
296,500
|
|
|
|
5.07
|
|
|
|
4.18
|
|
|
|
296,500
|
|
|
|
5.07
|
|
|
|
4.18
|
|
|
10.85-14.74
|
|
|
|
277,932
|
|
|
|
5.88
|
|
|
|
10.90
|
|
|
|
277,932
|
|
|
|
5.88
|
|
|
|
10.90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.23-14.74
|
|
|
|
701,732
|
|
|
|
6.12
|
|
|
$
|
6.31
|
|
|
|
576,732
|
|
|
|
5.46
|
|
|
$
|
7.42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The aggregate pretax intrinsic value of stock options
outstanding and exercisable was approximately $320,000 and
$2,000, respectively, at December 31, 2009. The amount
represents the value that would have been received by the option
holders had the respective options been exercised on
December 31, 2009.
Restricted
Stock Awards
In addition to stock options, our 2003 and 2006 Plans allow for
the grant of restricted stock awards, or 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
74
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
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, 2009
|
|
|
December 31, 2008
|
|
|
December 31, 2007
|
|
|
|
Number
|
|
|
Weighted Ave.
|
|
|
Number
|
|
|
Weighted Ave.
|
|
|
Number
|
|
|
Weighted Ave.
|
|
|
|
of
|
|
|
Grant Date Fair
|
|
|
of
|
|
|
Grant Date Fair
|
|
|
of
|
|
|
Grant Date Fair
|
|
|
|
Shares
|
|
|
Value Per Share
|
|
|
Shares
|
|
|
Value Per Share
|
|
|
Shares
|
|
|
Value Per Share
|
|
|
Beginning balance
|
|
|
953,102
|
|
|
$
|
15.34
|
|
|
|
993,203
|
|
|
$
|
17.45
|
|
|
|
27,000
|
|
|
$
|
18.30
|
|
Granted
|
|
|
17,000
|
|
|
|
1.23
|
|
|
|
258,670
|
|
|
|
9.47
|
|
|
|
996,203
|
|
|
|
17.44
|
|
Vested
|
|
|
(122,276
|
)
|
|
|
11.68
|
|
|
|
(298,771
|
)
|
|
|
17.26
|
|
|
|
(30,000
|
)
|
|
|
18.01
|
|
Forfeited
|
|
|
(10,200
|
)
|
|
|
12.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
|
837,626
|
|
|
$
|
15.63
|
|
|
|
953,102
|
|
|
$
|
15.34
|
|
|
|
993,203
|
|
|
$
|
17.45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The total fair value of RSA shares that vested during 2009 was
approximately $371,000. As of December 31, 2009, there was
approximately $4.8 million of total unrecognized
compensation cost related to nonvested RSAs, with
$3.4 million, $1.2 million, and $195,000 to be
recognized during the years ended December 31, 2010, 2011
and 2012, respectively.
|
|
NOTE 11
|
STOCK
PURCHASE WARRANTS
|
In conjunction with our purchase of Mountain Compressed Air,
Inc., or MCA, 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.
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.
In conjunction with BCH debt financing in January of 2007, BCH
issued a common stock warrant for 250,000 shares to a
financial institution. The warrant entitles the holder to
acquire up to 250,000 shares of common stock of BCH at an
exercise price of $10.00 per share over a five-year period.
|
|
NOTE 12
|
GAIN ON
DEBT EXTINGUISHMENT
|
We recorded a gain of $26.4 million as a result of a tender
offer that we completed on June 29, 2009. We purchased
$30.6 million aggregate principal of our 9.0% senior
notes and $44.2 million aggregate principal of our
8.5% senior notes for approximately $46.4 million. We
also wrote-off $1.5 million of debt issuance costs related
to the retired notes and we incurred approximately $466,000 in
expenses related to the transactions.
75
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
NOTE 13
|
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):
CONDENSED
CONSOLIDATING BALANCE SHEETS
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers
|
|
|
|
|
|
Subsidiary
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors
|
|
|
Adjustments
|
|
|
Total
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
|
|
|
$
|
31,858
|
|
|
$
|
9,214
|
|
|
$
|
|
|
|
$
|
41,072
|
|
Trade receivables, net
|
|
|
|
|
|
|
47,358
|
|
|
|
58,962
|
|
|
|
(1,261
|
)
|
|
|
105,059
|
|
Inventories
|
|
|
|
|
|
|
16,271
|
|
|
|
18,257
|
|
|
|
|
|
|
|
34,528
|
|
Intercompany receivables
|
|
|
|
|
|
|
79,521
|
|
|
|
767
|
|
|
|
(80,288
|
)
|
|
|
|
|
Note receivable from affiliate
|
|
|
28,379
|
|
|
|
|
|
|
|
|
|
|
|
(28,379
|
)
|
|
|
|
|
Prepaid expenses and other
|
|
|
891
|
|
|
|
6,826
|
|
|
|
9,872
|
|
|
|
|
|
|
|
17,589
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
29,270
|
|
|
|
181,834
|
|
|
|
97,072
|
|
|
|
(109,928
|
)
|
|
|
198,248
|
|
Property and equipment, net
|
|
|
|
|
|
|
489,921
|
|
|
|
256,557
|
|
|
|
|
|
|
|
746,478
|
|
Goodwill
|
|
|
|
|
|
|
23,251
|
|
|
|
17,388
|
|
|
|
|
|
|
|
40,639
|
|
Other intangible assets, net
|
|
|
460
|
|
|
|
25,236
|
|
|
|
6,953
|
|
|
|
|
|
|
|
32,649
|
|
Debt issuance costs, net
|
|
|
9,408
|
|
|
|
137
|
|
|
|
|
|
|
|
|
|
|
|
9,545
|
|
Note receivable from affiliates
|
|
|
4,415
|
|
|
|
|
|
|
|
|
|
|
|
(4,415
|
)
|
|
|
|
|
Investments in affiliates
|
|
|
942,378
|
|
|
|
|
|
|
|
|
|
|
|
(942,378
|
)
|
|
|
|
|
Other assets
|
|
|
24,366
|
|
|
|
25,039
|
|
|
|
3,656
|
|
|
|
|
|
|
|
53,061
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,010,297
|
|
|
$
|
745,418
|
|
|
$
|
381,626
|
|
|
$
|
(1,056,721
|
)
|
|
$
|
1,080,620
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
$
|
|
|
|
$
|
4,444
|
|
|
$
|
12,583
|
|
|
$
|
|
|
|
$
|
17,027
|
|
Trade accounts payable
|
|
|
|
|
|
|
12,195
|
|
|
|
23,905
|
|
|
|
(1,261
|
)
|
|
|
34,839
|
|
Accrued salaries, benefits and payroll taxes
|
|
|
|
|
|
|
2,762
|
|
|
|
20,092
|
|
|
|
|
|
|
|
22,854
|
|
Accrued interest
|
|
|
15,372
|
|
|
|
228
|
|
|
|
221
|
|
|
|
|
|
|
|
15,821
|
|
Accrued expenses
|
|
|
752
|
|
|
|
11,608
|
|
|
|
9,558
|
|
|
|
|
|
|
|
21,918
|
|
Intercompany payables
|
|
|
80,288
|
|
|
|
|
|
|
|
|
|
|
|
(80,288
|
)
|
|
|
|
|
Note payable to affiliate
|
|
|
|
|
|
|
|
|
|
|
28,379
|
|
|
|
(28,379
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
96,412
|
|
|
|
31,237
|
|
|
|
94,738
|
|
|
|
(109,928
|
)
|
|
|
112,459
|
|
Long-term debt, net of current maturities
|
|
|
430,238
|
|
|
|
19,941
|
|
|
|
25,027
|
|
|
|
|
|
|
|
475,206
|
|
Note payable to affiliate
|
|
|
|
|
|
|
|
|
|
|
4,415
|
|
|
|
(4,415
|
)
|
|
|
|
|
Deferred income tax liability
|
|
|
|
|
|
|
|
|
|
|
8,166
|
|
|
|
|
|
|
|
8,166
|
|
Other long-term liabilities
|
|
|
|
|
|
|
|
|
|
|
1,142
|
|
|
|
|
|
|
|
1,142
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
526,650
|
|
|
|
51,178
|
|
|
|
133,488
|
|
|
|
(114,343
|
)
|
|
|
596,973
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Stock
|
|
|
34,183
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34,183
|
|
Common stock
|
|
|
714
|
|
|
|
3,526
|
|
|
|
42,963
|
|
|
|
(46,489
|
)
|
|
|
714
|
|
Capital in excess of par value
|
|
|
422,823
|
|
|
|
570,512
|
|
|
|
137,439
|
|
|
|
(707,951
|
)
|
|
|
422,823
|
|
Retained earnings
|
|
|
25,927
|
|
|
|
120,202
|
|
|
|
67,736
|
|
|
|
(187,938
|
)
|
|
|
25,927
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
483,647
|
|
|
|
694,240
|
|
|
|
248,138
|
|
|
|
(942,378
|
)
|
|
|
483,647
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stock holders equity
|
|
$
|
1,010,297
|
|
|
$
|
745,418
|
|
|
$
|
381,626
|
|
|
$
|
(1,056,721
|
)
|
|
$
|
1,080,620
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
76
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
CONDENSED
CONSOLIDATING INCOME STATEMENTS
For the Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers
|
|
|
|
|
|
Subsidiary
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors
|
|
|
Adjustments
|
|
|
Total
|
|
|
Revenues
|
|
$
|
|
|
|
$
|
202,727
|
|
|
$
|
303,579
|
|
|
$
|
(53
|
)
|
|
$
|
506,253
|
|
Operating costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs
|
|
|
|
|
|
|
133,629
|
|
|
|
245,861
|
|
|
|
(53
|
)
|
|
|
379,437
|
|
Depreciation
|
|
|
|
|
|
|
56,886
|
|
|
|
21,390
|
|
|
|
|
|
|
|
78,276
|
|
Selling, general and administrative
|
|
|
4,054
|
|
|
|
32,592
|
|
|
|
14,117
|
|
|
|
|
|
|
|
50,763
|
|
Loss on asset dispositions
|
|
|
|
|
|
|
|
|
|
|
1,602
|
|
|
|
|
|
|
|
1,602
|
|
Amortization
|
|
|
46
|
|
|
|
3,907
|
|
|
|
769
|
|
|
|
|
|
|
|
4,722
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
4,100
|
|
|
|
227,014
|
|
|
|
283,739
|
|
|
|
(53
|
)
|
|
|
514,800
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(4,100
|
)
|
|
|
(24,287
|
)
|
|
|
19,840
|
|
|
|
|
|
|
|
(8,547
|
)
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in affiliates, net of tax
|
|
|
1,051
|
|
|
|
|
|
|
|
|
|
|
|
(1,051
|
)
|
|
|
|
|
Interest, net
|
|
|
(44,568
|
)
|
|
|
(25
|
)
|
|
|
(3,480
|
)
|
|
|
|
|
|
|
(48,073
|
)
|
Gain on debt extinguishment
|
|
|
26,365
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,365
|
|
Other
|
|
|
62
|
|
|
|
(155
|
)
|
|
|
(705
|
)
|
|
|
|
|
|
|
(798
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(17,090
|
)
|
|
|
(180
|
)
|
|
|
(4,185
|
)
|
|
|
(1,051
|
)
|
|
|
(22,506
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(21,190
|
)
|
|
|
(24,467
|
)
|
|
|
15,655
|
|
|
|
(1,051
|
)
|
|
|
(31,053
|
)
|
Income tax benefit (expense)
|
|
|
|
|
|
|
15,590
|
|
|
|
(5,727
|
)
|
|
|
|
|
|
|
9,863
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
(21,190
|
)
|
|
|
(8,877
|
)
|
|
|
9,928
|
|
|
|
(1,051
|
)
|
|
|
(21,190
|
)
|
Preferred stock dividend
|
|
|
(1,302
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,302
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributed to common stockholders
|
|
$
|
(22,492
|
)
|
|
$
|
(8,877
|
)
|
|
$
|
9,928
|
|
|
$
|
(1,051
|
)
|
|
$
|
(22,492
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
77
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOW
For the Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Chalmers
|
|
|
|
|
|
Subsidiaries
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
(Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors)
|
|
|
Adjustments
|
|
|
Total
|
|
|
Cash Flows from Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(21,190
|
)
|
|
$
|
(8,877
|
)
|
|
$
|
9,928
|
|
|
$
|
(1,051
|
)
|
|
$
|
(21,190
|
)
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation & amortization
|
|
|
46
|
|
|
|
60,793
|
|
|
|
22,159
|
|
|
|
|
|
|
|
82,998
|
|
Amortization and write-off of deferred financing fees
|
|
|
2,215
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
2,231
|
|
Gain on debt extinguishment
|
|
|
(26,365
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(26,365
|
)
|
Stock based compensation
|
|
|
4,799
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,799
|
|
Allowance for bad debts
|
|
|
|
|
|
|
2,835
|
|
|
|
|
|
|
|
|
|
|
|
2,835
|
|
Equity earnings in affiliates
|
|
|
(1,051
|
)
|
|
|
|
|
|
|
|
|
|
|
1,051
|
|
|
|
|
|
Deferred income taxes
|
|
|
(18,173
|
)
|
|
|
1,569
|
|
|
|
(1,279
|
)
|
|
|
|
|
|
|
(17,883
|
)
|
Gain (loss) on sale of equipment
|
|
|
|
|
|
|
(957
|
)
|
|
|
9
|
|
|
|
|
|
|
|
(948
|
)
|
Gain on asset dispositions
|
|
|
|
|
|
|
|
|
|
|
1,602
|
|
|
|
|
|
|
|
1,602
|
|
Changes in operating assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in accounts receivables
|
|
|
|
|
|
|
38,074
|
|
|
|
11,903
|
|
|
|
|
|
|
|
49,977
|
|
Decrease in inventories
|
|
|
|
|
|
|
3,111
|
|
|
|
1,448
|
|
|
|
|
|
|
|
4,559
|
|
Decrease (increase) in other current assets
|
|
|
7,369
|
|
|
|
3,279
|
|
|
|
(6,020
|
)
|
|
|
|
|
|
|
4,628
|
|
Decrease (increase) in other assets
|
|
|
(111
|
)
|
|
|
223
|
|
|
|
1,536
|
|
|
|
|
|
|
|
1,648
|
|
(Decrease) in accounts payable
|
|
|
|
|
|
|
(13,346
|
)
|
|
|
(14,242
|
)
|
|
|
|
|
|
|
(27,588
|
)
|
(Decrease) increase in accrued interest
|
|
|
(2,560
|
)
|
|
|
228
|
|
|
|
(470
|
)
|
|
|
|
|
|
|
(2,802
|
)
|
(Decrease) in accrued expenses
|
|
|
(632
|
)
|
|
|
(2,233
|
)
|
|
|
(1,742
|
)
|
|
|
|
|
|
|
(4,607
|
)
|
(Decrease) in other liabilities
|
|
|
|
|
|
|
(64
|
)
|
|
|
(987
|
)
|
|
|
|
|
|
|
(1,051
|
)
|
(Decrease) increase in accrued salaries, benefits and payroll
taxes
|
|
|
|
|
|
|
(1,171
|
)
|
|
|
3,833
|
|
|
|
|
|
|
|
2,662
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by operating activities
|
|
|
(55,653
|
)
|
|
|
83,480
|
|
|
|
27,678
|
|
|
|
|
|
|
|
55,505
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
78
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Chalmers
|
|
|
|
|
|
Subsidiaries
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
(Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors)
|
|
|
Adjustments
|
|
|
Total
|
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales (purchases) of investment interests
|
|
|
(2,393
|
)
|
|
|
|
|
|
|
1,291
|
|
|
|
|
|
|
|
(1,102
|
)
|
Purchase of property and equipment
|
|
|
|
|
|
|
(58,142
|
)
|
|
|
(19,925
|
)
|
|
|
|
|
|
|
(78,067
|
)
|
Deposits on asset commitments
|
|
|
|
|
|
|
1,995
|
|
|
|
690
|
|
|
|
|
|
|
|
2,685
|
|
Investment in affiliates
|
|
|
(4,100
|
)
|
|
|
|
|
|
|
|
|
|
|
4,100
|
|
|
|
|
|
Notes receivable from affiliates
|
|
|
(2,069
|
)
|
|
|
|
|
|
|
|
|
|
|
2,069
|
|
|
|
|
|
Proceeds from asset dispositions
|
|
|
|
|
|
|
|
|
|
|
3,916
|
|
|
|
|
|
|
|
3,916
|
|
Proceeds from sale of equipment
|
|
|
|
|
|
|
8,400
|
|
|
|
181
|
|
|
|
|
|
|
|
8,581
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) in investing activities
|
|
|
(8,562
|
)
|
|
|
(47,747
|
)
|
|
|
(13,847
|
)
|
|
|
6,169
|
|
|
|
(63,987
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of long-term debt
|
|
|
|
|
|
|
25,000
|
|
|
|
|
|
|
|
|
|
|
|
25,000
|
|
Payments on long-term debt
|
|
|
(47,167
|
)
|
|
|
(4,811
|
)
|
|
|
(12,777
|
)
|
|
|
|
|
|
|
(64,755
|
)
|
Net repayments on lines of credit
|
|
|
(36,500
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(36,500
|
)
|
Proceeds from issuance of stock, net of offering costs
|
|
|
120,223
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
120,223
|
|
Payment of preferred stock dividend
|
|
|
(665
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(665
|
)
|
Proceeds from parent contributions
|
|
|
|
|
|
|
|
|
|
|
4,100
|
|
|
|
(4,100
|
)
|
|
|
|
|
Accounts receivable from affiliates
|
|
|
|
|
|
|
(26,834
|
)
|
|
|
(1,952
|
)
|
|
|
28,786
|
|
|
|
|
|
Accounts payable to affiliates
|
|
|
28,786
|
|
|
|
|
|
|
|
|
|
|
|
(28,786
|
)
|
|
|
|
|
Note payable to affiliate
|
|
|
|
|
|
|
|
|
|
|
2,069
|
|
|
|
(2,069
|
)
|
|
|
|
|
Proceeds from exercise of options
|
|
|
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
43
|
|
Debt issuance costs
|
|
|
(505
|
)
|
|
|
(153
|
)
|
|
|
|
|
|
|
|
|
|
|
(658
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by financing activities
|
|
|
64,215
|
|
|
|
(6,798
|
)
|
|
|
(8,560
|
)
|
|
|
(6,169
|
)
|
|
|
42,688
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
|
|
|
|
28,935
|
|
|
|
5,271
|
|
|
|
|
|
|
|
34,206
|
|
Cash and cash equivalents at beginning of year
|
|
|
|
|
|
|
2,923
|
|
|
|
3,943
|
|
|
|
|
|
|
|
6,866
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
|
|
|
$
|
31,858
|
|
|
$
|
9,214
|
|
|
$
|
|
|
|
$
|
41,072
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
79
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
December 31,
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chalmers
|
|
|
|
|
|
Subsidiary
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors
|
|
|
Adjustments
|
|
|
Total
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
|
|
|
$
|
2,923
|
|
|
$
|
3,943
|
|
|
$
|
|
|
|
$
|
6,866
|
|
Trade receivables, net
|
|
|
|
|
|
|
88,528
|
|
|
|
70,865
|
|
|
|
(1,522
|
)
|
|
|
157,871
|
|
Inventories
|
|
|
|
|
|
|
19,382
|
|
|
|
19,705
|
|
|
|
|
|
|
|
39,087
|
|
Intercompany receivables
|
|
|
|
|
|
|
51,038
|
|
|
|
|
|
|
|
(51,038
|
)
|
|
|
|
|
Note receivable from affiliate
|
|
|
20,680
|
|
|
|
|
|
|
|
|
|
|
|
(20,680
|
)
|
|
|
|
|
Prepaid expenses and other
|
|
|
8,798
|
|
|
|
8,074
|
|
|
|
4,542
|
|
|
|
|
|
|
|
21,414
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
29,478
|
|
|
|
169,945
|
|
|
|
99,055
|
|
|
|
(73,240
|
)
|
|
|
225,238
|
|
Property and equipment, net
|
|
|
|
|
|
|
499,704
|
|
|
|
261,286
|
|
|
|
|
|
|
|
760,990
|
|
Goodwill
|
|
|
|
|
|
|
23,251
|
|
|
|
20,022
|
|
|
|
|
|
|
|
43,273
|
|
Other intangible assets, net
|
|
|
506
|
|
|
|
29,143
|
|
|
|
7,722
|
|
|
|
|
|
|
|
37,371
|
|
Debt issuance costs, net
|
|
|
12,664
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,664
|
|
Note receivable from affiliates
|
|
|
10,045
|
|
|
|
|
|
|
|
|
|
|
|
(10,045
|
)
|
|
|
|
|
Investments in affiliates
|
|
|
937,227
|
|
|
|
|
|
|
|
|
|
|
|
(937,227
|
)
|
|
|
|
|
Other assets
|
|
|
3,837
|
|
|
|
27,663
|
|
|
|
4,015
|
|
|
|
|
|
|
|
35,515
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
993,757
|
|
|
$
|
749,706
|
|
|
$
|
392,100
|
|
|
$
|
(1,020,512
|
)
|
|
$
|
1,115,051
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
$
|
782
|
|
|
$
|
992
|
|
|
$
|
12,843
|
|
|
$
|
|
|
|
$
|
14,617
|
|
Trade accounts payable
|
|
|
|
|
|
|
27,759
|
|
|
|
35,841
|
|
|
|
(1,522
|
)
|
|
|
62,078
|
|
Accrued salaries, benefits and payroll taxes
|
|
|
|
|
|
|
3,933
|
|
|
|
16,259
|
|
|
|
|
|
|
|
20,192
|
|
Accrued interest
|
|
|
17,932
|
|
|
|
|
|
|
|
691
|
|
|
|
|
|
|
|
18,623
|
|
Accrued expenses
|
|
|
281
|
|
|
|
13,841
|
|
|
|
12,520
|
|
|
|
|
|
|
|
26,642
|
|
Intercompany payables
|
|
|
49,853
|
|
|
|
|
|
|
|
1,185
|
|
|
|
(51,038
|
)
|
|
|
|
|
Note payable to affiliate
|
|
|
|
|
|
|
|
|
|
|
20,680
|
|
|
|
(20,680
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
68,848
|
|
|
|
46,525
|
|
|
|
100,019
|
|
|
|
(73,240
|
)
|
|
|
142,152
|
|
Long-term debt, net of current maturities
|
|
|
541,500
|
|
|
|
|
|
|
|
37,544
|
|
|
|
|
|
|
|
579,044
|
|
Note payable to affiliate
|
|
|
|
|
|
|
|
|
|
|
10,045
|
|
|
|
(10,045
|
)
|
|
|
|
|
Deferred income tax liability
|
|
|
|
|
|
|
|
|
|
|
8,253
|
|
|
|
|
|
|
|
8,253
|
|
Other long-term liabilities
|
|
|
|
|
|
|
64
|
|
|
|
2,129
|
|
|
|
|
|
|
|
2,193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
610,348
|
|
|
|
46,589
|
|
|
|
157,990
|
|
|
|
(83,285
|
)
|
|
|
731,642
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock
|
|
|
357
|
|
|
|
3,526
|
|
|
|
42,963
|
|
|
|
(46,489
|
)
|
|
|
357
|
|
Capital in excess of par value
|
|
|
334,633
|
|
|
|
570,512
|
|
|
|
133,339
|
|
|
|
(703,851
|
)
|
|
|
334,633
|
|
Retained earnings
|
|
|
48,419
|
|
|
|
129,079
|
|
|
|
57,808
|
|
|
|
(186,887
|
)
|
|
|
48,419
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
383,409
|
|
|
|
703,117
|
|
|
|
234,110
|
|
|
|
(937,227
|
)
|
|
|
383,409
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stock holders equity
|
|
$
|
993,757
|
|
|
$
|
749,706
|
|
|
$
|
392,100
|
|
|
$
|
(1,020,512
|
)
|
|
$
|
1,115,051
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
80
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
CONDENSED
CONSOLIDATING INCOME STATEMENTS
For the Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers
|
|
|
|
|
|
Subsidiary
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors
|
|
|
Adjustments
|
|
|
Total
|
|
|
Revenues
|
|
$
|
|
|
|
$
|
384,649
|
|
|
$
|
291,335
|
|
|
$
|
(36
|
)
|
|
$
|
675,948
|
|
Operating costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs
|
|
|
|
|
|
|
217,360
|
|
|
|
226,090
|
|
|
|
(36
|
)
|
|
|
443,414
|
|
Depreciation
|
|
|
|
|
|
|
49,177
|
|
|
|
14,283
|
|
|
|
|
|
|
|
63,460
|
|
Selling, general and administrative
|
|
|
6,924
|
|
|
|
45,147
|
|
|
|
10,703
|
|
|
|
|
|
|
|
62,774
|
|
Gain on asset dispositions
|
|
|
|
|
|
|
(166
|
)
|
|
|
|
|
|
|
|
|
|
|
(166
|
)
|
Impairment of goodwill
|
|
|
|
|
|
|
115,774
|
|
|
|
|
|
|
|
|
|
|
|
115,774
|
|
Amortization
|
|
|
46
|
|
|
|
4,133
|
|
|
|
33
|
|
|
|
|
|
|
|
4,212
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
6,970
|
|
|
|
431,425
|
|
|
|
251,109
|
|
|
|
(36
|
)
|
|
|
689,468
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(6,970
|
)
|
|
|
(46,776
|
)
|
|
|
40,226
|
|
|
|
|
|
|
|
(13,520
|
)
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in affiliates, net of tax
|
|
|
9,161
|
|
|
|
|
|
|
|
|
|
|
|
(9,161
|
)
|
|
|
|
|
Interest, net
|
|
|
(41,727
|
)
|
|
|
57
|
|
|
|
(1,124
|
)
|
|
|
|
|
|
|
(42,794
|
)
|
Other
|
|
|
72
|
|
|
|
88
|
|
|
|
(723
|
)
|
|
|
|
|
|
|
(563
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(32,494
|
)
|
|
|
145
|
|
|
|
(1,847
|
)
|
|
|
(9,161
|
)
|
|
|
(43,357
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(39,464
|
)
|
|
|
(46,631
|
)
|
|
|
38,379
|
|
|
|
(9,161
|
)
|
|
|
(56,877
|
)
|
Income tax benefit (expense)
|
|
|
|
|
|
|
29,580
|
|
|
|
(12,167
|
)
|
|
|
|
|
|
|
17,413
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(39,464
|
)
|
|
$
|
(17,051
|
)
|
|
$
|
26,212
|
|
|
$
|
(9,161
|
)
|
|
$
|
(39,464
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
81
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOW
For the Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Chalmers
|
|
|
|
|
|
Subsidiaries
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
(Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors)
|
|
|
Adjustments
|
|
|
Total
|
|
|
Cash Flows from Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(39,464
|
)
|
|
$
|
(17,051
|
)
|
|
$
|
26,212
|
|
|
$
|
(9,161
|
)
|
|
$
|
(39,464
|
)
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation & amortization
|
|
|
46
|
|
|
|
53,310
|
|
|
|
14,316
|
|
|
|
|
|
|
|
67,672
|
|
Amortization and write-off of debt issuance costs
|
|
|
2,089
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,089
|
|
Impairment of goodwill
|
|
|
|
|
|
|
115,774
|
|
|
|
|
|
|
|
|
|
|
|
115,774
|
|
Stock based compensation
|
|
|
7,902
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,902
|
|
Allowance for bad debts
|
|
|
|
|
|
|
3,283
|
|
|
|
|
|
|
|
|
|
|
|
3,283
|
|
Equity earnings in affiliates
|
|
|
(9,161
|
)
|
|
|
|
|
|
|
|
|
|
|
9,161
|
|
|
|
|
|
Deferred income taxes
|
|
|
(13,620
|
)
|
|
|
(16,959
|
)
|
|
|
630
|
|
|
|
|
|
|
|
(29,949
|
)
|
Gain on sale of equipment
|
|
|
|
|
|
|
(1,485
|
)
|
|
|
(277
|
)
|
|
|
|
|
|
|
(1,762
|
)
|
Gain on asset dispositions
|
|
|
|
|
|
|
(166
|
)
|
|
|
|
|
|
|
|
|
|
|
(166
|
)
|
Changes in operating assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in trade receivables
|
|
|
|
|
|
|
(7,168
|
)
|
|
|
(20,331
|
)
|
|
|
|
|
|
|
(27,499
|
)
|
Increase in inventories
|
|
|
|
|
|
|
(7,037
|
)
|
|
|
(2,682
|
)
|
|
|
|
|
|
|
(9,719
|
)
|
(Increase) decrease in other current assets
|
|
|
211
|
|
|
|
219
|
|
|
|
(2,053
|
)
|
|
|
|
|
|
|
(1,623
|
)
|
(Increase) decrease in other assets
|
|
|
(138
|
)
|
|
|
(83
|
)
|
|
|
1,445
|
|
|
|
|
|
|
|
1,224
|
|
Increase in accounts payable
|
|
|
|
|
|
|
9,427
|
|
|
|
12,476
|
|
|
|
|
|
|
|
21,903
|
|
(Decrease) increase in accrued interest
|
|
|
223
|
|
|
|
(33
|
)
|
|
|
377
|
|
|
|
|
|
|
|
567
|
|
(Decrease) increase in accrued expenses
|
|
|
(1,379
|
)
|
|
|
3,823
|
|
|
|
(1,313
|
)
|
|
|
|
|
|
|
1,131
|
|
(Decrease) in other liabilities
|
|
|
(31
|
)
|
|
|
(178
|
)
|
|
|
(921
|
)
|
|
|
|
|
|
|
(1,130
|
)
|
Increase in accrued salaries, benefits and payroll taxes
|
|
|
|
|
|
|
221
|
|
|
|
3,231
|
|
|
|
|
|
|
|
3,452
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by operating activities
|
|
|
(53,322
|
)
|
|
|
135,897
|
|
|
|
31,110
|
|
|
|
|
|
|
|
113,685
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
82
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Chalmers
|
|
|
|
|
|
Subsidiaries
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
(Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors)
|
|
|
Adjustments
|
|
|
Total
|
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions, net of cash acquired
|
|
|
|
|
|
|
|
|
|
|
(53,709
|
)
|
|
|
|
|
|
|
(53,709
|
)
|
Net sales (purchases) of investment interests
|
|
|
|
|
|
|
1,374
|
|
|
|
|
|
|
|
|
|
|
|
1,374
|
|
Purchase of property and equipment
|
|
|
|
|
|
|
(81,724
|
)
|
|
|
(72,744
|
)
|
|
|
|
|
|
|
(154,468
|
)
|
Deposits on asset commitments
|
|
|
|
|
|
|
(20,667
|
)
|
|
|
10,766
|
|
|
|
|
|
|
|
(9,901
|
)
|
Investment in affiliates
|
|
|
(58,370
|
)
|
|
|
|
|
|
|
|
|
|
|
58,370
|
|
|
|
|
|
Notes receivable from affiliates
|
|
|
(6,075
|
)
|
|
|
|
|
|
|
|
|
|
|
6,075
|
|
|
|
|
|
Proceeds from asset dispositions
|
|
|
|
|
|
|
3,000
|
|
|
|
|
|
|
|
|
|
|
|
3,000
|
|
Proceeds from sale of equipment
|
|
|
|
|
|
|
11,046
|
|
|
|
434
|
|
|
|
|
|
|
|
11,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) in investing activities
|
|
|
(64,445
|
)
|
|
|
(86,971
|
)
|
|
|
(115,253
|
)
|
|
|
64,445
|
|
|
|
(202,224
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of long-term debt
|
|
|
|
|
|
|
|
|
|
|
25,000
|
|
|
|
|
|
|
|
25,000
|
|
Payments on long-term debt
|
|
|
|
|
|
|
(6,029
|
)
|
|
|
(3,876
|
)
|
|
|
|
|
|
|
(9,905
|
)
|
Net borrowings on lines of credit
|
|
|
36,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36,500
|
|
Proceeds from parent contributions
|
|
|
|
|
|
|
|
|
|
|
58,370
|
|
|
|
(58,370
|
)
|
|
|
|
|
Accounts receivable from affiliates
|
|
|
81,150
|
|
|
|
|
|
|
|
|
|
|
|
(81,150
|
)
|
|
|
|
|
Accounts payable to affiliates
|
|
|
|
|
|
|
(81,150
|
)
|
|
|
|
|
|
|
81,150
|
|
|
|
|
|
Note payable to affiliate
|
|
|
|
|
|
|
|
|
|
|
6,075
|
|
|
|
(6,075
|
)
|
|
|
|
|
Proceeds from exercise of options
|
|
|
633
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
633
|
|
Tax benefit on stock plans
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
|
|
Debt issuance costs
|
|
|
(525
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(525
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by financing activities
|
|
|
117,767
|
|
|
|
(87,179
|
)
|
|
|
85,569
|
|
|
|
(64,445
|
)
|
|
|
51,712
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
|
|
|
|
(38,253
|
)
|
|
|
1,426
|
|
|
|
|
|
|
|
(36,827
|
)
|
Cash and cash equivalents at beginning of year
|
|
|
|
|
|
|
41,176
|
|
|
|
2,517
|
|
|
|
|
|
|
|
43,693
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
|
|
|
$
|
2,923
|
|
|
$
|
3,943
|
|
|
$
|
|
|
|
$
|
6,866
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
83
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
|
|
Operating costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs
|
|
|
|
|
|
|
183,002
|
|
|
|
155,833
|
|
|
|
|
|
|
|
338,835
|
|
Depreciation
|
|
|
|
|
|
|
39,659
|
|
|
|
11,255
|
|
|
|
|
|
|
|
50,914
|
|
General and administrative
|
|
|
4,349
|
|
|
|
47,054
|
|
|
|
9,834
|
|
|
|
|
|
|
|
61,237
|
|
Gain on asset disposition
|
|
|
|
|
|
|
(8,868
|
)
|
|
|
|
|
|
|
|
|
|
|
(8,868
|
)
|
Amortization
|
|
|
46
|
|
|
|
3,988
|
|
|
|
33
|
|
|
|
|
|
|
|
4,067
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
4,395
|
|
|
|
264,835
|
|
|
|
176,955
|
|
|
|
|
|
|
|
446,185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
84
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 debt issuance costs
|
|
|
3,197
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,197
|
|
Stock based compensation
|
|
|
4,863
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,863
|
|
Allowance for bad debts
|
|
|
|
|
|
|
1,309
|
|
|
|
|
|
|
|
|
|
|
|
1,309
|
|
Equity earnings in affiliates
|
|
|
(102,208
|
)
|
|
|
|
|
|
|
|
|
|
|
102,208
|
|
|
|
|
|
Deferred income 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 trade receivables
|
|
|
|
|
|
|
(18,402
|
)
|
|
|
(13,002
|
)
|
|
|
|
|
|
|
(31,404
|
)
|
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
|
)
|
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
|
)
|
Investment in affiliates
|
|
|
(44,919
|
)
|
|
|
|
|
|
|
|
|
|
|
44,919
|
|
|
|
|
|
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
|
|
|
(51,728
|
)
|
|
|
(96,822
|
)
|
|
|
(40,254
|
)
|
|
|
51,728
|
|
|
|
(137,076
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
85
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOW
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Chalmers
|
|
|
|
|
|
Subsidiaries
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
(Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors)
|
|
|
Adjustments
|
|
|
Total
|
|
|
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
|
)
|
Proceeds from parent contributions
|
|
|
|
|
|
|
44,919
|
|
|
|
|
|
|
|
(44,919
|
)
|
|
|
|
|
Accounts receivable from affiliates
|
|
|
36,245
|
|
|
|
|
|
|
|
|
|
|
|
(36,245
|
)
|
|
|
|
|
Accounts payable to affiliates
|
|
|
|
|
|
|
(37,413
|
)
|
|
|
1,168
|
|
|
|
36,245
|
|
|
|
|
|
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
|
|
|
83,546
|
|
|
|
919
|
|
|
|
4,819
|
|
|
|
(51,728
|
)
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 14
|
RELATED
PARTY TRANSACTIONS
|
Our largest customer is Pan American Energy which is a joint
venture by British Petroleum and Bridas Corporation. One of our
Directors, Alejandro P. Bulgheroni, indirectly beneficially owns
50% of the shares of the Bridas Corporation. In 2009, 2008 and
2007, Pan American Energy represented 35.5%, 28.5%, and 20.7% of
our consolidated revenues, respectively. At December 31,
2009 and 2008, we had trade receivables with Pan American Energy
of $11.0 million and $40.0 million, respectively.
In 2009, 2008 and 2007, we derived revenue of approximately
$3.3 million, $1.0 million and $1.7 million from
BEUSA Energy, Inc., or BEUSA, a company controlled by Alejandro
P. Bulgheroni. At December 31, 2009 and 2008, we had trade
receivables from BEUSA of approximately $1.2 million and
$558,000, respectively.
Lime Rock Partners III, L.P., an affiliated fund of Lime Rock
Partners V, L.P., owns a majority stake in the parent
company of GES Global Energy Services, Inc., or GES Global
Energy, a Houston based global supplier of drilling rigs and rig
components. In 2008, we ordered two drilling rigs from GES
Global Energy for an aggregate value of approximately
$30.7 million. We have made payments totaling approximately
$18.6 million on these rigs. No interest is due or payable
on this transaction. We expect to take delivery of these rigs
during 2010 and will pay the remaining balance of approximately
$12.1 million at that time. Saad Bargach and John Reynolds
are each a Managing Director of Lime Rock Management LP, the
manager for Lime Rock Partners III, L.P. and Lime Rock
Partners V, L.P. Messrs. Bargach and Reynolds are also
members of our Board of Directors. As of February 26, 2010,
Lime Rock Partners V, L.P. holds 19,889,044 shares of
our common stock, representing approximately 27.8% of our issued
and outstanding shares. In addition, Lime
86
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
Rock Partners V, L.P. owns 36,393 shares of preferred
stock which are convertible into 14,202,146 shares of our
common stock. Through its ownership of common and preferred
stock, Lime Rock Partners V, L.P. controls, in the
aggregate, 35% of our stockholders voting power.
|
|
NOTE 15
|
SEGMENT
INFORMATION
|
All of our 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,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services
|
|
$
|
143,564
|
|
|
$
|
280,835
|
|
|
$
|
233,986
|
|
Drilling & Completion
|
|
|
303,975
|
|
|
|
291,335
|
|
|
|
215,795
|
|
Rental Services
|
|
|
58,714
|
|
|
|
103,778
|
|
|
|
121,186
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
506,253
|
|
|
$
|
675,948
|
|
|
$
|
570,967
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services
|
|
$
|
(14,691
|
)
|
|
$
|
38,643
|
|
|
$
|
53,218
|
|
Drilling & Completion
|
|
|
19,222
|
|
|
|
40,226
|
|
|
|
38,839
|
|
Rental Services
|
|
|
140
|
|
|
|
(74,361
|
)
|
|
|
49,139
|
|
General corporate
|
|
|
(13,218
|
)
|
|
|
(18,028
|
)
|
|
|
(16,414
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income (loss) from operations
|
|
$
|
(8,547
|
)
|
|
$
|
(13,520
|
)
|
|
$
|
124,782
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and Amortization Expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services
|
|
$
|
30,589
|
|
|
$
|
24,725
|
|
|
$
|
16,838
|
|
Drilling & Completion
|
|
|
22,321
|
|
|
|
14,316
|
|
|
|
11,288
|
|
Rental Services
|
|
|
29,791
|
|
|
|
28,131
|
|
|
|
26,353
|
|
General corporate
|
|
|
297
|
|
|
|
500
|
|
|
|
502
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depreciation and amortization expense
|
|
$
|
82,998
|
|
|
$
|
67,672
|
|
|
$
|
54,981
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services
|
|
$
|
11,357
|
|
|
$
|
58,400
|
|
|
$
|
48,610
|
|
Drilling & Completion
|
|
|
58,393
|
|
|
|
73,362
|
|
|
|
28,911
|
|
Rental Services
|
|
|
8,230
|
|
|
|
22,550
|
|
|
|
34,883
|
|
General corporate
|
|
|
87
|
|
|
|
156
|
|
|
|
747
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures
|
|
$
|
78,067
|
|
|
$
|
154,468
|
|
|
$
|
113,151
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
87
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Goodwill:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services
|
|
$
|
23,250
|
|
|
$
|
23,250
|
|
|
$
|
30,493
|
|
Drilling & Completion
|
|
|
17,389
|
|
|
|
20,023
|
|
|
|
1,523
|
|
Rental Services
|
|
|
|
|
|
|
|
|
|
|
106,382
|
|
General corporate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total goodwill
|
|
$
|
40,639
|
|
|
$
|
43,273
|
|
|
$
|
138,398
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services
|
|
$
|
255,899
|
|
|
$
|
309,901
|
|
|
$
|
299,300
|
|
Drilling & Completion
|
|
|
441,482
|
|
|
|
411,486
|
|
|
|
235,020
|
|
Rental Services
|
|
|
307,283
|
|
|
|
360,376
|
|
|
|
454,216
|
|
General corporate
|
|
|
75,956
|
|
|
|
33,288
|
|
|
|
65,049
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,080,620
|
|
|
$
|
1,115,051
|
|
|
$
|
1,053,585
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
188,436
|
|
|
$
|
365,529
|
|
|
$
|
339,476
|
|
Argentina
|
|
|
243,913
|
|
|
|
288,792
|
|
|
|
207,491
|
|
Brazil
|
|
|
43,564
|
|
|
|
|
|
|
|
|
|
Other international
|
|
|
30,340
|
|
|
|
21,627
|
|
|
|
24,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
506,253
|
|
|
$
|
675,948
|
|
|
$
|
570,967
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Long Lived Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
572,727
|
|
|
$
|
573,975
|
|
|
$
|
655,513
|
|
Argentina
|
|
|
168,681
|
|
|
|
212,456
|
|
|
|
166,972
|
|
Brazil
|
|
|
82,477
|
|
|
|
79,568
|
|
|
|
|
|
Other international
|
|
|
58,487
|
|
|
|
23,814
|
|
|
|
13,206
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long lived assets
|
|
$
|
882,372
|
|
|
$
|
889,813
|
|
|
$
|
835,691
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
88
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield
|
|
|
Drilling &
|
|
|
Rental
|
|
|
|
|
|
|
Services
|
|
|
Completion
|
|
|
Services
|
|
|
Total
|
|
|
Goodwill:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2007
|
|
$
|
30,493
|
|
|
$
|
1,523
|
|
|
$
|
106,382
|
|
|
$
|
138,398
|
|
Goodwill acquired during period
|
|
|
3,000
|
|
|
|
18,500
|
|
|
|
|
|
|
|
21,500
|
|
Asset dispositions
|
|
|
(851
|
)
|
|
|
|
|
|
|
|
|
|
|
(851
|
)
|
Impairment charges
|
|
|
(9,392
|
)
|
|
|
|
|
|
|
(106,382
|
)
|
|
|
(115,774
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2008
|
|
|
23,250
|
|
|
|
20,023
|
|
|
|
|
|
|
|
43,273
|
|
Purchase price and other adjustments
|
|
|
|
|
|
|
(2,634
|
)
|
|
|
|
|
|
|
(2,634
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2009
|
|
$
|
23,250
|
|
|
$
|
17,389
|
|
|
$
|
|
|
|
$
|
40,639
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 16
|
SUPPLEMENTAL
CASH FLOWS INFORMATION (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Interest paid
|
|
$
|
49,605
|
|
|
$
|
46,541
|
|
|
$
|
40,363
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes paid
|
|
$
|
6,242
|
|
|
$
|
20,670
|
|
|
$
|
17,272
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other non-cash investing and financing transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Insurance premiums financed
|
|
$
|
3,204
|
|
|
$
|
2,995
|
|
|
$
|
4,434
|
|
Assets transferred as investment in joint venture
|
|
|
1,639
|
|
|
|
|
|
|
|
|
|
Preferred stock dividend
|
|
|
637
|
|
|
|
|
|
|
|
|
|
Tax benefit on stock plans
|
|
|
2,335
|
|
|
|
|
|
|
|
|
|
Non-cash investing and financing transactions in connection
with acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of Property and equipment
|
|
$
|
|
|
|
$
|
|
|
|
$
|
4,345
|
|
Fair value of goodwill and other intangibles
|
|
|
(1,343
|
)
|
|
|
3,000
|
|
|
|
350
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(1,343
|
)
|
|
$
|
3,000
|
|
|
$
|
4,695
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Seller financed note
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,600
|
|
Deferred tax liability
|
|
|
|
|
|
|
|
|
|
|
3,095
|
|
Accrued expenses
|
|
|
(1,343
|
)
|
|
|
3,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(1,343
|
)
|
|
$
|
3,000
|
|
|
$
|
4,695
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash investing and financing transactions in connection
with asset disposition:
|
|
|
|
|
|
|
|
|
|
|
|
|
Value of goodwill and other intangibles disposed
|
|
$
|
|
|
|
$
|
2,246
|
|
|
$
|
|
|
Value of inventory financed
|
|
|
|
|
|
|
509
|
|
|
|
|
|
Value of property and equipment disposed
|
|
|
|
|
|
|
337
|
|
|
|
|
|
Accrued expenses
|
|
|
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of note receivable
|
|
$
|
|
|
|
$
|
3,102
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
89
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
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 18
|
SUMMARIZED
QUARTERLY FINANCIAL DATA (UNAUDITED) (in thousands, except per
share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Year 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
145,103
|
|
|
$
|
112,505
|
|
|
$
|
120,016
|
|
|
$
|
128,629
|
|
Operating income (loss)
|
|
|
7,771
|
|
|
|
(12,543
|
)
|
|
|
(3,070
|
)
|
|
|
(705
|
)
|
Net loss attributed to common stockholders
|
|
$
|
(2,605
|
)
|
|
$
|
(125
|
)
|
|
$
|
(10,280
|
)
|
|
$
|
(9,482
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.07
|
)
|
|
$
|
0.00
|
|
|
$
|
(0.14
|
)
|
|
$
|
(0.13
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
(0.07
|
)
|
|
$
|
0.00
|
|
|
$
|
(0.14
|
)
|
|
$
|
(0.13
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Year 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
153,182
|
|
|
$
|
163,135
|
|
|
$
|
178,265
|
|
|
$
|
181,366
|
|
Operating income (loss)
|
|
|
23,582
|
|
|
|
27,668
|
|
|
|
29,033
|
|
|
|
(93,803
|
)
|
Net income (loss)
|
|
$
|
8,050
|
|
|
$
|
10,558
|
|
|
$
|
12,312
|
|
|
$
|
(70,384
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.23
|
|
|
$
|
0.30
|
|
|
$
|
0.35
|
|
|
$
|
(2.00
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.23
|
|
|
$
|
0.30
|
|
|
$
|
0.35
|
|
|
$
|
(2.00
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
90
|
|
ITEM 9.
|
CHANGES
IN 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, 2009. 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, 2009 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 Business Ethics and Conduct 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.
In order to evaluate the effectiveness of our internal control
over financial reporting as of December 31, 2009, 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, concluded that, as of
December 31, 2009, our internal controls over financial
reporting are effective based on these criteria.
91
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, 2009, which can be found in Item 8 of
this report.
(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
|
On November 6, 2009, we held our Annual Meeting of
Stockholders. At the meeting, the stockholders voted on the
following matters:
1. The election of nine directors to serve a one-year term
expiring at the 2010 annual meeting of stockholders.
2. The approval of an amendment to our Amended and Restated
Certificate of Incorporation to increase the number of shares of
authorized common stock from 100 million to
200 million.
3. The approval of the Second Amended and Restated 2006
Incentive Plan.
4. The ratification of the appointment of UHY LLP as our
independent auditor for the fiscal year ending December 31,
2009.
The nine nominees to our Board of Directors were elected at the
meeting, and the other proposals received the affirmative vote
required for approval. The following table sets forth the
results of the voting with respect to each such matter:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Against or
|
|
|
|
|
|
|
|
|
|
|
|
|
For
|
|
|
Withheld
|
|
|
Abstentions
|
|
|
Broker Non-Vote
|
|
|
|
1.
|
|
|
Election of Directors
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Saad Bargach
|
|
|
67,260,499
|
|
|
|
6,623,976
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alejandro P. Bulgheroni
|
|
|
72,420,667
|
|
|
|
1,463,808
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Giovanni DellOrto
|
|
|
72,247,860
|
|
|
|
1,636,615
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Victor F. Germack
|
|
|
65,840,516
|
|
|
|
8,043,959
|
|
|
|
|
|
|
|
|
|
|
|
|
|
James M. Hennessy
|
|
|
72,650,559
|
|
|
|
1,233,916
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Munawar H. Hidayatallah
|
|
|
72,731,336
|
|
|
|
1,153,139
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Robert E. Nederlander
|
|
|
70,593,523
|
|
|
|
3,290,952
|
|
|
|
|
|
|
|
|
|
|
|
|
|
John T. Reynolds
|
|
|
70,505,725
|
|
|
|
3,378,750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Zane Tankel
|
|
|
65,892,555
|
|
|
|
7,991,920
|
|
|
|
|
|
|
|
|
|
|
2.
|
|
|
Approve amendment to our Amended and Restated Certificate of
Incorporation
|
|
|
69,218,356
|
|
|
|
4,588,897
|
|
|
|
77,220
|
|
|
|
|
|
|
3.
|
|
|
Approve Second Amended and Restated 2006 Incentive Plan
|
|
|
43,648,673
|
|
|
|
11,700,743
|
|
|
|
706,256
|
|
|
|
17,828,804
|
|
|
4.
|
|
|
Ratification of UHY LLP as our independent accountants
|
|
|
72,598,329
|
|
|
|
1,025,715
|
|
|
|
260,426
|
|
|
|
|
|
92
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 2010 annual meeting of stockholders filed within
120 days of the end of our fiscal year ending
December 31, 2009.
|
|
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 2010 annual meeting of stockholders filed within
120 days of the end of our fiscal year ending
December 31, 2009.
|
|
ITEM 12.
|
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
|
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 2010 annual meeting of stockholders filed within
120 days of the end of our fiscal year ending
December 31, 2009.
|
|
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 2010 annual meeting of stockholders filed within
120 days of the end of our fiscal year ending
December 31, 2009.
|
|
ITEM 14.
|
PRINCIPAL
ACCOUNTING 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 2010 annual meeting of stockholders filed within
120 days of the end of our fiscal year ending
December 31, 2009.
PART IV
|
|
ITEM 15.
|
EXHIBITS AND
FINANCIAL STATEMENT SCHEDULES
|
(a) (1) Financial Statements: The
following financial statements for Allis-Chalmers Energy Inc.
and Subsidiaries are included in Item 8. Financial
Statements and Supplementary Data
|
Consolidated Balance Sheets as of December 31, 2009 and
2008.
|
Consolidated Statements of Operations for the years ended
December 31, 2009, 2008 and 2007.
|
Consolidated Statement of Stockholders Equity for the
years ended December 31, 2009, 2008 and 2007.
|
Consolidated Statements of Cash Flows for the years ended
December 31, 2009, 2008 and 2007.
|
Notes to Consolidated Financial Statements.
|
|
(2) Financial Statement Schedules
|
|
Schedule II Valuation and Qualifying Accounts
|
All other schedules are omitted because they are not applicable,
not required, or the information is included in the financial
statements or the notes thereto.
93
(3) Exhibits
The exhibits listed on the accompanying Exhibit Index are
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
|
|
|
Additions
|
|
|
|
|
|
|
|
|
|
Balance at
|
|
|
Charged to
|
|
|
Charged to
|
|
|
|
|
|
Balance at
|
|
|
|
Beginning
|
|
|
Costs and
|
|
|
Other
|
|
|
|
|
|
End of
|
|
Description
|
|
of Period
|
|
|
Expense
|
|
|
Account
|
|
|
Deductions
|
|
|
Period
|
|
|
|
(In thousands)
|
|
|
Year Ended December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$
|
4,205
|
|
|
$
|
2,835
|
|
|
$
|
|
|
|
$
|
(2,117
|
)
|
|
$
|
4,923
|
|
Deferred tax assets valuation allowance
|
|
|
13,265
|
|
|
|
2,076
|
|
|
|
(1,342
|
)
|
|
|
|
|
|
|
13,999
|
|
Year Ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
|
1,924
|
|
|
|
3,283
|
|
|
|
|
|
|
|
(1,002
|
)
|
|
|
4,205
|
|
Deferred tax assets valuation allowance
|
|
|
|
|
|
|
|
|
|
|
13,265
|
|
|
|
|
|
|
|
13,265
|
|
Year Ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
|
826
|
|
|
|
1,309
|
|
|
|
|
|
|
|
(211
|
)
|
|
|
1,924
|
|
Deferred tax assets valuation allowance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The deferred tax asset valuation allowance established in the
year ended December 31, 2008 was an acquisition related
allowance. At the time of the acquisition of BCH, we had no
expectation to utilize their net operating loss carryforwards or
foreign tax credit carryfowards. Subsequent to 2008, we
determined that we would utilize $1.3 million of the
deferred tax assets related to the acquisition of BCH.
94
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, as amended, the registrant has
duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized on March 9, 2010.
ALLIS-CHALMERS ENERGY INC.
/s/ MUNAWAR
H. HIDAYATALLAH
Munawar H. Hidayatallah
Chief Executive Officer and Chairman
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, as amended, this report has
been signed on the date indicated by the following persons on
behalf of the registrant and in the capacities indicated.
|
|
|
|
|
|
|
Name
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ MUNAWAR
H. HIDAYATALLAH
Munawar
H. Hidayatallah
|
|
Chairman and Chief Executive Officer (Principal Executive
Officer)
|
|
March 9, 2010
|
|
|
|
|
|
/s/ VICTOR
M. PEREZ
Victor
M. Perez
|
|
Chief Financial Officer
(Principal Financial Officer)
|
|
March 9, 2010
|
|
|
|
|
|
/s/ BRUCE
SAUERS
Bruce
Sauers
|
|
Chief Accounting Officer
(Principal Accounting Officer)
|
|
March 9, 2010
|
|
|
|
|
|
/s/ SAAD
BARGACH
Saad
Bargach
|
|
Director
|
|
March 9, 2010
|
|
|
|
|
|
/s/ ALEJANDRO
P. BULGHERONI
Alejandro
P. Bulgheroni
|
|
Director
|
|
March 9, 2010
|
|
|
|
|
|
/s/ GIOVANNI
DELLORTO
Giovanni
Dellorto
|
|
Director
|
|
March 9, 2010
|
|
|
|
|
|
/s/ VICTOR
F. GERMACK
Victor
F. Germack
|
|
Director
|
|
March 9, 2010
|
|
|
|
|
|
/s/ JAMES
M. HENNESSY
James
M. Hennessy
|
|
Director
|
|
March 9, 2010
|
|
|
|
|
|
/s/ ROBERT
E. NEDERLANDER
Robert
E. Nederlander
|
|
Director
|
|
March 9, 2010
|
|
|
|
|
|
/s/ JOHN
T. REYNOLDS
John
T. Reynolds
|
|
Director
|
|
March 9, 2010
|
|
|
|
|
|
/s/ ZANE
TANKEL
Zane
Tankel
|
|
Director
|
|
March 9, 2010
|
95
EXHIBIT INDEX
|
|
|
|
|
Exhibit
|
|
Description
|
|
|
2
|
.1
|
|
First Amended Disclosure Statement pursuant to Section 1125
of the Bankruptcy Code, dated September 14, 1988, which
includes the First Amended and Restated Joint Plan of
Reorganization dated September 14, 1988 (incorporated by
reference to Registrants Current Report on
Form 8-K
dated December 1, 1988).
|
|
2
|
.2
|
|
Reorganization Trust Agreement dated September 14,
1988 by and between Registrant and John T. Grigsby, Jr., Trustee
(incorporated by reference to Exhibit D of the First
Amended and Restated Joint Plan of Reorganization dated
September 14, 1988 included in Registrants Current
Report on
Form 8-K
dated December 1, 1988).
|
|
2
|
.3
|
|
Agreement and Plan of Merger dated as of May 9, 2001 by and
among Registrant, Allis-Chalmers Acquisition Corp. and 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 Exhibit 10.61 to the Registrants Current Report on
Form 8-K
filed on November 16, 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).
|
|
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).
|
96
|
|
|
|
|
Exhibit
|
|
Description
|
|
|
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 Current Report on
Form 8-K
filed on January 24, 2008).
|
|
2
|
.21
|
|
First Amendment, dated as of June 1, 2008, to the Agreement
and Plan of Merger, by and among Allis-Chalmers Energy Inc.,
Elway Merger Sub, Inc. and Bronco Drilling Company, Inc.
(incorporated by reference to Exhibit 2.1 to the
Registrants Current Report on
Form 8-K
filed on June 2, 2008).
|
|
2
|
.22
|
|
Stock Purchase Agreement, dated December 19, 2008, by and
between the Registrant and BrazAlta Resources Corp.
(incorporated by reference to Exhibit 2.22 to the
Registrants Annual Report on
Form 10-K
filed on March 9, 2009).
|
|
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
|
|
Second Amended and Restated By-laws of Registrant (incorporated
by reference to Exhibit 3.1. to the Registrants
Current Report of
Form 8-K
filed April 3, 2008).
|
|
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).
|
|
3
|
.7
|
|
Certificate of Amendment to Amended and Restated Certificate of
Incorporation filed with the Delaware Secretary of State on
November 9, 2009.
|
|
3
|
.8
|
|
Certificate of Designations of 7% Convertible Perpetual
Preferred Stock (incorporated by reference to Exhibit 3.1
to the Registrants Current Report on
Form 8-K
filed July 1, 2009).
|
|
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 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
|
.4
|
|
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).
|
97
|
|
|
|
|
Exhibit
|
|
Description
|
|
|
4
|
.5
|
|
Registration Rights Agreement dated as of August 14, 2006
by and among the Registrant, the guarantors listed on
Schedule A thereto and RBC Capital Markets Corporation
(incorporated by reference to Exhibit 10.1 to the
Registrants
Form 8-K
filed on August 14, 2006).
|
|
4
|
.6
|
|
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
|
.7
|
|
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 Current Report on
Form 8-K
filed on August 14, 2006).
|
|
4
|
.8
|
|
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
|
.9
|
|
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
|
.10
|
|
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
|
.11
|
|
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).
|
|
4
|
.12
|
|
Investment Agreement, dated May 20, 2009, between
Allis-Chalmers Energy Inc. and Lime Rock Partners V, L.P.
(incorporated by reference to Exhibit 4.1 to Allis-Chalmers
Energy Inc.s Current Report on
Form 8-K
filed on May 27, 2009).
|
|
4
|
.13
|
|
First Amendment to Investment Agreement, dated June 25,
2009, between Allis-Chalmers Energy Inc. and Lime Rock
Partners V, L.P. (incorporated by reference to
Exhibit 4.1 to Allis-Chalmers Energy Inc.s Current
Report on
Form 8-K
filed on July 1, 2009).
|
|
4
|
.14
|
|
Second Amendment to Investment Agreement, dated
September 1, 2009, between Allis-Chalmers Energy Inc. and
Lime Rock Partners V, L.P. (incorporated by reference to
Exhibit 4.1 to Allis-Chalmers Energy Inc.s Current
Report on
Form 8-K
filed on September 2, 2009).
|
|
4
|
.15
|
|
Third Amendment to Investment Agreement, dated September 1,
2009, between Allis-Chalmers Energy Inc. and Lime Rock
Partners V, L.P. (incorporated by reference to
Exhibit 4.1 to Allis-Chalmers Energy Inc.s Current
Report on
Form 8-K
filed on January 5, 2010).
|
|
4
|
.16
|
|
Registration Rights Agreement, dated June 26, 2009, between
Allis-Chalmers Energy Inc. and Lime Rock Partners V, L.P.
(incorporated by reference to Exhibit 4.2 to Allis-Chalmers
Energy Inc.s Current Report on
Form 8-K
filed on July 1, 2009).
|
|
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).
|
98
|
|
|
|
|
Exhibit
|
|
Description
|
|
|
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 Exhibit 99.1 to the
Registrants Current Report on
Form 8-K
filed May 15, 2001).
|
|
10
|
.8
|
|
Termination Agreement dated May 9, 2001 by and between
Registrant, the Pension Benefit Guarantee Corporation and others
(incorporated by reference to Exhibit 99.2 to the
Registrants Current Report on
Form 8-K
filed on May 15, 2001).
|
|
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
Current Report on
Form 8-K
filed on November 6, 2007).
|
|
10
|
.10*
|
|
Amendment to Executive Employment Agreement, dated as of
December 31, 2008, by and between the Registrant and
Munawar H. Hidayatallah (incorporated by reference to
Exhibit 10.2 to the Registrants Current Report on
Form 8-K
filed on January 7, 2009).
|
|
10
|
.11*
|
|
Amended and Restated Employment Agreement, dated August 5,
2009, between Allis-Chalmers Energy Inc. and Victor M. Perez.
(incorporated by reference to Exhibit 10.1 to the
Registrants Current Report on
Form 8-K
filed on August 11, 2009).
|
|
10
|
.12*
|
|
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
Current Report on
Form 8-K
filed on July 24, 2007).
|
|
10
|
.13*
|
|
Amendment to Employment Agreement among the Registrant, AirComp
LLC and Terrence P. Keane, effective April 1, 2008
(incorporated by reference to Exhibit 10.1 to the
Registrants Current Report on
Form 8-K
filed on May 1, 2008).
|
|
10
|
.14*
|
|
Second Amendment to Executive Employment Agreement, dated
December 31, 2008, by and between the Registrant and
Terrence P. Keane (incorporated by reference to
Exhibit 10.14 to the Registrants Annual Report on
Form 10-K
filed on March 9, 2009).
|
|
10
|
.15*
|
|
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 Current Report on
Form 8-K
filed on December 6, 2007).
|
|
10
|
.16*
|
|
Executive Employment Agreement, effective July 1, 2007, by
and between Strata Directional Technology LLC and David K. Bryan
(incorporated by reference to Exhibit 10.17 to the
Registrants Annual Report on
Form 10-K
filed on March 9, 2009).
|
|
10
|
.17*
|
|
Amendment to Executive Employment Agreement, dated
December 31, 2008, by and between Strata Directional
Technology LLC and David K. Bryan (incorporated by reference to
Exhibit 10.17 to the Registrants Annual Report on
Form 10-K
filed on March 9, 2009).
|
|
10
|
.18*
|
|
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 Current Report on
Form 8-K
filed on February 25, 2008).
|
|
10
|
.19
|
|
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
|
.20
|
|
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
|
.21
|
|
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).
|
99
|
|
|
|
|
Exhibit
|
|
Description
|
|
|
10
|
.22
|
|
Investor Rights Agreement, dated December 18, 2006, by and
between the Registrant and Oil & Gas Rental Services,
Inc. (incorporated by reference to Exhibit 10.2 to the
Registrants Current Report on
Form 8-K
filed on December 19, 2006).
|
|
10
|
.23
|
|
First Amendment to Investor Rights Agreement, by and among
Allis-Chalmers Energy Inc. and the holders named thereto, dated
June 23, 2008 (incorporated by reference to
Exhibit 10.1 to the Registrants Current Report on
Form 8-K
filed on June 26, 2008).
|
|
10
|
.24
|
|
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 Current Report on
Form 8-K
filed on August 14, 2006).
|
|
10
|
.25*
|
|
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
|
.26*
|
|
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
|
.27*
|
|
Second Amended and Restated 2006 Incentive Plan (incorporated by
reference to Exhibit 10.1 to the Registrants Current
Report on
Form 8-K
filed on November 12, 2009).
|
|
10
|
.28*
|
|
Form of Employee Restricted Stock Agreement pursuant to the
Registrants 2006 Incentive Plan (incorporated by reference
to Exhibit 10.2 to the Registrants Current Report on
Form 8-K
filed on September 18, 2006).
|
|
10
|
.29*
|
|
Form of Employee Nonqualified Stock Option Agreement pursuant to
the Registrants 2006 Incentive Plan (incorporated by
reference to Exhibit 10.3 to the Registrants Current
Report on
Form 8-K
filed on September 18, 2006).
|
|
10
|
.30*
|
|
Form of Employee Incentive Stock Option Agreement pursuant to
the Registrants 2006 Incentive Plan (incorporated by
reference to Exhibit 10.4 to the Registrants Current
Report on
Form 8-K
filed on September 18, 2006).
|
|
10
|
.31*
|
|
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 Current Report on
Form 8-K
filed on September 18, 2006).
|
|
10
|
.32*
|
|
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 Current Report on
Form 8-K
filed on September 18, 2006).
|
|
10
|
.33*
|
|
Form of Performance Award Agreement, as amended and restated
effective March 3, 2010, pursuant to the Registrants
2006 Incentive Plan (incorporated by reference to
Exhibit 10.1 to the Registrants Current Report on
Form 8-K
filed on March 9, 2010).
|
|
10
|
.34
|
|
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
Quarterly Report
Form 10-Q
filed on May 10, 2007).
|
|
10
|
.35
|
|
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 Current Report on
Form 8-K
filed on December 6, 2007).
|
|
10
|
.36
|
|
Second Amendment to Second Amended and Restated Credit
Agreement, dated as of December 29, 2008, by and among the
Registrant, as borrower, Royal Bank of Canada, as administrative
agent, and the lenders named thereto (incorporated by reference
to Exhibit 10.1 to the Registrants Current Report on
Form 8-K
filed on January 7, 2009).
|
|
10
|
.37
|
|
Third Amendment to Second Amended and Restated Credit Agreement,
dated as of April 9, 2009, by and among the Company, as
borrower, certain subsidiaries of the Company, as guarantors,
Royal Bank of Canada, as administrative agent, and the lenders
named thereto (incorporated by reference to Exhibit 10.1 to
the Registrants Current Report on
Form 8-K
filed on April 9, 2009).
|
100
|
|
|
|
|
Exhibit
|
|
Description
|
|
|
10
|
.38
|
|
Fourth Amendment to Second Amended and Restated Credit
Agreement, dated May 20, 2009, by and among Allis-Chalmers
Energy Inc., the subsidiary guarantors party thereto, Royal Bank
of Canada, as Administrative Agent and Collateral Agent, and the
lenders party thereto (incorporated by reference to
Exhibit 10.1 to the Registrants Current Report on
Form 8-K
filed on May 27, 2009).
|
|
10
|
.39
|
|
Fifth Amendment to Second Amended and Restated Credit Agreement,
dated as of October 13, 2009, by and among the Company, as
borrower, certain subsidiaries of the Company, as guarantors,
Royal Bank of Canada, as administrative agent, and the lenders
named thereto (incorporated by reference to Exhibit 10.1 to
the Registrants Current Report on
Form 8-K
filed on October 16, 2009).
|
|
10
|
.40
|
|
Sixth Amendment to Second Amended and Restated Credit Agreement,
dated as of February 25, 2010, by and among the Company, as
borrower, certain subsidiaries of the Company as guarantors,
Royal Bank of Canada, as administrative agent, and the lenders
named thereto (incorporated by reference to Exhibit 10.1 to
the Registrants Current Report on
Form 8-K
filed on March 2, 2010).
|
|
10
|
.41
|
|
Master Loan and Security Agreement, dated as of January 23,
2009, by and among Allis-Chalmers Drilling LLC, as borrower,
Allis-Chalmers Energy Inc., as guarantor, and Caterpillar
Financial Services Corporation, as lender (incorporated by
reference to Exhibit 10.2 to the Registrants Current
Report on
Form 8-K
filed on May 27, 2009).
|
|
10
|
.42
|
|
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 Quarterly Report on
Form 10-Q
filed on May 10, 2007).
|
|
10
|
.43
|
|
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 Quarterly Report on
Form 10-Q
filed on May 10, 2007).
|
|
10
|
.44
|
|
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 Current
Report on
Form 8-K
filed on February 6, 2008).
|
|
10
|
.45
|
|
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 Current Report on
Form 8-K
filed on February 6, 2008).
|
|
10
|
.46
|
|
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 Current Report on
Form 8-K
filed on February 6, 2008).
|
|
10
|
.47
|
|
Form of Convertible Subordinated Secured Debenture (incorporated
by reference to Schedule E to Exhibit 10.1 to the
Registrants Current Report on
Form 8-K
filed on February 6, 2008).
|
|
10
|
.48
|
|
Mutual Termination and Release Agreement, dated August 8,
2008, by and among Allis-Chalmers Energy Inc., Bronco Drilling
Company, Inc. and Elway Merger Sub LLC (incorporated by
reference to Exhibit 10.1 to the Registrants Current
Report on
Form 8-K
filed on August 8, 2008).
|
|
10
|
.49
|
|
Amended and Restated Performance award Agreement, dated
March 11, 2009, between Allis-Chalmers Energy Inc. and
Munawar H. Hidayatallah (incorporated by reference to
Exhibit 10.1 to the Registrants Current Report on
Form 8-K
filed on March 13, 2009).
|
|
10
|
.50
|
|
Amended and Restated Performance Award Agreement, dated
August 5, 2009, between Allis-Chalmers Energy Inc. and
Victor M. Perez (incorporated by reference to Exhibit 10.2
to the Registrants Current Report on
Form 8-K
filed on August 11, 2009).
|
|
10
|
.51
|
|
Letter agreements dated March 9, 2009, by each of Munawar
H. Hidayatallah, Victor M. Perez, Theodore F. Pound III, David
Bryan, Terrence P. Keane and Mark Patterson (incorporated by
reference to Exhibit 10.2 to the Registrants Current
Report on
Form 8-K
filed on March 13, 2009).
|
|
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.
|
101
|
|
|
|
|
Exhibit
|
|
Description
|
|
|
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 |
|
|
|
Filed herewith. |
102