e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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FOR THE FISCAL YEAR ENDED
DECEMBER 31, 2008
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OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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FOR THE TRANSITION PERIOD
FROM TO
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Commission file number 1-2199
ALLIS-CHALMERS ENERGY
INC.
(Exact name of registrant as
specified in its charter)
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Delaware
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39-0126090
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(State or other jurisdiction
of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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5075 WESTHEIMER, SUITE 890
HOUSTON, TEXAS
(Address of principal
executive offices)
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77056
(Zip
code)
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(713) 369-0550
Registrants telephone
number, including area code
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE
ACT:
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Title of Security:
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Name of Exchange:
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Common Stock, par value $0.01 per share
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New York Stock Exchange
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SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE
ACT:
NONE
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes o No þ
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or
15(d). Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
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Large
accelerated
filer o
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Accelerated
filer þ
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Non-accelerated
filer o
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Smaller
reporting
company o
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(Do not check if a smaller
reporting
company)
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
The aggregate market value of the common equity held by
non-affiliates of the registrant, computed using the closing
price of the common stock of $17.80 per share on June 30,
2008, as reported on the New York Stock Exchange, was
approximately $372,126,700 (affiliates included for this
computation only: directors, executive officers and holders of
more than 5% of the registrants common stock).
As of February 23, 2009 there were 35,674,742 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 2009 annual meeting of
stockholders.
DEFINITIONS
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air drilling |
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A technique in which oil, natural gas, or geothermal wells are
drilled by creating a pressure within the well that is lower
than the reservoir pressure. The result is increased rate of
penetration, reduced formation damage and reduced drilling costs. |
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blow out preventors |
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A large safety device placed on the surface of an oil or natural
gas well to maintain high pressure well bores. |
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booster |
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A machine that increases the pressure and/or volume of air when
used in conjunction with a compressor or a group of compressors. |
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capillary tubing |
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A small diameter tubing installed in producing wells and through
which chemicals are injected to enhance production and reduce
corrosion and other problems. |
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casing |
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A pipe placed in a drilled well to secure the well bore and
formation. |
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choke manifolds |
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An arrangement of pipes, valves and special valves on the rig
floor that controls pressure during drilling by diverting
pressure away from the blow-out preventors and the annulus of
the well. |
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coiled tubing |
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A small diameter tubing used to service producing and
problematic wells and to work in high pressure applications
during drilling, production and workover operations. |
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directional drilling |
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The technique of drilling a well while varying the angle of
direction of a well and changing the direction of a well to hit
a specific target. |
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double studded adapter |
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A device that joins two dissimilar connections on certain
equipment, including valves, piping and blow-out preventers. |
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drill pipe |
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A pipe that attaches to the drill bit to drill a well. |
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foam unit |
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A compressor, a booster, a mist pump and a fuel tank all mounted
together on one flat bed trailer to be used for completion,
workover and/or shallow drilling operations. Foam units are
designed to provide a small footprint and easy transport. |
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horizontal drilling |
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The technique of drilling wells at a
90-degree
angle. |
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laydown machines |
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A truck mounted machine used to move drill pipe, casing and
tubing onto a pipe rack (from which a derrick crane lifts the
drill pipe, casing and tubing and inserts it into the well). |
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land drilling rig |
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Composed of a drawworks or hoist, a derrick, a power plant,
rotating equipment and pumps to circulate the drilling fluid and
the drill string. |
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measurement-while-drilling |
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The technique used to measure direction and angle while drilling
a well. |
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mist pump |
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A drilling pump that uses mist as the circulation medium for
injecting small amounts of foaming agent, corrosion agent and
other chemical solutions into the well. |
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pulling rig |
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A type of well-servicing rig used to pull downhole equipment,
such as tubing, rods or the pumps from a well, and replace them
when |
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necessary. A pulling rig is also used to set downhole tools and
perform lighter jobs. |
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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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torque turn service or torque turn
equipment. |
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A monitoring device to insure proper makeup of the casing. |
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tubing |
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A pipe placed inside the casing to allow the well to produce. |
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tubing work strings |
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The tubing used on workover rigs through which high pressure
liquids, gases or mixtures are pumped into a well to perform
production operations. |
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wear bushings |
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A device placed inside a wellhead to protect the wellhead from
wear. |
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workover rigs |
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Similar to a land drilling rig, however, they are smaller than
the drilling rig for the same depth of well. These rigs are used
to complete the drilled wells or to repair them whenever
necessary. |
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SPECIAL
NOTE
REGARDING FORWARD-LOOKING STATEMENTS
This annual report contains forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933,
as amended, or the Securities Act, regarding our business,
financial condition, results of operations and prospects. Words
such as expects, anticipates, intends, plans, believes, seeks,
estimates and similar expressions or variations of such words
are intended to identify forward-looking statements. However,
these are not the exclusive means of identifying forward-looking
statements. Although such forward-looking statements reflect our
good faith judgment, such statements can only be based on facts
and factors currently known to us. Consequently, forward-looking
statements are inherently subject to risks and uncertainties,
and actual outcomes may differ materially from the results and
outcomes discussed in the forward-looking statements. 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 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 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 our 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 13 of this annual report. You
should read those sections carefully. You should not place undue
reliance on forward-looking statements, which speak only as of
the date of this annual report. We undertake no obligation to
update publicly any forward-looking statements in order to
reflect any event or circumstance occurring after the date of
this annual report or currently unknown facts or conditions or
the occurrence of unanticipated events.
PART I.
We provide services and equipment to oil and natural gas
exploration and production companies throughout the
U.S. including Texas, Oklahoma, Louisiana, Arkansas,
Pennsylvania, New Mexico, Colorado, offshore in the Gulf of
Mexico, and internationally primarily in Argentina, Mexico and
Brazil. We operate in three sectors of the oil and natural gas
service industry: Oilfield Services; Drilling and Completion and
Rental Services. Our central operating strategy is to provide
high-quality, technologically advanced services and equipment.
As a result of our commitment to customer service, we have
developed strong relationships with many of the leading oil and
natural gas companies, including both independents and majors.
Our growth strategy is focused on identifying and pursuing
opportunities in markets we believe are growing faster than the
overall oilfield services industry and opportunities which we
believe help us to
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mitigate cyclical risk by diversifying our cash flow. 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. Since 2001, we have
completed 24 acquisitions, including six in 2005, six in 2006,
four in 2007 and one in 2008.
Our annual reports on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K
and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Securities Exchange Act of
1934, as amended, or the Exchange Act, are made available free
of charge on our website at www.alchenergy.com as soon as
reasonably practicable after we electronically file or furnish
them to the Securities and Exchange Commission, or SEC.
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 and Corporate Governance and
Nominating 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.
Divisional and geographic financial information appears in
Item 8. Financial Information Notes to
Consolidated Financial Statements Note 14.
Our
History
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We were incorporated in 1913 under Delaware law.
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We reorganized in bankruptcy in 1988 and sold all of our major
businesses. From 1988 to May 2001 we had only one operating
company in the equipment repair business.
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In May 2001, under new management we consummated a merger in
which we acquired Oil Quip Rentals, Inc., or Oil Quip, and its
wholly-owned subsidiary, Mountain Compressed Air, Inc., or MCA.
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In December 2001, we sold Houston Dynamic Services, Inc., our
last pre-bankruptcy business.
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In February 2002, we acquired approximately 81% of the capital
stock of Allis-Chalmers Tubular Services Inc., or Tubular,
formerly known as Jens Oilfield Service, Inc. and
substantially all of the capital stock of Strata Directional
Technology, Inc., or Strata.
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In July 2003, we entered into a limited liability company
operating agreement with M-I L.L.C., or M-I, a joint venture
between Smith International and Schlumberger N.V., to form a
Delaware limited liability company named AirComp LLC, or
AirComp. Pursuant to this agreement, we owned 55% and M-I owned
45% of AirComp.
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In September 2004, we acquired the remaining 19% of the capital
stock of Tubular.
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In September 2004, we acquired all of the outstanding stock of
Safco-Oil Field Products, Inc., or Safco.
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In November 2004, AirComp acquired substantially all of the
assets of Diamond Air Drilling Services, Inc. and Marquis Bit
Co., LLC, which we refer to collectively as Diamond Air.
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In December 2004, we acquired Downhole Injection Services, LLC,
or Downhole.
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In April 2005, we acquired all of the outstanding stock of Delta
Rental Service, Inc., or Delta.
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In May 2005, we acquired all of the outstanding stock of Capcoil
Tubing Services, Inc., or Capcoil.
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In July 2005, we acquired M-Is interest in AirComp, and
acquired the compressed air drilling assets of W. T.
Enterprises, Inc., or W.T.
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Effective August 2005, we acquired all of the outstanding stock
of Target Energy Inc., or Target.
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In September 2005, we acquired the casing and tubing assets of
IHS/Spindletop, a division of Patterson Services, Inc., a
subsidiary of RPC, Inc.
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In January 2006, we acquired all of the outstanding stock of
Specialty Rental Tools, Inc., or Specialty.
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In April 2006, we acquired all of the outstanding stock of
Rogers Oil Tool Services, Inc., or Rogers.
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In August 2006, we acquired all of the outstanding stock of DLS
Drilling, Logistics & Services Corporation, or DLS.
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In October 2006, we acquired all of the outstanding stock of
Petro-Rentals, Incorporated, or Petro Rentals.
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In December 2006, we acquired all of the outstanding stock of
Tanus Argentina S.A., or Tanus.
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In December 2006, we acquired substantially all of the assets of
Oil & Gas Rental Services, Inc., or OGR.
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In June 2007, we acquired all of the outstanding stock of Coker
Directional, Inc., or Coker and merged it with Strata.
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In June 2007, we sold our capillary assets that were acquired in
the Downhole and Capcoil acquisitions
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In July 2007, we acquired all of the outstanding stock of Diggar
Tools, LLC, or Diggar and merged it with Strata.
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In October 2007, we acquired all of the outstanding stock of
Rebel Rentals, Inc., or Rebel.
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In November 2007, we acquired substantially all the assets
Diamondback Oilfield Services, Inc. or Diamondback.
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In August 2008, we sold our drill pipe tong manufacturing assets
that we acquired in the acquisition of Rogers.
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In December 2008, we acquired all of the outstanding stock of
BCH Ltd., or BCH.
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As a result of these transactions, our prior results may not be
indicative of current or future operations of those sectors.
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 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. 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 prices
and the turmoil in the financial markets which affected the
availability of capital for our customers. As of
February 27, 2009, the U.S. rig count stood at 1,243.
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Business
Segments
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 services, land and offshore pumping services
and coiled tubing.
According to Baker Hughes, as of February 27, 2009, 56% of
all wells in the U.S. are drilled 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.
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, Oklahoma and
both onshore and offshore in the Gulf of Mexico and Mexico.
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 260 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.
In 2007, we expanded our directional drilling capability by
completing three acquisitions for approximately
$37.3 million in total. These were Coker (June 2007),
Diggar (July 2007) and Diamondback (November 2007). These
acquisitions provided additional directional drillers, downhole
motors, and MWD tools and enabled us to expand our presence in
the Northern Rockies and the Mid-Continent areas. We currently
maintain an inventory of approximately 330 drilling motors. Our
straight-hole motors offer an opportunity to capture additional
market share. We currently provide our directional drilling
services in Texas, Oklahoma, Pennsylvania, Louisiana, North
Dakota and offshore in the Gulf of Mexico.
We expanded our tubular services in September 2005 by acquiring
the casing and tubing assets of IHS/Spindletop, a division of
Patterson Services, Inc., a subsidiary of RPC, Inc. We paid
$15.7 million for RPC, Inc.s casing and tubing
assets, which consisted of casing and tubing installation
equipment, including hammers, elevators, trucks, pickups, power
units, laydown machines, casing tools and torque turn equipment.
The acquisition of RPC, Inc.s casing and tubing assets
increased our capability in tubular services and expanded our
geographic capability. We opened new field offices in Corpus
Christi, Texas, Kilgore, Texas, Lafayette, Louisiana and Houma,
Louisiana. The acquisition allowed us to enter the East Texas
and Louisiana market for casing and tubing services as well as
offshore in the Gulf of Mexico. Additionally, the acquisition
greatly expanded our premium tubing services. In April 2006 we
acquired Rogers for a purchase price of approximately
$13.7 million. Historically, Rogers rented, sold and
serviced power drill pipe tongs and accessories and rental tongs
for snubbing and well control applications and provided
specialized tong operators for rental jobs. In August 2008, we
sold the drill pipe tong manufacturing assets we acquired in the
Rogers acquisition for approximately $7.5 million. In
October 2007 we acquired Rebel Rentals, Inc. 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 July 2005, we purchased the compressed air drilling assets of
W. T., operating in West Texas for $6.0 million. The
acquired assets included air compressors, boosters, mist pumps,
rolling stock and other equipment. We also acquired the
remaining 45% equity interest in AirComp from M-I in July 2005.
We
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currently provide underbalanced drilling services in Texas,
Arkansas, Oklahoma, New Mexico, Colorado, Utah and Pennsylvania.
We started offering production related services with the
acquisition of Downhole, in December 2004, and the acquisition
of Capcoil, in May 2005. In October 2006, we expanded our
production services with the acquisition of Petro Rentals for a
purchase price of approximately $33.6 million. Petro
Rentals served both the onshore and offshore markets, providing
a variety of quality rental tools and equipment and services,
with an emphasis on production-related equipment and services,
including wire line services and equipment, land and offshore
pumping services and coiled tubing. On June 29, 2007, we
sold our capillary tubing units and related equipment for
approximately $16.3 million. We reported a gain of
approximately $8.9 million. The assets sold represented a
small portion of our Oilfield Services segment. We currently
provide production services in Texas, Louisiana and Arkansas.
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.
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 74 land
rigs, including 18 drilling rigs and 46 service rigs (workover
and pulling units) in Argentina, seven drilling rigs and one
service rig in Brazil and two drilling rigs in Bolivia.
Argentine rig operations are generally conducted in remote
regions of the country and require substantial infrastructure
and support. In 2007, we placed orders for four drilling rigs
and 16 service rigs. All of the service rigs and one of the
drilling rigs were placed into service at various dates in 2008.
A second drilling rig will be activated in March 2009 and the
remaining two drilling rigs are expected to be delivered in the
second quarter of 2009 for use in the U.S. for a customer
operating in the Haynesville Shale. As of February 28,
2009, all of our rig fleet was actively marketed, except for one
drilling rig that is presently inactive and is being refurbished
and upgraded.
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 in Texas, Louisiana,
Oklahoma, offshore in the Gulf of Mexico and internationally in
Mexico, Columbia, Libya and Malaysia.
Our Rental Services segment was established with the acquisition
of Safco in September 2004 and Delta in April 2005. We
significantly expanded our Rental Services segment in January
2006 with the acquisition of Specialty for a purchase price of
approximately $95.3 million. Specialty had been in the
rental business for over 25 years, providing oil and
natural gas operators and oilfield services companies with
rental equipment. We further expanded this segment with the
acquisition of substantially all the assets of OGR in December
2006 for a purchase price of approximately $342.4 million.
The assets we acquired included an extensive inventory of
premium rental equipment, including drill pipe, spiral heavy
weight drill pipe, tubing work strings, landing strings, blow
out preventors, choke manifolds and various valves and handling
tools for oil and natural gas drilling. Included in the
acquisition were OGRs facilities in Morgan City, Louisiana
and Victoria, Texas.
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Competitive
Strengths
We believe the following competitive strengths will enable us to
capitalize on future opportunities:
Strategic position in high growth markets. We
focus on markets we believe are growing faster than the overall
oilfield services industry and in which we can capitalize on our
competitive strengths. Pursuant to this strategy, we have become
a significant provider of products and services in directional
drilling, casing and tubing, underbalanced drilling, drilling
and completion and rental services.
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, Oklahoma, Louisiana, Arkansas,
Pennsylvania, New Mexico, Colorado, offshore in the Gulf of
Mexico, Argentina, Brazil and Mexico. Our largest customers
include Pan American Energy, Apache Corporation, Repsol-YPF,
Chesapeake Energy, Oxy, BP, ConocoPhilips, Anadarko Petroleum,
Devon Energy, Materiales y Equipo Petroleo, or Matyep, TXCO
Resources, Pioneer Natural Resources, North American Petroleum,
Jones Energy Ltd, Drilex SA DE CV, Mariner Energy, El Paso
Corporation, and Petroleo Brasileiro S.A, or Petrobras. 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 when compared to the
volatility in the U.S. domestic market. Our acquisition of
Petro Rentals in October 2006 significantly enhanced our
production-related services and equipment provided by our
Oilfield Services segment, and our acquisition of substantially
all the assets of OGR in December 2006 expanded our Rental
Services segment and increased our offshore and international
operations.
Experienced management team. Our executive
management team has extensive experience in the energy sector,
and consequently has developed strong and longstanding
relationships with many of the major and independent exploration
and production companies.
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, Colorado, Wyoming, Arkansas, Oklahoma,
Louisiana and Pennsylvania in order to enhance our proximity to
customers and more efficiently serve their needs. Our
acquisition of DLS expanded our geographic footprint into
Argentina and our acquisition of BCH expanded our geographic
footprint into Brazil. While we will continue to evaluate
locations to conveniently serve our
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customers, due to the decrease in the rig count in late 2008 and
2009 in the U.S., we have begun to consolidate overlapping
domestic operating yard locations in order to reduce costs.
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 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 2004, we have
invested approximately $329.7 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. Current economic conditions have led us to reduce our
capital spending and operating expenses consistent with the
decline in demand for our services as producers curtail their
drilling activity.
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. Currently, our focus has shifted to how
to limit the reduction of utilization due to decreased drilling
activity as a result of current economic conditions.
Customers
In 2008 and 2007, one of our customers, Pan American Energy LLC
Sucursal Argentina, or Pan American Energy, represented
approximately 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 and Carlos A. Bulgheroni, two of our
directors, may be deemed to indirectly beneficially own all of
the outstanding capital stock of Bridas Corporation and are
members 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
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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 Pride
International, Servicios WellTech, Ensign Energy Services,
Nabors and Helmerich & Payne, and San Antonio
Global Ltd in Brazil.
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 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 20, 2009, we had
approximately 3,580 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.
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Federal
Regulations and Environmental Matters
Our operations are subject to federal, state and local laws and
regulations relating to the energy industry in general and the
environment in particular. Environmental laws have in recent
years become more stringent and have generally sought to impose
greater liability on a larger number of potentially responsible
parties. Because we provide services to companies producing oil
and natural gas, which are toxic substances, we may become
subject to claims relating to the release of such substances
into the environment. While we are not currently aware of any
situation involving an environmental claim that would likely
have a material adverse effect on us, it is possible that an
environmental claim could arise that could cause our business to
suffer. We do not anticipate any material expenditures to comply
with environmental regulations affecting our operations.
In addition to claims based on our current operations, we are
from time to time named in environmental claims relating to our
activities prior to our reorganization in 1988 (See
Item 3. Legal Proceedings).
Intellectual
Property Rights
Except for our relationships with our customers and suppliers
described above, we do not own any patents, trademarks,
licenses, franchises or concessions which we believe are
material to the success of our business.
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. During recent months, there has been a substantial
downturn in business activity and in the worldwide credit and
capital markets that has led to a worldwide economic recession.
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 causes oil and
natural gas companies and drilling contractors to change their
strategies and expenditure levels. We have experienced in the
past, and expect to experience in 2009, significant fluctuations
in operating results based on these changes.
The current sustained declines in oil and natural gas prices,
particularly in combination with the constrained capital markets
and overall economic downturn, has resulted in a decline in
activity by customers in our Oilfield Services and Rental
Services segments during the first quarter of 2009. We cannot
predict the timing or the duration of this or any other economic
downturn in the economy and if the current conditions continue,
our operating results and financial conditions could be
materially adversely affected.
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
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
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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 in recent
months, 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 can be expected to
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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Recent adverse changes in the capital markets have also caused a
number of oil and natural gas producers to announce reductions
in capital budgets for future periods. 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, Mexico and elsewhere.
Historically, we have been dependent upon a few customers for a
significant portion of our revenues. In 2008, 2007 and 2006, one
of our customers, Pan American Energy represented 28.5%, 20.7%
and 11.7% of our consolidated revenues, respectively. Pan
American Energy also contributes a majority of the revenue
derived from our Drilling and Completion operations. In 2008,
2007 and 2006, Pan American Energy represented 66.0%, 51.0% and
45.6% of our Drilling and Completion revenues, respectively.
Additionally, in 2007, we placed orders for 16 new service rigs
and four drilling rigs pursuant to our strategic agreement with
Pan American Energy. The 16 service rigs and one of the drilling
rigs were delivered and placed in service in 2008 and an
additional drilling rig will be activated in March 2009. The
agreement with Pan American Energy currently has an expiration
date of June 30, 2011. However, Pan American Energy
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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.
This concentration of customers may increase our overall
exposure to credit risk, and customers will likely be similarly
affected by changes in economic and industry conditions. Our
financial condition and results of operations will be materially
adversely affected if one or more of our significant customers
fails to pay us or ceases to contract with us for our services
on terms that are favorable to us or at all.
Our
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.
An
oversupply of comparable rigs in the geographic markets in which
we compete could depress the utilization rates and dayrates for
our rigs and materially reduce our revenues and
profitability.
Utilization rates, which are the number of days a rig actually
works divided by the number of days the rig is available for
work, and dayrates, which are the contract prices customers pay
for rigs per day, are also affected by the total supply of
comparable rigs available for service in the geographic markets
in which we compete. Improvements in demand in a geographic
market may cause our competitors to respond by moving competing
rigs into the market, thus intensifying price competition.
Significant new rig construction could also intensify price
competition. In the past, there have been prolonged periods of
rig oversupply with correspondingly depressed utilization rates
and dayrates largely due to earlier, speculative construction of
new rigs. Improvements in dayrates and expectations of
longer-term, sustained improvements in utilization rates and
dayrates for drilling rigs may lead to construction of new rigs.
These increases in the supply of rigs could depress the
utilization rates and dayrates for our rigs and materially
reduce our revenues and profitability.
We may
experience increased labor costs or the unavailability of
skilled workers and the failure to retain key personnel could
hurt our operations.
Companies in our industry, including us, are dependent upon the
available labor pool of skilled employees. We compete with other
oilfield services businesses and other employers to attract and
retain qualified personnel with the technical skills and
experience required to provide our customers with the highest
quality service. We are also subject to the Fair Labor Standards
Act, which governs such matters as minimum wage, overtime and
other working conditions. A shortage in the labor pool of
skilled workers or other general inflationary pressures or
changes in applicable laws and regulations could make it more
difficult for us to attract and retain personnel and could
require us to enhance our wage and benefits packages. There can
be no assurance that labor costs will not increase. Any increase
in our operating costs could cause our business to suffer.
15
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. In the aftermath of the Argentine economic
crisis of 2001 and 2002, both the government and private sector
companies have experienced significant pressure from employees
and labor organizations relating to wage levels and employee
benefits. In early 2005, the Argentine government promised not
to order salary increases by decree. However, there has been no
abatement of pressure to mandate salary increases, and it is
possible the government will adopt measures that will increase
salaries or require our Drilling and Completion business to
provide additional benefits, which would increase our costs and
potentially reduce our profitability, cash flow
and/or
liquidity.
Rig
upgrade, refurbishment and construction projects are subject to
risks, including delays and cost overruns, which could have an
adverse effect on 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 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.
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.
Currently, we have two land drilling rigs under construction
that are to be completed in the second quarter of 2009. If these
rigs are not completed on time, our financing commitment will
expire. The turmoil in the financial markets in 2008 and its
impact on the financial condition of the banking sector and
other lenders, has increased the uncertainty that capital will
be available to us, or available at a reasonable cost. As such,
we may be unable to complete the acquisition of these two rigs.
In addition, we have halted construction on two other land
drilling rigs because of the drop in the U.S. rig count and
the feasibility of utilizing the rigs when completed.
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
16
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. In accordance with Financial Accounting Standards
Board No. 142, Goodwill and Other Intangible Assets,
or FASB No. 142, 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, 2008 and 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 continue to deteriorate or we have
a prolonged downturn, we may be required to record an additional
impairment of goodwill and such impairment could be material.
We may
fail to acquire additional businesses, which will restrict our
growth and may have a material adverse effect on our ability to
meet our obligations under the notes.
Part of our long term business strategy has been to acquire
companies operating in the oilfield services industry. However,
there can be no assurance that we will be successful in
acquiring any additional companies. Successful acquisition of
new companies will depend on various factors, including but not
limited to:
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our ability to obtain financing;
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the competitive environment for acquisitions; and
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the integration and synergy issues described in the next risk
factor.
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There can be no assurance that we will be able to acquire and
successfully operate any particular business or that we will be
able to expand into areas that we have targeted. If we fail to
acquire additional businesses or are unable to finance such
acquisitions, our financial condition, our results of operations
and our ability to meet our debt obligations may be materially
adversely affected.
Difficulties
in integrating acquired businesses may result in reduced
revenues and income.
We may not be able to successfully integrate any business we
acquire in the future. The integration of a business could be
complex and time consuming and place a significant strain on
management and our information systems, and this strain could
disrupt our businesses. Furthermore, if our combined businesses
continue to grow rapidly, we may be required to replace our
current information and accounting systems with systems designed
for companies that are larger than ours. We may encounter
substantial difficulties, costs and delays involved in
integrating common accounting, information and communication
systems, operating procedures, internal controls and human
resources practices, including incompatibility of business
cultures and the loss of key employees and customers. These
difficulties may reduce our ability to gain customers or retain
existing customers, and may increase operating expenses,
resulting in reduced revenues and income and a failure to
realize the anticipated benefits of acquisitions.
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We have made numerous acquisitions during the past five years.
As a result of these transactions, our past performance is not
indicative of future performance, and investors should not base
their expectations as to our future performance on our
historical results.
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.
Likewise, during the course of our integration of any acquired
business, we may identify needed improvements to our or such
acquired business internal controls and may be required to
design enhanced processes and controls in order to make such
improvements. This could result in significant delays and costs
to us and could require us to divert substantial resources,
including management time, from other activities.
If we fail to maintain the adequacy of our disclosure controls
and procedures and our internal controls, we may not be able to
conclude that we have effective disclosure controls and
procedures
and/or
effective internal controls over financial reporting in
accordance with Section 404 of the Sarbanes-Oxley Act.
Also, our independent registered public accounting firm may be
unable to express an opinion on our managements evaluation
of, or on the effectiveness of, our internal controls.
If it is determined that our disclosure controls and procedures
and/or our
internal controls over financial reporting are not effective
and/or we
fail to satisfy the requirements of Section 404 of the
Sarbanes-Oxley Act on a timely basis, we may not be able to
provide reliable financial and other reports or prevent fraud,
which, in turn:
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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.
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 45.9% of our consolidated revenue in the year
ended December 31, 2008. 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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18
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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
and where our competitors who are not subject to U.S. laws
and regulations, such as the Foreign Corrupt Practices Act, can
gain competitive advantages over us by securing business awards,
licenses or other preferential treatment in those jurisdictions
using methods that U.S. law and regulations prohibit us
from using. For example, our
non-U.S. competitors
are not 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. We may be subject to competitive disadvantages
to the extent that our competitors are able to secure business,
licenses or other preferential treatment by making payments to
government officials and others in positions of influence.
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.
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
19
years and the absence of a clear political consensus in favor of
any particular set of economic policies have given rise to
significant uncertainties about the countrys economic and
political future. It is currently unclear whether the economic
and political instability experienced over the past several
years will continue and it is possible that, despite recent
economic growth, Argentina may return to a deeper recession,
higher inflation and unemployment and greater social unrest. If
instability persists, there could be a material adverse effect
on our results of operations and financial condition.
In the event of further social or political crisis, companies in
Argentina may also face the risk of further civil and social
unrest, strikes, expropriation, nationalization, forced
renegotiation or modification of existing contracts and changes
in taxation policies, including royalty and tax increases and
retroactive tax claims.
In addition, investments in Argentine companies may be further
affected by changes in laws and policies of the
U.S. affecting foreign trade, taxation and investment.
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 in 2002 before substantially stabilizing in 2003
and remaining stable in 2004. In 2005, however, inflation rates
began to increase. In addition, in response to the economic
crisis in 2002, the federal government granted the Central Bank
greater control over monetary policy than was available to it
under the previous monetary regime, known as the
Convertibility regime, including the ability to
print currency, to make advances to the federal government to
cover its anticipated budget deficit and to provide financial
assistance to financial institutions with liquidity problems. We
cannot assure you that inflation rates will remain stable in the
future. Significant inflation in Argentina could have a material
adverse effect on our results of operations and financial
condition.
The
loss of key executives would adversely affect our ability to
effectively finance and manage our business, acquire new
businesses, and obtain and retain customers.
We are dependent upon the efforts and skills of our executives
to finance and manage our business, identify and consummate
additional acquisitions and obtain and retain customers. These
executives include our Chief Executive Officer and Chairman of
the Board, Munawar H. Hidayatallah.
In addition, our development and expansion will require
additional experienced management and operations personnel. No
assurance can be given that we will be able to identify and
retain these employees. Also, the loss of the services of one or
more of our key executives could increase our exposure to the
other risks described in this Risk Factors section.
We do not maintain key man insurance on any of our personnel.
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
20
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. We believe that claims
against us are barred by applicable bankruptcy law, and that the
products liability trust will continue to be responsible for
products liability claims. Since 1988, no court has ruled that
we are responsible for products liability claims. However, if we
are held responsible for product liability claims, we could
suffer substantial losses that could have a material adverse
effect on our financial condition and results of operations. We
have not manufactured products containing asbestos since our
reorganization in 1988.
We may
be subject to claims for personal injury and property damage,
which could materially adversely affect our financial condition
and results of operations.
Our products and services are used for the exploration and
production of oil and natural gas. These operations are subject
to inherent hazards that can cause personal injury or loss of
life, damage to or destruction of property, equipment, the
environment and marine life, and suspension of operations.
Litigation arising from an accident at a location where our
products or services are used or provided may cause us to be
named as a defendant in lawsuits asserting potentially large
claims. We maintain customary insurance to protect our business
against these potential losses. Our insurance has deductibles or
self-insured retentions and contains certain coverage
exclusions. However, we could become subject to material
uninsured liabilities that could have a material adverse effect
on our financial condition and results of operations.
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
21
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 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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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 common stock, or the
perception that such sales could occur, could adversely affect
the market price of our common stock by introducing a large
number of sellers to the market. Such sales could cause the
market price of our common stock to decline.
We have 35,674,742 shares outstanding as of
February 23, 2009. At December 31, 2008, we had
reserved an additional 1,661,187 shares of common stock for
issuance under our equity compensation plans, of which
901,732 shares were issuable upon the exercise of
outstanding options with a weighted average exercise price of
$10.95 per share and 481,666 shares were issuable under
restricted stock award grants subject to performance based
vesting. In addition, we have reserved 4,000 shares of
common stock for issuance upon the exercise of outstanding
options (with an exercise price of $13.75 per share) granted to
board members in 1999 and 2000.
In connection with our acquisition of DLS, we entered into an
investors rights agreement with the seller parties to the DLS
stock purchase agreement, who collectively hold
4,867,000 shares of our common stock as of
February 23, 2009. Under that agreement, the DLS sellers
are entitled to certain rights with respect to the registration
of the sale of such shares under the Securities Act. By
exercising their registration rights and causing a large number
of shares to be sold in the public market, these holders could
cause the market price of our common stock to decline.
We cannot predict whether future sales of our common stock, or
the availability of our common stock for sale, will adversely
affect the market price for our common stock or our ability to
raise capital by offering equity securities.
In
connection with our acquisitions of DLS, the DLS sellers have
the right to designate two nominees for election to our board of
directors. The interests of the DLS sellers may be different
from yours.
The DLS sellers collectively hold 4,867,000 shares of our
common stock, representing approximately 13.6% of our issued and
outstanding shares as of February 23, 2009. 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.
As a result, the DLS sellers have a greater ability to determine
the composition of our
22
board of directors and to control our future operations and
strategy as compared to the voting power and control that could
be exercised by a stockholder owning the same number of shares
and not benefiting from board designation rights.
Conflicts of interest between the DLS sellers, 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 other matters. In addition, the interests of
the DLS sellers regarding any proposed merger or sale may differ
from the interests of other holders of our securities.
The board designation rights described above could also have the
effect of delaying or preventing a change in our control or
otherwise discouraging a potential acquirer from attempting to
obtain control of us, which in turn could have a material and
adverse effect on the market price of our securities
and/or our
ability to meet our obligations thereunder.
Existing
stockholders interest in us may be diluted by additional
issuances of equity securities.
We expect to issue additional equity securities to fund the
acquisition of additional businesses and pursuant to employee
benefit plans. We may also issue additional equity securities
for other purposes. These securities may have the same rights as
our common stock or, alternatively, may have dividend,
liquidation, or other preferences to our common stock. The
issuance of additional equity securities will dilute the
holdings of existing stockholders and may reduce the share price
of our common stock.
We do
not expect to pay dividends on our common stock, and investors
will be able to receive cash in respect of the shares of common
stock only upon the sale of the shares.
We have not paid any cash dividends on our common stock within
the last ten years, and we have no intention in the foreseeable
future to pay any cash dividends on our common stock.
Furthermore, our credit agreement and the indentures governing
our outstanding senior notes restrict our ability to pay
dividends on our common stock. Therefore, an investor in our
common stock will obtain an economic benefit from the common
stock only after an increase in its trading price and only by
selling the common stock.
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, as well as by the terms of our credit
agreement and the indentures governing our 9.0% senior
notes, our 8.5% senior notes and any other debt securities
we may offer. 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.
23
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, 2008, we have approximately
$593.7 million of consolidated total indebtedness
outstanding and approximately $47.7 million of additional
secured borrowing capacity available under our credit agreement.
Our substantial debt could have important consequences for you.
For example, it could:
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make it more difficult for us to satisfy our obligations with
respect to our 9.0% senior notes, our 8.5% senior
notes and any other debt securities we may offer and our other
debt;
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increase our vulnerability to general adverse economic and
industry conditions, including declines in oil and natural gas
prices and declines in drilling activities;
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limit our ability to obtain additional financing for future
working capital, capital expenditures, mergers and other general
corporate purposes;
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require us to dedicate a substantial portion of our cash flow
from operations to payments on our debt, thereby reducing the
availability of our cash flow for operations and other purposes;
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limit our flexibility in planning for, or reacting to, changes
in our business and the industry in which we operate;
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make us more vulnerable to increases in interest rates;
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place us at a competitive disadvantage compared to our
competitors that have less debt; and
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have a material adverse effect on us if we fail to comply with
the covenants in the indentures relating to our 9.0% senior
notes, our 8.5% senior notes and any other debt securities
we may offer or in the instruments governing our other debt.
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In addition, we may incur substantial additional debt in the
future. Each of the indentures governing our 9.0% senior
notes and our 8.5% senior notes permits (and we anticipate
that the indentures governing any other debt securities we may
offer will also permit) us to incur additional debt, and our
credit agreement permits additional borrowings. If new debt is
added to our current debt levels, these related risks could
increase.
We may not maintain sufficient revenues to sustain profitability
or to meet our capital expenditure requirements and our
financial obligations. Also, we may not be able to generate a
sufficient amount of cash flow to meet our debt service
obligations.
Our ability to make scheduled payments or to refinance our
obligations with respect to our debt will depend on our
financial and operating performance, which, in turn, is subject
to prevailing economic conditions and to certain financial,
business and other factors beyond our control. If our cash flow
and capital resources are insufficient to fund our debt service
obligations, we may be forced to reduce or delay scheduled
expansion and capital expenditures, sell material assets or
operations, obtain additional capital or restructure our debt.
We cannot assure you that our operating performance, cash flow
and capital resources will be sufficient for payment of our debt
in the future. In the event that we are required to dispose of
material assets or operations or restructure our debt to meet
our debt service and other obligations, we cannot assure you
that the terms of any such transaction would be satisfactory to
us or if or how soon any such transaction could be completed.
If we
fail to obtain additional financing, we may be unable to
refinance our existing debt, expand our current operations or
acquire new businesses, which could result in a failure to grow
or result in defaults in our obligations under our credit
agreement, our 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
24
financings or other sources, will be available or, if available,
will be on terms satisfactory to us. The turmoil in the
financial markets in 2008 and its impact on the financial
condition of the banking sector and other lenders, has increased
the uncertainty that capital will be available to us, or
available at a reasonable 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 the U.S. rig count experienced late in 2008 and
early 2009, the expectation of additional decreases in the
U.S. rig count, and the resulting decrease in demand for
our services 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 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.
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UNRESOLVED
STAFF COMMENTS
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None.
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The following table describes the location and general character
of the principal physical properties used in each of our
companys businesses as of March 2, 2009. Our
principal executive office is rented and located in Houston,
Texas and the table below presents all of our operating
locations and whether the property is owned or leased.
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Business Segment
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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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1 Owned & 3 Leased
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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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Washington, 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 2 locations
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Kilgore, Texas
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Leased
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San Angelo, Texas
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Leased
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Sonora, Texas
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Leased
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Casper, Wyoming
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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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1 Owned
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Aracuja, Sergipe, 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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ITEM 3.
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LEGAL
PROCEEDINGS
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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.
26
We do not administer any of the aforementioned trusts and retain
no responsibility for the assets transferred to or distributions
to be made by such trusts pursuant to our plan of reorganization.
As part of our plan of reorganization, we settled 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, has responded to
such claims, generally, by informing claimants that our
liabilities were discharged in the bankruptcy. Each of such
claims has been disposed of without material cost. However,
there can be no assurance that we will not be subject to
environmental claims relating to pre-bankruptcy activities that
would have a material adverse effect on us.
The EPA and certain state agencies continue from time to time to
request information in connection with various waste disposal
sites containing products manufactured by us before consummation
of the plan of reorganization that were disposed of by other
parties. Although we have been discharged of liabilities with
respect to hazardous waste sites, we are under a continuing
obligation to provide information with respect to our products
to federal and state agencies. The A-C Reorganization Trust,
under its mandate to provide plan of reorganization
implementation services to us, has responded to these
informational requests because pre-bankruptcy activities are
involved.
The A-C Reorganization Trust has been dissolved, and as a
result, 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 are referred to and handled by a special products
liability trust formed to be responsible for such claims in
connection with our reorganization. As with environmental
claims, we do not believe we are liable for product liability
claims relating to our business prior to our bankruptcy;
moreover, the products liability trust continues to defend all
such claims. However, there can be no assurance that we will not
be subject to material product liability claims in the future or
that the products liability trust will continue to have funds to
pay any such claims.
We have been named as a defendant in two lawsuits in connection
with our proposed merger with Bronco Drilling, Inc., which was
terminated August 2008. We do not believe that the suits have
any merit.
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.
27
|
|
ITEM 4.
|
SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS
|
On December 4, 2008, we held our Annual Meeting of
Stockholders. At the meeting, the stockholders voted on the
following matters:
1. The election of eleven directors to serve a one-year
term expiring at the 2009 annual meeting of stockholders.
2. The ratification of the appointment of UHY LLP as our
independent auditor for the fiscal year ending December 31,
2008.
The eleven nominees to our Board of Directors were elected at
the meeting, and the other proposals received the affirmative
vote required for approval. The following sets forth the results
of the voting with respect to each such matter:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Against or
|
|
|
|
|
|
|
|
|
|
For
|
|
|
Withheld
|
|
|
Abstentions
|
|
|
|
1.
|
|
|
Election of Directors
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ali H. Afdhal
|
|
|
30,884,749
|
|
|
|
1,046,735
|
|
|
|
|
|
|
|
|
|
Munir Akram
|
|
|
31,712,686
|
|
|
|
218,798
|
|
|
|
|
|
|
|
|
|
Alejandro P. Bulgheroni
|
|
|
31,015,872
|
|
|
|
915,612
|
|
|
|
|
|
|
|
|
|
Carlos A. Bulgheroni
|
|
|
24,323,218
|
|
|
|
7,608,266
|
|
|
|
|
|
|
|
|
|
Victor F. Germack
|
|
|
31,713,089
|
|
|
|
218,395
|
|
|
|
|
|
|
|
|
|
James M. Hennessy
|
|
|
31,709,189
|
|
|
|
222,295
|
|
|
|
|
|
|
|
|
|
Munawar H. Hidayatallah
|
|
|
31,540,548
|
|
|
|
390,936
|
|
|
|
|
|
|
|
|
|
John E. McConnaughy, Jr.
|
|
|
31,552,284
|
|
|
|
379,200
|
|
|
|
|
|
|
|
|
|
Robert E. Nederlander
|
|
|
31,633,737
|
|
|
|
297,747
|
|
|
|
|
|
|
|
|
|
Leonard Toboroff
|
|
|
29,278,023
|
|
|
|
2,653,461
|
|
|
|
|
|
|
|
|
|
Zane Tankel
|
|
|
31,502,086
|
|
|
|
429,398
|
|
|
|
|
|
|
2.
|
|
|
Ratification of UHY LLP as our independent accountants
|
|
|
31,657,507
|
|
|
|
230,628
|
|
|
|
43,347
|
|
PART II
|
|
ITEM 5.
|
MARKET
FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES.
|
MARKET
PRICE INFORMATION
Our common stock is traded on the New York Stock Exchange under
the symbol ALY. Prior to March 22, 2007, our
common stock was traded on the American Stock Exchange. The
following table sets forth, for periods prior to March 22,
2007, high and low sales prices of our common stock, as reported
on the American Stock Exchange and for periods since
March 22, 2007, high and low sale prices of our common
stock reported on the New York Stock Exchange.
|
|
|
|
|
|
|
|
|
Calendar Quarter
|
|
High
|
|
|
Low
|
|
|
2007
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
23.61
|
|
|
$
|
14.10
|
|
Second Quarter
|
|
|
24.39
|
|
|
|
15.83
|
|
Third Quarter
|
|
|
28.10
|
|
|
|
18.35
|
|
Fourth Quarter
|
|
|
19.49
|
|
|
|
14.09
|
|
2008
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
15.21
|
|
|
$
|
9.56
|
|
Second Quarter
|
|
|
18.50
|
|
|
|
13.01
|
|
Third Quarter
|
|
|
18.00
|
|
|
|
9.76
|
|
Fourth Quarter
|
|
|
12.68
|
|
|
|
3.69
|
|
28
Holders
As of February 23, 2009, there were approximately 1,309
holders of record of our common stock. On February 23,
2009, the closing price for our common stock reported on the New
York Stock Exchange was $1.83 per share.
Dividends
No dividends were declared or paid during the past three years,
and no dividends are anticipated to be declared or paid in the
foreseeable future. Our credit facilities and the indentures
governing our senior notes restrict our ability to pay dividends
on our common stock.
EQUITY
COMPENSATION PLAN INFORMATION
The following table provides information as of December 31,
2008 with respect to the shares of our common stock that may be
issued under our existing equity compensation plans.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Securities
|
|
|
|
|
|
|
|
|
|
Remaining Available
|
|
|
|
Number of
|
|
|
|
|
|
for Future Issuance
|
|
|
|
Securities to be
|
|
|
Weighted
|
|
|
Under Equity
|
|
|
|
Issued Upon
|
|
|
Average Exercise
|
|
|
Compensation Plans
|
|
|
|
Exercise of
|
|
|
Price of
|
|
|
(Excluding
|
|
|
|
Outstanding
|
|
|
Outstanding
|
|
|
Securities
|
|
|
|
Options, Warrants
|
|
|
Options, Warrants
|
|
|
Reflected in First
|
|
Plan Category
|
|
And Rights
|
|
|
and Rights
|
|
|
Column)
|
|
|
Equity compensation plans approved by security holders
|
|
|
1,379,398
|
|
|
$
|
10.94
|
|
|
|
281,789
|
|
Equity compensation plans not approved by security holders
|
|
|
4,000
|
|
|
$
|
13.75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,383,398
|
|
|
$
|
10.95
|
|
|
|
281,789
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2008, 4,000 of these options
remain outstanding.
29
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, 2008. 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,
2003 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ending December 31,
|
Company/Index/Market
|
|
2003
|
|
2004
|
|
2005
|
|
2006
|
|
2007
|
|
2008
|
Allis-Chalmers Energy Inc.
|
|
|
100.00
|
|
|
|
188.46
|
|
|
|
479.62
|
|
|
|
886.15
|
|
|
|
567.31
|
|
|
|
211.54
|
|
|
Oil & Gas Equipment/Svcs
|
|
|
100.00
|
|
|
|
137.25
|
|
|
|
207.42
|
|
|
|
244.86
|
|
|
|
348.71
|
|
|
|
140.65
|
|
|
Russell 2000 Index
|
|
|
100.00
|
|
|
|
117.49
|
|
|
|
121.40
|
|
|
|
142.12
|
|
|
|
135.10
|
|
|
|
88.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30
|
|
ITEM 6.
|
SELECTED
FINANCIAL DATA.
|
The following selected historical financial information for each
of the five years ended December 31, 2008, 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,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Statement of Operations Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
675,948
|
|
|
$
|
570,967
|
|
|
$
|
310,964
|
|
|
$
|
108,022
|
|
|
$
|
49,307
|
|
Impairment of goodwill
|
|
$
|
115,774
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Income (loss) from operations
|
|
$
|
(13,520
|
)
|
|
$
|
124,782
|
|
|
$
|
67,730
|
|
|
$
|
13,518
|
|
|
$
|
4,291
|
|
Net income (loss) from continuing operations
|
|
$
|
(39,464
|
)
|
|
$
|
50,440
|
|
|
$
|
35,626
|
|
|
$
|
7,175
|
|
|
$
|
888
|
|
Net income (loss) attributed to common stockholders
|
|
$
|
(39,464
|
)
|
|
$
|
50,440
|
|
|
$
|
35,626
|
|
|
$
|
7,175
|
|
|
$
|
764
|
|
Per Share Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(1.13
|
)
|
|
$
|
1.48
|
|
|
$
|
1.73
|
|
|
$
|
0.48
|
|
|
$
|
0.10
|
|
Diluted
|
|
$
|
(1.13
|
)
|
|
$
|
1.45
|
|
|
$
|
1.66
|
|
|
$
|
0.44
|
|
|
$
|
0.09
|
|
Weighted average number of common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
35,052
|
|
|
|
34,158
|
|
|
|
20,548
|
|
|
|
14,832
|
|
|
|
7,930
|
|
Diluted
|
|
|
35,052
|
|
|
|
34,701
|
|
|
|
21,410
|
|
|
|
16,238
|
|
|
|
9,510
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Balance Sheet Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,111,058
|
|
|
$
|
1,053,585
|
|
|
$
|
908,326
|
|
|
$
|
137,355
|
|
|
$
|
80,192
|
|
Long-term debt classified as:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
$
|
14,617
|
|
|
$
|
6,434
|
|
|
$
|
6,999
|
|
|
$
|
5,632
|
|
|
$
|
5,541
|
|
Long-term
|
|
$
|
579,044
|
|
|
$
|
508,300
|
|
|
$
|
561,446
|
|
|
$
|
54,937
|
|
|
$
|
24,932
|
|
Redeemable convertible Preferred stock
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Stockholders equity
|
|
$
|
383,409
|
|
|
$
|
414,329
|
|
|
$
|
253,933
|
|
|
$
|
60,875
|
|
|
$
|
35,109
|
|
Book value per share
|
|
$
|
10.75
|
|
|
$
|
11.80
|
|
|
$
|
8.99
|
|
|
$
|
3.61
|
|
|
$
|
2.58
|
|
|
|
ITEM 7.
|
MANAGEMENTS
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
|
The following discussion and analysis should be read in
conjunction with our selected historical financial data and our
accompanying financial statements and the notes to those
financial statements included elsewhere in this document. The
following discussion contains forward-looking statements within
the meaning of the Private Securities Litigation Reform Act of
1995 that reflect our plans, estimates and beliefs. Our actual
31
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,
Oklahoma, Louisiana, Arkansas, Pennsylvania, New Mexico,
Colorado, offshore in the Gulf of Mexico, and internationally,
primarily in Argentina, Mexico and Brazil. 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. The rig count in the
U.S. increased from 862 as of December 27, 2002 to
1,721 as of December 26, 2008, according to the Baker
Hughes rig count. However the rig count in 2008 reached a peak
of 2,031 in August 2008 and began to decline in the fourth
quarter of 2008 and has continued to decline to 1,243 as of
February 27, 2009. The rapid decline in the U.S. rig
count is due to the economic slowdown in the U.S. and the
decrease in natural gas and oil prices which has impacted the
capital expenditures of our customers. The turmoil in the
financial markets and its impact on the availability of capital
for our customers has also affected drilling activity in the
U.S. Directional and horizontal rig counts increased from
283 as of December 27, 2002 to 912 as of December 26,
2008, which accounted for 33% and 53% of the total U.S. rig
count, respectively. The directional and horizontal rig count
also decreased to 692 as of February 27, 2009. The offshore
Gulf of Mexico rig count was 51 rigs at February 27, 2009
from 58 at February 28, 2008.
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 our
Oilfield Service and Rental Services segment will suffer
significantly in 2009, due to the drop in U.S. rig count
and the reduction of our customers spending. We have
already taken steps in 2009 to reduce costs, including laying
off employees and closing unprofitable operating locations. Even
with these steps, our Oilfield Services segment may still
generate negative operating income in 2009 due to its focus in
the U.S. market. Although we expect our Rental Services
segment to be negatively impacted in a material fashion by the
industry wide reduction in drilling and completion activity, we
believe that our Rental Services segment will still generate
positive operating income, albeit on lower revenue and at
reduced margins. We anticipate our Drilling and Completion
segment will exceed 2008 results for both revenue and operating
income as we benefit from a full year of operations on rigs
acquired during 2008 and from the acquisition of BCH at the end
of 2008. Our Drilling and Completion segment primarily operates
in Argentina and Brazil, but we have two rigs coming into
service in 2009 in the U.S. market. Currently, we have no
firm commitments of work for our U.S. rigs, so the impact
of revenue and operating income from these rigs may be
insignificant. BCH is a relatively new company and has not yet
attained the levels of profitability we have forecasted.
32
We expect to incur less general and administrative expenses in
2009 as we reduce our administrative staffs to reflect the
decline in activity. 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 2009. In
addition, the interest rate on our credit facilities may
increase if we violate any of our financial covenants in 2009.
We anticipate that our effective tax rate will increase in 2009
due to a lower taxable income to spread the negative effects of
non-deductible items and state income taxes. This rate could
exceed 50.0% for U.S. tax purposes in 2009. In addition,
the favorable tax rates we realized in 2008 from our
international operations due to foreign currency fluctuations,
may not be realized in 2009.
The sustainability and future growth in our operating income is
principally dependent on our level of revenues and the pricing
environment of our services. In addition, our sustainability and
the 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. Recent declines in both natural gas and oil
prices have caused our customers to delay or curtail capital
spending plans. In addition to the impact of the decline in
natural gas prices on our customers capital expenditures
and overall liquidity, the recent credit crisis has limited the
availability of funds, which lead to decreased capital
expenditures for our customers. The shortage of liquidity and
credit combined with recent substantial losses in worldwide
equity markets could lead to an extended global recession. The
slowdown in economic activity caused by the recession has
reduced demand for energy and resulted in lower oil and natural
gas prices. Such a continued slowdown in economic activity could
have a material adverse effect on our revenue and profitability.
We are monitoring the credit worthiness of our customers, as
well as outstanding receivables, in light of the current credit
crisis and as such increased our reserve for doubtful accounts
significantly at December 31, 2008, but further reserves
may be necessary in 2009.
We continue to monitor the effect of the global financial crisis
on our industry, and the resulting impact on the capital
spending budgets of our customers in order to estimate the
effect on our company. We have already reduced our planned
capital spending significantly in 2009 compared to 2008. We
currently expect that 2009 capital expenditures will total
approximately $75.0 million compared to 2008 capital
expenditures of $154.5 million. We believe that 2009 will
be an extremely challenging year for our operations but we are
optimistic that our cost saving cuts, coupled with our strategy
of striving to mitigate cyclical risk through our international
growth, by offering new equipment and technology to our
customers and our focus on the U.S. land shale plays, will
carry us through the current recession.
Results
of Operations
In April 2006, we acquired all of the outstanding stock of
Rogers and in October 2006, we acquired all of the outstanding
stock of Petro Rentals, and the results for the operations of
both acquired companies are included in our Oilfield Services
segment. In August 2006, we acquired all of the outstanding
stock of DLS and in December 2006, we acquired all of the
outstanding stock of Tanus. We report the operations of DLS and
Tanus in our Drilling and Completion segment. In January 2006,
we acquired all of the outstanding stock of Specialty and in
December 2006, we acquired substantially all of the assets of
OGR. We report the operations of Specialty and OGR in our Rental
Services segment.
In 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 will be 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.
33
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, 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 30.7% to $446.2 million, or 66.0% of revenues,
compared to $341.5 million, or 59.8%, 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 24.4% 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 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 that 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
34
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 $60.0 million for
the year ended December 31, 2008 compared to
$58.6 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 8.9% in 2008 compared to 10.3%
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.
In accordance with FASB No. 142, 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 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 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 a 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
35
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 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
36
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.
Comparison
of Years Ended December 31, 2007 and December 31,
2006
Our revenues for the year ended December 31, 2007 were
$571.0 million, an increase of 83.6% compared to
$311.0 million for the year ended December 31, 2006.
Revenues increased in all of our business segments due
principally to the acquisitions completed during the two year
period ended December 31, 2007, the investment in new
equipment and the opening of new operating locations. The most
significant increase in revenues was due to the acquisition of
DLS on August 14, 2006 which established our Drilling and
Completion segment. The Drilling and Completion segment
generated $215.8 million in revenues for the twelve months
ended December 31, 2007 compared to $69.5 million for
the period from the date of the DLS acquisition to
December 31, 2006. Revenues also increased significantly at
our Rental Services segment due to the acquisition of the OGR
assets on December 18, 2006. The OGR assets, including its
two rental yards, expanded our assets available for rent. The
OGR assets generated revenues of $82.2 million for the
twelve months ended December 31, 2007 compared to
$2.1 million for the period from the date of acquisition of
the OGR assets to December 31, 2006. We experienced a
decline in demand at our Rental Services segment in the last
half of 2007 due to a reduction of drilling activity in the
U.S. Gulf of Mexico as rigs departed the U.S. Gulf in
favor of the international markets. Our Oilfield Services
segment revenues increased in the 2007 period compared to the
2006 period due to acquisitions completed in the third and
fourth quarters of 2007 which added downhole motors, 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
acquisition of Petro-Rentals in October 2006 and the purchase of
additional equipment, principally new compressor packages for
our underbalanced operations, 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
$3.1 million in revenues from the date of acquisition to
December 31, 2007. The Petro-Rentals acquisition and
additional coil tubing equipment provided an additional
$20.6 million in revenues for the year ended
December 31, 2007 compared to 2006. These gains in revenues
were partly offset by a reduction of $6.7 million in
revenues from our capillary assets compared to 2006 as the
assets were sold on June 29, 2007.
Our direct costs for the year ended December 31, 2007
increased 84.0% to $341.5 million, or 59.8% of revenues,
compared to $185.6 million, or 59.7%, of revenues for the
year ended December 31, 2006. The increase in direct costs
is due to the increase in revenues in all of our business
segments.
Depreciation expense increased 151.3% to $50.9 million for
the year ended December 31, 2007 from $20.3 million
for the year ended December 31, 2006. The primary increase
in depreciation expense is due to the acquisitions of the OGR
assets, DLS and Petro-Rentals and our capital expenditures. The
increase in our depreciation expense related to the OGR assets
was $15.9 million to $16.6 million for the year ended
December 31, 2007 compared to $650,000 for the period from
the date of the acquisition of the OGR assets to
December 31, 2006. Depreciation expense for DLS increased
$7.2 million to $11.3 million for the year ended
December 31, 2007 from $4.1 million for the period
from the date of acquisition of DLS to December 31, 2006.
Depreciation expense for Petro-Rentals for the year ended
December 31, 2007 was $3.6 million compared to
$688,000 for the period from the date of acquisition of
Petro-Rentals to December 31, 2006.
General and administrative expense was $58.6 million for
the year ended December 31, 2007 compared to
$35.5 million for the year ended December 31, 2006.
General and administrative expense increased due to the
acquisitions, and the hiring of additional sales, operations,
accounting and administrative personnel. As a percentage of
revenues, general and administrative expenses were 10.3% in 2007
compared to 11.4% in 2006. General and administrative expense
includes share-based compensation expense of $4.7 million
in 2007 and $3.0 million in 2006.
37
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.
Amortization expense was $4.1 million for the year ended
December 31, 2007 compared to $1.9 million for the
year ended December 31, 2006. The increase in amortization
expense is primarily due to the amortization of intangible
assets in connection with our acquisition of the OGR assets,
which increased $2.2 million to $2.3 million for the
year ended December 31, 2007 compared to $96,000 for the
period from the date of the acquisition of the OGR assets to
December 31, 2006.
Income from operations for the year ended December 31, 2007
totaled $124.8 million, an 84.2% increase over the
$67.7 million in income from operations for the year ended
December 31, 2006, reflecting the increase in our revenues
of $260.0 million, offset in part by increased direct costs
of $155.9 million, increased general and administrative
expense of $23.1 million and increased amortization expense
of $2.2 million. Our income from operations as a percentage
of revenues increased slightly to 21.9% in 2007 from 21.8% in
2006. Income from operations in the 2007 period includes an
$8.9 million gain from the sale of our capillary tubing
assets in the second quarter of 2007.
Our net interest expense was $46.3 million for the year
ended December 31, 2007, compared to $20.3 million for
the year ended December 31, 2006. Interest expense
increased in 2007 due to our increased debt. In August 2006 we
issued $95.0 million of senior notes bearing interest at
9.0% to fund a portion of the acquisition of DLS. In January
2007 we issued $250.0 million of senior notes bearing
interest at 8.5% to pay off, in part, the $300.0 million
bridge loan utilized to complete the OGR acquisition and for
working capital. This bridge loan was repaid on January 29,
2007. The average interest rate on the bridge loan was
approximately 10.6%. Interest expense for 2007 includes the
write-off of deferred financing fees of $1.2 million
related to the repayment of the bridge loan. Interest expense
includes amortization expense of deferred financing costs of
$1.9 million and $1.5 million for 2007 and 2006,
respectively.
Our income tax expense for the year ended December 31, 2007
was $28.8 million, or 36.4% of our net income before income
taxes, compared to $11.4 million, or 24.3% of our net
income before income taxes for 2006. The increase in our income
tax expense is attributable to the increase in our operating
income and a higher effective tax rate. The effective tax rate
in 2006 was favorably impacted by the reversal of our valuation
allowance on our deferred tax assets. The valuation allowance
was reversed due to operating results that allowed for the
realization of our deferred tax assets.
We had net income of $50.4 million for the year ended
December 31, 2007, an increase of 41.6%, compared to net
income of $35.6 million for the year ended
December 31, 2006.
The following table compares revenues and income from operations
for each of our business segments for the years ended
December 31, 2007 and December 31, 2006. Income from
operations consists of our revenues and gain on asset
disposition less direct costs, general and administrative
expenses, depreciation and amortization:
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Revenues
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Income (Loss) from Operations
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2007
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2006
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Change
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2007
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2006
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Change
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(In thousands)
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Oilfield Services
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$
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233,986
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$
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189,953
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$
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44,033
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$
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53,218
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$
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43,157
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$
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10,061
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Drilling & Completion
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215,795
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69,490
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146,305
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38,839
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12,233
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26,606
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Rental Services
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121,186
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51,521
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69,665
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49,139
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26,293
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22,846
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General Corporate
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(16,414
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(13,953
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(2,461
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Total
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$
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570,967
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$
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310,964
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$
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260,003
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$
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124,782
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$
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67,730
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$
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57,052
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Oilfield Services. Revenues for the year ended
December 31, 2007 for our Oilfield Services segment were
$234.0 million, an increase of 23.2% from the
$190.0 million in revenues for the year ended
December 31, 2006. The increase in revenues is due to the
purchase of additional MWD tools, new compressors and new
foam units for our underbalanced drilling operations
and the benefit of acquisitions
38
completed in the last half of 2007 which added downhole motors,
MWDs, and directional drillers and the acquisition of
Petro-Rentals completed in the last half of 2006. 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
$3.1 million of revenues from the date of acquisition to
December 31, 2007. Income from operations increased 23.3%
to $53.2 million for 2007 from $43.2 million for 2006.
Income from operations as a percentage of revenues remained
constant at 22.7%. Income from operations in the 2007 period
includes an $8.9 million gain on sale of our capillary
tubing assets.
Drilling and Completion. On August 14,
2006, we acquired DLS which established our Drilling and
Completion segment. Our Drilling and Completion revenues were
$215.8 million for the year ended December 31, 2007,
an increase from the $69.5 million in revenues for the
period from the date of the DLS acquisition until
December 31, 2006. Income from operations increased to
$38.8 million in 2007 compared to $12.2 million from
the date of the DLS acquisition until December 31, 2006.
Income from operations as percentage of revenue increased to
18.0% for 2007 compared to 17.6% for 2006. We believe the
increase in the percentage was primarily due to the price
increases implemented in 2007. During 2007 we placed orders for
16 service rigs (workover rigs and pulling rigs) and four
drilling rigs. Four of the service rigs were delivered in the
fourth quarter of 2007.
Rental Services. Our Rental Services revenues
were $121.2 million for the year ended December 31,
2007, an increase of 135.2% from the $51.5 million in
revenues for the year ended December 31, 2006. Income from
operations increased 86.9% to $49.1 million in 2007
compared to $26.3 million in 2006. The increase in revenue
and operating income is primarily attributable to the
acquisition of the OGR assets in December 2006. The OGR assets,
including its two rental yards, expanded our assets available
for rent. We generated $82.2 million for the twelve months
ended December 31, 2007 compared to $2.1 million for
the period from the date of acquisition of the OGR assets to
December 31, 2006. Income from operations as a percentage
of revenues decreased to 40.5% for 2007 compared to 51.0% for
the prior year as a result of higher depreciation expense
associated with the OGR acquisition and capital expenditures.
Our depreciation expense for the OGR assets increased
$15.9 million to $16.6 million for the year ended
December 31, 2007 compared to $650,000 for the period from
the date of acquisition of the OGR assets to December 31,
2006. Rental Services revenues and operating income was impacted
by a more competitive market environment due to the decreased
U.S. Gulf of Mexico drilling activity in the last half of
2007 attributed to the hurricane season and the departure of
drilling rigs in favor of the international markets.
Liquidity
and Capital Resources
Our on-going capital requirements arise primarily from our need
to service our debt, to acquire and maintain equipment, to fund
our working capital requirements and to complete acquisitions.
Our primary sources of liquidity are proceeds from the issuance
of debt and equity securities and cash flows from operations.
Our amended and restated revolving credit facility permits
borrowings of up to $90.0 million in principal amount. As
of December 31, 2008, we had $47.7 million available
for borrowing under our amended and restated revolving credit
facility. We also have up to $29.0 million available under
a new credit agreement which we executed in February 2009 to
fund a portion of the purchase price of two drilling rigs. Cash
flows from operations are expected to be our primary source of
liquidity in fiscal 2009. We had cash and cash equivalents of
$6.9 million at December 31, 2008 compared to
$43.7 million at December 31, 2007.
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
early 2009, the expectation of additional decreases in the
U.S. rig count, and the resulting decrease in demand for
our services adversely impacts our ability to maintain or meet
such financial ratios.
39
We have reduced our planned capital spending for 2009 compared
to 2008. Exclusive of any opportunistic acquisitions, we
currently expect to spend a total of approximately
$66.0 million in 2009, which is net of equipment deposits
paid in 2008. As of December 31, 2008, we had commitments
covering $41.4 million of the $66.0 million. We
believe that our cash generated from operations, cash on hand
and cash available under our credit facilities will provide
sufficient funds for our identified projects. 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, many of which are
beyond our control.
Operating
Activities
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 as
required under SFAS No. 123R, $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 tax 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 as
required under SFAS No. 123R, $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 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.
40
In the year ended December 31, 2006, we generated
$53.7 million in cash from operating activities. Our net
income for the year ended December 31, 2006 was
$35.6 million. Non-cash additions to net income totaled
$27.6 million in the 2006 period consisting primarily of
$22.1 million of depreciation and amortization,
$3.4 million related to the expensing of stock options as
required under SFAS No. 123R, $2.2 million of
deferred income tax, $781,000 for bad debts and
$1.5 million for amortization of finance fees, including
the bridge loan fees, partially offset by $2.4 million of
gain from the disposition of equipment.
During the year ended December 31, 2006, changes in working
capital used $9.9 million in cash, principally due to an
increase of $23.2 million in accounts receivable, an
increase of $2.6 million in inventories, a decrease of
$2.3 million in accounts payable, offset in part by a
decrease in other current assets of $2.5 million, an
increase of $11.4 million in accrued interest, an increase
of $3.4 million in accrued employee benefits and payroll
taxes and an increase of $872,000 in accrued expenses. Our
accounts receivables increased at December 31, 2006
primarily due to the increase in our revenues in 2006. Accrued
interest increased at December 31, 2006 due principally to
interest accrued on our 9.0% senior notes, which are
payable semi-annually. Our accrued employee benefits and payroll
taxes and other accrued expenses increased primarily due to the
increase in costs due to our growth in revenues and acquisition
completed in 2006.
Investing
Activities
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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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.
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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
41
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.
During the year ended December 31, 2006, we used
$559.4 million in investing activities consisting of six
acquisitions and our capital expenditures. During the year ended
December 31, 2006, we completed the following acquisitions
for a total net cash outlay of $526.6 million, consisting
of the purchase price and acquisition costs less cash acquired:
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Effective January 1, 2006, we acquired Specialty for a
purchase price of approximately $95.3 million in cash.
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Effective April 1, 2006, we acquired Rogers for a purchase
price of approximately $11.3 million in cash,
125,285 shares of our common stock and a promissory note
for $750,000.
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On August 14, 2006, we acquired DLS for a purchase price of
approximately $93.7 million in cash, 2.5 million
shares of our common stock and the assumption of
$9.1 million of indebtedness.
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On October 16, 2006, we acquired Petro Rentals for a
purchase price of approximately $20.2 million in cash,
246,761 shares of our common stock and the payment of
approximately $9.6 million of debt.
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Effective December 1, 2006, we acquired Tanus for a
purchase price of $2.5 million in cash.
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On December 18, 2006, we acquired substantially all of the
assets of OGR for a purchase price of approximately
$291.0 million in cash and 3.2 million shares of our
common stock.
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In addition we made capital expenditures of approximately
$39.7 million during the year ended December 31, 2006,
including $29.1 million to purchase and upgrade equipment
for our Oilfield Services segment, $5.8 million to
purchase, improve and replace equipment in our Drilling and
Completion segment and $4.5 million to replace
lost-in-hole
equipment and to increase our inventory of equipment in the
Rental Services segment. We also received $6.9 million from
the sale of assets during the year ended December 31, 2006,
comprised mostly from equipment
lost-in-hole
from our Rental Services segment ($3.8 million) and our
Oilfield Services segment ($1.8 million).
Financing
Activities
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.
During the year ended December 31, 2006, financing
activities provided a net of $543.6 million in cash. We
received $557.8 million in borrowings under long-term debt
facilities, consisting primarily of the issuance of
$255.0 million of our 9.0% senior notes due 2014 and a
$300.0 million senior unsecured bridge loan. The bridge
loan, which was repaid on January 29, 2007, was used to
fund the acquisition of substantially all the
42
assets of OGR. We also received $46.3 million in net
proceeds from the issuance of 3,450,000 shares of our
common stock, $6.4 million on the tax benefit of options
and $6.3 million from the proceeds of warrant and option
exercises with 1,851,377 shares of our common stock being
issued under our equity compensation plans. The proceeds were
used to repay long-term debt totaling $54.0 million, repay
$6.4 million in net borrowings under our revolving credit
facility, repay related party debt of $3.0 million and to
pay $9.9 million in debt issuance costs.
On January 18, 2006 and August 14, 2006, we closed on
private offerings, to qualified institutional buyers pursuant to
Rule 144A under the Securities Act, of $160.0 million
and $95.0 million aggregate principal amount of our senior
notes, respectively. The senior notes are due January 15,
2014 and bear interest at 9.0%. The proceeds were used to fund
the acquisitions of Specialty and DLS, to repay existing debt
and for general corporate purposes. Debt repaid included all
outstanding balances under our credit agreement, including a
$42.1 million term loan and $6.4 million in working
capital advances, a $4.0 million subordinated note issued
in connection with acquisition of AirComp, approximately
$3.0 million subordinated note issued in connection with
the acquisition of Tubular, approximately $548,000 on a real
estate loan and approximately $350,000 on outstanding equipment
financing.
On December 18, 2006, we closed on a $300.0 million
senior unsecured bridge loan. The bridge loan was due
18 months after closing and had a weighted average interest
rate of 10.6%. The bridge loan, which was repaid on
January 29, 2007, was used to fund the acquisition of
substantially all the assets of OGR.
In January 2007, we closed on a private offering, to qualified
institutional buyers pursuant to Rule 144A under the
Securities Act, of $250.0 million principal amount of
8.5% senior notes due 2017. The proceeds of the senior
notes offering, together with a portion of the proceeds of our
concurrent common stock offering, were used to repay the debt
outstanding under our $300.0 million bridge loan facility
which we incurred to finance our acquisition of substantially
all the assets of OGR.
On January 18, 2006, we also executed an amended and
restated credit agreement which provides for a
$25.0 million revolving line of credit with a maturity of
January 2010. On April 26, 2007, we entered into a Second
Amended and Restated Credit Agreement, which increased our
revolving line of credit to $62.0 million, and has a final
maturity date of April 26, 2012. On December 3, 2007,
we entered into a First Amendment to Second Amended and Restated
Credit Agreement, which increased our revolving line of credit
to $90.0 million. The amended and restated credit agreement
contains customary events of default and financial covenants and
limits our ability to incur additional indebtedness, make
capital expenditures, pay dividends or make other distributions,
create liens and sell assets. Our obligations under the amended
and restated credit agreement are secured by substantially all
of our assets located in the U.S. The credit agreement loan
rates are based on prime or LIBOR plus a margin. We were in
compliance with all debt covenants as of December 31, 2008
and 2007. The weighted average interest rate was 4.6% at
December 31, 2008. As of December 31, 2008 and 2007,
amounts borrowed under the facility were $36.5 million and
$0 and availability was reduced by outstanding letters of credit
of $5.8 million and $8.4 million, respectively.
As part of our acquisition of DLS, we assumed various bank loans
with floating interest rates based on LIBOR plus a margin and
terms ranging from two to five years. The weighted average
interest rates on these loans was 5.1% and 6.7% at
December 31, 2008 and 2007, respectively. The bank loans
are denominated in U.S. dollars and the outstanding amount
due as of December 31, 2008 and 2007 was $2.5 million
and $4.9 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 facility was available for borrowings until
December 31, 2008. Each drawdown shall be repaid 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, 2008. The bank loan rates are based on LIBOR
plus a margin. The weighted average interest rate was 6.9% at
43
December 31, 2008. The bank loans are denominated in
U.S. dollars and the outstanding amount as of
December 31, 2008 was $25.0 million.
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, 2008. The credit facility loan is denominated
in U.S. dollars and interest rates are based on LIBOR plus
a margin. At December 31, 2008, the outstanding balance was
$22.1 million and the interest rate was 6.0%.
In connection with the acquisition of Rogers, we issued to the
seller a note in the amount of $750,000. The note bears interest
at 5.0% and is due April 3, 2009. In connection with the
purchase of Coker, we issued to the seller a note in the amount
of $350,000. The note bore interest at 8.25% and was repaid in
June 2008. In connection with the purchase of Diggar, we issued
to the seller a note in the amount of $750,000. The note bore
interest at 6.0% and was repaid in July 2008. In connection with
the purchase of Rebel, we issued to the sellers notes in the
amount of $500,000. The notes bore interest at 5.0% and were
repaid in October 2008.
In connection with the purchase of Capcoil, we agreed to pay a
total of $500,000 to two management employees in exchange for
non-compete agreements. We were required to make annual payments
of $110,000 through May 2008. Total amounts due under these
non-compete agreements at December 31, 2008 and 2007 were
$0 and $110,000, respectively.
In 2000 we compensated directors, including current directors
Nederlander and Toboroff, who served on the board of directors
from 1989 to March 31, 1999 without compensation, by
issuing promissory notes totaling $325,000. The notes bear
interest at the rate of 5.0%. At December 31, 2008 and
2007, the principal and accrued interest on these notes totaled
approximately $32,000.
We have various rig and equipment financing loans with interest
rates ranging from 8.3% to 8.7% and terms of 2 to 5 years.
As of December 31, 2008 and 2007, the outstanding balances
for rig and equipment financing loans were $0 and $595,000,
respectively.
In April 2007 and August 2007, we obtained insurance premium
financings in the aggregate amount of $4.4 million with a
fixed weighted average interest rate of 5.9%. 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 $1.7 million as of
December 31, 2008 and 2007, 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 $991,000 at December 31, 2008.
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 $779,000 at December 31,
2008. We also had other capital leases with terms that expired
in 2008. As of December 31, 2007, amounts outstanding under
capital leases were $14,000.
44
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments by Period
|
|
|
|
|
|
|
Less Than
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1 Year
|
|
|
1-3 Years
|
|
|
3-5 Years
|
|
|
After 5 Years
|
|
|
|
(In thousands)
|
|
|
Contractual Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
592,882
|
|
|
$
|
14,026
|
|
|
$
|
24,318
|
|
|
$
|
49,538
|
|
|
$
|
505,000
|
|
Capital leases(a)
|
|
|
779
|
|
|
|
591
|
|
|
|
188
|
|
|
|
|
|
|
|
|
|
Interest payments on long-term debt
|
|
|
301,497
|
|
|
|
48,687
|
|
|
|
95,026
|
|
|
|
89,536
|
|
|
|
68,248
|
|
Operating leases
|
|
|
9,486
|
|
|
|
2,888
|
|
|
|
3,843
|
|
|
|
1,720
|
|
|
|
1,035
|
|
Purchase obligations
|
|
|
41,400
|
|
|
|
41,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employment contracts
|
|
|
4,853
|
|
|
|
2,800
|
|
|
|
2,053
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual cash obligations
|
|
$
|
950,897
|
|
|
$
|
110,392
|
|
|
$
|
125,428
|
|
|
$
|
140,794
|
|
|
$
|
574,283
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
These amounts represent our minimum capital lease obligations,
net of interest payments totaling $86,000. |
Recent
Developments
In February 2009, we entered into a new credit agreement in an
amount up to $29.0 million. The credit agreement is subject
to customary closing conditions, with the proceeds being used to
fund 80% of the purchase price of two land drilling rigs
and related equipment that are scheduled for delivery in the
second quarter of 2009. The loan will be secured by the
equipment and will be repaid in quarterly installments over six
years from the funding date.
We expect to utilize the two land drilling rigs for an existing
client operating in the Haynesville Shale under a long-term
alliance which would include other services that we would
provide. We have suspended the construction of two other land
drilling rigs which were ordered in the summer of 2008.
In February 2009, we executed a joint venture agreement with
Rawabi Holding Company Ltd., or Rawabi, under the laws of the
Kingdom of Saudi Arabia. The purpose of the joint venture is to
provide oilfield services and rental equipment in the Kingdom of
Saudi Arabia. We will own 50% of the joint venture.
As a result of the economic environment and the decrease in the
U.S. rig count in 2009, in February of 2009 we announced
cost reduction steps which include a reduction in the
U.S. workforce of approximately 235 people, reduction
of certain day rates paid to personnel, reduction or
consolidation of certain operating yards and reduction of
employee benefits. Additional workforce reductions and other
cost saving measures are anticipated. Capital expenditures for
2009 will be limited to required maintenance levels and those
related to firm commitments made in 2008.
Critical
Accounting Policies
We have identified the policies below as critical to our
business operations and the understanding of our results of
operations. The impact and any associated risks related to these
policies on our business operations is discussed throughout
Managements Discussion and Analysis of Financial Condition
and Results of Operations where such policies affect our
reported and expected financial results. For a detailed
discussion on the application of these and other accounting
policies, see Note 1 in the Notes to the Consolidated
Financial Statements included elsewhere in this document. Our
preparation of this report requires us to make estimates and
assumptions that affect the reported amount of assets and
liabilities, disclosure of contingent assets and liabilities at
the date of our financial statements, and the reported amounts
of revenue and expenses during the reporting period. There can
be no assurance that actual results will not differ from those
estimates.
45
Allowance For Doubtful Accounts. The
determination of the collectibility of amounts due from our
customers requires us to use estimates and make judgments
regarding future events and trends, including monitoring our
customer payment history and current credit worthiness to
determine that collectibility is reasonably assured, as well as
consideration of the overall business climate in which our
customers operate. Those uncertainties require us to make
frequent judgments and estimates regarding our customers
ability to pay amounts due us in order to determine the
appropriate amount of valuation allowances required for doubtful
accounts. Provisions for doubtful accounts are recorded when it
becomes evident that the customers will not be able to make the
required payments at either contractual due dates or in the
future.
Revenue Recognition. We provide rental
equipment and drilling services to our customers at per day, 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 or
whenever events or changes in circumstances indicate that the
carrying amounts may not be recoverable. An impairment loss is
recorded in the period in which it is determined that the
carrying amount is not recoverable. This requires us to make
long-term forecasts of our future revenues and costs related to
the assets subject to review. These forecasts require
assumptions about demand for our products and services, future
market conditions and technological developments. Significant
and unanticipated changes to these assumptions could require a
provision for impairment in a future period.
Goodwill And Other Intangibles. As of
December 31, 2008, we have recorded approximately
$43.3 million of goodwill and $37.4 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 finite live for amortization purposes.
We perform our annual impairment test in accordance with FASB
No. 142. Our tests included two approaches to
determine the carrying amount of the individual reporting units.
The first approach is the Discounted Cash Flow Method, which
focuses on our expected cash flow. In applying this approach,
the cash flow available for distribution is projected for a
finite period of years. Cash flow available for distribution is
defined as the amount of cash that could be distributed as a
dividend without impairing our future profitability or
operations. The cash flow available for distribution and the
terminal value (our value at the end of the estimation period)
are then discounted to present value to derive an indication of
value of the business enterprise. This valuation method is
dependent upon the assumptions made regarding future cash flow
and cash requirements. The second approach is the Guideline
Company Method which focuses on comparing us to selected
reasonably similar publicly traded companies. Under this method,
valuation multiples are: (i) derived from operating data of
selected similar companies; (ii) evaluated and adjusted
based on our strengths and weaknesses relative to the selected
guideline companies; and (iii) applied to our operating
data to arrive at an indication of value. This valuation method
is dependent upon the assumption that our value can be evaluated
by analysis of our earnings and our strengths and weaknesses
relative to the selected similar companies. We recorded an
impairment charge of $115.8 million in 2008 as a result of
our test. 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
46
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.
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. We provide for
uncertain tax positions pursuant to FASB Interpretation
No. 48, Accounting for Uncertainty in Income
Taxes an Interpretation of FASB Statement
No. 109.
It is our intention to permanently reinvest all of the
undistributed earnings of our
non-U.S. subsidiaries
in such subsidiaries. Accordingly, we have not provided for
U.S. deferred taxes on the undistributed earnings of our
non-U.S. subsidiaries.
If a distribution is made to us from the undistributed earnings
of these subsidiaries, we could be required to record additional
taxes. Because we cannot predict when, if at all, we will make a
distribution of these undistributed earnings, we are unable to
make a determination of the amount of unrecognized deferred tax
liability.
Recently
Issued Accounting Standards
In September 2006, the Financial Accounting Standards Board, or
FASB, issued Statement of Financial Accounting Standards
No. 157, Fair Value Measurements, or
SFAS No. 157. SFAS No. 157 clarifies the
principle that fair value should be based on the assumptions
that market participants would use when pricing an asset or
liability and establishes a fair value hierarchy that
prioritizes the information used to develop those assumptions.
Under the standard, fair value measurements would be separately
disclosed by level within the fair value hierarchy.
SFAS No. 157 is effective for financial statements
issued for fiscal years beginning after November 15, 2007,
and interim periods within those fiscal years, with early
adoption permitted. Subsequently, the FASB provided for a
one-year deferral of the provisions of SFAS No. 157
for non-financial assets and liabilities that are recognized or
disclosed at fair value in the consolidated financial statements
on a non-recurring basis. As allowed under
SFAS No. 157, we adopted all requirements of
SFAS No. 157 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 statements.
In February 2007, the FASB issued Statement of Financial
Accounting Standards No. 159, The Fair Value Option for
Financial Assets and Financial Liabilities, or
SFAS No. 159, which permits entities to elect to
measure many financial instruments and certain other items at
fair value. Upon adoption of SFAS No. 159, an entity
may elect the fair value option for eligible items that exist at
the adoption date. Subsequent to the initial adoption, the
election of the fair value option should only be made at the
initial recognition of the asset or liability or upon a
re-measurement event that gives rise to the new-basis of
accounting. All subsequent changes in fair value for that
instrument are reported in earnings. SFAS No. 159 does
not affect any existing accounting literature that requires
certain assets and liabilities to be recorded at fair value nor
does it eliminate disclosure requirements included in other
accounting standards. SFAS No. 159 is effective as of
the beginning of each reporting entitys first fiscal year
that begins after November 15, 2007. We adopted
SFAS No. 159 on January 1, 2008 and there was no
impact on our financial statements.
47
In December 2007, the FASB issued Statement of Financial
Accounting Standards No. 141 (revised 2007), Business
Combinations, or SFAS No. 141(R).
SFAS No. 141(R) changes the requirements for an
acquirers recognition and measurement of the assets
acquired and the liabilities assumed in a business combination.
Additionally, SFAS No. 141(R) requires that
acquisition-related costs, including restructuring costs, be
recognized as expense separately from the acquisition. We
adopted SFAS No. 141(R) on January 1, 2009 and
there was no impact on our financial statements.
In December 2007, the FASB issued Statement of Financial
Accounting Standards No. 160, Non-controlling Interests
in Consolidated Financial Statements an amendment of
ARB No. 51, or SFAS No. 160.
SFAS No. 160 requires (i) that non-controlling
(minority) interests be reported as a component of
shareholders equity, (ii) that net income
attributable to the parent and to the non-controlling interest
be separately identified in the consolidated statement of
operations, (iii) that changes in a parents ownership
interest while the parent retains its controlling interest be
accounted for as equity transactions, (iv) that any
retained non-controlling equity investment upon the
deconsolidation of a subsidiary be initially measured at fair
value, and (v) that sufficient disclosures are provided
that clearly identify and distinguish between the interests of
the parent and the interests of the non-controlling owners.
SFAS No. 160 is effective for annual periods beginning
after December 15, 2008 and should be applied
prospectively. The presentation and disclosure requirements of
the statement shall be applied retrospectively for all periods
presented. We adopted SFAS No. 160 on January 1,
2009 and there was no impact on our financial statements.
In March 2008, the FASB issued Statement of Financial Accounting
Standards No. 161, Disclosures about Derivative
Instruments and Hedging Activities an amendment of
FASB Statement No. 133, or SFAS No. 161.
SFAS No. 161 requires qualitative disclosures about
objectives and strategies for using derivatives, quantitative
data about the fair value of and gains and losses on derivative
contracts, and details of credit-risk-related contingent
features in hedged positions. The statement also requires
enhanced disclosures regarding how and why entities use
derivative instruments, how derivative instruments and related
hedged items are accounted and how derivative instruments and
related hedged items affect entities financial position,
financial performance, and cash flows. SFAS No. 161 is
effective for fiscal years beginning after November 15,
2008. We adopted SFAS No. 161 on January 1, 2009
and there was no impact on our financial statements.
In April 2008, the FASB issued FASB Staff Position
SFAS 142-3,
Determination of the Useful Life of Intangible Assets, or
FSP
SFAS 142-3.
FSP
SFAS 142-3
amends the factors that should be considered in developing
renewal or extension assumptions used to determine the useful
life of a recognized intangible asset under
SFAS No. 142. The objective of FSP
SFAS 142-3
is to improve the consistency between the useful life of a
recognized intangible asset under SFAS No. 142 and the
period of expected cash flows used to measure the fair value of
the asset under SFAS No. 141R, and other
U.S. GAAP principles. FSP
SFAS 142-3
is effective for fiscal years beginning after December 15,
2008. We adopted FSP
SFAS 142-3
on January 1, 2009 and there was no impact on our financial
statements.
Off-Balance
Sheet Arrangements
We have no off balance sheet arrangements, other than normal
operating leases and employee contracts, that have or are likely
to have a current or future material effect on our financial
condition, changes in financial condition, revenues, expenses,
results of operations, liquidity, capital expenditures or
capital resources. We have a $90.0 million revolving credit
facility with a maturity of April 2012. At December 31,
2008, $36.5 million was borrowed on the facility and
availability is further reduced by outstanding letters of credit
of $5.8 million. We do not guarantee obligations of any
unconsolidated entities.
48
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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, 2008, we were exposed to interest rate
fluctuations on approximately $86.1 million of bank loans
carrying variable interest rates. A hypothetical one hundred
basis point increase in interest rates for these notes payable
would increase our annual interest expense by approximately
$861,000. Due to the uncertainty of fluctuations in interest
rates and the specific actions that might be taken by us to
mitigate the impact of such fluctuations and their possible
effects, the foregoing sensitivity analysis assumes no changes
in our financial structure.
We have also been subject to interest rate market risk for
short-term invested cash and cash equivalents. The principal of
such invested funds would not be subject to fluctuating value
because of their highly liquid short-term nature. As of
December 31, 2008, we had no 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, 2008, 2007 and 2006, we had a net foreign
exchange loss of $1.2 million, $128,000 and $515,000,
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.
49
|
|
ITEM 8.
|
FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA.
|
INDEX TO
FINANCIAL STATEMENTS
ALLIS-CHALMERS
ENERGY INC. AND SUBSIDIARIES
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Page
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51
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52
|
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54
|
|
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|
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55
|
|
|
|
|
56
|
|
|
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57
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|
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58
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96
|
|
50
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, 2008, 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, 2008 has been audited by UHY
LLP, an independent registered public accounting firm, as stated
in their report, which is included herein.
Managements
Certifications
The certifications of Allis-Chalmers Chief Executive
Officer and Chief Financial Officer required by the
Sarbanes-Oxley Act of 2002 have been included as
Exhibits 31 and 32 in Allis-Chalmers
Form 10-K.
ALLIS-CHALMERS
ENERGY INC.
|
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By:
|
|
/s/ Munawar H. Hidayatallah
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By:
|
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/s/ Victor M. Perez
|
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Munawar H. Hidayatallah
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Victor Perez
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Chief Executive Officer
|
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Chief Financial Officer
|
51
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, 2008 and 2007, and
the related consolidated statements of operations,
stockholders equity and cash flows for each of the three
years in the period ended December 31, 2008. These
consolidated financial statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these consolidated financial statements and financial
statement schedule based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audits to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Allis-Chalmers Energy Inc. and
subsidiaries as of December 31, 2008 and 2007, and the
consolidated results of their operations and their cash flows
for each of the three years in the period ended
December 31, 2008, 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, 2008, 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,
2009 expressed an unqualified opinion thereon.
/s/ UHY LLP
Houston, Texas
March 9, 2009
52
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, 2008,
based on criteria established in Internal Control-Integrated
Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO criteria).
Allis-Chalmers Energy Inc.s management is responsible for
maintaining effective internal control over financial reporting,
and for its assessment of the effectiveness of internal control
over financial reporting included in the accompanying
Managements Report on Internal Control Over Financial
Reporting. Our responsibility is to express an opinion on the
Companys internal control over financial reporting based
on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting of Oversight Board (United States).
Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal
control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk
that a material weakness exists, testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk, and performing such other procedures as we
considered necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles and that receipts and expenditures of the company are
being made only in accordance with authorizations of management
and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, Allis-Chalmers Energy Inc. and subsidiaries
maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2008, 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, 2008 and 2007, and the
related consolidated statements of operations,
stockholders equity, and cash flows for each of the three
years in the period ended December 31, 2008, and our report
dated March 9, 2009 expressed an unqualified opinion
thereon.
/s/ UHY LLP
Houston, Texas
March 9, 2009
53
ALLIS-CHALMERS
ENERGY INC.
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except
|
|
|
|
for share and per share
|
|
|
|
amounts)
|
|
|
ASSETS
|
Cash and cash equivalents
|
|
$
|
6,866
|
|
|
$
|
43,693
|
|
Trade receivables, net of allowance for doubtful accounts of
$4,205 and $1,924 at December 31, 2008 and 2007,
respectively
|
|
|
157,871
|
|
|
|
130,094
|
|
Inventories
|
|
|
39,087
|
|
|
|
32,209
|
|
Deferred income tax asset
|
|
|
6,176
|
|
|
|
1,847
|
|
Prepaid expenses and other
|
|
|
15,238
|
|
|
|
10,051
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
225,238
|
|
|
|
217,894
|
|
Property and equipment, at cost net of accumulated depreciation
of $137,180 and $77,008 at December 31, 2008 and 2007,
respectively
|
|
|
760,990
|
|
|
|
626,668
|
|
Goodwill
|
|
|
43,273
|
|
|
|
138,398
|
|
Other intangible assets, net of accumulated amortization of
$9,251 and $6,218 at December 31, 2008 and 2007,
respectively
|
|
|
37,371
|
|
|
|
35,180
|
|
Debt issuance costs, net of accumulated amortization of $4,806
and $2,718 at December 31, 2008 and 2007, respectively
|
|
|
12,664
|
|
|
|
14,228
|
|
Other assets
|
|
|
31,522
|
|
|
|
21,217
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,111,058
|
|
|
$
|
1,053,585
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current maturities of long-term debt
|
|
$
|
14,617
|
|
|
$
|
6,434
|
|
Trade accounts payable
|
|
|
62,078
|
|
|
|
37,464
|
|
Accrued salaries, benefits and payroll taxes
|
|
|
20,192
|
|
|
|
15,283
|
|
Accrued interest
|
|
|
18,623
|
|
|
|
17,817
|
|
Accrued expenses
|
|
|
26,642
|
|
|
|
20,545
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
142,152
|
|
|
|
97,543
|
|
Deferred income tax liability
|
|
|
4,260
|
|
|
|
30,090
|
|
Long-term debt, net of current maturities
|
|
|
579,044
|
|
|
|
508,300
|
|
Other long-term liabilities
|
|
|
2,193
|
|
|
|
3,323
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
727,649
|
|
|
|
639,256
|
|
Commitments and Contingencies
|
|
|
|
|
|
|
|
|
Stockholders Equity
|
|
|
|
|
|
|
|
|
Preferred stock, $0.01 par value (25,000,000 shares
authorized, none issued)
|
|
|
|
|
|
|
|
|
Common stock, $0.01 par value (100,000,000 shares
authorized; 35,674,742 issued and outstanding at
December 31, 2008 and 35,116,035 issued and outstanding at
December 31, 2007)
|
|
|
357
|
|
|
|
351
|
|
Capital in excess of par value
|
|
|
334,633
|
|
|
|
326,095
|
|
Retained earnings
|
|
|
48,419
|
|
|
|
87,883
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
383,409
|
|
|
|
414,329
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
1,111,058
|
|
|
$
|
1,053,585
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated
Financial Statements.
54
ALLIS-CHALMERS
ENERGY INC.
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands, except per
|
|
|
|
share amounts)
|
|
|
Revenues
|
|
$
|
675,948
|
|
|
$
|
570,967
|
|
|
$
|
310,964
|
|
Operating costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs
|
|
|
446,235
|
|
|
|
341,450
|
|
|
|
185,579
|
|
Depreciation
|
|
|
63,460
|
|
|
|
50,914
|
|
|
|
20,261
|
|
General and administrative
|
|
|
59,953
|
|
|
|
58,622
|
|
|
|
35,536
|
|
Gain on asset dispositions
|
|
|
(166
|
)
|
|
|
(8,868
|
)
|
|
|
|
|
Impairment of goodwill
|
|
|
115,774
|
|
|
|
|
|
|
|
|
|
Amortization
|
|
|
4,212
|
|
|
|
4,067
|
|
|
|
1,858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
689,468
|
|
|
|
446,185
|
|
|
|
243,234
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(13,520
|
)
|
|
|
124,782
|
|
|
|
67,730
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(48,411
|
)
|
|
|
(49,534
|
)
|
|
|
(21,309
|
)
|
Interest income
|
|
|
5,617
|
|
|
|
3,259
|
|
|
|
972
|
|
Other
|
|
|
(563
|
)
|
|
|
776
|
|
|
|
(347
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(43,357
|
)
|
|
|
(45,499
|
)
|
|
|
(20,684
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(56,877
|
)
|
|
|
79,283
|
|
|
|
47,046
|
|
Income tax benefit (expense)
|
|
|
17,413
|
|
|
|
(28,843
|
)
|
|
|
(11,420
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(39,464
|
)
|
|
$
|
50,440
|
|
|
$
|
35,626
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(1.13
|
)
|
|
$
|
1.48
|
|
|
$
|
1.73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
(1.13
|
)
|
|
$
|
1.45
|
|
|
$
|
1.66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
35,052
|
|
|
|
34,158
|
|
|
|
20,548
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
35,052
|
|
|
|
34,701
|
|
|
|
21,410
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated
Financial Statements.
55
ALLIS-CHALMERS
ENERGY INC.
CONSOLIDATED
STATEMENT OF STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital in
|
|
|
Retained
|
|
|
Total
|
|
|
|
Common Stock
|
|
|
Excess of
|
|
|
Earnings
|
|
|
Stockholders
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Par Value
|
|
|
(Deficit)
|
|
|
Equity
|
|
|
|
(In thousands, except share amounts)
|
|
|
Balances, December 31, 2005
|
|
|
16,859,988
|
|
|
$
|
169
|
|
|
$
|
58,889
|
|
|
$
|
1,817
|
|
|
$
|
60,875
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35,626
|
|
|
|
35,626
|
|
Issuance of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions
|
|
|
6,072,046
|
|
|
|
61
|
|
|
|
94,919
|
|
|
|
|
|
|
|
94,980
|
|
Secondary public offering, net of offering costs
|
|
|
3,450,000
|
|
|
|
34
|
|
|
|
46,263
|
|
|
|
|
|
|
|
46,297
|
|
Issuance under stock plans
|
|
|
1,851,377
|
|
|
|
18
|
|
|
|
6,303
|
|
|
|
|
|
|
|
6,321
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
3,394
|
|
|
|
|
|
|
|
3,394
|
|
Tax benefits on stock plans
|
|
|
|
|
|
|
|
|
|
|
6,440
|
|
|
|
|
|
|
|
6,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2006
|
|
|
28,233,411
|
|
|
|
282
|
|
|
|
216,208
|
|
|
|
37,443
|
|
|
|
253,933
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50,440
|
|
|
|
50,440
|
|
Issuance of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Secondary public offering, net of offering costs
|
|
|
6,000,000
|
|
|
|
60
|
|
|
|
99,995
|
|
|
|
|
|
|
|
100,055
|
|
Issuance under stock plans
|
|
|
882,624
|
|
|
|
9
|
|
|
|
3,310
|
|
|
|
|
|
|
|
3,319
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
4,863
|
|
|
|
|
|
|
|
4,863
|
|
Tax benefits on stock plans
|
|
|
|
|
|
|
|
|
|
|
1,719
|
|
|
|
|
|
|
|
1,719
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2007
|
|
|
35,116,035
|
|
|
|
351
|
|
|
|
326,095
|
|
|
|
87,883
|
|
|
|
414,329
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated
Financial Statements.
56
ALLIS-CHALMERS
ENERGY INC.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Cash Flows from Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(39,464
|
)
|
|
$
|
50,440
|
|
|
$
|
35,626
|
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
67,672
|
|
|
|
54,981
|
|
|
|
22,119
|
|
Amortization and write-off of deferred financing fees
|
|
|
2,089
|
|
|
|
3,197
|
|
|
|
1,527
|
|
Impairment of goodwill
|
|
|
115,774
|
|
|
|
|
|
|
|
|
|
Stock-based compensation
|
|
|
7,902
|
|
|
|
4,863
|
|
|
|
3,394
|
|
Bad debt expense
|
|
|
3,283
|
|
|
|
1,309
|
|
|
|
781
|
|
Imputed interest
|
|
|
|
|
|
|
|
|
|
|
355
|
|
Deferred taxes
|
|
|
(29,949
|
)
|
|
|
8,017
|
|
|
|
2,215
|
|
Gain on sale of property and equipment
|
|
|
(1,762
|
)
|
|
|
(2,323
|
)
|
|
|
(2,444
|
)
|
Gain on asset dispositions
|
|
|
(166
|
)
|
|
|
(8,868
|
)
|
|
|
|
|
Changes in operating assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in accounts receivable
|
|
|
(27,499
|
)
|
|
|
(31,404
|
)
|
|
|
(23,175
|
)
|
Increase in inventories
|
|
|
(9,719
|
)
|
|
|
(5,375
|
)
|
|
|
(2,637
|
)
|
(Increase) decrease in prepaid expenses and other assets
|
|
|
(1,623
|
)
|
|
|
8,202
|
|
|
|
2,505
|
|
(Increase) decrease in other assets
|
|
|
1,224
|
|
|
|
(4,492
|
)
|
|
|
308
|
|
Increase (decrease) in trade accounts payable
|
|
|
21,903
|
|
|
|
10,732
|
|
|
|
(2,337
|
)
|
Increase in accrued interest
|
|
|
567
|
|
|
|
5,950
|
|
|
|
11,382
|
|
Increase in accrued expenses
|
|
|
1,131
|
|
|
|
1,508
|
|
|
|
872
|
|
Increase (decrease) in other liabilities
|
|
|
(1,130
|
)
|
|
|
2,700
|
|
|
|
(224
|
)
|
Increase in accrued salaries, benefits and payroll taxes
|
|
|
3,452
|
|
|
|
4,031
|
|
|
|
3,392
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
113,685
|
|
|
|
103,468
|
|
|
|
53,659
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions, net of cash acquired
|
|
|
(53,709
|
)
|
|
|
(41,000
|
)
|
|
|
(526,572
|
)
|
Net sales (purchases) of investment interests
|
|
|
1,374
|
|
|
|
(498
|
)
|
|
|
|
|
Purchases of property and equipment
|
|
|
(154,468
|
)
|
|
|
(113,151
|
)
|
|
|
(39,697
|
)
|
Deposits on asset commitments
|
|
|
(9,901
|
)
|
|
|
(11,488
|
)
|
|
|
|
|
Proceeds from sale of asset dispositions
|
|
|
3,000
|
|
|
|
16,250
|
|
|
|
|
|
Proceeds from sale of property and equipment
|
|
|
11,480
|
|
|
|
12,811
|
|
|
|
6,881
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(202,224
|
)
|
|
|
(137,076
|
)
|
|
|
(559,388
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of long-term debt
|
|
|
25,000
|
|
|
|
250,000
|
|
|
|
557,820
|
|
Payments on long-term debt
|
|
|
(9,905
|
)
|
|
|
(309,745
|
)
|
|
|
(54,030
|
)
|
Payments on related party debt
|
|
|
|
|
|
|
|
|
|
|
(3,031
|
)
|
Net (repayments) borrowings on lines of credit
|
|
|
36,500
|
|
|
|
|
|
|
|
(6,400
|
)
|
Proceeds from issuance of common stock, net of offering costs
|
|
|
|
|
|
|
100,055
|
|
|
|
46,297
|
|
Proceeds from exercise of options and warrants
|
|
|
633
|
|
|
|
3,319
|
|
|
|
6,321
|
|
Tax benefit on stock plans
|
|
|
9
|
|
|
|
1,719
|
|
|
|
6,440
|
|
Debt issuance costs
|
|
|
(525
|
)
|
|
|
(7,792
|
)
|
|
|
(9,863
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
51,712
|
|
|
|
37,556
|
|
|
|
543,554
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
(36,827
|
)
|
|
|
3,948
|
|
|
|
37,825
|
|
Cash and cash equivalents at beginning of year
|
|
|
43,693
|
|
|
|
39,745
|
|
|
|
1,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
6,866
|
|
|
$
|
43,693
|
|
|
$
|
39,745
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated
Financial Statements.
57
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,
Oklahoma, New Mexico, Colorado, Pennsylvania, Arkansas, offshore
in the Gulf of Mexico, and internationally, primarily in
Argentina, Brazil 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, 2008 are AirComp LLC (AirComp),
Allis-Chalmers Tubular Services LLC (Tubular),
Strata Directional Technology LLC (Strata),
Allis-Chalmers Rental Services LLC (Rental),
Allis-Chalmers Production Services LLC (Production),
Allis-Chalmers Management LLC, Allis-Chalmers Holdings Inc., DLS
Drilling, Logistics & Services Company
(DLS), DLS Argentina Limited, Tanus Argentina S.A.
(Tanus), Petro-Rentals LLC
(Petro-Rental), Rebel Rentals LLC
(Rebel), Allis-Chalmers Drilling LLC, BCH Ltd.
(BCH) and BCH Energy do Brasil Servicos de Petroleo
Ltda. All significant inter-company transactions have been
eliminated.
Revenue
Recognition
We provide rental equipment and drilling services to our
customers at per day, or daywork, and per job contractual rates
and recognize the drilling related revenue as the work
progresses and when collectibility is reasonably assured.
Revenue from daywork contracts is recognized when it is realized
or realizable and earned. On daywork contracts, revenue is
recognized based on the number of days completed at fixed rates
stipulated by the contract. For certain contracts, we receive
lump-sum and other fees for equipment and other mobilization
costs. Mobilization fees and the related costs are deferred and
amortized over the contract terms when material. We recognize
reimbursements received for out-of-pocket expenses incurred as
revenues and account for out-of-pocket expenses as direct costs.
Payments from customers for the cost of oilfield rental
equipment that is damaged or
lost-in-hole
are reflected as revenues. We recognized revenue from damaged or
58
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
lost-in-hole
equipment of $10.6 million, $12.6 million and
$2.4 million for the years ended December 31, 2008,
2007 and 2006, 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, 2008 and 2007, we
had recorded an allowance for doubtful accounts of
$4.2 million and $1.9 million respectively. Bad debt
expense was $3.3 million, $1.3 million and $781,000
for the years ended December 31, 2008, 2007 and 2006,
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 three to twenty years. Depreciation is
computed on the straight-line method for financial reporting
purposes. Capital leases are amortized using the straight-line
method over the estimated useful lives of the assets and lease
amortization is included in depreciation expense. Depreciation
expense charged to operations was $63.5 million,
$50.9 million and $20.3 million for the years ended
December 31, 2008, 2007 and 2006, respectively.
59
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. If the fair value of the reporting unit is
less than the book value (including goodwill) then goodwill is
reduced to its implied fair value and the amount of the
write-down is charged against earnings. We perform impairment
tests on the carrying value of our goodwill on an annual basis
as of December 31st for each of our reportable
segments. Historically, we have used the Discounted Cash Flow
method, which focuses on our expected cash flow. In applying
this approach, the cash flow available for distribution is
projected for a finite period of years, we use five years. The
cash flow available for distribution and the terminal value,
which is an estimate of the value at the end of the five years,
are then discounted to present value to derive an indication of
value of the business unit. For our annual assessment of
impairment for 2008, due to the economic conditions affecting
our industry, we also utilized the Guideline Company Method.
Under this method we make a comparison of our projections to
reasonably similar publicly traded companies. As a result we
recorded an impairment of $115.8 million at
December 31, 2008. At December 31, 2007, no impairment
was deemed necessary. Increases in estimated future costs or
decreases in projected revenues could lead to an impairment of
all or a portion of our goodwill in future period.
Impairment
of Long-Lived Assets
Long-lived assets, which include property, plant and equipment,
and other intangible assets, and certain other assets are
reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount may not be
recoverable. An impairment loss is recorded in the period in
which it is determined that the carrying amount is not
recoverable. The determination of recoverability is made based
upon the estimated undiscounted future net cash flows, excluding
interest expense. The impairment loss is determined by comparing
the fair value, as determined by a discounted cash flow
analysis, with the carrying value of the related assets.
Financial
Instruments
Financial instruments consist of cash and cash equivalents,
accounts receivable and payable, and debt. The carrying value of
cash and cash equivalents and accounts receivable and payable
approximate fair value due to their short-term nature. We
believe the fair values and the carrying value of our debt,
excluding the senior notes, would not be materially different
due to the instruments interest rates approximating market
rates for similar borrowings at December 31, 2008 and 2007.
Our senior notes, in the aggregate amount of $505 million,
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 $284 million
and $490 million at December 31, 2008 and 2007,
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.
60
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
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, 2008, we have approximately $782,000 and
$3.2 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, 2008 by a total of
$7.0 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 2008, 2007 and
2006, one of our customers, Pan American Energy LLC Sucursal
Argentina, or Pan American Energy, represented 28.5%, 20.7% and
11.7% of our consolidated revenues, respectively. Revenues from
Pan American Energy represented 62.0%, 51.0% and 45.6% of our
international revenues in 2008, 2007 and 2006, respectively (see
Note 13).
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 $2.1 million, $1.9 million and
$1.5 million for the years ended December 31, 2008,
2007 and 2006, 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. We provide for
uncertain tax positions pursuant to Financial Accounting
Standards Board, or FASB, Interpretation No. 48,
Accounting for Uncertainty in Income Taxes an
Interpretation of FASB Statement No. 109
(FIN 48). Our policy is that we recognize
interest and penalties accrued on any unrecognized tax benefits
as a component of income tax expense. As of the date of adoption
of FIN 48, we did not have any accrued interest or
penalties associated with any unrecognized tax benefits. For
U.S. federal tax purposes, our tax returns for the tax
years 2001 through 2007 remain open for
61
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
examination by the tax authorities. Our foreign tax returns
remain open for examination for the tax years 2001 through 2007.
Generally, for state tax purposes, our 2003 through 2007 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 $57.8 million of
undistributed earnings of our
non-U.S. subsidiaries
as of December 31, 2008. If a distribution is made to us
from the undistributed earnings of these subsidiaries, we could
be required to record additional taxes. Because we cannot
predict when, if at all, we will make a distribution of these
undistributed earnings, we are unable to make a determination of
the amount of unrecognized deferred tax liability.
Stock-Based
Compensation
We adopted Statement of Financial Accounting Standards
No. 123R, Share-Based Payment
(SFAS No. 123R), effective
January 1, 2006. This statement requires all share-based
payments to employees, including grants of employee stock
options, to be recognized in the financial statements based on
their grant-date fair values. We adopted SFAS No. 123R
using the modified prospective transition method, utilizing the
Black-Scholes option pricing model for the calculation of the
fair value of our employee stock options. Under the modified
prospective method, we record compensation cost related to
unvested stock awards as of December 31, 2005 by
recognizing the unamortized grant date fair value of these
awards over the remaining vesting periods of those awards with
no change in historical reported earnings. We estimated
forfeiture rates for 2008, 2007 and 2006 based on our historical
experience.
The Black-Scholes model incorporates assumptions to value
stock-based awards. The risk-free rate of interest is the
related U.S. Treasury yield curve for periods within the
expected term of the option at the time of grant. The dividend
yield on our common stock is assumed to be zero as we have
historically not paid dividends and have no current plans to do
so in the future. The expected volatility is based on historical
volatility of our common stock.
Our net income (loss) for the years ended December 31,
2008, 2007 and 2006 includes approximately $7.9 million,
$4.9 million and $3.4 million of compensation costs
related to share-based payments, respectively. The tax benefit
recorded in association with the share-based payments was
$9,000, $1.7 million and $6.4 million for the
years-ended December 31, 2008, 2007 and 2006, respectively.
As of December 31, 2008 there is $10.8 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 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Expected dividend yield
|
|
|
|
|
|
|
|
|
Expected price volatility
|
|
|
66.21
|
%
|
|
|
72.28
|
%
|
Risk-free interest rate
|
|
|
4.8
|
%
|
|
|
5.1
|
%
|
Expected life of options
|
|
|
5 years
|
|
|
|
7 years
|
|
Weighted average fair value of options granted at market value
|
|
$
|
12.86
|
|
|
$
|
10.58
|
|
62
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
Income
(Loss) Per Common Share
We compute income (loss) per common share in accordance with the
provisions of Statement of Financial Accounting Standards
No. 128, Earnings Per Share
(SFAS No. 128). SFAS No. 128
requires companies with complex capital structures to present
basic and diluted earnings per share. Basic earnings per share
are computed on the basis of the weighted average number of
shares of common stock outstanding during the period. Diluted
earnings per share is similar to basic earnings per share, but
presents the dilutive effect on a per share basis of potential
common shares (e.g., convertible preferred stock, stock options,
etc.) as if they had been converted. Restricted stock grants are
legally considered issued and outstanding, but are included in
basic and diluted earnings per share only to the extent that
they are vested. Unvested restricted stock is included in the
computation of diluted earnings per share using the treasury
stock method. Potential dilutive common shares that have an
anti-dilutive effect (e.g., those that increase income per
share) are excluded from diluted earnings per share.
The components of basic and diluted earnings (deficit) per share
are as follows (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(39,464
|
)
|
|
$
|
50,440
|
|
|
$
|
35,626
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding excluding nonvested
restricted stock
|
|
|
35,052
|
|
|
|
34,158
|
|
|
|
20,548
|
|
Effect of potentially dilutive common shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants and share based compensation shares
|
|
|
|
|
|
|
543
|
|
|
|
862
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding and assumed
conversions
|
|
|
35,052
|
|
|
|
34,701
|
|
|
|
21,410
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(1.13
|
)
|
|
$
|
1.48
|
|
|
$
|
1.73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
(1.13
|
)
|
|
$
|
1.45
|
|
|
$
|
1.66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Potentially dilutive securities excluded as anti-dilutive
|
|
|
1,041
|
|
|
|
1,108
|
|
|
|
53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants and share based compensation shares of approximately
332,000 were excluded in the computation of diluted earnings per
share for 2008 as the effect would have been anti-dilutive due
to the net loss for the year.
Segments
of an Enterprise and Related Information
We disclose the results of our segments in accordance with
Statement of Financial Accounting Standards No. 131,
Disclosures About Segments Of An Enterprise And Related
Information (SFAS No. 131). We
designate the internal organization that is used by management
for allocating resources and assessing performance as the source
of our reportable segments. SFAS No. 131 also requires
disclosures about products and services, geographic areas and
major customers. Please see Note 14 for further disclosure
of segment information in accordance with SFAS No. 131.
Reclassification
Certain prior period balances have been reclassified to conform
to current year presentation.
63
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
New
Accounting Pronouncements
In September 2006, the FASB, issued Statement of Financial
Accounting Standards No. 157, Fair Value Measurements,
or SFAS No. 157. SFAS No. 157 clarifies
the principle that fair value should be based on the assumptions
that market participants would use when pricing an asset or
liability and establishes a fair value hierarchy that
prioritizes the information used to develop those assumptions.
Under the standard, fair value measurements would be separately
disclosed by level within the fair value hierarchy.
SFAS No. 157 is effective for financial statements
issued for fiscal years beginning after November 15, 2007,
and interim periods within those fiscal years, with early
adoption permitted. Subsequently, the FASB provided for a
one-year deferral of the provisions of SFAS No. 157
for non-financial assets and liabilities that are recognized or
disclosed at fair value in the consolidated financial statements
on a non-recurring basis. As allowed under
SFAS No. 157, we adopted all requirements of
SFAS No. 157 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 statements.
In February 2007, the FASB issued Statement of Financial
Accounting Standards No. 159, The Fair Value Option for
Financial Assets and Financial Liabilities, or
SFAS No. 159, which permits entities to elect to
measure many financial instruments and certain other items at
fair value. Upon adoption of SFAS No. 159, an entity
may elect the fair value option for eligible items that exist at
the adoption date. Subsequent to the initial adoption, the
election of the fair value option should only be made at the
initial recognition of the asset or liability or upon a
re-measurement event that gives rise to the new-basis of
accounting. All subsequent changes in fair value for that
instrument are reported in earnings. SFAS No. 159 does
not affect any existing accounting literature that requires
certain assets and liabilities to be recorded at fair value nor
does it eliminate disclosure requirements included in other
accounting standards. SFAS No. 159 is effective as of
the beginning of each reporting entitys first fiscal year
that begins after November 15, 2007. We adopted
SFAS No. 159 on January 1, 2008 and there was no
impact on our financial statements.
In December 2007, the FASB issued Statement of Financial
Accounting Standards No. 141 (revised 2007), Business
Combinations, or SFAS No. 141(R).
SFAS No. 141(R) changes the requirements for an
acquirers recognition and measurement of the assets
acquired and the liabilities assumed in a business combination.
Additionally, SFAS No. 141(R) requires that
acquisition-related costs, including restructuring costs, be
recognized as expense separately from the acquisition. We
adopted SFAS No. 141(R) on January 1, 2009 and
there was no impact on our financial statements.
In December 2007, the FASB issued Statement of Financial
Accounting Standards No. 160, Non-controlling Interests
in Consolidated Financial Statements an amendment of
ARB No. 51, or SFAS No. 160.
SFAS No. 160 requires (i) that non-controlling
(minority) interests be reported as a component of
shareholders equity, (ii) that net income
attributable to the parent and to the non-controlling interest
be separately identified in the consolidated statement of
operations, (iii) that changes in a parents ownership
interest while the parent retains its controlling interest be
accounted for as equity transactions, (iv) that any
retained non-controlling equity investment upon the
deconsolidation of a subsidiary be initially measured at fair
value, and (v) that sufficient disclosures are provided
that clearly identify and distinguish between the interests of
the parent and the interests of the non-controlling owners.
SFAS No. 160 is effective for annual periods beginning
after December 15, 2008 and should be applied
prospectively. The presentation and disclosure requirements of
the statement shall be applied retrospectively for all periods
presented. We adopted SFAS No. 160 on January 1,
2009 and there was no impact on our financial statements.
In March 2008, the FASB issued Statement of Financial Accounting
Standards No. 161, Disclosures about Derivative
Instruments and Hedging Activities an amendment of
FASB Statement No. 133, or SFAS No. 161.
SFAS No. 161 requires qualitative disclosures about
objectives and strategies for using derivatives, quantitative
data about the fair value of and gains and losses on derivative
contracts, and details of credit-risk-related contingent
features in hedged positions. The statement also requires
enhanced disclosures
64
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
regarding how and why entities use derivative instruments, how
derivative instruments and related hedged items are accounted
and how derivative instruments and related hedged items affect
entities financial position, financial performance, and
cash flows. SFAS No. 161 is effective for fiscal years
beginning after November 15, 2008. We adopted
SFAS No. 161 on January 1, 2009 and there was no
material impact on our financial statements.
In April 2008, the FASB issued FASB Staff Position
SFAS 142-3,
Determination of the Useful Life of Intangible Assets, or
FSP
SFAS 142-3.
FSP
SFAS 142-3
amends the factors that should be considered in developing
renewal or extension assumptions used to determine the useful
life of a recognized intangible asset under FASB Statement of
Financial Accounting Standards No. 142, Goodwill and
Other Intangible Assets, or SFAS No. 142. The
objective of FSP
SFAS 142-3
is to improve the consistency between the useful life of a
recognized intangible asset under SFAS No. 142 and the
period of expected cash flows used to measure the fair value of
the asset under SFAS No. 141R, Business
Combinations, and other U.S. GAAP principles. FSP
SFAS 142-3
is effective for fiscal years beginning after December 15,
2008. We adopted FSP
SFAS 142-3
on January 1, 2009 and there was no impact on our financial
statements.
See also Note 6 Income Taxes for a discussion
of the FASBs Interpretation No. 48
Accounting for Uncertainty in Income Taxes.
|
|
NOTE 2
|
POST
RETIREMENT BENEFIT OBLIGATIONS
|
Medical
and Life
Pursuant to the Plan of Reorganization that was confirmed by the
Bankruptcy Court after acceptances by our creditors and
stockholders and was consummated on December 2, 1988, we
assumed the contractual obligation to Simplicity Manufacturing,
Inc. (SMI) to reimburse SMI for 50% of the actual cost of
medical and life insurance claims for a select group of retirees
(SMI Retirees) of the prior Simplicity Manufacturing Division of
Allis-Chalmers. The actuarial present value of the expected
retiree benefit obligation is determined by an actuary and is
the amount that results from applying actuarial assumptions to
(1) historical claims-cost data, (2) estimates for the
time value of money (through discounts for interest) and
(3) the probability of payment (including decrements for
death, disability, withdrawal, or retirement) between today and
expected date of benefit payments. As of December 31, 2008
and 2007, we have post-retirement benefit obligations of $0 and
$31,000, respectively.
401(k)
Savings Plan
On June 30, 2003, we adopted the 401(k) Profit Sharing Plan
(the Plan). The Plan is a defined contribution
savings plan designed to provide retirement income to our
eligible employees. The Plan is intended to be qualified under
Section 401(k) of the Internal Revenue Code of 1986, as
amended. It is funded by voluntary pre-tax contributions from
eligible employees who may contribute a percentage of their
eligible compensation, limited and subject to statutory limits.
The Plan is also funded by discretionary matching employer
contributions. Eligible employees cannot participate in the Plan
until they have attained the age of 21 and completed
three-months of service with us. Each participant is 100% vested
with respect to the participants contributions while our
matching contributions are vested over a three-year period in
accordance with the Plan document. Contributions are invested,
as directed by the participant, in investment funds available
under the Plan. Matching contributions of approximately
$1.5 million, $1.8 million and $735,000 were paid in
2008, 2007 and 2006, respectively.
65
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
NOTE 3
|
ACQUISITIONS
AND ASSET DISPOSITIONS
|
Effective January 1, 2006, we acquired 100% of the
outstanding stock of Specialty Rental Tools, Inc., or Specialty,
for approximately $95.3 million in cash. In addition,
approximately $588,000 of costs were incurred in relation to the
Specialty acquisition. Specialty, located in Lafayette,
Louisiana, was engaged in the rental of high quality drill pipe,
heavy weight spiral drill pipe, tubing work strings, blow-out
preventors, choke manifolds and various valves and handling
tools for oil and natural gas drilling. The following table
summarizes the allocation of the purchase price and related
acquisition costs to the estimated fair value of the assets
acquired and liabilities assumed at the date of acquisition (in
thousands):
|
|
|
|
|
Current assets
|
|
$
|
7,645
|
|
Property and equipment
|
|
|
90,622
|
|
|
|
|
|
|
Total assets acquired
|
|
|
98,267
|
|
|
|
|
|
|
Current liabilities
|
|
|
2,193
|
|
Long-term debt
|
|
|
74
|
|
|
|
|
|
|
Total liabilities assumed
|
|
|
2,267
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
96,000
|
|
|
|
|
|
|
Specialtys historical property and equipment values were
increased by approximately $71.6 million based on
third-party valuations. The results of Specialty since the
acquisition are included in our Rental Services segment.
Effective April 1, 2006, we acquired 100% of the
outstanding stock of Rogers Oil Tools, Inc., or Rogers, based in
Lafayette, Louisiana, for a total consideration of approximately
$13.7 million, which includes approximately
$11.3 million in cash, $1.6 million in our common
stock and a $750,000 three-year promissory note. In addition,
approximately $380,000 of costs were incurred in relation to the
Rogers acquisition. Rogers sells, services and rents power drill
pipe tongs and accessories and rental tongs for snubbing and
well control applications. Rogers also provides specialized tong
operators for rental jobs. The following table summarizes the
allocation of the purchase price and related acquisition costs
to the estimated fair value of the assets acquired and
liabilities assumed at the date of acquisition (in thousands):
|
|
|
|
|
Current assets
|
|
$
|
4,520
|
|
Property and equipment
|
|
|
9,866
|
|
Intangible assets, including goodwill
|
|
|
4,941
|
|
|
|
|
|
|
Total assets acquired
|
|
|
19,327
|
|
|
|
|
|
|
Current liabilities
|
|
|
1,376
|
|
Deferred income tax liabilities
|
|
|
3,760
|
|
Other long-term liabilities
|
|
|
150
|
|
|
|
|
|
|
Total liabilities assumed
|
|
|
5,286
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
14,041
|
|
|
|
|
|
|
Rogers historical property and equipment values were
increased by approximately $8.4 million based on
third-party valuations. Intangible assets include approximately
$2.4 million assigned to goodwill, $1.2 million
assigned to patents, $1.1 million assigned to customer list
and $150,000 assigned to non-compete based on third-party
valuations and employment contracts. The amortizable intangibles
have a weighted-average useful life of 10.5 years. The
results of Rogers since the acquisition are included in our
Oilfield Services segment.
66
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
Effective August 14, 2006, we acquired 100% of the
outstanding stock of DLS, based in Argentina, for a total
consideration of approximately $114.5 million, which
includes approximately $93.7 million in cash,
$38.1 million in our common stock, less approximately
$17.3 million of debt assigned to us. In addition,
approximately $3.4 million of costs were incurred in
relation to the DLS acquisition. DLS operated a fleet of 51
rigs, including 20 drilling rigs, 18 workover rigs and 12
pulling rigs in Argentina and one drilling rig in Bolivia. The
following table summarizes the allocation of the purchase price
and related acquisition costs to the estimated fair value of the
assets acquired and liabilities assumed at the date of
acquisition (in thousands):
|
|
|
|
|
Current assets
|
|
$
|
52,033
|
|
Property and equipment
|
|
|
130,389
|
|
Other long-term assets
|
|
|
21
|
|
|
|
|
|
|
Total assets acquired
|
|
|
182,443
|
|
|
|
|
|
|
Current liabilities
|
|
|
34,386
|
|
Long-term debt, less current portion
|
|
|
5,921
|
|
Intercompany note
|
|
|
17,256
|
|
Deferred tax liabilities
|
|
|
6,948
|
|
|
|
|
|
|
Total liabilities assumed
|
|
|
64,511
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
117,932
|
|
|
|
|
|
|
DLS historical property and equipment values were
increased by approximately $22.7 million based on
third-party valuations. The results of DLS since the acquisition
are included in our Drilling and Completion segment.
On October 16, 2006, we acquired 100% of the outstanding
stock of Petro Rental, based in Lafayette, Louisiana, for a
total consideration of approximately $33.6 million, which
includes approximately $20.2 million in cash,
$3.8 million in our common stock and repaid
$9.6 million of existing Petro Rental debt. In addition,
approximately $82,000 of costs were incurred in relation to the
Petro-Rental acquisition. Petro-Rental provides a variety of
production-related rental tools and equipment and services,
including wire line services and equipment, land and offshore
pumping services and coiled tubing. The following table
summarizes the allocation of the purchase price and related
acquisition costs to the estimated fair value of the assets
acquired and liabilities assumed at the date of acquisition (in
thousands):
|
|
|
|
|
Current assets
|
|
$
|
8,175
|
|
Property and equipment
|
|
|
28,792
|
|
Intangible assets, including goodwill
|
|
|
5,811
|
|
Other long-term assets
|
|
|
2
|
|
|
|
|
|
|
Total assets acquired
|
|
|
42,780
|
|
|
|
|
|
|
Current liabilities
|
|
|
2,135
|
|
Deferred tax liabilities
|
|
|
6,954
|
|
|
|
|
|
|
Total liabilities assumed
|
|
|
9,089
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
33,691
|
|
|
|
|
|
|
Petro Rentals historical property and equipment values
were increased by approximately $13.4 million based on
third-party valuations. Intangible assets include approximately
$3.6 million assigned to goodwill and $2.2 million
assigned to customer relationships based on third-party
valuations. The amortizable intangibles
67
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
have a weighted-average useful life of 10 years. The
results of Petro-Rental since the acquisition are included in
our Oilfield Services segment.
Effective December 1, 2006, we acquired 100% of the
outstanding stock of Tanus, based in Argentina, for a total
consideration of $2.5 million. In addition, approximately
$17,000 of costs were incurred in relation to the Tanus
acquisition. Tanus is engaged in the research and manufacturing
of additives for the oil, natural gas and water well drilling
and completion fluids in Argentina. The following table
summarizes the allocation of the purchase price and related
acquisition costs to the estimated fair value of the assets
acquired and liabilities assumed at the date of the acquisition
(in thousands).
|
|
|
|
|
Current assets
|
|
$
|
2,254
|
|
Property and equipment
|
|
|
2
|
|
Goodwill
|
|
|
1,504
|
|
|
|
|
|
|
Total assets acquired
|
|
|
3,760
|
|
Current liabilities
|
|
|
1,243
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
2,517
|
|
|
|
|
|
|
The results of Tanus since the acquisition are included in our
Drilling and Completion segment.
On December 18, 2006, we acquired substantially all of the
assets of Oil & Gas Rental Services, Inc, or OGR,
based in Morgan City, Louisiana, for a total consideration of
approximately $342.4 million, which includes approximately
$291.0 million in cash, and $51.4 million in our
common stock. In addition, approximately $3.0 million of
costs were incurred in relation to the acquisition of the assets
of OGR The following table summarizes the allocation of the
purchase price and related acquisition costs to the estimated
fair value of the assets acquired at the date of acquisition (in
thousands):
|
|
|
|
|
Current assets
|
|
$
|
12,735
|
|
Property and equipment
|
|
|
199,015
|
|
Investments
|
|
|
4,618
|
|
Intangible assets, including goodwill
|
|
|
128,976
|
|
|
|
|
|
|
Total assets acquired
|
|
$
|
345,344
|
|
|
|
|
|
|
OGRs historical property and equipment values were
increased by approximately $168.9 million based on
third-party valuations. Intangible assets include approximately
$106.1 million assigned to goodwill, $22.0 million to
customer relations, $831,000 to patents and $35,000 assigned to
employment agreements based on third-party valuations. The
amortizable intangibles have a weighted-average useful life of
10.1 years. The results of the OGR assets since their
acquisition are included in our Rental Services segment.
On June 29 2007, we acquired Coker Directional, Inc., or Coker,
for a total consideration of approximately $3.9 million,
which includes approximately $3.6 million in cash and a
promissory note for $350,000. In addition, approximately $5,000
of costs were incurred in relation to the Coker acquisition.
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
|
|
|
|
|
|
|
68
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
Intangible assets include approximately $1.8 million
assigned to goodwill and $2.1 million assigned to customer
relationships and non-compete. The amortizable intangibles have
a weighted-average useful life of 9.4 years. The results of
Coker since the acquisition are included in our Oilfield
Services segment.
On July 26, 2007, we acquired Diggar Tools, LLC, or Diggar,
for a total consideration of approximately $10.3 million,
which includes approximately $6.7 million in cash, a
promissory note for $750,000 and payment of approximately
$2.8 million of existing Diggar debt. In addition,
approximately $29,000 of costs were incurred in relation to the
Diggar acquisition. 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
|
|
|
|
|
|
|
Diggars historical property and equipment values were
increased by approximately $3.4 million based on
third-party valuations. Intangible assets include approximately
$2.7 million assigned to goodwill. The results of Diggar
since the acquisition are included in our Oilfield Services
segment.
On October 23, 2007, we acquired Rebel for a total
consideration of approximately $7.3 million, which includes
approximately $5.0 million in cash, promissory notes for an
aggregate of $500,000, payment of approximately
$1.5 million of existing Rebel debt and the deposit of
$305,000 in escrow to cover distributions owed under the Rebel
Defined Benefit Pension Plan & Trust. In addition,
approximately $214,000 of costs were incurred in relation to the
Rebel acquisition. 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 include approximately
$461,000 assigned to goodwill and $683,000 assigned to customer
relations. The amortizable intangibles have a useful life of
15 years. The results of Rebel since the acquisition are
included in our 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
69
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
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 include approximately
$7.6 million assigned to goodwill, $650,000 assigned to
non-compete, $620,000 assigned to trade name and
$3.4 million assigned to customer relations based on
third-party valuations. The amortizable intangibles have a
weighted-average useful life of 13.3 years. Subsequent to
the date of acquisition, the sellers earned an additional
$3.0 million cash earn-out payment as the business achieved
certain earning objectives. The earn-out increased goodwill and
was accrued at December 31, 2008 and will be 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 preliminary allocation of the purchase
price and related acquisition costs to the estimated fair value
of the assets acquired at the date of acquisition (in thousands):
|
|
|
|
|
Current assets
|
|
$
|
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 include 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. We do not expect any material differences from
the preliminary allocation of the purchase price and the final
purchase price allocations.
The acquisitions were accounted for using the purchase method of
accounting.
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.
70
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
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.
The following unaudited pro forma consolidated summary financial
information for the year ended December 31, 2006
illustrates the effects of the acquisitions and the related
public offerings of debt and equity for Rogers, DLS,
Petro-Rental and OGR as if the acquisitions occurred as of
January 1, 2006, based on the historical results of the
acquisitions. The historical results for OGR are based on their
historical year end of October 31 (in thousands, except per
share amounts):
|
|
|
|
|
Revenues
|
|
$
|
502,418
|
|
Operating income
|
|
$
|
93,082
|
|
Net income
|
|
$
|
32,358
|
|
Net income per common share
|
|
|
|
|
Basic
|
|
$
|
0.96
|
|
Diluted
|
|
$
|
0.94
|
|
Inventories are comprised of the following as of December 31 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Manufactured
|
|
|
|
|
|
|
|
|
Finished goods
|
|
$
|
2,821
|
|
|
$
|
2,198
|
|
Work in process
|
|
|
1,654
|
|
|
|
1,781
|
|
Raw materials
|
|
|
2,499
|
|
|
|
4,464
|
|
|
|
|
|
|
|
|
|
|
Total manufactured
|
|
|
6,974
|
|
|
|
8,443
|
|
Hammers
|
|
|
2,257
|
|
|
|
1,434
|
|
Drive pipe
|
|
|
443
|
|
|
|
420
|
|
Rental supplies
|
|
|
3,023
|
|
|
|
2,261
|
|
Chemicals and drilling fluids
|
|
|
3,698
|
|
|
|
3,236
|
|
Rig parts and related inventory
|
|
|
13,097
|
|
|
|
9,985
|
|
Coiled tubing and related inventory
|
|
|
1,817
|
|
|
|
1,014
|
|
Shop supplies and related inventory
|
|
|
7,778
|
|
|
|
5,416
|
|
|
|
|
|
|
|
|
|
|
Total inventories
|
|
$
|
39,087
|
|
|
$
|
32,209
|
|
|
|
|
|
|
|
|
|
|
71
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
NOTE 5
|
PROPERTY
AND OTHER INTANGIBLE ASSETS
|
Property and equipment is comprised of the following as of
December 31 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
|
|
|
|
|
|
|
Period
|
|
|
2008
|
|
|
2007
|
|
|
Land
|
|
|
|
|
|
$
|
2,214
|
|
|
$
|
2,040
|
|
Building and improvements
|
|
|
15-20 years
|
|
|
|
8,387
|
|
|
|
6,986
|
|
Transportation equipment
|
|
|
3-10 years
|
|
|
|
34,493
|
|
|
|
26,132
|
|
Drill pipe and rental equipment
|
|
|
3-20 years
|
|
|
|
373,064
|
|
|
|
350,202
|
|
Drilling, workover and pulling rigs
|
|
|
20 years
|
|
|
|
228,857
|
|
|
|
127,725
|
|
Machinery and equipment
|
|
|
3-20 years
|
|
|
|
212,594
|
|
|
|
157,626
|
|
Furniture, computers, software and leasehold improvements
|
|
|
3-10 years
|
|
|
|
8,711
|
|
|
|
5,817
|
|
Construction in progress equipment
|
|
|
N/A
|
|
|
|
29,850
|
|
|
|
27,148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
898,170
|
|
|
|
703,676
|
|
Less: accumulated depreciation
|
|
|
|
|
|
|
(137,180
|
)
|
|
|
(77,008
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
|
|
|
|
$
|
760,990
|
|
|
$
|
626,668
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The net book value of equipment recorded under capital leases
was $1.7 million and $285,000 as of December 31, 2008
and 2007, respectively. Interest expense capitalized to property
and equipment was $1.9 million and $0 for the years ended
December 31, 2008 and 2007, respectively.
Other intangible assets are as follows as of December 31 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization
|
|
|
|
|
|
|
|
|
|
Period
|
|
|
2008
|
|
|
2007
|
|
|
Trade name
|
|
|
10-20 years
|
|
|
$
|
3,829
|
|
|
$
|
1,629
|
|
Non-compete agreements
|
|
|
3-5 years
|
|
|
|
2,640
|
|
|
|
2,852
|
|
Customer relationships
|
|
|
10-15 years
|
|
|
|
38,033
|
|
|
|
33,528
|
|
Patents
|
|
|
12-15 years
|
|
|
|
1,327
|
|
|
|
2,560
|
|
Other intangible assets
|
|
|
2-10 years
|
|
|
|
793
|
|
|
|
829
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
46,622
|
|
|
|
41,398
|
|
Less: accumulated amortization
|
|
|
|
|
|
|
(9,251
|
)
|
|
|
(6,218
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other intangibles assets, net
|
|
|
|
|
|
$
|
37,371
|
|
|
$
|
35,180
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
Gross
|
|
|
Accumulated
|
|
|
Gross
|
|
|
Accumulated
|
|
|
|
Value
|
|
|
Amortization
|
|
|
Value
|
|
|
Amortization
|
|
|
Intellectual property
|
|
$
|
3,829
|
|
|
$
|
507
|
|
|
$
|
1,629
|
|
|
$
|
410
|
|
Non-compete agreements
|
|
|
2,640
|
|
|
|
1,198
|
|
|
|
2,852
|
|
|
|
1,367
|
|
Customer relationships
|
|
|
38,033
|
|
|
|
6,676
|
|
|
|
33,528
|
|
|
|
3,497
|
|
Patents
|
|
|
1,327
|
|
|
|
279
|
|
|
|
2,560
|
|
|
|
423
|
|
Other intangible assets
|
|
|
793
|
|
|
|
591
|
|
|
|
829
|
|
|
|
521
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
46,622
|
|
|
$
|
9,251
|
|
|
$
|
41,398
|
|
|
$
|
6,218
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
72
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
Amortization expense related to other intangibles was
$4.2 million, $4.1 million and $1.9 million for
the years ended December 31, 2008, 2007 and 2006,
respectively. Future amortization of intangible assets at
December 31, 2008 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible Amortization by Period
|
|
|
|
Years Ended December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013 and
|
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Thereafter
|
|
|
Intellectual property
|
|
$
|
316
|
|
|
$
|
316
|
|
|
$
|
316
|
|
|
$
|
316
|
|
|
$
|
2,058
|
|
Non-compete agreements
|
|
|
681
|
|
|
|
489
|
|
|
|
248
|
|
|
|
24
|
|
|
|
|
|
Customer relationships
|
|
|
3,532
|
|
|
|
3,532
|
|
|
|
3,532
|
|
|
|
3,532
|
|
|
|
17,229
|
|
Patents
|
|
|
102
|
|
|
|
102
|
|
|
|
102
|
|
|
|
102
|
|
|
|
640
|
|
Other intangible assets
|
|
|
89
|
|
|
|
83
|
|
|
|
28
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Intangible Amortization
|
|
$
|
4,720
|
|
|
$
|
4,522
|
|
|
$
|
4,226
|
|
|
$
|
3,976
|
|
|
$
|
19,927
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We had a loss before income taxes of $95.3 million for
U.S. tax purposes for the year ended December 31,
2008. We had income before income taxes of $41.7 million
and $35.9 million for U.S. tax purposes for the years
ended December 31, 2007 and 2006, respectively. We also had
income before income taxes of $38.4 million,
$37.6 million and $11.1 million reported in
non-U.S. countries
for the years ended December 31, 2008, 2007 and 2006,
respectively. We treat the withholding taxes incurred by our
U.S. subsidiaries in foreign countries as foreign tax, and
we anticipate using those tax payments to offset U.S. tax.
The income tax provision consists of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Current income tax expense (benefit):
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
(1,525
|
)
|
|
$
|
6,814
|
|
|
$
|
5,865
|
|
State
|
|
|
471
|
|
|
|
1,053
|
|
|
|
898
|
|
Foreign
|
|
|
13,590
|
|
|
|
12,959
|
|
|
|
2,442
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,536
|
|
|
|
20,826
|
|
|
|
9,205
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax expense (benefit):
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(28,462
|
)
|
|
|
7,081
|
|
|
|
(946
|
)
|
State
|
|
|
(1,149
|
)
|
|
|
349
|
|
|
|
573
|
|
Foreign
|
|
|
(338
|
)
|
|
|
587
|
|
|
|
2,588
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(29,949
|
)
|
|
|
8,017
|
|
|
|
2,215
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(17,413
|
)
|
|
$
|
28,843
|
|
|
$
|
11,420
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We are required to file a consolidated U.S. federal income
tax return. We pay foreign income taxes in Argentina related to
our Drilling and Completion operations and in Mexico related to
Oilfield Services revenues from Matyep.
73
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
The following table reconciles the statutory tax rates to our
actual tax rate:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Statutory income tax rate
|
|
|
34.0
|
%
|
|
|
35.0
|
%
|
|
|
35.0
|
%
|
State taxes, net of federal benefit
|
|
|
0.4
|
|
|
|
1.8
|
|
|
|
2.1
|
|
Valuation allowances
|
|
|
|
|
|
|
|
|
|
|
(57.7
|
)
|
Foreign currency remeasurement
|
|
|
2.1
|
|
|
|
|
|
|
|
|
|
Nondeductible goodwill, permanent differences and other
|
|
|
(5.9
|
)
|
|
|
(0.4
|
)
|
|
|
44.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate
|
|
|
30.6
|
%
|
|
|
36.4
|
%
|
|
|
24.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Significant components of deferred income tax assets as of
December 31, were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Deferred income tax assets:
|
|
|
|
|
|
|
|
|
Net future deductible items
|
|
$
|
35,384
|
|
|
$
|
874
|
|
Share-based compensation
|
|
|
2,691
|
|
|
|
1,898
|
|
Net operating loss carryforwards
|
|
|
2,287
|
|
|
|
2,681
|
|
Foreign tax credits
|
|
|
760
|
|
|
|
|
|
A-C Reorganization Trust and Product Liability Trust
|
|
|
2,448
|
|
|
|
4,099
|
|
|
|
|
|
|
|
|
|
|
Total deferred income tax assets
|
|
|
43,570
|
|
|
|
9,552
|
|
Deferred income tax liabilities
|
|
|
|
|
|
|
|
|
Net future taxable items
|
|
|
(1,130
|
)
|
|
|
|
|
Depreciation and amortization
|
|
|
(40,524
|
)
|
|
|
(37,795
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
(41,654
|
)
|
|
|
(37,795
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred income tax assets (liabilities)
|
|
$
|
1,916
|
|
|
$
|
(28,243
|
)
|
|
|
|
|
|
|
|
|
|
Net current deferred income tax asset
|
|
$
|
6,176
|
|
|
$
|
1,847
|
|
Net noncurrent deferred income tax liability
|
|
|
(4,260
|
)
|
|
|
(30,090
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred income tax assets (liabilities)
|
|
$
|
1,916
|
|
|
$
|
(28,243
|
)
|
|
|
|
|
|
|
|
|
|
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. For example, the goodwill impairment
that we recorded in 2008 for financial statement purposes
related to our Rental Services segment has created a deferred
tax asset that will be realized over the next 13 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, 2008 and
2007 were $6.7 million and $7.7 million, respectively,
expiring through 2024.
Our 1988 Plan of Reorganization established the A-C
Reorganization Trust to settle claims and to make distributions
to creditors and certain stockholders. We transferred cash and
certain other property to the A-C Reorganization Trust on
December 2, 1988. Payments made by us to the A-C
Reorganization Trust did not
74
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
generate tax deductions for us upon the transfer but generate
deductions for us as the A-C Reorganization Trust makes payments
to holders of claims and for administrative expenses. The Plan
of Reorganization also created a trust to process and liquidate
product liability claims. Payments made by the A-C
Reorganization Trust to the Product Liability Trust did not
generate current tax deductions for us upon the payment but
generates deductions for us as the Product Liability Trust makes
payments to liquidate claims or incurs administrative expenses.
We believe the aforementioned trusts are grantor trusts and
therefore we include the income or loss of these trusts in our
income or loss for tax purposes. The income or loss of these
trusts is not included in our results of operations for
financial reporting purposes.
A valuation allowance is established for deferred tax assets
when management, based upon available information, considers it
more likely than not that a benefit from such assets will not be
realized. As of December 31, 2008 and 2007, the valuation
allowance was zero.
Approximately $4.7 million and $9.7 million of ad
valorem, franchise, income, sales and other tax accruals are
included in our accrued expense balances of $26.6 million
and $20.5 million as of December 31, 2008 and 2007,
respectively.
We adopted the provisions of FIN 48 on January 1,
2007. This interpretation clarifies the accounting for uncertain
tax positions and requires companies to recognize the impact of
a tax position in their financial statements, if that position
is more likely than not of being sustained on audit, based on
the technical merits of the position. The adoption of
FIN 48 did not have any impact on the total liabilities or
stockholders equity.
Our long-term debt consists of the following as of December 31
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Senior notes
|
|
$
|
505,000
|
|
|
$
|
505,000
|
|
Bank term loans
|
|
|
49,609
|
|
|
|
4,926
|
|
Revolving line of credit
|
|
|
36,500
|
|
|
|
|
|
Seller notes
|
|
|
750
|
|
|
|
2,350
|
|
Notes payable to former directors
|
|
|
32
|
|
|
|
32
|
|
Equipment & vehicle installment notes
|
|
|
|
|
|
|
595
|
|
Insurance premium financing notes
|
|
|
991
|
|
|
|
1,707
|
|
Obligations under non-compete agreements
|
|
|
|
|
|
|
110
|
|
Capital lease obligations
|
|
|
779
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
Total debt
|
|
|
593,661
|
|
|
|
514,734
|
|
Less: current maturities of long-term debt
|
|
|
14,617
|
|
|
|
6,434
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
579,044
|
|
|
$
|
508,300
|
|
|
|
|
|
|
|
|
|
|
Our weighted average interest rate for current and total debt
was approximately 6.4% and 8.3% as of December 31, 2008 and
6.3% and 8.7% as of December 31, 2007, respectively.
75
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
Maturities of debt obligations as of December 31, 2008 are
as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt
|
|
|
Capital Leases
|
|
|
Total
|
|
|
Year Ending:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
$
|
14,026
|
|
|
$
|
591
|
|
|
$
|
14,617
|
|
December 31, 2010
|
|
|
12,333
|
|
|
|
188
|
|
|
|
12,521
|
|
December 31, 2011
|
|
|
11,984
|
|
|
|
|
|
|
|
11,984
|
|
December 31, 2012
|
|
|
46,663
|
|
|
|
|
|
|
|
46,663
|
|
December 31, 2013
|
|
|
2,876
|
|
|
|
|
|
|
|
2,876
|
|
Thereafter
|
|
|
505,000
|
|
|
|
|
|
|
|
505,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
592,882
|
|
|
$
|
779
|
|
|
$
|
593,661
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior
notes, bank loans and line of credit agreements
On January 18, 2006 and August 14, 2006, we closed on
private offerings, to qualified institutional buyers pursuant to
Rule 144A under the Securities Act of 1933, of $160.0 and
$95.0 million aggregate principal amount of our senior
notes, respectively. The senior notes are due January 15,
2014 and bear interest at 9.0%. The proceeds were used to fund
the acquisitions of Specialty and DLS, to repay existing debt
and for general corporate purposes.
On December 18, 2006, we closed on a $300.0 million
senior unsecured bridge loan. The bridge loan was due
18 months after closing and had a weighted average interest
rate of 10.6%. The bridge loan, which was repaid on
January 29, 2007, was used to fund the acquisition of
substantially all the assets of OGR.
In January 2007, we closed on a private offering, to qualified
institutional buyers pursuant to Rule 144A under the
Securities Act, of $250.0 million principal amount of
8.5% senior notes due 2017. The proceeds of the senior
notes offering, together with a portion of the proceeds of our
concurrent common stock offering, were used to repay the debt
outstanding under our $300.0 million bridge loan facility
which we incurred to finance our acquisition of substantially
all the assets of OGR.
On January 18, 2006, we also executed an amended and
restated credit agreement which 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. 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, 2008 and 2007.
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 of December 31, 2008 and 2007,
amounts borrowed under the facility were $36.5 million and
$0 and availability was reduced by outstanding letters of credit
of $5.8 million and $8.4 million, respectively.
As part of our acquisition of DLS, we assumed various bank loans
with floating interest rates based on LIBOR plus a margin and
terms ranging from 2 to 5 years. The weighted average
interest rates on these loans was 5.1% and 6.7% as of
December 31, 2008 and 2007, respectively. The bank loans
are denominated in U.S. dollars and the outstanding amount
due as of December 31, 2008 and 2007 was $2.5 million
and $4.9 million, respectively.
76
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
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 facility was available for borrowings until
December 31, 2008. Each drawdown shall be repaid 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, 2008. The bank loan rates are based on LIBOR
plus a margin. The weighted average interest rate was 6.9% at
December 31, 2008. The bank loans are denominated in
U.S. dollars and the outstanding amount as of
December 31, 2008 was $25.0 million.
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, 2008. The credit facility loan is denominated
in U.S. dollars and interest rates are based on LIBOR plus
a margin. At December 31, 2008, the outstanding amount of
the loan was $22.1 million and the interest rate was 6.0%.
Notes
payable
In connection with the acquisition of Rogers, we issued to the
seller a note in the amount of $750,000. The note bears interest
at 5.0% and is due April 2009. In connection with the purchase
of Coker, we issued to the seller a note in the amount of
$350,000. The note bore interest at 8.25% and was repaid in June
2008. In connection with the purchase of Diggar, we issued to
the seller a note in the amount of $750,000. The note bore
interest at 6.0% and was repaid in July 2008. In connection with
the purchase of Rebel, we issued to the sellers notes in the
amount of $500,000. The notes bore interest at 5.0% and were
repaid in October 2008.
In 2000 we compensated directors, including current directors
Nederlander and Toboroff, who served on the board of directors
from 1989 to March 31, 1999 without compensation, by
issuing promissory notes totaling $325,000. The notes bear
interest at the rate of 5.0%. As of December 31, 2008 and
2007, the principal and accrued interest on these notes totaled
approximately $32,000.
We have various rig and equipment financing loans with interest
rates ranging from 8.3% to 8.7% and terms of 2 to 5 years.
As of December 31, 2008 and 2007, the outstanding balances
for rig and equipment financing loans were $0 and $595,000,
respectively.
In April 2007 and August 2007, we obtained insurance premium
financings in the aggregate amount of $4.4 million with a
fixed weighted average interest rate of 5.9%. 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 $1.7 million as of
December 31, 2008 and 2007, 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 $991,000 at December 31, 2008.
Other
debt
In connection with the purchase of Capcoil Tubing Services,
Inc., we agreed to pay a total of $500,000 to two management
employees in exchange for non-compete agreements. We were
required to make annual
77
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
payments of $110,000 through May 2008. Total amounts due under
these non-compete agreements as of December 31, 2008 and
2007 were $0 and $110,000, respectively.
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 $779,000 at December 31,
2008. We also had other capital leases with terms that expired
in 2008. As of December 31, 2007, amounts outstanding under
capital leases were $14,000.
|
|
NOTE 8
|
COMMITMENTS
AND CONTINGENCIES
|
We have placed orders for capital equipment totaling
$41.4 million to be received and paid for through 2009.
Approximately $22.6 million is for drilling and service
rigs for our Drilling and Completion segment, $10.0 million
is for other drilling equipment for our Drilling and Completion
segment, $5.5 million is for rental equipment, principally
drill pipe, for our Rental Services segment and
$3.3 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, 2008, 2007 and 2006 was
$2.8 million, $2.7 million and $1.6 million,
respectively.
At December 31, 2008, future minimum rental commitments for
all operating leases are as follows (in thousands):
|
|
|
|
|
Years Ending:
|
|
|
|
|
December 31, 2009
|
|
$
|
2,888
|
|
December 31, 2010
|
|
|
2,113
|
|
December 31, 2011
|
|
|
1,730
|
|
December 31, 2012
|
|
|
981
|
|
December 31, 2013
|
|
|
739
|
|
Thereafter
|
|
|
1,035
|
|
|
|
|
|
|
Total
|
|
$
|
9,486
|
|
|
|
|
|
|
|
|
NOTE 9
|
STOCKHOLDERS
EQUITY
|
During 2006, we issued 125,285 shares, 2.5 million
shares, 246,761 shares and 3.2 million shares of our
common stock in relation to the Rogers, DLS, Petro Rental and
OGR asset acquisitions, respectively (see Note 3).
On August 14, 2006 we closed on a public offering of
3,450,000 shares of our common stock at a public offering
price of $14.50 per share. Net proceeds from the public offering
of approximately $46.3 million were used to fund a portion
of our acquisition of DLS.
During 2006, we had options and warrants exercised, which
resulted in 1,851,377 shares of our common stock being
issued for approximately $6.3 million. We recognized
approximately $3.4 million of compensation expense related
to stock options in 2006 that was recorded as capital in excess
of par value (see Note 1). We also recorded approximately
$6.4 million of tax benefit related to our stock
compensation plans.
In January 2007 we closed on a public offering of
6.0 million shares of our common stock at a public offering
price of $17.65 per share. Net proceeds from the public
offering, together with the proceeds of our concurrent senior
notes offering, were used to repay the debt outstanding under
our $300.0 million bridge loan facility, which we incurred
to finance the OGR acquisition and for general corporate
purposes.
78
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
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 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, 2008, 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.
On May 31, 2001, the Board granted to Leonard Toboroff, one
of our directors, an option to purchase 100,000 shares of
our common stock at $2.50 per share, exercisable for
10 years from October 15, 2001. The option was granted
for services provided by Mr. Toboroff to Oil Quip Rentals,
Inc., or Oil Quip, prior to the merger, including providing
financial advisory services, assisting in Oil Quips
capital structure and assisting Oil Quip in finding strategic
acquisition opportunities. We recorded compensation expense of
$500,000 for the issuance of the option for the year ended
December 31, 2001. All of the stock options were exercised
in May 2006.
The 2003 Incentive Stock Plan (2003 Plan), as
amended, permits us to grant to our key employees and outside
directors various forms of stock incentives, including, among
others, incentive and non-qualified stock options and restricted
stock. The 2003 Plan is administered by the Compensation
Committee of the Board, which consists of two or more directors
appointed by the Board. The following benefits may be granted
under the 2003 Plan: (a) stock appreciation rights;
(b) restricted stock; (c) performance awards;
(d) incentive stock options; (e) nonqualified stock
options; and (f) other stock-based awards. Stock incentive
terms are not to be in excess of ten years. The maximum number
of shares 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 (2006 Plan), was approved by
our stockholders in November 2006. 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 1,500,000 shares, subject to adjustment in
the event of stock splits and certain other corporate events.
The 2006 Plan provides for the grant of any or all of the
following types of awards: (i) stock options, including
incentive stock options and non-qualified stock options;
(ii) bonus stock; (iii) restricted stock awards;
(iv) performance awards; and (v) other stock-based
awards. Except with respect to awards of incentive stock
options, all of our employees, consultants and non-employee
directors are eligible to participate in the 2006 Plan. The term
of each Award shall be for such period as may be determined by
the Committee; provided, that in no event shall the term of any
Award exceed a period of ten years from the date of its grant.
79
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
A summary of our stock option activity and related information
is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
December 31, 2007
|
|
|
December 31, 2006
|
|
|
|
Shares
|
|
|
Weighted Ave.
|
|
|
Shares
|
|
|
Weighted Ave.
|
|
|
Shares
|
|
|
Weighted Avg.
|
|
|
|
Under
|
|
|
Exercise
|
|
|
Under
|
|
|
Exercise
|
|
|
Under
|
|
|
Exercise
|
|
|
|
Option
|
|
|
Price
|
|
|
Option
|
|
|
Price
|
|
|
Option
|
|
|
Price
|
|
|
Beginning balance
|
|
|
986,763
|
|
|
$
|
10.77
|
|
|
|
1,350,365
|
|
|
$
|
6.88
|
|
|
|
2,860,867
|
|
|
$
|
5.10
|
|
Granted
|
|
|
|
|
|
|
|
|
|
|
220,000
|
|
|
|
21.83
|
|
|
|
15,000
|
|
|
|
14.74
|
|
Canceled
|
|
|
(13,328
|
)
|
|
|
8.87
|
|
|
|
(17,334
|
)
|
|
|
8.45
|
|
|
|
(54,567
|
)
|
|
|
5.97
|
|
Exercised
|
|
|
(71,703
|
)
|
|
|
8.83
|
|
|
|
(566,268
|
)
|
|
|
5.86
|
|
|
|
(1,470,935
|
)
|
|
|
3.54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
|
901,732
|
|
|
$
|
10.95
|
|
|
|
986,763
|
|
|
$
|
10.77
|
|
|
|
1,350,365
|
|
|
$
|
6.88
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 $542,000, $6.6 million and $18.8 million
during the years ended December 31, 2008, 2007 and 2006,
respectively. As of December 31, 2008, there was
approximately $1.5 million of total unrecognized
compensation cost related to stock options, with $918,000 and
$532,000 to be recognized during the years ended
December 31, 2009 and 2010, respectively.
The following table summarizes additional information about our
stock options outstanding as of December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
|
Options Exercisable
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
Weighted
|
|
|
|
|
|
Weighted Average
|
|
|
Weighted
|
|
Range of
|
|
|
|
|
|
Remaining
|
|
|
Average
|
|
|
|
|
|
Remaining
|
|
|
Average
|
|
Exercise
|
|
|
Number of
|
|
|
Contractual Life
|
|
|
Exercise
|
|
|
Number of
|
|
|
Contractual Life
|
|
|
Exercise
|
|
Prices
|
|
|
options
|
|
|
(in Years)
|
|
|
Price
|
|
|
options
|
|
|
(in Years)
|
|
|
Price
|
|
|
$
|
2.75-4.87
|
|
|
|
343,800
|
|
|
|
6.00
|
|
|
$
|
4.07
|
|
|
|
343,800
|
|
|
|
6.00
|
|
|
$
|
4.07
|
|
|
10.85-14.74
|
|
|
|
338,932
|
|
|
|
6.89
|
|
|
|
10.89
|
|
|
|
338,932
|
|
|
|
6.89
|
|
|
|
10.89
|
|
|
16.50-21.95
|
|
|
|
219,000
|
|
|
|
8.59
|
|
|
|
21.85
|
|
|
|
43,000
|
|
|
|
8.59
|
|
|
|
21.95
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.75-21.95
|
|
|
|
901,732
|
|
|
|
6.96
|
|
|
$
|
10.95
|
|
|
|
725,732
|
|
|
|
6.57
|
|
|
$
|
8.32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The aggregate pretax intrinsic value of stock options
outstanding and exercisable was approximately $490,000 at
December 31, 2008. The amount represents the value that
would have been received by the option holders had the
respective options been exercised on December 31, 2008.
Restricted
Stock Awards
In addition to stock options, our 2003 and 2006 Plans allow for
the grant of restricted stock awards (RSA). A
time-lapse RSA is an award of common stock, where each unit
represents the right to receive at the end of a stipulated
period one unrestricted share of stock with no exercise price.
The time-lapse RSA restrictions lapse periodically over an
extended period of time not exceeding 10 years. We
determine the fair value of RSAs based on the market price of
our common stock on the date of grant. Compensation cost for
RSAs is primarily recognized on a straight-line basis over the
vesting or service period and is net of forfeitures. A
performance-based RSA is an award of common stock, where each
unit represents the right to receive one unrestricted share of
stock with no exercise price at the attainment of established
performance criteria. During 2007, we granted 710,000
performance based RSAs with market conditions. The
performance-based RSAs are granted, but not earned and issued
until certain annual total shareholder return criteria are
attained over the next 3 years. The fair value of the
performance-based RSAs were based on third-party valuations.
80
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
The following table summarizes activity in our nonvested
restricted stock awards:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
December 31, 2007
|
|
|
December 31, 2006
|
|
|
|
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
|
|
|
993,203
|
|
|
$
|
17.45
|
|
|
|
27,000
|
|
|
$
|
18.30
|
|
|
|
|
|
|
$
|
|
|
Granted
|
|
|
258,670
|
|
|
|
9.47
|
|
|
|
996,203
|
|
|
|
17.44
|
|
|
|
27,000
|
|
|
|
18.30
|
|
Vested
|
|
|
(298,771
|
)
|
|
|
17.26
|
|
|
|
(30,000
|
)
|
|
|
18.01
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
|
953,102
|
|
|
$
|
15.34
|
|
|
|
993,203
|
|
|
$
|
17.45
|
|
|
|
27,000
|
|
|
$
|
18.30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The total fair value of RSA shares that vested during 2008 was
approximately $4.7 million. As of December 31, 2008,
there was approximately $9.4 million of total unrecognized
compensation cost related to nonvested RSAs, with
$6.0 million, $2.5 million, $709,000 and $208,000 to
be recognized during the years ended December 31, 2009,
2010, 2011 and 2012, respectively.
|
|
NOTE 11
|
STOCK
PURCHASE WARRANTS
|
In conjunction with Oil Quips 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.
We issued two warrants (Warrants A and B) for the
purchase of 233,000 total shares of our common stock at an
exercise price of $0.75 per share and one warrant for the
purchase of 67,000 shares of our common stock at an
exercise price of $5.00 per share (Warrant C) in
connection with our subordinated debt financing for MCA in 2001.
Warrants A and B were paid off on December 7, 2004. Warrant
C was exercised during November 2006.
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.
81
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
NOTE 12
|
CONDENSED
CONSOLIDATED FINANCIAL INFORMATION
|
Set forth on the following pages are the condensed consolidating
financial statements of (i) Allis-Chalmers Energy Inc.,
(ii) its subsidiaries that are guarantors of the senior
notes and revolving credit facility and (iii) the
subsidiaries that are not guarantors of the senior notes and
revolving credit facility (in thousands):
CONDENSED
CONSOLIDATING BALANCE SHEETS
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
|
|
|
|
(3,993
|
)
|
|
|
31,522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
993,757
|
|
|
$
|
749,706
|
|
|
$
|
392,100
|
|
|
$
|
(1,024,505
|
)
|
|
$
|
1,111,058
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
(3,993
|
)
|
|
|
4,260
|
|
Other long-term liabilities
|
|
|
|
|
|
|
64
|
|
|
|
2,129
|
|
|
|
|
|
|
|
2,193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
610,348
|
|
|
|
46,589
|
|
|
|
157,990
|
|
|
|
(87,278
|
)
|
|
|
727,649
|
|
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
|
|
|
$
|
(1,024,505
|
)
|
|
$
|
1,111,058
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
82
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
|
|
|
|
|
|
|
220,181
|
|
|
|
226,090
|
|
|
|
(36
|
)
|
|
|
446,235
|
|
Depreciation
|
|
|
|
|
|
|
49,177
|
|
|
|
14,283
|
|
|
|
|
|
|
|
63,460
|
|
General and administrative
|
|
|
6,924
|
|
|
|
42,326
|
|
|
|
10,703
|
|
|
|
|
|
|
|
59,953
|
|
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
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
83
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 deferred financing fees
|
|
|
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 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 accounts 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
84
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
85
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
CONDENSED
CONSOLIDATING BALANCE SHEETS
December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chalmers
|
|
|
|
|
|
Subsidiary
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors
|
|
|
Adjustments
|
|
|
Total
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
|
|
|
$
|
41,176
|
|
|
$
|
2,517
|
|
|
$
|
|
|
|
$
|
43,693
|
|
Trade receivables, net
|
|
|
|
|
|
|
83,126
|
|
|
|
46,973
|
|
|
|
(5
|
)
|
|
|
130,094
|
|
Inventories
|
|
|
|
|
|
|
15,699
|
|
|
|
16,510
|
|
|
|
|
|
|
|
32,209
|
|
Intercompany receivables
|
|
|
31,297
|
|
|
|
|
|
|
|
|
|
|
|
(31,297
|
)
|
|
|
|
|
Note receivable from affiliate
|
|
|
8,270
|
|
|
|
|
|
|
|
|
|
|
|
(8,270
|
)
|
|
|
|
|
Prepaid expenses and other
|
|
|
7,731
|
|
|
|
2,564
|
|
|
|
1,603
|
|
|
|
|
|
|
|
11,898
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
47,298
|
|
|
|
142,565
|
|
|
|
67,603
|
|
|
|
(39,572
|
)
|
|
|
217,894
|
|
Property and equipment, net
|
|
|
|
|
|
|
477,055
|
|
|
|
149,613
|
|
|
|
|
|
|
|
626,668
|
|
Goodwill
|
|
|
|
|
|
|
136,875
|
|
|
|
1,523
|
|
|
|
|
|
|
|
138,398
|
|
Other intangible assets, net
|
|
|
552
|
|
|
|
34,572
|
|
|
|
56
|
|
|
|
|
|
|
|
35,180
|
|
Debt issuance costs, net
|
|
|
14,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,228
|
|
Note receivable from affiliates
|
|
|
16,380
|
|
|
|
|
|
|
|
|
|
|
|
(16,380
|
)
|
|
|
|
|
Investments in affiliates
|
|
|
869,696
|
|
|
|
|
|
|
|
|
|
|
|
(869,696
|
)
|
|
|
|
|
Other assets
|
|
|
15
|
|
|
|
4,977
|
|
|
|
16,225
|
|
|
|
|
|
|
|
21,217
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
948,169
|
|
|
$
|
796,044
|
|
|
$
|
235,020
|
|
|
$
|
(925,648
|
)
|
|
$
|
1,053,585
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
$
|
32
|
|
|
$
|
4,026
|
|
|
$
|
2,376
|
|
|
$
|
|
|
|
$
|
6,434
|
|
Trade accounts payable
|
|
|
|
|
|
|
16,815
|
|
|
|
20,654
|
|
|
|
(5
|
)
|
|
|
37,464
|
|
Accrued salaries, benefits and payroll taxes
|
|
|
|
|
|
|
3,712
|
|
|
|
11,571
|
|
|
|
|
|
|
|
15,283
|
|
Accrued interest
|
|
|
17,709
|
|
|
|
33
|
|
|
|
75
|
|
|
|
|
|
|
|
17,817
|
|
Accrued expenses
|
|
|
1,660
|
|
|
|
7,127
|
|
|
|
11,758
|
|
|
|
|
|
|
|
20,545
|
|
Intercompany payables
|
|
|
|
|
|
|
30,112
|
|
|
|
1,185
|
|
|
|
(31,297
|
)
|
|
|
|
|
Note payable to affiliate
|
|
|
|
|
|
|
|
|
|
|
8,270
|
|
|
|
(8,270
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
19,401
|
|
|
|
61,825
|
|
|
|
55,889
|
|
|
|
(39,572
|
)
|
|
|
97,543
|
|
Long-term debt, net of current maturities
|
|
|
505,750
|
|
|
|
|
|
|
|
2,550
|
|
|
|
|
|
|
|
508,300
|
|
Note payable to affiliate
|
|
|
|
|
|
|
|
|
|
|
16,380
|
|
|
|
(16,380
|
)
|
|
|
|
|
Deferred income tax liability
|
|
|
8,658
|
|
|
|
13,809
|
|
|
|
7,623
|
|
|
|
|
|
|
|
30,090
|
|
Other long-term liabilities
|
|
|
31
|
|
|
|
242
|
|
|
|
3,050
|
|
|
|
|
|
|
|
3,323
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
533,840
|
|
|
|
75,876
|
|
|
|
85,492
|
|
|
|
(55,952
|
)
|
|
|
639,256
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock
|
|
|
351
|
|
|
|
3,526
|
|
|
|
42,963
|
|
|
|
(46,489
|
)
|
|
|
351
|
|
Capital in excess of par value
|
|
|
326,095
|
|
|
|
570,512
|
|
|
|
74,969
|
|
|
|
(645,481
|
)
|
|
|
326,095
|
|
Retained earnings
|
|
|
87,883
|
|
|
|
146,130
|
|
|
|
31,596
|
|
|
|
(177,726
|
)
|
|
|
87,883
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
414,329
|
|
|
|
720,168
|
|
|
|
149,528
|
|
|
|
(869,696
|
)
|
|
|
414,329
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stock holders equity
|
|
$
|
948,169
|
|
|
$
|
796,044
|
|
|
$
|
235,020
|
|
|
$
|
(925,648
|
)
|
|
$
|
1,053,585
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
86
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
|
|
|
|
|
|
|
185,617
|
|
|
|
155,833
|
|
|
|
|
|
|
|
341,450
|
|
Depreciation
|
|
|
|
|
|
|
39,659
|
|
|
|
11,255
|
|
|
|
|
|
|
|
50,914
|
|
General and administrative
|
|
|
4,349
|
|
|
|
44,439
|
|
|
|
9,834
|
|
|
|
|
|
|
|
58,622
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
87
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOW
For the Year Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Chalmers
|
|
|
|
|
|
Subsidiaries
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
(Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors)
|
|
|
Adjustments
|
|
|
Total
|
|
|
Cash Flows from Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
50,440
|
|
|
$
|
77,384
|
|
|
$
|
24,824
|
|
|
$
|
(102,208
|
)
|
|
$
|
50,440
|
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation & amortization
|
|
|
46
|
|
|
|
43,647
|
|
|
|
11,288
|
|
|
|
|
|
|
|
54,981
|
|
Amortization and write-off of deferred financing fees
|
|
|
3,197
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,197
|
|
Stock based compensation
|
|
|
4,863
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,863
|
|
Bad debt expense
|
|
|
|
|
|
|
1,309
|
|
|
|
|
|
|
|
|
|
|
|
1,309
|
|
Equity earnings in affiliates
|
|
|
(102,208
|
)
|
|
|
|
|
|
|
|
|
|
|
102,208
|
|
|
|
|
|
Deferred taxes
|
|
|
7,430
|
|
|
|
|
|
|
|
587
|
|
|
|
|
|
|
|
8,017
|
|
Gain on sale of equipment
|
|
|
|
|
|
|
(2,182
|
)
|
|
|
(141
|
)
|
|
|
|
|
|
|
(2,323
|
)
|
Gain on capillary asset sale
|
|
|
|
|
|
|
(8,868
|
)
|
|
|
|
|
|
|
|
|
|
|
(8,868
|
)
|
Changes in operating assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in accounts receivables
|
|
|
|
|
|
|
(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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
88
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
|
|
|
|
|
|
|
(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
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
89
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
CONDENSED
CONSOLIDATING INCOME STATEMENTS
For the Year Ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers
|
|
|
|
|
|
Subsidiary
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors
|
|
|
Adjustments
|
|
|
Total
|
|
|
Revenues
|
|
$
|
|
|
|
$
|
241,474
|
|
|
$
|
69,490
|
|
|
$
|
|
|
|
$
|
310,964
|
|
Operating costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs
|
|
|
|
|
|
|
134,638
|
|
|
|
50,941
|
|
|
|
|
|
|
|
185,579
|
|
Depreciation
|
|
|
|
|
|
|
16,198
|
|
|
|
4,063
|
|
|
|
|
|
|
|
20,261
|
|
General and administrative
|
|
|
2,643
|
|
|
|
30,651
|
|
|
|
2,242
|
|
|
|
|
|
|
|
35,536
|
|
Amortization
|
|
|
46
|
|
|
|
1,801
|
|
|
|
11
|
|
|
|
|
|
|
|
1,858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
2,689
|
|
|
|
183,288
|
|
|
|
57,257
|
|
|
|
|
|
|
|
243,234
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(2,689
|
)
|
|
|
58,186
|
|
|
|
12,233
|
|
|
|
|
|
|
|
67,730
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in affiliates, net of tax
|
|
|
58,077
|
|
|
|
|
|
|
|
|
|
|
|
(58,077
|
)
|
|
|
|
|
Interest, net
|
|
|
(19,807
|
)
|
|
|
67
|
|
|
|
(597
|
)
|
|
|
|
|
|
|
(20,337
|
)
|
Other
|
|
|
45
|
|
|
|
97
|
|
|
|
(489
|
)
|
|
|
|
|
|
|
(347
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
38,315
|
|
|
|
164
|
|
|
|
(1,086
|
)
|
|
|
(58,077
|
)
|
|
|
(20,684
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
35,626
|
|
|
|
58,350
|
|
|
|
11,147
|
|
|
|
(58,077
|
)
|
|
|
47,046
|
|
Provision for income taxes
|
|
|
|
|
|
|
(7,045
|
)
|
|
|
(4,375
|
)
|
|
|
|
|
|
|
(11,420
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
35,626
|
|
|
$
|
51,305
|
|
|
$
|
6,772
|
|
|
$
|
(58,077
|
)
|
|
$
|
35,626
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
90
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOW
For the Year Ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Chalmers
|
|
|
|
|
|
Subsidiaries
|
|
|
|
|
|
|
|
|
|
(Parent/
|
|
|
Subsidiary
|
|
|
(Non-
|
|
|
Consolidating
|
|
|
Consolidated
|
|
|
|
Guarantor)
|
|
|
Guarantors
|
|
|
Guarantors)
|
|
|
Adjustments
|
|
|
Total
|
|
|
Cash Flows from Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
35,626
|
|
|
$
|
51,305
|
|
|
$
|
6,772
|
|
|
$
|
(58,077
|
)
|
|
$
|
35,626
|
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation & amortization
|
|
|
46
|
|
|
|
17,999
|
|
|
|
4,074
|
|
|
|
|
|
|
|
22,119
|
|
Amortization & write-off of deferred financing fees
|
|
|
1,527
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,527
|
|
Stock based compensation
|
|
|
3,394
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,394
|
|
Bad debt expense
|
|
|
|
|
|
|
781
|
|
|
|
|
|
|
|
|
|
|
|
781
|
|
Imputed interest
|
|
|
|
|
|
|
355
|
|
|
|
|
|
|
|
|
|
|
|
355
|
|
Equity earnings in affiliates
|
|
|
(58,077
|
)
|
|
|
|
|
|
|
|
|
|
|
58,077
|
|
|
|
|
|
Deferred taxes
|
|
|
(619
|
)
|
|
|
247
|
|
|
|
2,587
|
|
|
|
|
|
|
|
2,215
|
|
Gain on sale of equipment
|
|
|
|
|
|
|
(2,428
|
)
|
|
|
(16
|
)
|
|
|
|
|
|
|
(2,444
|
)
|
Changes in operating assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in accounts receivables
|
|
|
|
|
|
|
(23,144
|
)
|
|
|
(31
|
)
|
|
|
|
|
|
|
(23,175
|
)
|
(Increase) decrease in inventories
|
|
|
|
|
|
|
(2,989
|
)
|
|
|
352
|
|
|
|
|
|
|
|
(2,637
|
)
|
(Increase) decrease in other current assets
|
|
|
(2,482
|
)
|
|
|
4,120
|
|
|
|
867
|
|
|
|
|
|
|
|
2,505
|
|
(Increase) decrease in other assets
|
|
|
296
|
|
|
|
101
|
|
|
|
(89
|
)
|
|
|
|
|
|
|
308
|
|
(Decrease) increase in accounts payable
|
|
|
(82
|
)
|
|
|
3,587
|
|
|
|
(5,842
|
)
|
|
|
|
|
|
|
(2,337
|
)
|
(Decrease) increase in accrued interest
|
|
|
11,508
|
|
|
|
(45
|
)
|
|
|
(81
|
)
|
|
|
|
|
|
|
11,382
|
|
(Decrease) increase in accrued expenses
|
|
|
(390
|
)
|
|
|
1,633
|
|
|
|
(371
|
)
|
|
|
|
|
|
|
872
|
|
(Decrease) in other liabilities
|
|
|
(31
|
)
|
|
|
(193
|
)
|
|
|
|
|
|
|
|
|
|
|
(224
|
)
|
(Decrease) increase in accrued salaries, benefits and payroll
taxes
|
|
|
(1,951
|
)
|
|
|
2,780
|
|
|
|
2,563
|
|
|
|
|
|
|
|
3,392
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by operating activities
|
|
|
(11,235
|
)
|
|
|
54,109
|
|
|
|
10,785
|
|
|
|
|
|
|
|
53,659
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions, net of cash acquired
|
|
|
(528,167
|
)
|
|
|
3,649
|
|
|
|
(2,054
|
)
|
|
|
|
|
|
|
(526,572
|
)
|
Notes receivable from affiliates
|
|
|
(585
|
)
|
|
|
|
|
|
|
|
|
|
|
585
|
|
|
|
|
|
Investment in affiliates
|
|
|
(367
|
)
|
|
|
|
|
|
|
|
|
|
|
367
|
|
|
|
|
|
Purchase of property and equipment
|
|
|
|
|
|
|
(33,930
|
)
|
|
|
(5,767
|
)
|
|
|
|
|
|
|
(39,697
|
)
|
Proceeds from sale of property and equipment
|
|
|
|
|
|
|
6,730
|
|
|
|
151
|
|
|
|
|
|
|
|
6,881
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) in investing activities
|
|
|
(529,119
|
)
|
|
|
(23,551
|
)
|
|
|
(7,670
|
)
|
|
|
952
|
|
|
|
(559,388
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91
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 Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from long-term debt
|
|
|
555,000
|
|
|
|
2,820
|
|
|
|
|
|
|
|
|
|
|
|
557,820
|
|
Payments on long-term debt
|
|
|
(42,414
|
)
|
|
|
(9,875
|
)
|
|
|
(1,741
|
)
|
|
|
|
|
|
|
(54,030
|
)
|
Payments on related party debt
|
|
|
|
|
|
|
(3,031
|
)
|
|
|
|
|
|
|
|
|
|
|
(3,031
|
)
|
Net (payments) borrowings on lines of credit
|
|
|
(6,400
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,400
|
)
|
Proceeds from parent contributions
|
|
|
|
|
|
|
367
|
|
|
|
|
|
|
|
(367
|
)
|
|
|
|
|
Accounts receivable from affiliates
|
|
|
(16,077
|
)
|
|
|
|
|
|
|
|
|
|
|
16,077
|
|
|
|
|
|
Accounts payable to affiliates
|
|
|
|
|
|
|
16,060
|
|
|
|
17
|
|
|
|
(16,077
|
)
|
|
|
|
|
Note payable to affiliate
|
|
|
|
|
|
|
|
|
|
|
585
|
|
|
|
(585
|
)
|
|
|
|
|
Proceeds from issuance of common stock, net of offering costs
|
|
|
46,297
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
46,297
|
|
Proceeds from exercise of options and warrants
|
|
|
6,321
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,321
|
|
Tax benefit on stock plans
|
|
|
6,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,440
|
|
Debt issuance costs
|
|
|
(9,863
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,863
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by financing activities
|
|
|
539,304
|
|
|
|
6,341
|
|
|
|
(1,139
|
)
|
|
|
(952
|
)
|
|
|
543,554
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
(1,050
|
)
|
|
|
36,899
|
|
|
|
1,976
|
|
|
|
|
|
|
|
37,825
|
|
Cash and cash equivalents at beginning of year
|
|
|
1,050
|
|
|
|
870
|
|
|
|
|
|
|
|
|
|
|
|
1,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
|
|
|
$
|
37,769
|
|
|
$
|
1,976
|
|
|
$
|
|
|
|
$
|
39,745
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 13
|
RELATED
PARTY TRANSACTIONS
|
DLS largest customer is Pan American Energy which is a
joint venture by British Petroleum and Bridas Corporation. Two
of our Directors, Alejandro P. Bulgheroni and Carlos A.
Bulgheroni, indirectly beneficially own substantially all of the
shares of the Bridas Corporation. In 2008, 2007 and 2006, Pan
American Energy represented 28.5%, 20.7%, and 11.7% of our
consolidated revenues, respectively. At December 31, 2008
and 2007, we had trade receivables with Pan American Energy of
$40.0 million and $23.1 million, respectively.
In 2008 and 2007, we derived revenue of approximately
$1.0 million and $1.7 million from BEUSA Energy, Inc.,
or BEUSA, a company controlled by Alejandro P. Bulgheroni. At
December 31, 2008 and 2007, we had trade receivables from
BEUSA of approximately $558,000 and $1.6 million,
respectively.
We purchase general oilfield supplies and materials from Ralow
Services, Inc., or Ralow. Ralow is owned by Brad A. Adams and
Bruce A. Adams who are brothers of Burt A. Adams, a former
member of our board of directors and our former President and
Chief Operating Officer. We purchased supplies and materials
from Ralow in an aggregate amount of approximately $747,000 and
$3.5 million for the years ended December 31, 2008 and
2007, respectively.
92
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
NOTE 14
|
SEGMENT
INFORMATION
|
On January 31, 2008, we created the positions of Senior
Vice President Oilfield Services and Senior Vice
President Rental Services. In conjunction with this
organizational change, we reviewed the presentation of our
reporting segments during the first quarter of 2008. Based on
this review, we determined that our operational performance
would be segmented and reviewed by the Oilfield Services,
Drilling and Completion and Rental Services segments. The
Oilfield Services segment includes our underbalanced drilling,
directional drilling, tubular services and production services
operations. The Drilling and Completion segment includes our
international drilling operations. As a result, we realigned our
financial reporting segments and now report the following
operations as separate, distinct reporting segments:
(1) Oilfield Services, (2) Drilling and Completion and
(3) Rental Services. Our historical segment data previously
reported for the years ended December 31, 2007 and 2006
have been restated to conform to the new presentation.
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,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services
|
|
$
|
280,835
|
|
|
$
|
233,986
|
|
|
$
|
189,953
|
|
Drilling & Completion
|
|
|
291,335
|
|
|
|
215,795
|
|
|
|
69,490
|
|
Rental Services
|
|
|
103,778
|
|
|
|
121,186
|
|
|
|
51,521
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
675,948
|
|
|
$
|
570,967
|
|
|
$
|
310,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services
|
|
$
|
38,643
|
|
|
$
|
53,218
|
|
|
$
|
43,157
|
|
Drilling & Completion
|
|
|
40,226
|
|
|
|
38,839
|
|
|
|
12,233
|
|
Rental Services
|
|
|
(74,361
|
)
|
|
|
49,139
|
|
|
|
26,293
|
|
General corporate
|
|
|
(18,028
|
)
|
|
|
(16,414
|
)
|
|
|
(13,953
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income (loss) from operations
|
|
$
|
(13,520
|
)
|
|
$
|
124,782
|
|
|
$
|
67,730
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and Amortization Expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services
|
|
$
|
24,725
|
|
|
$
|
16,838
|
|
|
$
|
10,434
|
|
Drilling & Completion
|
|
|
14,316
|
|
|
|
11,288
|
|
|
|
4,074
|
|
Rental Services
|
|
|
28,131
|
|
|
|
26,353
|
|
|
|
7,268
|
|
General corporate
|
|
|
500
|
|
|
|
502
|
|
|
|
343
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depreciation and amortization expense
|
|
$
|
67,672
|
|
|
$
|
54,981
|
|
|
$
|
22,119
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services
|
|
$
|
58,400
|
|
|
$
|
48,610
|
|
|
$
|
29,077
|
|
Drilling & Completion
|
|
|
73,362
|
|
|
|
28,911
|
|
|
|
5,770
|
|
Rental Services
|
|
|
22,550
|
|
|
|
34,883
|
|
|
|
4,538
|
|
General corporate
|
|
|
156
|
|
|
|
747
|
|
|
|
312
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures
|
|
$
|
154,468
|
|
|
$
|
113,151
|
|
|
$
|
39,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
93
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Goodwill:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services
|
|
$
|
23,250
|
|
|
$
|
30,493
|
|
|
$
|
18,199
|
|
Drilling & Completion
|
|
|
20,023
|
|
|
|
1,523
|
|
|
|
1,504
|
|
Rental Services
|
|
|
|
|
|
|
106,382
|
|
|
|
106,132
|
|
General corporate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total goodwill
|
|
$
|
43,273
|
|
|
$
|
138,398
|
|
|
$
|
125,835
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services
|
|
$
|
338,121
|
|
|
$
|
299,300
|
|
|
$
|
215,199
|
|
Drilling & Completion
|
|
|
411,486
|
|
|
|
235,020
|
|
|
|
185,677
|
|
Rental Services
|
|
|
333,894
|
|
|
|
454,216
|
|
|
|
453,802
|
|
General corporate
|
|
|
27,557
|
|
|
|
65,049
|
|
|
|
53,648
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,111,058
|
|
|
$
|
1,053,585
|
|
|
$
|
908,326
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
365,529
|
|
|
$
|
339,476
|
|
|
$
|
231,852
|
|
Argentina
|
|
|
288,792
|
|
|
|
207,491
|
|
|
|
66,516
|
|
Brazil
|
|
|
|
|
|
|
|
|
|
|
|
|
Other international
|
|
|
21,627
|
|
|
|
24,000
|
|
|
|
12,596
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
675,948
|
|
|
$
|
570,967
|
|
|
$
|
310,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Long Lived Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
569,982
|
|
|
$
|
655,513
|
|
|
$
|
574,302
|
|
Argentina
|
|
|
212,456
|
|
|
|
166,972
|
|
|
|
132,955
|
|
Brazil
|
|
|
79,568
|
|
|
|
|
|
|
|
|
|
Other international
|
|
|
23,814
|
|
|
|
13,206
|
|
|
|
20,307
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long lived assets
|
|
$
|
885,820
|
|
|
$
|
835,691
|
|
|
$
|
727,564
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
94
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
NOTE 15
|
SUPPLEMENTAL
CASH FLOWS INFORMATION (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Interest paid
|
|
$
|
46,541
|
|
|
$
|
40,363
|
|
|
$
|
8,571
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes paid
|
|
$
|
20,670
|
|
|
$
|
17,272
|
|
|
$
|
5,796
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other non-cash investing and financing transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Insurance premiums financed
|
|
$
|
2,995
|
|
|
$
|
4,434
|
|
|
$
|
2,871
|
|
Non-cash investing and financing transactions in connection
with acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of Property and equipment
|
|
$
|
|
|
|
$
|
4,345
|
|
|
$
|
109,632
|
|
Fair value of goodwill and other intangibles
|
|
|
3,000
|
|
|
|
350
|
|
|
|
4,010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,000
|
|
|
$
|
4,695
|
|
|
$
|
113,642
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Value of common stock, issued
|
|
$
|
|
|
|
$
|
|
|
|
$
|
94,980
|
|
Seller financed note
|
|
|
|
|
|
|
1,600
|
|
|
|
750
|
|
Deferred tax liability
|
|
|
|
|
|
|
3,095
|
|
|
|
17,662
|
|
Accrued expenses
|
|
|
3,000
|
|
|
|
|
|
|
|
250
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,000
|
|
|
$
|
4,695
|
|
|
$
|
113,642
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 have been named as a defendant in two lawsuits in connection
with our proposed merger with Bronco Drilling, Inc., which was
terminated August 2008. We do not believe that the suits have
any merit.
We are involved in various other legal proceedings in the
ordinary course of business. The legal proceedings are at
different stages; however, we believe that the likelihood of
material loss relating to any such legal proceeding is remote.
|
|
NOTE 17
|
SUBSEQUENT
EVENTS
|
In February 2009, we entered into a new credit agreement in an
amount up to $29.0 million. The credit agreement is subject
to customary closing conditions, with the proceeds being used to
fund 80% of the purchase price of two land drilling rigs
and related equipment that scheduled for delivery in the second
quarter of 2009. The loan will be secured by the equipment and
will be repaid in quarterly installments over six years from the
funding date.
95
ALLIS-CHALMERS
ENERGY INC.
Notes to
Consolidated Financial
Statements (Continued)
In February 2009, we executed a joint venture agreement with
Rawabi Holding Company Ltd., or Rawabi, under the laws of the
Kingdom of Saudi Arabia. The purpose of the joint venture is to
provide oilfield services and rental equipment in the Kingdom of
Saudi Arabia. We will own 50% of the joint venture.
|
|
NOTE 18
|
SUMMARIZED
QUARTERLY FINANCIAL DATA (UNAUDITED) (in thousands, except per
share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Year 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
135,900
|
|
|
$
|
143,362
|
|
|
$
|
147,881
|
|
|
$
|
143,824
|
|
Operating income
|
|
|
31,470
|
|
|
|
41,474
|
|
|
|
31,148
|
|
|
|
20,690
|
|
Net income
|
|
$
|
12,165
|
|
|
$
|
19,504
|
|
|
$
|
12,987
|
|
|
$
|
5,784
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.38
|
|
|
$
|
0.56
|
|
|
$
|
0.37
|
|
|
$
|
0.17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.37
|
|
|
$
|
0.55
|
|
|
$
|
0.37
|
|
|
$
|
0.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
96
|
|
ITEM 9.
|
CHANGES
AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
|
None.
|
|
ITEM 9A.
|
CONTROLS
AND PROCEDURES
|
|
|
(a)
|
Evaluation
Of Disclosure Controls And Procedures
|
Our management, with the participation of our Chief Executive
Officer and Chief Financial Officer, evaluated the effectiveness
of our disclosure controls and procedures (as
defined in Exchange Act
Rules 13a-15(e)
and
15d-15(e)),
as of December 31, 2008. 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, 2008 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. Our evaluation did not include companies which were
acquired during fiscal year 2008, since, under SEC guidelines,
acquisitions do not have to be evaluated until twelve months
after the acquisition date.
In order to evaluate the effectiveness of our internal control
over financial reporting as of December 31, 2008, 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, 2008, our internal controls over financial
reporting are effective based on these criteria.
97
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, 2008, 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
|
None.
PART III
|
|
ITEM 10.
|
DIRECTORS,
EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
|
Pursuant to General Instructions G(3), information on
directors and executive officers of Allis-Chalmers will be filed
in an amendment to this Annual Report on
Form 10-K
or incorporated by reference from our Definitive Proxy Statement
for the 2009 annual meeting of stockholders filed within
120 days of the end of our fiscal year ending
December 31, 2008.
|
|
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 2009 annual meeting of stockholders filed within
120 days of the end of our fiscal year ending
December 31, 2008.
|
|
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 2009 annual meeting of stockholders filed within
120 days of the end of our fiscal year ending
December 31, 2008.
|
|
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 2009 annual meeting of stockholders filed within
120 days of the end of our fiscal year ending
December 31, 2008.
|
|
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 2009 annual meeting of stockholders filed within
120 days of the end of our fiscal year ending
December 31, 2008.
98
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, 2008 and
2007.
Consolidated Statements of Operations for the years ended
December 31, 2008, 2007 and 2006.
Consolidated Statement of Stockholders Equity for the
years ended December 31, 2008, 2007 and 2006.
Consolidated Statements of Cash Flows for the years ended
December 31, 2008, 2007 and 2006.
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.
(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
|
|
|
|
|
|
|
|
|
|
Balance at
|
|
|
Charged to
|
|
|
|
|
|
Balance at
|
|
|
|
Beginning
|
|
|
Costs and
|
|
|
|
|
|
End of
|
|
Description
|
|
of Period
|
|
|
Expense
|
|
|
Deductions
|
|
|
Period
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Year Ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
|
1,924
|
|
|
|
3,283
|
|
|
|
(1,002
|
)
|
|
|
4,205
|
|
Deferred tax assets valuation allowance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
|
826
|
|
|
|
1,309
|
|
|
|
(211
|
)
|
|
|
1,924
|
|
Deferred tax assets valuation allowance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
|
383
|
|
|
|
781
|
|
|
|
(338
|
)
|
|
|
826
|
|
Deferred tax assets valuation allowance
|
|
|
27,131
|
|
|
|
|
|
|
|
(27,131
|
)
|
|
|
|
|
99
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, 2009.
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, 2009
|
|
|
|
|
|
/s/ VICTOR
M. PEREZ
Victor
M. Perez
|
|
Chief Financial Officer
(Principal Financial Officer)
|
|
March 9, 2009
|
|
|
|
|
|
/s/ BRUCE
SAUERS
Bruce
Sauers
|
|
Chief Accounting Officer
(Principal Accounting Officer)
|
|
March 9, 2009
|
|
|
|
|
|
Ali
H. M. Afdhal
|
|
Director
|
|
March 9, 2009
|
|
|
|
|
|
/s/ MUNIR
AKRAM
Munir
Akram
|
|
Director
|
|
March 9, 2009
|
|
|
|
|
|
Alejandro
P. Bulgheroni
|
|
Director
|
|
March 9, 2009
|
|
|
|
|
|
Carlos
A. Bulgheroni
|
|
Director
|
|
March 9, 2009
|
|
|
|
|
|
/s/ VICTOR
F. GERMACK
Victor
F. Germack
|
|
Director
|
|
March 9, 2009
|
|
|
|
|
|
/s/ JAMES
M. HENNESSY
James
M. Hennessy
|
|
Director
|
|
March 9, 2009
|
|
|
|
|
|
John
E. McConnaughy, Jr.
|
|
Director
|
|
March 9, 2009
|
|
|
|
|
|
/s/ ROBERT
E. NEDERLANDER
Robert
E. Nederlander
|
|
Director
|
|
March 9, 2009
|
|
|
|
|
|
Zane
Tankel
|
|
Director
|
|
March 9, 2009
|
|
|
|
|
|
/s/ LEONARD
TOBOROFF
Leonard
Toboroff
|
|
Director
|
|
March 9, 2009
|
100
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).
|
101
|
|
|
|
|
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.
|
|
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).
|
|
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).
|
102
|
|
|
|
|
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).
|
|
10
|
.1
|
|
Amended and Restated Retiree Health Trust Agreement dated
September 14, 1988 by and between Registrant and Wells
Fargo Bank (incorporated by reference to
Exhibit C-1
of the First Amended and Restated Joint Plan of Reorganization
dated September 14, 1988 included in Registrants
Current Report on
Form 8-K
dated December 1, 1988).
|
|
10
|
.2
|
|
Amended and Restated Retiree Health Trust Agreement dated
September 18, 1988 by and between Registrant and Firstar
Trust Company (incorporated by reference to
Exhibit C-2
of the First Amended and Restated Joint Plan of Reorganization
dated September 14, 1988 included in Registrants
Current Report on
Form 8-K
dated December 1, 1988).
|
|
10
|
.3
|
|
Product Liability Trust Agreement dated September 14,
1988 by and between Registrant and Bruce W. Strausberg,
Trustee (incorporated by reference to Exhibit E of the
First Amended and Restated Joint Plan of Reorganization dated
September 14, 1988 included in Registrants Current
Report on
Form 8-K
dated December 1, 1988).
|
|
10
|
.4*
|
|
Allis-Chalmers Savings Plan (incorporated by reference to
Registrants Annual Report on
Form 10-K
for the year ended December 31, 1988).
|
|
10
|
.5*
|
|
Allis-Chalmers Consolidated Pension Plan (incorporated by
reference to Registrants Annual Report on
Form 10-K
for the year ended December 31, 1988).
|
|
10
|
.6
|
|
Agreement dated as of March 31, 1999 by and between
Registrant and the Pension Benefit Guaranty Corporation
(incorporated by reference to Exhibit 10.1 to the
Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 1999).
|
|
10
|
.7
|
|
Letter Agreement dated May 9, 2001 by and between
Registrant and the Pension Benefit Guarantee Corporation
(incorporated by reference to 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).
|
103
|
|
|
|
|
Exhibit
|
|
Description
|
|
|
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*
|
|
Executive Employment Agreement, effective April 3, 2007, by
and between the Registrant and Victor M. Perez (incorporated by
reference to Exhibit 10.4 to the Registrants
Quarterly Report on
Form 10-Q
filed on November 6, 2007).
|
|
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.
|
|
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 10.1 to the
Registrants Current Report on
Form 8-K
filed on July 13, 2007).
|
|
10
|
.17*
|
|
Amendment to Executive Employment Agreement, dated
December 31, 2008, by and between Strata Directional
Technology LLC and David K. Bryan.
|
|
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).
|
|
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*
|
|
2006 Incentive Plan, as amended and restated.
|
104
|
|
|
|
|
Exhibit
|
|
Description
|
|
|
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 December 31, 2008, pursuant to the
Registrants 2006 Incentive Plan.
|
|
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
|
|
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
|
.38
|
|
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
|
.39
|
|
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
|
.40
|
|
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
|
.41
|
|
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
|
.42
|
|
Form of Convertible Subordinated Secured Debenture (incorporate
by reference to Schedule E to Exhibit 10.1 to the
Registrants Current Report on
Form 8-K
filed on February 6, 2008).
|
|
10
|
.43*
|
|
Agreement, dated April 1, 2007, by and between the
Registrant and David Wilde (incorporated by reference to
Exhibit 99.1 to the Registrants Current Report on
Form 8-K
filed on April 3, 2007).
|
105
|
|
|
|
|
Exhibit
|
|
Description
|
|
|
10
|
.44
|
|
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).
|
|
21
|
.1
|
|
Subsidiaries of Registrant.
|
|
23
|
.1
|
|
Consent of UHY LLP.
|
|
31
|
.1
|
|
Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31
|
.2
|
|
Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.1
|
|
Certification of the Chief Executive Officer and Chief Financial
Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
* |
|
Compensation Plan or Agreement |
|
|
|
Filed herewith. |
106