UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
Form 10-K/A
Amendment No. 1
(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2010
OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE TRANSITION PERIOD FROM TO
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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27-3321250 |
(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.) |
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11125 EQUITY DRIVE, SUITE 200, HOUSTON, TEXAS
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77041 |
(Address of principal executive offices)
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(Zip code) |
(713) 856-4222
Registrants telephone number, including area code
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: None
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule
405 of the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to
Section 13 or 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days. Yes o No þ
Indicate by check mark whether the registrant has submitted electronically and posted on
it corporate Website, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files).
Yes o No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation
S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of
registrants knowledge, in definitive proxy or information statements incorporated by reference in
Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act):
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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) |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2
of the Act). Yes o No þ
The aggregate market value of the common equity held by non-affiliates of the registrant,
computed using the closing price of the common stock of $2.06 per share on June 30, 2010, as
reported on the New York Stock Exchange, was approximately $73,905,369.
As of August 26, 2011 there were 1,000 shares of common stock issued and outstanding.
Allis-Chalmers Energy Inc. meets the conditions set forth in general instruction I(1)(a)
and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.
TABLE OF CONTENTS
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EX-23.1 |
EX-31.1 |
EX-31.2 |
EX-32.1 |
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DEFINITIONS
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blow out preventers
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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 preventers and the
annulus of the well. |
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coiled tubing
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A small diameter tubing used to service producing and problematic wells and to work in
high pressure applications during drilling, production and workover operations. |
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directional drilling
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The technique of drilling a well while varying the angle of direction of a well and
changing the direction of a well to hit a specific target. |
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double studded adapter
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A device that joins two dissimilar connections on certain equipment, including valves,
piping and blow-out preventers. |
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drill pipe
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A pipe that attaches to the drill bit to drill a well. |
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foam unit
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A compressor, a booster, a mist pump and a fuel tank all mounted together on one flat
bed trailer to be used for completion, workover and/or shallow drilling operations.
Foam units are designed to provide a small footprint and easy transport. |
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horizontal drilling
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The technique of drilling wells at a 90-degree angle. |
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land drilling rig
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Composed of a drawworks or hoist, a derrick, a power plant, rotating equipment and pumps
to circulate the drilling fluid and the drill string. |
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measurement-while-drilling
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The technique used to measure direction and angle while drilling a well. |
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mist pump
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A drilling pump that uses mist as the circulation medium for injecting small amounts of
foaming agent, corrosion agent and other chemical solutions into the well. |
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pulling rig
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A type of well-servicing rig used to pull downhole equipment, such as tubing, rods or
the pumps from a well, and replace them when necessary. A pulling rig is also used to
set downhole tools and perform lighter jobs. |
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service rig
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A type of well-servicing rig which can function as either a workover or as a pulling rig. |
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spacer spools
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High pressure connections or links which are stacked to elevate the blow out preventers
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 preventers. |
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tubing
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A pipe placed inside the casing to allow the well to produce. |
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tubing work strings
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The tubing used on workover rigs through which high pressure
liquids, gases or mixtures are pumped into a well to perform
production operations. |
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underbalanced drilling
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A technique in which oil, natural gas, or geothermal wells are
drilled by creating a pressure within the well that is lower than
the reservoir pressure. The result is increased rate of
penetration, reduced formation damage and reduced drilling costs. |
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wear bushings
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A device placed inside a wellhead to protect the wellhead from wear. |
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workover rigs
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Similar to a land drilling rig, however, they are smaller than the
drilling rig for the same depth of well. These rigs are used to
complete the drilled wells or to repair them whenever necessary. |
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SPECIAL NOTE
REGARDING FORWARD-LOOKING STATEMENTS
This annual report contains forward-looking statements within the meaning of Section 27A
of the Securities Act of 1933, as amended, or the Securities Act, regarding our business, financial
condition, results of operations and prospects. Words such as expects, anticipates, intends,
plans, believes, seeks, estimates and similar expressions or variations of such words are intended
to identify forward-looking statements. However, these are not the exclusive means of identifying
forward-looking statements. Although such forward-looking statements reflect our good faith
judgment, such statements can only be based on facts and factors currently known to us.
Consequently, forward-looking statements are inherently subject to risks and uncertainties, and
actual outcomes may differ materially from the results and outcomes discussed in the
forward-looking statements. These factors include, but are not limited to, the following:
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the impact of the weak economic conditions and the future impact of such conditions on
the oil and natural gas industry and demand for our services; |
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unexpected future capital expenditures (including the amount and nature thereof); |
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unexpected difficulties in integrating our operations as a result of any significant
acquisitions; |
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adverse weather conditions in certain regions; |
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the impact of political disturbances, war, or terrorist attacks and changes in global
trade policies; |
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the availability (or lack thereof) of capital to fund our business strategy and/or
operations; |
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the potential impact of the loss of one or more key employees; |
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the effect of environmental liabilities that are not covered by an effective indemnity
or insurance; |
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the impact of current and future laws; |
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the impact of customer defaults and related bad debt expense; |
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the potential impairment in the carrying value of goodwill and other acquired intangible
assets; |
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the risks associated with doing business outside the United States, including currency
exchange rates; |
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the effects of competition; and |
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the effects of our indebtedness, which could adversely restrict our ability to operate,
could make us vulnerable to general adverse economic and industry conditions, could place
us at a competitive disadvantage compared to competitors that have less debt, and could
have other adverse consequences |
Further information about the risks and uncertainties that may impact us are described in
Risk Factors beginning on page - 11 - 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.
EXPLANATORY NOTE
We are filing this Amendment No. 1 on Form 10-K/A (the Amendment) to our Annual Report
on Form 10-K for the year ended December 31, 2010, filed with the Securities and Exchange
Commission, or SEC, on March 15, 2011 (the Original Filing) to amend and restate our audited
financial statements and related disclosures for the year ended December 31, 2010, as discussed in
Note 2 to the accompanying restated audited financial statements.
On July 25, 2011, our management concluded that the previously filed consolidated financial
statements for the fourth quarter and for the year ended December 31, 2010 were no longer reliable.
The restatement is necessitated by our determination that positive evidence available at year end
2010 was not sufficient to overcome the negative evidence around the deferred tax assets and to
justify not booking a valuation allowance against federal income tax assets and foreign tax
credits. The correction of this error resulted in a $37.4 million increase in the deferred tax
valuation allowance and income tax expense. As a result of this determination, management
concluded that a material weakness in the Companys internal control over financial reporting over
the calculation and valuation of deferred tax assets, the related income tax provision and the
related financial statement disclosures existed as of December 31, 2010. Further explanation of
the error and the impact on Allis-Chalmers financial statements and
internal control over financial reporting is contained in Note 2 to the financial statements
contained in Part II, Item 8 and in Part 9 of this Amendment.
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This Amendment includes our restated financial statements as of and for the year ended
December 31, 2010 to correct our income tax expense, deferred tax asset, net loss and accumulated
deficit with accompanying notes. We have not changed any information included in the Original
Filing that is not affected by the restatement or the material weakness in the Companys internal
control over financial reporting. Accordingly, the information included in the Original Filing and
included in this Amendment that is not affected by the restatement or the material weakness
describes conditions as they existed and were presented in the Original Filing at the time we filed
that report with the SEC on March 15, 2011.
The following items have been amended:
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Part I Item 1A. Risk Factors |
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Part II Item 7. Managements Discussion and Analysis of Financial Condition and
Results of Operations |
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Part II Item 8. Financial Statements and Supplementary Data |
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Part II Item 9A. Control and Procedures |
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Part IV Item 15. Exhibits and Financial Statement Schedules |
In accordance with applicable SEC rules, this Amendment includes certifications from our Chief
Executive Officer and Chief Financial Officer dated as of the date of this filing.
As used herein, Allis-Chalmers, we, our and us may refer to Allis-Chalmers Energy Inc.
or its subsidiaries. The use of these terms is not intended to connote any particular corporate
status or relationship.
PART I
We provide services and equipment to oil and natural gas exploration and production companies
throughout the United States including Texas, Louisiana, Pennsylvania, West Virginia, Wyoming,
Oklahoma, offshore in the Gulf of Mexico, and internationally primarily in Argentina, Brazil,
Bolivia and Mexico. Our central operating strategy is to provide high-quality, technologically
advanced services and equipment. As a result of our commitment to customer service, we have
developed strong relationships with many of the leading oil and natural gas companies, including
both independents and majors.
Our growth strategy is focused on identifying and pursuing opportunities in markets, products
and services we believe will grow faster than the overall oilfield services industry and
opportunities which we believe help us to mitigate cyclical risk by diversifying our cash flow,
both domestically and internationally. Over the past several years, we have significantly expanded
the geographic scope of our operations and the range of services we provide through strategic
acquisitions and organic growth. Our organic growth has primarily been achieved by expanding our
geographic scope, acquiring complementary property and equipment, hiring personnel to service new
regions and cross-selling our products and services.
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Our History
We were incorporated in 1913 under Delaware law. We reorganized in bankruptcy in 1988 and
sold all of our major businesses. From 1988 to May 2001, we had only one operating company in the
equipment repair business, which was sold in December 2001.
In May 2001, under new management, we embarked on a new course of direction into the oilfield
service industry. Since 2001, we have completed 25 acquisitions, including six in 2005, six in
2006, four in 2007, one in 2008 and one in 2010. Our first series of acquisitions became the
backbone of our Oilfield Services segment. In May 2001, we entered the underbalanced drilling
market and then in February of 2002 we entered the directional drilling business and the tubular
services business. In December 2004, we entered the production services business. We have
improved our product line offerings by completing additional acquisitions for all product lines.
We also disposed of some nonstrategic assets in our production services business in June 2007 and
in our tubular services business in August 2008.
In September 2004, we entered the Rental Services market which we subsequently expanded with
acquisitions in April 2005 and January and December 2006. In July 2010, we acquired American Well
Control, Inc., or AWC, as an expansion of our portfolio of services in our Rental Services segment.
AWC is a leading manufacturer of premium high-pressure valves used in hydraulic fracturing in the
unconventional gas shale plays. As a result of these acquisitions, we are now a major provider of
oilfield rental tools primarily in the Gulf Coast region of the United States.
In August 2006, we entered the Drilling and Completion business with the acquisition of DLS
Drilling, Logistics & Services Corporation, or DLS, in Argentina. Subsequently, in December 2008,
we increased our business in this segment with the acquisition of BCH Ltd, or BCH, in Brazil.
On August 12, 2010, we entered into a merger agreement with Seawell Limited, or Seawell, and
Wellco Sub Company, a wholly owned subsidiary of Seawell. On February 23, 2011, the merger
transactions closed and we merged with and into Wellco Sub Company, becoming a wholly owned
subsidiary of Seawell under the name Allis-Chalmers Energy Inc. Following the merger, Seawell
and its subsidiaries, including us, have begun operating under the name Archer; however, our legal
name will remain Allis-Chalmers Energy Inc. until further notice.
As a result of these transactions, our prior results may not be indicative of current or
future operations. Segment and geographic financial information appears in Item 8. Financial
Information Notes to Consolidated Financial Statements Note 16.
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 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 United States, according to Baker Hughes,
peaked at 2,031 in August of 2008. In the last quarter of 2008, the rig count in the United States
began to drop due to the weakening United States 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. The Baker Hughes United States rig count decreased to 876 in June 2009 and then
gradually began to improve in response to increased prices and more stable natural gas prices. As
of March 4, 2011, the Baker Hughes United States rig count stood at 1,707.
Business Segments
We conduct our operations through three principal segments:
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Oilfield Services. This segment includes the following oilfield service divisions:
directional drilling services, casing and tubular services, underbalanced drilling
services and production services. |
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Drilling and Completion. This segment includes drilling, completion, workover and
related services. |
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Rental Services. This segment includes the rental of specialized oilfield equipment. |
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Oilfield Services. We utilize state-of-the-art equipment to provide well planning and
engineering services, directional drilling packages, downhole motor technology, well site
directional supervision, exploratory and development re-entry drilling, downhole guidance services
and other drilling services to our customers, including measurement-while-drilling (MWD) services.
We provide compressed air equipment, chemicals and other specialized products for underbalanced
drilling and production applications. We also provide specialized equipment and trained operators
to perform a variety of pipe handling services, including installing casing and tubing, changing
out drill pipe and retrieving production tubing for both onshore and offshore drilling and workover
operations, which we refer to as tubular services. In addition, we provide a variety of quality
production-related rental tools and equipment and services, including wire line support services
and coiled tubing.
According to Baker Hughes, as of March 4, 2011, 71% of the active drilling rigs in the United
States were drilling directionally and/or horizontally. We believe directional drilling offers
several advantages over conventional drilling including: 1) improvement of total cumulative
recoverable reserves; 2) improved reservoir production performance beyond conventional vertical
wells; and 3) reduction of the number of field development wells.
We currently maintain an inventory of approximately 338 drilling motors which are utilized in
our directional drilling services. Our straight-hole motors offer an opportunity to capture
additional market share. We currently provide directional drilling services primarily in Texas,
Wyoming, Pennsylvania, Louisiana and Oklahoma.
All wells drilled for oil and natural gas require casing to be installed for drilling, and if
the well is producing, tubing will be required in the completion phase. We currently provide
tubular services primarily in Texas, Louisiana and both onshore and offshore in the Gulf of Mexico
and Mexico.
Underbalanced drilling shortens the time required to drill a well and enhances production by
minimizing formation damage. We currently have a combined fleet of approximately 233 compressors,
boosters and foam units which are utilized in our underbalanced services. We believe we are one of
the largest providers of underbalanced drilling services in the United States. We also provide
premium air hammers and bits to oil and natural gas companies for use in underbalanced drilling.
Our broad and diversified product line enables us to compete in the underbalanced market with
equipment and services packages engineered and customized to specifically meet customer
requirements. We currently provide underbalanced drilling services primarily in Pennsylvania,
Arkansas, West Virginia, New Mexico and Texas.
Our production services product line is focused on coiled tubing services and rental of
various tools used in the production process. We currently provide production services primarily
in Texas, Louisiana, West Virginia and Pennsylvania.
Drilling and Completion. We provide drilling, completion, workover and related services for
oil and natural gas wells. We service the San Jorge, Cuyan, Neuquen, Austral and Noroeste basins
of Argentina and the Espirito Santo, Potiguar, Reconcavo, Sergipe/Alagoas, Sao Francisco and Campos
basins of Brazil and in Bolivia. We also offer a wide variety of other oilfield services such as
drilling fluids and completion fluids and engineering and logistics to complement our customers
field organization. We provide the rigs and drilling crews and we also provide rig management
services on a variety of rigs, consisting of technical drilling assistance, personnel, repair and
maintenance services and drilling operation management services.
Our Drilling and Completion segment was established with the acquisition of DLS in August 2006
for a purchase price of approximately $114.5 million. We expanded our Drilling and Completion
segment with the acquisition of BCH, which operates in Brazil. In 2008, we invested $40.0 million
into BCH via a 15% convertible subordinated secured debenture and we acquired the common stock of
BCH for a total purchase price of $56.1 million. We currently operate a fleet of 77 land rigs,
including 18 drilling rigs and 48 service rigs (workover and pulling units) in Argentina, seven
drilling rigs and one service rig in Brazil and three drilling rigs in Bolivia. In 2007, we
placed orders for four drilling rigs and 16 service rigs. All of the service rigs and one of the
drilling rigs were placed into service in Argentina at various dates in 2008. A second drilling
rig was activated in Argentina in March 2009. The remaining two drilling rigs were sold to the
manufacturer due to an operational problem and we realized a $10.6 million loss on the transaction
in 2010. Additionally in 2008, we placed orders for two 1600 horsepower drilling rigs from a
different manufacturer and both of those rigs were completed in the fourth quarter of 2010. One of
those rigs was placed in service in Texas in January 2011, while the remaining rig has been awarded
a two year contract in Argentina and it will be mobilized there.
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Rental Services. We provide specialized oilfield rental equipment, including premium drill
pipe, spiral heavy weight drill pipe, tubing work strings, blow out preventers, choke manifolds and
various valves and handling tools, for both onshore and offshore well drilling, completion and
workover operations. Most wells drilled for oil and natural gas require some form of rental
equipment in both the drilling and completion of a well. We have an inventory of specialized
equipment, which includes double studded adapters, test plugs, wear bushings, adaptor spools,
baskets, spacer spools and other assorted handling tools in various sizes to meet our customers
demands. We charge customers for rental equipment on a daily basis. Our customers are liable for
the cost of inspection, repairs and lost or damaged equipment. We currently provide rental
equipment primarily in Texas, Louisiana, Pennsylvania, offshore in the Gulf of Mexico and
internationally in Mexico, Columbia and Egypt.
Customers
In 2010, 2009 and 2008, one of our customers, Pan American Energy, or PAE, represented
approximately 31.1%, 35.5% and 28.5% of our consolidated revenues, respectively. PAE is now wholly
owned by Bridas Corporation, and Bridas Corporation is owned 50% by Bridas Energy Holdings Ltd and
50% by CNOOC International Limited. Alejandro P. Bulgheroni, one of the directors of our parent
company, may be deemed to indirectly beneficially own 50% of the outstanding capital stock of
Bridas Energy Holdings Ltd and is a member of the Management Committee of PAE. The loss without
replacement of any 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 four major directional drilling companies, Schlumberger,
Halliburton, Baker Hughes and Weatherford, that market worldwide, as well as numerous smaller
regional players. Significant competitors in the tubular markets we serve include Franks Casing
Crew and Rental Tools, Weatherford, Baker Hughes, Tesco and Premier. These markets remain highly
competitive and fragmented with numerous casing and tubing crew companies working in the United
States. Our primary competitors in Mexico are South American Enterprises and Weatherford, both of
which provide similar products and services. Our largest competitor for underbalanced drilling
services is Weatherford. Weatherford focuses on large projects, but also competes in the more
common compressed air, mist, foam and aerated mud drilling applications. Other competition comes
from smaller regional companies. In the production services market there are numerous competitors,
most of which have larger coiled tubing services operations than us including Schlumberger,
Halliburton, Baker Hughes, Weatherford and Premier.
Our five largest competitors in the Drilling and Completion segment, which operate primarily
in Argentina, are Servicios WellTech, Ensign Energy Services, Nabors and Helmerich & Payne, and San
Antonia Global Ltd in Brazil.
The Rental Services business is highly fragmented with hundreds of companies offering various
rental tool services. Our largest competitors include Weatherford, Quail Rental Tools, Knight
Rental Tools, Superior Energy Services (Workstrings) and Schlumberger (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.
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Employees
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 March 1, 2011, we had approximately 3,750 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 (See Item 1A. Risk Factors Risks Associated with Our Company).
Seasonality
Oil and natural gas operations of our customers located offshore and onshore in the United
States 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 United States 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 United
States are also adversely affected by seasonal weather conditions. These weather conditions limit
our access to these job sites and our ability to service wells in these areas. These constraints
decrease drilling activity and the resulting shortages or high costs could delay our operations and
materially increase our operating and capital costs.
Federal Regulations and Environmental Matters
Our operations are subject to federal, state and local laws and regulations relating to the
energy industry in general and the environment in particular. Environmental laws have in recent
years become more stringent and have generally sought to impose greater liability on a larger
number of potentially responsible parties. Because we provide services to companies producing oil
and natural gas, which are toxic substances, we may become subject to claims relating to the
release of such substances into the environment. While we are not currently aware of any situation
involving an environmental claim that would likely have a material adverse effect on us, it is
possible that an environmental claim could arise that could cause our business to suffer. We do
not anticipate any material expenditures to comply with environmental regulations affecting our
operations.
In addition to claims based on our current operations, we are from time to time named in
environmental claims relating to our activities prior to our reorganization in 1988 (See Item 3.
Legal Proceedings).
Intellectual Property Rights
Except for our relationships with our customers and suppliers described above, we do not own
any patents, trademarks, licenses, franchises or concessions which we believe are material to the
success of our business.
Available Information
We have publicly traded, registered debt securities, which require us to file reports with the
Securities and Exchange Commission, or SEC. All of our SEC filings, which include our annual
reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to
those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act
of 1934, as amended, or the Exchange Act, are made available free of charge on our web site at
www.alchenergy.com as soon as reasonably practicable after we electronically file or furnish them
to the SEC.
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Information contained on or connected to our website is not incorporated by reference into
this annual report on Form 10-K and should not be considered part of this report or any other
filing we make with the SEC.
Our business, financial condition, results of operations and the trading price of our
securities can be materially and adversely affected by many events and conditions, including the
following:
Risks Associated With Our Industry
Global political, economic and market conditions could negatively impact our business.
Our operations are affected by global political, economic and market conditions and the
condition of the oil and natural gas industry. Our operating results and the forward-looking
information we provide are based on our current assumptions about oil and natural gas supply and
demand, oil and natural gas prices, rig count and other market trends. Our assumptions on these
matters are in turn based on currently available information, which is subject to change. The oil
and natural gas industry is extremely volatile and subject to change based on political and
economic factors outside our control. This volatility caused oil and natural gas companies and
drilling contractors to change their strategies and expenditure levels late in 2008 and in 2009.
We have experienced in the past, and expect to experience in the future, significant fluctuations
in operating results based on these changes.
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The Deepwater Horizon incident in the United States Gulf of Mexico and its consequences,
including the potential enactment of further restrictions or regulations on offshore drilling,
could have a material adverse effect on our business. |
On April 20, 2010, a fire and explosion occurred onboard the semisubmersible drilling rig
Deepwater Horizon, which was owned by Transocean Ltd. and under contract to a subsidiary of BP plc.
The accident resulted in the loss of life and a significant oil spill. In response to this
incident, the Minerals Management Service of the United States Department of Interior, or the MMS,
issued a notice on May 30, 2010 implementing a six-month moratorium on certain drilling activities
in the United States Gulf of Mexico. The notice also stated that the MMS would not consider
drilling permits for new wells and related activities for specified water depths during the
six-month moratorium period.
On October 12, 2010, the moratorium was lifted, and deepwater oil and natural gas drilling in
the United States Gulf of Mexico has been allowed to resume, provided that operators certify
compliance with all existing rules and requirements, including those that recently went into
effect, and demonstrate the availability of adequate blowout containment resources. The first
drilling permit was not issued until March 2011.
Our business has historically been very dependent on drilling activity in the United States
Gulf of Mexico. Although the moratorium on oil and natural gas drilling in the United States Gulf
of Mexico has been lifted, new guidelines, regulations and restrictions could increase the costs of
exploration and production, reduce the area of operations and result in further permitting delays.
These may include new or additional bonding and safety requirements and other requirements
regarding certification of equipment. There is no assurance that operations related to drilling
offshore in the United States will reach the same levels that existed prior to the moratorium. The
delay in resuming these activities or the failure of these activities to reach levels that existed
prior to the moratorium has and could continue to adversely impact our operating results. The
enactment of stricter restrictions on offshore drilling or further regulation of offshore drilling
or contracting services operations could materially affect our business, financial condition and
results of operations.
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. Many other oilfield services
companies are larger than we are and have resources that are significantly greater than our
resources. These competitors are better able to withstand industry downturns, compete on the basis
of price and acquire new equipment and technologies, all of which could affect our revenues and
profitability. These competitors compete with us both for customers and for acquisitions of other
businesses. This competition may cause our business to suffer. We believe that competition for
contracts will continue to be intense in the foreseeable future.
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Risks Associated With Our Company
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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.
Any prolonged reduction in oil and natural gas prices will depress levels of exploration,
development, and production activity. Such price declines reduce drilling activity and demand for
our services, which could lead to lower pricing for our products and services. Accordingly,
prolonged periods of lower drilling activity and the reduction in our customers expenditures could
have a materially adverse effect on our financial condition, results of operations and cash flows.
Oil and natural gas prices depend on many factors beyond our control, including the following:
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economic conditions in the United States and elsewhere; |
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changes in global supply and demand for oil and natural gas; |
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the level of production of the Organization of Petroleum Exporting Countries, commonly
called OPEC; |
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the level of production of non-OPEC countries; |
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the price and quantity of imports of foreign oil and natural gas; |
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political conditions, including embargoes, in or affecting other oil and natural gas
producing activities; |
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the level of global oil and natural gas inventories; |
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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. |
Limitations on the availability of capital, or higher costs of capital, for financing
expenditures may cause oil and natural gas producers to make additional reductions to capital
budgets in the future even if commodity prices remain at historically high levels.
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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 United
States, Argentina, Brazil, Mexico and elsewhere. Historically, we have been dependent upon a few
customers for a significant portion of our revenues. In 2010, 2009 and 2008, one of our customers,
PAE represented 31.1%, 35.5% and 28.5% of our consolidated revenues, respectively. PAE also
contributes a majority of the revenue derived from our Drilling and Completion operations. In 2010,
2009 and 2008, PAE represented 54.2%, 59.2% and 66.0% of our Drilling and Completion revenues,
respectively.
The strategic agreement with PAE currently has an expiration date of June 30, 2011. However,
PAE 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 PAE. In addition, our results of operations could be
materially adversely affected if any of our major customers terminates its contracts with us, fails
to renew its existing contracts or refuses to award new contracts to us and we are unable to enter
into contracts with new customers at comparable rates.
This concentration of customers may increase our overall exposure to credit risk. Our
customers could similarly be affected by changes in economic and industry conditions. Our
financial condition and results of operations could 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.
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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.
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If we are unable to renew or obtain new and favorable contracts for rigs whose contracts are
expiring or are terminated, our revenues and profitability could be materially reduced. |
We have a number of contracts that will expire in 2011. Our ability to renew these contracts
or obtain new contracts and the terms of any such contracts will depend on market conditions. We
may be unable to renew our expiring contracts or obtain new contracts for the rigs under contracts
that have expired or been terminated, and the dayrates under any new contracts may be substantially
below the existing dayrates, which could materially reduce our revenues and profitability.
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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.
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The loss of the services of key executives or our failure to attract and retain skilled workers
and key personnel could hurt our operations. |
We are dependent upon the efforts and skills of our executives to manage our business,
identify and consummate additional acquisitions and obtain and retain customers. We do not
maintain key man insurance on any of our personnel.
In addition, companies in our industry, including us, are dependent upon the available labor
pool of skilled employees. Our development and expansion will require additional experienced
management and operations personnel. No assurance can be given that we will be able to identify
and retain these employees. We compete with other oilfield services businesses and other employers
to attract and retain qualified personnel with the technical skills and experience required to
provide our customers with the highest quality service. We are also subject to the Fair Labor
Standards Act, which governs such matters as minimum wage, overtime and other working conditions.
A shortage in the labor pool of skilled workers, increases in wage rates or changes in applicable
laws and regulations could make it more difficult for us to attract and retain personnel and could
require us to enhance our wage and benefits packages. There can be no assurance that labor costs
will not increase. Any increase in our operating costs could cause our business to suffer.
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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.
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The Argentine government has in the past and may in the future promulgate laws, regulations
and decrees requiring companies in the private sector to maintain minimum wage levels and provide
specified benefits to employees, including significant mandatory severance payments. It is possible
the government will adopt measures that will increase salaries or require our Drilling and
Completion business to provide additional benefits, which would increase our costs and potentially
reduce our profitability, cash flow and/or liquidity. In addition, in many of the countries in
which we operate, our workforce has certain compensation and other rights arising from our various
collective bargaining agreements and from statutory requirements of those countries relating to
involuntary terminations. If we choose to cease operations in one of those countries or if market
conditions reduce the demand for our drilling services in such a country, we could incur costs,
which may be material, associated with workforce reductions.
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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.
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Severe weather could have a material adverse impact on our business. |
Our business could be materially and adversely affected by severe weather. Repercussions of
severe weather conditions may include:
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curtailment of services; |
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weather-related damage to facilities and equipment resulting in suspension of operations; |
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inability to deliver materials to job sites in accordance with contract schedules; and |
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loss of productivity. |
For example, oil and natural gas operations of our customers located offshore and onshore in
the Gulf of Mexico and in Mexico have from time to time been adversely affected by floods,
hurricanes and tropical storms, resulting in reduced demand for our services. In 2008, Hurricanes
Gustav and Ike disrupted our operations along the Texas and Louisiana Gulf Coast and the East
Texas/West Louisiana corridor. Further, our customers operations in the Mid-Continent and Rocky
Mountain regions of the United States are also adversely affected by seasonal weather conditions.
This limits our access to these job sites and our ability to service wells in these areas. These
constraints decrease drilling activity and the resulting shortages or high costs could delay our
operations and materially increase our operating and capital costs.
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We have recorded substantial goodwill as the result of our acquisitive nature and as such
goodwill is subject to periodic reviews of impairment. |
We perform purchase price allocations to intangible assets when we make a business
combination. Business combinations and purchase price allocations have been consummated for
acquisitions in all of our reportable segments. The excess of the purchase price after allocation
of fair values to tangible assets is allocated to identifiable intangibles and thereafter to
goodwill. We conduct periodic reviews of goodwill for impairment in value. Any impairments would
result in a non-cash charge against earnings in the period reviewed, which may or may not create a
tax benefit, and would have a corresponding decrease in stockholders equity.
We reviewed goodwill at December 31, 2010 and 2009 and recorded no impairment but based on our
review of goodwill at December 31, 2008 we recorded an impairment of $115.8 million, which was all
of our goodwill for the Rental Services segment as well as the impairment of goodwill associated
with our Tubular Services and Production Services businesses within our Oilfield Services segment.
In the event that market conditions deteriorate or we have a prolonged downturn, we may be required
to record an additional impairment of goodwill and such impairment could be material.
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Future growth could impact our ability to maintain effective disclosure controls and
procedures and/or internal controls over financial reporting, which could have a material
adverse effect on our operations. |
As part of our growth strategy, we may make additional strategic acquisitions of privately
held businesses. It is likely that our future acquired businesses will not have been required to
maintain such disclosure controls and procedures or internal controls prior to their acquisition.
Likewise, upon the completion of any future acquisition, we will be required to integrate the
acquired business into our consolidated companys system of disclosure controls and procedures and
internal controls over financial reporting, but we cannot assure you as to how long the integration
process may take for any business that we may acquire. Furthermore, during the integration
process, we may not be able to fully implement our consolidated disclosure controls and internal
controls over financial reporting. This could result in significant delays and costs to us and
could require us to divert substantial resources, including management time, from other activities.
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We have discovered material weaknesses in our internal accounting controls and our inability to
correct these weaknesses could reduce confidence in our financial statements. |
Management, through documentation, testing and assessment of our internal control over
financial reporting pursuant to the rules promulgated by the SEC under Section 404 of the
Sarbanes-Oxley Act of 2002 and Item 308 of Regulation S-K, has concluded that our internal control
over financial reporting had a material weakness in accounting for income taxes as of December 31,
2010. See Item 9A Controls and Procedures. The Public Company Accounting Oversight Board
(United States) (PCAOB) defines a material weakness as a control deficiency, or combination of
control deficiencies, in internal control over financial reporting such that there is a reasonable
possibility that a material misstatement of annual or interim financial statements will not be
prevented or detected on a timely basis.
If we are unable to correct the identified deficiencies in our internal control, or if we
identify other material weaknesses or deficiencies in the future 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, or |
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adversely affect our ability to timely file our periodic reports with the SEC. |
Any failure to timely file our periodic reports with the SEC may give rise to a default under
the indentures governing our outstanding 9.0% senior notes due 2014, 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, 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 other credit agreements. 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.
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We do business in international jurisdictions whose political and regulatory environments and
compliance regimes differ from those in the United States. |
A significant amount of our revenue is attributable to operations in foreign countries. These
activities accounted for approximately 59.2% of our consolidated revenue in the year ended December
31, 2010. Risks associated with our operations in foreign areas include, but are not limited to:
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political instability, terrorist acts, war and civil disturbances; |
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changes in laws or policies regarding the award of contracts; |
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the inability to collect or repatriate currency, income, capital or assets; |
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expropriation of assets; |
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nationalization of components of the energy industry in the geographic areas where we
operate; |
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foreign currency fluctuations and devaluation; and |
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new economic and tax policies. |
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 United States dollar exchange rate. To the extent
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possible, we seek to limit our exposure to local currencies by matching the acceptance of
local currencies to our local expense requirements in those currencies. Although we have done this
in the past, we may not be able to take these actions in the future, thereby exposing us to foreign
currency fluctuations that could cause our results of operations, financial condition and cash
flows to deteriorate materially.
Additionally, in some jurisdictions we are subject to foreign governmental regulations
favoring or requiring the awarding of contracts to local contractors or requiring foreign
contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These
regulations may adversely affect our ability to compete. Our international business operations also
include projects in countries where governmental corruption has been known to exist. We are
subject to the anti-bribery restrictions of the Foreign Corrupt Practices Act, which make it
illegal to give anything of value to foreign officials or employees or agents of nationally owned
oil companies in order to obtain or retain any business or other advantage.
Violations of these laws could result in monetary and criminal penalties against us or our
subsidiaries and could damage our reputation and, therefore, our ability to do business.
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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 United States dollar. We
cannot predict how these uncertainties will affect our financial results, but there is a risk that
our financial performance could be adversely affected. Moreover, we cannot predict whether the
Argentine government will further modify its monetary policy and, if so, what effect any of these
changes could have on the value of the Argentine Peso. Such changes could have an adverse effect
on our financial condition and results of operations. Similar economic and political turmoil in
Mexico and Brazil could also expose us to unpredictable currency exchange rates in these countries
that may result in an adverse effect on our financial condition and results of operations.
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Argentina continues to face considerable political and economic uncertainty. |
Although general economic conditions have shown improvement and political protests and social
disturbances have diminished considerably since the economic crisis of 2001 and 2002, the rapid and
radical nature of the changes in the Argentine social, political, economic and legal environment
over the past several years and the absence of a clear political consensus in favor of any
particular set of economic policies have given rise to significant uncertainties about the
countrys economic and political future. It is currently unclear whether the economic and
political instability experienced over the past several years will continue and it is possible
that, despite recent economic growth, Argentina may return to a deeper recession, higher inflation
and unemployment and greater social unrest. If instability persists, there could be a material
adverse effect on our results of operations and financial condition.
In the event of further social or political crisis, companies in Argentina may also face the
risk of further civil and social unrest, strikes, expropriation, nationalization, forced
renegotiation or modification of existing contracts and changes in taxation policies, including
royalty and tax increases and retroactive tax claims.
An increase in inflation in Argentina could have a material adverse effect on our results of
operations.
Historically, the devaluation of the Argentine Peso has created pressures on the domestic
price system that generated high rates of inflation. We cannot assure you that inflation rates
will remain stable in the future. Significant inflation in Argentina could have a material adverse
effect on our results of operations and financial condition.
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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
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become more stringent in recent years and may in certain circumstances impose strict
liability, rendering us liable for environmental and natural resource damages without regard to
negligence or fault on our part. These laws and regulations may expose us to liability for the
conduct of, or conditions caused by, others or for acts that were in compliance with all applicable
laws at the time the acts were performed. The application of these requirements, the modification
of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory
or development drilling for oil and gas could materially limit future contract drilling
opportunities or materially increase our costs or both.
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Existing or future laws, regulations, treaties or international agreements related to greenhouse
gases and climate change could have a negative impact on our business and may result in
additional compliance obligations with respect to the release, capture, and use of carbon
dioxide that could have a material adverse effect on our liquidity, consolidated results of
operations, and consolidated financial condition. |
International, national, and state governments and agencies are currently evaluating and
promulgating climate-related legislation and regulations that are focused on restricting greenhouse
gas (GHG) emissions. In the United States, the Environmental Protection Agency (EPA) is taking
steps to require monitoring and reporting of GHG emissions and to regulate GHGs as pollutants under
the Clean Air Act (CAA). The EPAs Mandatory Reporting of Greenhouse Gases rule established a
comprehensive scheme of regulations that require monitoring and reporting of GHG emissions that
began in 2010. Furthermore, the EPA recently proposed additional GHG reporting rules specifically
for the oil and gas industry. The EPA has also published a final rule, the Endangerment Finding,
finding that GHGs in the atmosphere endanger public health and welfare, and that emissions of GHGs
from mobile sources cause or contribute to the GHG pollution. Following issuance of the
Endangerment Finding, the EPA promulgated final motor vehicle GHG emission standards on April 1,
2010. The EPA has asserted that the final motor vehicle GHG emission standards will trigger
construction and operating permit requirements for stationary sources. In addition, climate change
legislation is pending in the United States Congress. These developments may curtail production
and demand for fossil fuels such as oil and gas in areas of the world where our customers operate
and thus adversely affect future demand for our services, which may in turn adversely affect future
results of operations. Additionally, legislation to reduce greenhouse gases may have an adverse
effect on our operations, including payment of additional costs due to carbon emissions. Higher
carbon emission activities include transportation, including marine vessels, cement production (by
third party suppliers), and electricity generation (by third party suppliers) as well as other
activities. Finally, our business could be negatively affected by climate change related physical
changes or changes in weather patterns, which could result in damages to or loss of our physical
assets, impacts to our ability to conduct operations and/or disruption of our customers
operations.
Legislation may be introduced in the United States Congress that would authorize the EPA to
regulate hydraulic fracturing. In addition, a number of states are evaluating the adoption of
legislation or regulations governing hydraulic fracturing. Such legislation or regulations could
reduce demand for pressure pumping services. If federal and/or state legislation or regulations
were enacted, it could adversely affect our financial condition, results of operations and cash
flows. We are unable to predict whether the proposed legislation, regulations, or any other
proposals will ultimately be enacted.
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Environmental liabilities relating to discontinued operations could result in substantial
losses. |
Since our reorganization under the United States 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 United States federal bankruptcy laws in 1988, we have been
regularly named in products liability lawsuits primarily resulting from the manufacture of products
containing asbestos. In connection with our bankruptcy, a special products liability trust was
established and funded to address products liability claims. This product liability trust is in
the process of being dissolved. We believe that product liability claims relating to our business
prior to bankruptcy are barred by applicable bankruptcy law. Since 1988, no court has ruled that
we are responsible for products liability claims. However, if we are held responsible for product
liability claims, we could suffer substantial losses that could have a material adverse effect on
our financial condition and results of operations. We have not manufactured products containing
asbestos since our reorganization in 1988.
- 17 -
|
|
We may be subject to claims for personal injury and property damage, which could materially
adversely affect our financial condition and results of operations. |
We provide services and equipment to oil and natural gas exploration and production companies.
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. 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.
We operate with our customers through Master Service Agreements, or MSAs. We endeavor to
allocate potential liabilities and risks between the parties in the MSAs. Generally, our MSAs
contain indemnification to us for liability for pollution or environmental claims arising from
subsurface conditions or resulting from the drilling activities of our customers or their
operators. We may have liability in such cases if we are grossly negligent or commit willful acts.
In addition, any liability may be capped for either party to an MSA. Generally, our customers
also agree to indemnify us against claims arising from their employees personal injury or death,
unless resulting from our gross negligence or willful misconduct. Similarly, we agree to indemnify
our customers for liabilities arising from personal injury or death of any of our employees, unless
resulting from gross negligence or willful misconduct of the customer. In addition, our customers
agree to indemnify us for loss or destruction of customer-owned property or equipment, and in turn,
we agree to indemnify our customers for loss or destruction of property or equipment we own.
However, for equipment we rent to our customers, our contracts generally provide that the customer
is responsible for the replacement of any damaged or lost equipment in their care. Losses due to
catastrophic events, such as blowouts, are generally the responsibility of the customer. However,
despite this general allocation of risk, we might not succeed in enforcing such contractual
allocation or we might incur an unforeseen liability falling outside the scope of such allocation.
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 general
liability policy would cover claims where we agreed to indemnify the customer, subject to any
typical exclusions that may exist under the policy. However, we could become subject to material
uninsured liabilities that could have a material adverse effect on our financial condition and
results of operations. The limits and deductibles for our general liability policy are as follows:
|
|
|
General Aggregate $2,000,000; |
|
|
|
|
Products/Completed Operations Aggregate $2,000,000; |
|
|
|
|
Occurrence Limit $1,000,000; |
|
|
|
|
Personal/Advertising Injury Limit $1,000,000; |
|
|
|
|
Deductible (Bodily Injury & Property Damage Combined) Per Claim $100,000. |
In addition, our general liability policy is scheduled under a $30.0 million umbrella/excess
liability policy (subject to the policys terms, conditions and exclusions). We also have workers
compensation insurance coverage up to $1,000,000.
We have a contractors pollution liability policy of $10.0 million which has a $200,000
deductible, and all environmental claims would be subject to the terms, conditions and exclusions
of that policy. Our umbrella policy does not apply to the contractors pollution liability policy.
There is no assurance that such insurance or indemnification agreements will adequately
protect us against liability from all of the consequences of the hazards and risks described above.
The occurrence of an event not fully insured or for which we are not indemnified against, or the
failure of a customer or insurer to meet its indemnification or insurance obligations, could result
in substantial losses. In addition, there can be no assurance that insurance will continue to be
available to cover any or all of these risks, or, even if available, that insurance premiums or
other costs will not rise significantly in the future so as to make the cost of such insurance
prohibitive.
- 18 -
Risks Related to the Merger
We have and will continue to incur transaction costs in connection with the merger.
We have incurred, and expect to continue to incur, significant costs in connection with
the merger, including the fees of our respective professional advisors. We will also incur
integration and restructuring costs following the completion of the merger as our operations are
integrated with Seawells operations. The efficiencies anticipated to arise from the merger may
not be achieved in the near term or at all, and, if achieved, may not be sufficient to offset the
costs associated with the merger. Unanticipated costs, or the failure to achieve expected
efficiencies, may have an adverse impact on the results of operations of the combined company
following the completion of the merger.
|
|
Following the merger, the combined company may be unable to successfully integrate our
business into Archers business and realize the anticipated benefits of the merger. |
The merger involves the combination of two companies that operated as independent public
companies. The combined company will be required to devote management attention and resources to
integrating its business practices and operations. Potential difficulties that the combined
company may encounter in the integration process include the following:
|
|
|
the inability to successfully integrate our business into Seawells business in a
manner that permits the combined company to achieve the cost savings and operating
synergies anticipated to result from the merger, which would result in the anticipated
benefits of the merger not being realized partly or wholly in the time frame currently
anticipated or at all; |
|
|
|
|
integrating personnel from the two companies while maintaining focus on providing
consistent, high quality products and customer service; |
|
|
|
|
potential unknown liabilities and unforeseen increased expenses, delays or
regulatory conditions associated with the merger; and |
|
|
|
|
performance shortfalls at one or both of the two companies as a result of the
diversion of managements attention caused by completing the merger and integrating
the companies operations. |
It is possible that the integration process could result in the diversion of managements
attention, the disruption or interruption of, or the loss of momentum in, our ongoing businesses or
inconsistencies in standards, controls, procedures and policies, any of which could adversely
affect our ability to maintain relationships with customers, suppliers and employees or our ability
to achieve the anticipated benefits of the merger, or could reduce the earnings or otherwise
adversely affect the business and financial results of the combined company.
Following the merger, the carrying value of our assets may differ significantly from the
historical cost.
As part of the acquisition process, we are currently undergoing a purchase price valuation
exercise to review the fair values of our assets. As part of this review, the book values of
assets may differ materially once the exercise is concluded and the new values pushed down into our
balance sheet. The accounting rules related to the valuation of assets acquired in a business
combination are different from the reporting of historical results. We expect this exercise to be
completed by June 30, 2011.
The failure of the lenders under Seawells undrawn credit facilities to perform could have a
material adverse effect on our liquidity and results of operations. We are exposed to systemic
risk of the financial markets and institutions and the risk of non-performance of the individual
lenders under Seawells undrawn credit facilities.
Maintaining sufficient liquidity in our business for maintenance and operating expenditures,
capital expenditures and collateral is crucial in order to mitigate the risk of future financial
distress to us. Accordingly, Seawell maintains a revolving credit facility to manage its expected
liquidity needs and contingencies. The failure of the lenders to perform under the Seawell
revolving credit facility could have a material adverse effect on our results of operations. In
the event that financial institutions are unwilling or unable to renew Seawells existing revolving
credit facility or enter into new revolving credit facilities, our ability to hedge economically
our assets could be impaired.
- 19 -
Risks Associated With Our Indebtedness
|
|
We are an indirect wholly owned subsidiary of Seawell. Seawell can exercise substantial control
over our business and operations and could do so in a manner that is adverse to our interests. |
We are managed by officers and employees of Seawell. Our management will make determinations
with respect to the following:
|
|
|
decisions on our financings and our capital raising activities; |
|
|
|
|
mergers or other business combinations; and |
|
|
|
|
our acquisition or disposition of assets. |
We are a wholly owned subsidiary. As a result, we are dependent upon cash dividends,
distributions or other transfers we receive from our parent to repay any debt we may incur, and to
meet our other obligations. The ability of our parent to 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.
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 our parent or debt financings or other sources, will be available or, if
available, will be on terms satisfactory to us. The turmoil in the financial markets since
mid-2008 and its impact on the financial condition of the banking sector and other lenders, has
significantly reduced access to the capital markets. It is uncertain to what extent capital will
be available to us in the future and at what cost. If we are unable to obtain financing, we will
be unable to acquire additional businesses and may be unable to meet our obligations under our 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
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
contain various restrictive covenants that limit managements discretion in operating our business.
In particular, these covenants limit our ability to, among other things:
|
|
|
incur additional debt; |
|
|
|
|
make certain investments or pay dividends or distributions on our capital stock or
purchase or redeem or retire capital stock; |
|
|
|
|
sell assets, including capital stock of our restricted subsidiaries; |
|
|
|
|
restrict dividends or other payments by restricted subsidiaries; |
|
|
|
|
create liens; |
|
|
|
|
enter into transactions with affiliates; and |
|
|
|
|
merge or consolidate with another company. |
If there were an event of default under any of the indentures, the affected creditors could
cause all amounts borrowed under these instruments to be due and payable immediately.
|
|
|
ITEM 1B. |
|
UNRESOLVED STAFF COMMENTS |
None.
- 20 -
The following table describes the location and general character of the principal physical
properties used in each of our companys businesses as of March 1, 2011. Our principal executive
office is rented and located in Houston, Texas and the table below presents all of our material
operating locations and whether the property is owned or leased.
|
|
|
|
|
Business Segment |
|
Location |
|
Owned/Leased |
Oilfield Services
|
|
Kensett, Arkansas
|
|
Leased |
|
|
Youngsville, Louisiana
|
|
Owned |
|
|
Carlsbad, New Mexico
|
|
Leased |
|
|
Farmington, New Mexico
|
|
Leased |
|
|
Elk City, Oklahoma
|
|
Leased |
|
|
McAlester, Oklahoma
|
|
Leased |
|
|
Mt Morris, Pennsylvania
|
|
Leased |
|
|
Muncy, Pennsylvania
|
|
Leased |
|
|
Conroe, Texas
|
|
Leased |
|
|
Corpus Christi, Texas
|
|
Leased 2 locations |
|
|
Houston, Texas
|
|
Leased |
|
|
Kilgore, Texas
|
|
Leased |
|
|
Longview, Texas
|
|
Leased |
Drilling and Completion
|
|
Buenos Aires, Argentina
|
|
Leased |
|
|
Comodoro Rivadavia, Argentina
|
|
Owned |
|
|
Neuquen, Argentina
|
|
Owned |
|
|
Pio Truncado, Santa Cruz, Argentina
|
|
Leased |
|
|
Rincon de los Sauces, Argentina
|
|
Owned |
|
|
Rio Grande, Tierra del Fuego, Argentina
|
|
Leased |
|
|
Tartagal, Argentina
|
|
Owned |
|
|
Santa Cruz, Bolivia
|
|
Leased |
|
|
Catu, Bahia, Brazil
|
|
Owned |
|
|
Aracuja, Sergipe, Brazil
|
|
Leased |
|
|
Macae, Rio de Janeiro, Brazil
|
|
Leased |
|
|
Parnamirim, Rio Grande de Norte, Brazil
|
|
Leased |
|
|
Rio de Janeiro, Rio de Janeiro, Brazil
|
|
Leased |
Rental Services
|
|
Broussard, Louisiana
|
|
Leased |
|
|
Morgan City, Louisiana
|
|
Owned |
|
|
Muncy, Pennsylvania
|
|
Leased |
|
|
Conroe, Texas
|
|
Owned |
|
|
Victoria, Texas
|
|
Owned |
|
|
|
ITEM 3. |
|
LEGAL PROCEEDINGS |
On June 29, 1987, we filed for reorganization under Chapter 11 of the United States Bankruptcy
Code. Our plan of reorganization was confirmed by the Bankruptcy Court after acceptance by our
creditors and stockholders, and was consummated on December 2, 1988.
At confirmation of our plan of reorganization, the United States Bankruptcy Court approved the
establishment of the A-C Reorganization Trust as the primary vehicle for distributions and the
administration of claims under our plan of reorganization, two trust funds to service health care
and life insurance programs for retired employees and a trust fund to process and liquidate future
product liability claims. The trusts assumed responsibility for substantially all remaining cash
distributions to be made to holders of claims and interests pursuant to our plan of reorganization.
We were thereby discharged of all debts that arose before confirmation of our plan of
reorganization.
We do not administer any of the aforementioned trusts, some of which have been dissolved, and
retain no responsibility for the assets transferred to or distributions made or to be made by such
trusts pursuant to our plan of reorganization.
As part of our plan of reorganization, we settled with the EPA certain 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.
- 21 -
Subsequent to our bankruptcy reorganization, the EPA and state environmental protection
agencies have in a few cases asserted that we are liable for cleanup costs or fines in connection
with several hazardous waste disposal sites containing products manufactured by us prior to
consummation of our plan of reorganization. In each instance, we have taken the position that the
cleanup costs and all other liabilities related to these sites were discharged in the bankruptcy,
and the cases have been disposed of without material cost. A number of Federal Courts of Appeal
have issued rulings consistent with this position, and based on such rulings, we believe that we
will continue to prevail in our position that our liability to the EPA and third parties for claims
for environmental cleanup costs that had pre-petition triggers have been discharged. A number of
claimants have asserted claims for environmental cleanup costs that had pre-petition triggers, and
in each event, the A-C Reorganization Trust, under its mandate to provide plan of reorganization
implementation services to us, had responded to such claims, generally, by informing claimants that
our liabilities were discharged in the bankruptcy. Each of such claims have been disposed of
without material cost. However, there can be no assurance that we will not be subject to
environmental claims relating to pre-bankruptcy activities that would have a material adverse
effect on us.
We have assumed the responsibility of responding to claimants and to the EPA and state
agencies previously undertaken by the A-C Reorganization Trust. However, we have been advised by
the A-C Reorganization Trust that its cost of providing these services has not been material in the
past, and therefore we do not expect to incur material expenses as a result of responding to such
requests. However, there can be no assurance that we will not be subject to environmental claims
relating to pre-bankruptcy activities that would have a material adverse effect on us.
We are named as a defendant from time to time in product liability lawsuits alleging personal
injuries resulting from our activities prior to our reorganization involving asbestos. These
claims had previously been referred to and handled by a special products liability trust formed to
be responsible for such claims in connection with our reorganization. Such products liability
trust is in the process of being dissolved. As with environmental claims, we do not believe we are
liable for product liability claims relating to our business prior to our bankruptcy. However,
there can be no assurance that we will not be subject to material product liability claims in the
future.
Shortly following the announcement of the merger agreement, ten putative stockholder
class-action petitions and compliants were filed against various combinations of us, members of our
board of directors, Seawell, and Wellco. Seven of the lawsuits were filed in the District Court of
Harris County, Texas, which we refer to as the Texas Actions, and three lawsuits were filed in the
Court of Chancery of the State of Delaware, which we refer to as the Delaware Actions. These
lawsuits challenge the proposed merger and generally allege, among other things, that our directors
have breached their fiduciary duties owed to our public stockholders by approving the proposed
merger and failing to take steps to maximize our value to our public stockholders, that we,
Seawell, and Wellco aided and abetted such breaches of fiduciary duties, and that the merger
agreement unreasonably dissuades potential suitors from making competing offers and restricts us
from considering competing offers. The lawsuits generally seek, among other things, compensatory
damages, attorneys and experts fees, declaratory and injunctive relief concerning the alleged
breaches of fiduciary duties, and injunctive relief prohibiting the defendants from consummating
the merger.
Various plaintiffs in the Texas Actions filed competing motions to consolidate the suits, to
appoint their counsel as interim class counsel and to compel expedited discovery. On September 16,
2010, the defendants filed joint motions to stay the Texas Actions in favor of a first-filed
Delaware lawsuit, and opposing the motions for expedited discovery. There is no hearing date set
for these motions. The parties to the Texas State Court actions have agreed that the various
defendants need not respond to the petitions until after lead counsel is appointed, a consolidated
amended petition is filed and served or, alternatively, an active petition is designated by lead
counsel.
On September 21, 2010, the plaintiffs in the Delaware Actions wrote the court seeking
consolidation of the Delaware cases. Defendants did not oppose consolidation and took no position
regarding lead plaintiff. On September 29, 2010, the Delaware court granted the motion to
consolidate. Previously, on September 16, 2010, Seawell and Wellco answered the first-filed Girard
Complaint, which is the operative complaint post-consolidation. We answered the consolidated
complaint on October 4, 2010. On January 26, 2011, the plaintiffs in the Delaware Actions filed an
amended complaint that included, among other claims, allegations that the disclosures made by
Defendants concerning the merger are incomplete and misleading. Also on January 26, 2011, the
plaintiffs in the Delaware Actions filed a motion to expedite proceedings for discovery and
briefing and to set a date and time to hear their application for a preliminary injunction to
enjoin the merger. Following a hearing, on February 3, 2011, the Delaware court denied plaintiffs
motion.
We believe all of these lawsuits are without merit and intend to defend them vigorously.
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.
- 22 -
ITEM 4. [RESERVED]
PART II
ITEM 5. MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES.
MARKET PRICE INFORMATION
On February 23, 2011, we merged with and into Wellco Sub Company, a wholly owned subsidiary of
Seawell. Accordingly, there is no established public trading market for our common stock. Prior
to the merger, our common stock was traded on the New York Stock Exchange under the symbol ALY.
The following table sets forth high and low sale prices of our common stock reported on the New
York Stock Exchange for 2010 and 2009.
|
|
|
|
|
|
|
|
|
Calendar Quarter |
|
High |
|
|
Low |
|
2010 |
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
4.57 |
|
|
$ |
3.36 |
|
Second Quarter |
|
|
4.28 |
|
|
|
2.00 |
|
Third Quarter |
|
|
4.18 |
|
|
|
1.79 |
|
Fourth Quarter |
|
|
7.17 |
|
|
|
4.16 |
|
2009 |
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
6.07 |
|
|
$ |
0.71 |
|
Second Quarter |
|
|
4.53 |
|
|
|
1.80 |
|
Third Quarter |
|
|
4.94 |
|
|
|
2.01 |
|
Fourth Quarter |
|
|
4.87 |
|
|
|
3.06 |
|
Holder
There was one record holder of our common stock at March 1, 2011.
Dividends
No dividends were declared or paid on our common stock during the past two years, and no
dividends are anticipated to be declared or paid in the foreseeable future on such common stock.
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, 2010 with respect to the shares of
our common stock that may be issued under our 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 |
|
|
2,683,101 |
|
|
$ |
4.74 |
|
|
|
4,342,286 |
|
Equity compensation plans not approved by security holders |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
2,683,101 |
|
|
$ |
4.74 |
|
|
|
4,342,286 |
|
|
|
|
|
|
|
|
|
|
|
|
Equity Compensation Plans Not Approved By Security Holders
None
- 23 -
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, 2010. 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, 2005 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.
- 24 -
COMPARISON OF CUMULATIVE TOTAL RETURN OF ONE OR MORE
COMPANIES, PEER GROUPS, INDUSTRY INDEXES AND/OR BROAD MARKETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FISCAL YEAR ENDING |
|
COMPANY/INDEX/MARKET |
|
12/31/2005 |
|
|
12/31/2006 |
|
|
12/30/2007 |
|
|
12/29/2008 |
|
|
12/31/2009 |
|
|
12/31/2010 |
|
Allis-Chalmers Energy Inc. |
|
|
100.00 |
|
|
|
184.76 |
|
|
|
118.28 |
|
|
|
44.11 |
|
|
|
31.51 |
|
|
|
59.25 |
|
Russell 2000 Index |
|
|
100.00 |
|
|
|
118.37 |
|
|
|
116.51 |
|
|
|
77.15 |
|
|
|
98.11 |
|
|
|
124.46 |
|
Oil & Gas Equipment/Svcs |
|
|
100.00 |
|
|
|
120.81 |
|
|
|
174.92 |
|
|
|
70.98 |
|
|
|
116.10 |
|
|
|
158.33 |
|
|
|
|
ITEM 6. |
|
SELECTED FINANCIAL DATA. |
Omitted pursuant to Instruction I of Form 10-K. (Omission of Information by Certain Wholly
Owned Subsidiaries).
|
|
|
ITEM 7. |
|
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Pursuant to General Instruction I of Form 10-K Omission of Information by Certain Wholly-Owned
Subsidiaries, this section includes only managements narrative analysis of the results of
operations for the year ended December 31, 2010, the most recent fiscal year, compared with the
year ended December 31, 2009, the fiscal year immediately preceding it.
The following discussion and analysis should be read in conjunction with our accompanying
financial statements and the notes to those financial statements included elsewhere in this
document. The following discussion contains forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995 that reflect our plans, estimates and beliefs.
Our actual results could differ materially from those anticipated in these forward-looking
statements as a result of risks and uncertainties, including, but not limited to, those discussed
under Item 1A. Risk Factors.
Restatement of the Consolidated Financial Statements
On July 25, 2011, management concluded that the previously filed consolidated financial
statements for the fourth quarter and as of and for the year ended December 31, 2010 needed to be
restated. The restatement is necessitated by our determination that positive evidence available at
year end 2010 was not sufficient to overcome the negative evidence around the deferred tax assets
and to justify not booking a valuation allowance against federal income tax assets and foreign tax
credits. The correction of this error resulted in a $37.4 million increase in the deferred tax
valuation allowance and income tax expense.
Overview of Our Business
We are a multi-faceted oilfield service company that provides services and equipment to oil
and natural gas exploration and production companies, throughout the United States including Texas,
Louisiana, Pennsylvania, Arkansas, West Virginia, Oklahoma, Colorado, offshore in the Gulf of
Mexico and internationally primarily in Argentina, Brazil, Bolivia and Mexico. We operate in three
sectors of the oil and natural gas service industry: Oilfield Services; Drilling and Completion and
Rental Services.
We derive operating revenues from rates per day and 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 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.
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.
- 25 -
Merger with Seawell
On February 23, 2011, we merged with and into Wellco Sub Company, a wholly owned subsidiary of
Seawell, and each share of our common stock was converted into the right to receive either 1.15
Seawell common shares or $4.25 in cash. In connection with the merger, Wellco Sub Company changed
its name to Allis-Chalmers Energy Inc. We recorded approximately $2.1 million of costs related to
the merger during the year ended December 31, 2010, which are included in selling, general and
administrative expense on our Consolidated Statements of Operations. Approval of the merger
resulted in certain of our contractual obligations being triggered or accelerated under the change
of control provisions of such contractual arrangements. Examples of such arrangements include
stock-based compensation awards, severance and retirement plan agreements applicable to executive
officers, directors and certain employees and certain other debt obligations, including our senior
notes.
Company Outlook
Throughout the first half of 2009, we saw a significant decline in the global economy which
led to reduced activity in the energy sector. This reduced activity in the energy sector resulted
in lower demand for our services and we incurred significant losses. Since the second quarter of
2009, we have experienced quarter over quarter improvement in our total revenues which has resulted
in reduced net losses.
On April 20, 2010, a fire and explosion occurred onboard the semisubmersible drilling rig
Deepwater Horizon, which was owned by Transocean Ltd. and under contract to a subsidiary of BP plc.
The accident resulted in the loss of life and a significant oil spill. In response to this
incident, the Minerals Management Service of the United States Department of Interior, or the MMS,
issued a notice on May 30, 2010 implementing a six-month moratorium on certain drilling activities
in the United States Gulf of Mexico. The notice also stated that the MMS would not consider
drilling permits for new wells and related activities for specified water depths during the
six-month moratorium period. In addition, entities in the process of drilling wells covered by the
moratorium were required to halt drilling and take steps to secure such wells. On October 12,
2010, the moratorium was lifted, and deepwater oil and natural gas drilling in the United States
Gulf of Mexico has been allowed to resume, provided that operators certify compliance with all
existing rules and requirements, including those that recently went into effect, and demonstrate
the availability of adequate blowout containment resources. The first new permit was not issued
until March 2011.
Although the moratorium on oil and natural gas drilling in the United States Gulf of Mexico
has been lifted, new guidelines, regulations and restrictions could increase the costs of
exploration and production, reduce the area of operations and result in permitting delays. These
may include new or additional bonding and safety requirements, and other requirements regarding
certification of equipment. The enactment of stricter restrictions on offshore drilling or further
regulation of offshore drilling or contracting services operations could materially affect our
business, financial condition and results of operations.
Results of Operations
In July 2010, we acquired all of the outstanding stock of AWC, which is reported as part of
our Rental Services segment. We consolidated the results of this acquisition from the day it was
acquired. The foregoing acquisition affects 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, 2010 and December 31, 2009
Our revenues for the year ended December 31, 2010 were $659.7 million, an increase of 30.3%
compared to $506.3 million for the year ended December 31, 2009. Revenues increased in all three
of our segments. Both our Oilfield Services and Rental Services segments have a strong
concentration in the United States domestic oil and natural gas market. Due to the increased
drilling activity in the United States, particularly in the natural gas shale plays, compared to
2009, we experienced significant improvement in both equipment utilization and pricing. This
resulted in an increase in revenues of our Oilfield Services segment to $210.6 million for the year
ended December 31, 2010 compared to revenues of $143.6 million for the year ended December 31,
2009. Our Rental Services segment had an increase in revenues to $70.9 million for the year ended
December 31, 2010 compared to revenues of $58.7 million for the year ended December 31, 2009. The
acquisition of AWC in July 2010 contributed $15.7 million of the increase in revenues for the
Rental Services segment. The contribution in revenues by AWC and the increase in activity from the
United States land shale plays were partially offset by the drilling moratorium in the Gulf of
Mexico. The increase in revenues in our Drilling and Completion segment was due to higher rig
utilization and pricing in our Argentina operations. The Drilling and Completion segment generated
$378.2 million in revenues for the year ended December 31, 2010 compared to revenues of $304.0
million for the year ended December 31, 2009.
- 26 -
Our direct costs for the year ended December 31, 2010 increased 31.3% to $498.1 million, or
75.5% of revenues, compared to $379.4 million, or 75.0%, of revenues for the year ended December
31, 2009. The increase in direct costs is consistent with the increase in revenues. Our Oilfield
Services segment direct costs for the year ended December 31, 2010 increased $35.0 million, or
31.4%, from direct costs for the year ended December 31, 2009, while the revenues increased 46.7%
over that same period, resulting in an improved gross margin of 30.4% for 2010 compared to 22.3%
for 2009. In addition, our Oilfield Services segment had $1.2 million of expenses recorded during
the year ended December 31, 2009 related to severance payments, the closing of unprofitable
locations and downsizing other locations. Direct costs in our Drilling and Completion segment
increased $74.4 million, or 30.2%, for the year ended December 31, 2010 compared to the year ended
December 31, 2009, while the revenues increased 24.4% over that same period, resulting in a
reduction of gross margin to 15.1% for 2010 compared to 18.8% in 2009. This unfavorable variance
is primarily attributed to labor and other cost increases due to the inflationary environment in
Argentina and decreased utilization and pricing for our rigs in Brazil. Our Rental Services
segment direct costs for the year ended December 31, 2010 increased $9.3 million, or 43.9%, from
direct costs for the year ended December 31, 2009, while the revenues increased 20.7% over that
same period, resulting in a reduction of gross margin to 57.0% in 2010 compared to 63.9% in 2009.
The AWC acquisition in July 2010 contributed $15.7 million in revenues and $9.5 million in direct
costs to the Rental Services segment for the year ended December 31, 2010 for an effective gross
margin as a percentage of revenues of 39.5%. The lower margin manufacturing operation of AWC is
the primary reason that the gross margin percentage in the Rental Services segment declined for the
year ended December 31, 2010 compared to the year ended December 31, 2009.
Depreciation expense increased 7.5% to $84.1 million for the year ended December 31, 2010 from
$78.3 million for the year ended December 31, 2009. The primary increase in depreciation expense
is due to our on-going investment in equipment to serve our customer base.
Selling, general and administrative expense was $60.4 million for the year ended December 31,
2010 compared to $50.8 million for the year ended December 31, 2009. Selling, general and
administrative expense increased primarily due to bonuses, the amortization of share-based
compensation arrangements and merger related transaction costs, partially offset by reduced bad
debt provision. Bonus expense for the year ended December 31, 2010 was $6.9 million compared to
$1.3 million for the prior year due to the improved operating results for 2010 compared to 2009.
Selling, general and administrative expense includes share-based compensation expense of $8.0
million in 2010 and $4.8 million in 2009. Transaction costs related to the merger with Seawell
were $2.1 million and included our fairness opinion and other professional fees. Our bad debt
expense for the year ended December 31, 2010 was $368,000 compared to $2.8 million for the year
ended December 31, 2009 and is a reflection of the improved market conditions in the United States
oilfield industry. As a percentage of revenues, selling, general and administrative expenses were
9.2% in 2010 compared to 10.0% in 2009.
During the year ended December 31, 2010, we recorded a $10.6 million loss on the sale of two
drilling rigs that we had constructed in 2008 which we were never able to operate on a reliable
basis. We received $25.0 million for the rigs, but our costs related to the rig were $35.2
million. In addition, we incurred a $311,000 early repayment fee and wrote off deferred financing
costs of $115,000 related to the underlying debt to those two rigs. During the year ended December
31, 2009, we recorded a $1.6 million loss on an asset disposition from the total loss of a rig from
a blow-out in our Drilling and Completion segment. The insurance proceeds for the loss were not
sufficient to cover the book value of the rig and related assets.
Amortization expense was $4.8 million for the year ended December 31, 2010 compared to $4.7
million for the year ended December 31, 2009. The increase was primarily attributable to
intangible assets associated with our acquisition of AWC in July 2010.
Our income from operations for the year ended December 31, 2010 totaled $1.6 million, compared
to an $8.5 million loss for the year ended December 31, 2009, for an improvement of $10.1 million.
The improvement is primarily related to increased revenues in all our segments, partially offset by
higher selling, general and administrative costs, the increased loss on asset dispositions and
increased depreciation and amortization expense for the year ended December 31, 2010 compared to
year ended December 31, 2009.
Our interest expense was $45.8 million for the year ended December 31, 2010, compared to $48.1
million for the year ended December 31, 2009. On June 29, 2009 we purchased $74.8 million of our
senior notes with proceeds from our $125.6 million in equity issuances on that same date. We also
prepaid the then $35.0 million outstanding loan balance under our revolving credit facility on June
29, 2009 from those same equity proceeds. Our outstanding balance under our revolving credit
facility was $36.5 million at December 31, 2010 compared to no borrowings at December 31, 2009. In
November 2010, we repaid the outstanding balance of $20.8 million term loan on the two rigs that
were sold in 2010. Interest expense includes amortization expense of debt issuance costs of $2.2
million for both of the years ended December 31, 2010 and 2009.
- 27 -
Our interest income was $537,000 for the year ended December 31, 2010, compared to $72,000 for
the year ended December 31, 2009. We received $405,000 of interest income related to a receivable
that was collected through bankruptcy proceedings in 2010.
During the year ended December 31, 2009, we recorded a gain of $26.4 million as a result of a
tender offer that we completed on June 29, 2009. We purchased $30.6 million aggregate principal of
our 9.0% senior notes and $44.2 million aggregate principal of 8.5% senior notes for approximately
$46.4 million. Included in the computation of the gain is the write-off of $1.5 million of debt
issuance costs related to the retired notes and we incurred approximately $466,000 in expenses
related to the transactions.
Income tax expense for the year ended December 31, 2010 was $30.0 million, or (63.8)% of our
net loss before income taxes, compared to an income tax benefit of $9.9 million, or 31.8% of our
net loss before income taxes for 2009. Our effective tax rate in the United States was (34.8)% in
2010 compared to 35.5% in 2009, while our effective tax rate for international activities increased
to 85.6% in 2010 compared to 44.4% in 2009. The fluctuation in the United States tax rate was
primarily attributable to the $37.4 million valuation allowance recorded in 2010 due to the
uncertainty related to the realizability of our excess deferred tax assets. The increase in the
international tax rate is primarily due to our BCH operations which generate a loss in Brazil but
incurs a withholding tax on its revenues which is reported as an income tax.
We had a net loss of $76.9 million for the year ended December 31, 2010, compared to a net
loss of $21.2 million for the year ended December 31, 2009. The net loss for the year ended
December 31, 2010 included the $10.6 million loss on the sale of two rigs and $37.4 million
valuation allowance on deferred tax assets, while the net loss in 2009 includes the $26.4 million
gain as a result of the senior notes tender offer.
The net loss attributed to common stockholders for the years ended December 31, 2010 and 2009
was $79.4 million and $22.5 million, respectively, after $2.5 million and $1.3 million in preferred
stock dividends, respectively. The preferred stock dividend relates to 36,393 shares of $1,000 par
value preferred shares at 7.0%.
The following table compares revenues and income (loss) from operations for each of our
business segments for the years ended December 31, 2010 and December 31, 2009. Income (loss) from
operations consists of our revenues and the gain (loss) on asset dispositions less direct costs,
general and administrative expenses, depreciation and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
Income (Loss) from Operations |
|
|
|
2010 |
|
|
2009 |
|
|
Change |
|
|
2010 |
|
|
2009 |
|
|
Change |
|
|
|
(In thousands) |
|
Oilfield Services |
|
$ |
210,617 |
|
|
$ |
143,564 |
|
|
$ |
67,053 |
|
|
$ |
15,393 |
|
|
$ |
(14,691 |
) |
|
$ |
30,084 |
|
Drilling & Completion |
|
|
378,154 |
|
|
|
303,975 |
|
|
|
74,179 |
|
|
|
4,369 |
|
|
|
19,222 |
|
|
|
(14,853 |
) |
Rental Services |
|
|
70,894 |
|
|
|
58,714 |
|
|
|
12,180 |
|
|
|
4,115 |
|
|
|
140 |
|
|
|
3,975 |
|
General Corporate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(22,314 |
) |
|
|
(13,218 |
) |
|
|
(9,096 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
659,665 |
|
|
$ |
506,253 |
|
|
$ |
153,412 |
|
|
$ |
1,563 |
|
|
$ |
(8,547 |
) |
|
$ |
10,110 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services. Revenues for the year ended December 31, 2010 for our Oilfield Services
segment were $210.6 million, an increase of 46.7% from the $143.6 million in revenues for the year
ended December 31, 2009. Income from operations for our Oilfield Services segment increased $30.1
million and resulted in an income from operations of $15.4 million for the year ended December 31,
2010 compared to loss from operations of $14.7 million for the year ended December 31, 2009. Our
Oilfield Services segment revenues and operating income for the year ended December 31, 2010
increased compared to the year ended December 31, 2009 due to improved market conditions that
resulted in increased demand and pricing for our services. During the year ended December 31,
2009, we incurred $1.2 million of costs related to severance payments, the closing of unprofitable
locations and downsizing other locations in our Oilfield Services segment.
Drilling and Completion. Our Drilling and Completion revenues were $378.2 million for the
year ended December 31, 2010, an increase of 24.4% from the $304.0 million in revenues for the year
ended December 31, 2009. Our Drilling and Completion revenues increased in 2010 primarily due to
increased activity in Argentina. Income from operations decreased to $4.4 million in 2010 compared
to $19.2 million for the year ended December 31, 2009. Income from operations as percentage of
revenue decreased to 1.2% for 2010 compared to 6.3% for 2009. This reduction was due to: (1) a
$10.6 million loss on the disposition of two drilling rigs manufactured in 2008 that never achieved
acceptable performance; (2) increased labor and other costs in Argentina during the year ended
December 31, 2010; (3) an increase of $4.1 million, or 18.4%, in depreciation and amortization in
the year ended December 31, 2010; and (4) reduced rig utilization and rig rates in Brazil during
the year ended December 31, 2010 compared to the prior year. Results for the Drilling and
Completion segment in 2010 were also impacted by a high incidence of labor strikes in Argentina
during the year. Operating income in 2009 was impacted by (1) a $1.6 million non-cash loss
recorded in the year ended December 31, 2009 on a rig destroyed in a blow-out; (2) $1.7 million of
severance costs during the year ended December 31, 2009 related to workforce reductions in
Argentina as a result of lower activity and (3) $329,000 of costs incurred to
- 28 -
consolidate operating locations in Brazil during the year ended December 31, 2009. The
increase in depreciation and amortization expense was the result of our continual upgrade to our
equipment.
Rental Services. Our Rental Services revenues were $70.9 million for the year ended December
31, 2010, an increase of 20.7% from the $58.7 million in revenues for the year ended December 31,
2009. Income from operations for our Rental Services segment increased to $4.1 million for the
year ended December 31, 2010 compared to $140,000 for the year ended December 31, 2009. Our Rental
Services segment revenues and operating income for the year ended December 31, 2010 increased
compared to the prior year due primarily to the acquisition of AWC. AWC generated $15.7 million of
revenues and $5.3 million of operating income from its acquisition in July 2010 through December
31, 2010. Our Rental Services segment was negatively impacted by the moratorium in the Gulf of
Mexico resulting from the Deepwater Horizon incident, partially offset by increased pricing and
utilization of certain equipment as a result of our focus on the land shale drilling activity. We
had no bad debt expense recorded in our Rental Services segment for the year ended December 31,
2010 compared to $1.5 million for the year ended December 31, 2009.
General Corporate. General corporate expenses increased $9.1 million to $22.3 million for the
year ended December 31, 2010 compared to $13.2 million for the year ended December 31, 2009. The
increase was primarily due to the increase in share-based compensation expense, bonus expense and
transaction costs related to the merger with Seawell. Share-based compensation expense included in
general corporate was $6.7 million for the year ended December 31, 2010 compared to $3.7 million
for the year ended December 31, 2009, with the increase primarily attributed to accelerated vesting
on restricted stock in connection with the then pending merger with Seawell. Bonus expense for the
year ended December 31, 2010 was $6.4 million higher than the previous year due to a new bonus plan
adopted in 2010 and the achievement of certain performance goals for 2010. We incurred $2.1
million of costs related to the Seawell merger during the year ended December 31, 2010.
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. In the past, our primary source of liquidity were the proceeds from the issuance of
debt and equity securities and cash flows from operations. At the completion of the merger our
revolving credit facility was repaid and cancelled and future funds will be provided by operating
cash flow or advances from our parent company.
Operating Activities
In the year ended December 31, 2010, we generated $54.9 million in cash from operating
activities. Our net loss for the year ended December 31, 2010 was $76.9 million. Non-cash
additions to the net loss totaled $133.4 million in the 2010 period consisting primarily of $88.9
million of depreciation and amortization, $10.6 million related to loss on disposition of two
drilling rigs, $8.0 million related to the expensing of stock options, $2.2 million of amortization
and write-off of deferred financing fees, $1.5 million from the loss on the sale of an investment
in an exploration and production company, $0.8 million from losses incurred by a joint venture
operating in Saudi Arabia, $0.7 million of losses from the disposition of equipment and $20.3
million in deferred income taxes.
During the year ended December 31, 2010, changes in working capital used $1.6 million in cash.
Cash was provided by decreases in prepaid expenses and other of $11.1 million and $1.7 million in
other assets, increases in trade payables of $11.1 million, $7.4 million in accrued expense and
$9.9 million in accrued salaries, benefits and payroll taxes, this was offset by cash used by
increases in accounts receivable of $35.7 million and $6.0 million in inventories, and a decrease
of $0.9 million in other liabilities. Our accounts receivables increased at December 31, 2010
primarily due to the increase in our revenues in 2010. Inventories increased at December 31, 2010
primarily due to the acquisition of AWC which had $3.0 million of manufacturing related inventory
at December 31, 2010 and also due to an increase in activity. Prepaid expenses and other current
assets decreased primarily due to tax prepayments in Argentina being utilized to cover current
period income taxes and due to the amortization of insurance premiums that were financed. The
decrease in other assets relates to recurring amortization of deferred mobilization costs as well
as amortization on oil and gas investments. Our accounts payable and accrued expenses increased
primarily due to the increase in costs due to our increase in activity. Approximately $5.0 million
of the increase in accrued salaries, benefits and payroll taxes relates to yearend bonus accruals
at December 31, 2010 and the rest of the increase relates to general timing differences on when
payroll is paid.
In the year ended December 31, 2009, we generated $55.5 million in cash from operating
activities. Our net loss for the year ended December 31, 2009 was $21.2 million. Non-cash
additions to net loss totaled $49.3 million in the 2009 period consisting primarily of $83.0
million of depreciation and amortization, $4.8 million related to the expensing of stock options,
$2.8 million for bad debts, $2.2 million of amortization and write-off of deferred financing fees
and $1.6 million related to loss on rig destroyed by fire, partially offset by $26.4 million from
gain on debt extinguishment, $17.9 million in deferred income taxes and $0.9 million of gains from
the dispositions of equipment.
- 29 -
During the year ended December 31, 2009, changes in working capital provided $27.4 million in
cash, principally due to a decrease of $50.0 million in accounts receivable, a decrease of $4.6
million in inventories, a decrease in other current assets of $4.6 million and an increase of $2.7
million in accrued employee benefits and payroll taxes, offset by an decrease of $27.6 million in
accounts payable, a decrease of $4.6 million in accrued expenses and a decrease in accrued interest
of $2.8 million. Our accounts receivables decreased at December 31, 2009 primarily due to the
decrease in our revenues in 2009. Inventories decreased at December 31, 2009 primarily due to a
slowdown in our activity. Other current assets decreased primarily due to tax refunds received in
2009. Our accounts payable, and other accrued expenses decreased primarily due to the decrease in
costs due to our decrease in activity.
Investing Activities
During the year ended December 31, 2010, we used $67.7 million in investing activities,
consisting of $102.2 million for capital expenditures, $15.9 million for the acquisition of AWC,
offset by a decrease of $18.3 million in deposits on asset commitments, $6.6 million of proceeds
from equipment sales and $25.0 million in proceeds from the sale of two drilling rig manufactured
in 2008. Included in the $102.2 million for capital expenditures was $26.6 million for our
Oilfield Services segment, $38.4 million for two domestic drilling rigs and $21.8 million for
additional equipment in our Drilling and Completion segment and $14.6 million for drill pipe and
other equipment used in our Rental Services segment. We acquired AWC for a cash payment of $17.2
million directly to the seller and 1.0 million shares of our common stock at a value of $2.0
million. The acquired assets of AWC included $1.2 million in cash. The decrease in deposits on
asset commitments was primarily due to the completion of all drilling rigs under construction by
December 31, 2010. We also received $6.6 million from the sale of assets during the year ended
December 31, 2010, comprised mostly from equipment lost-in-hole from our Rental Services segment
($4.0 million) and our Oilfield Services segment ($1.8 million).
During the year ended December 31, 2009, we used $64.0 million in investing activities,
consisting of $78.1 million for capital expenditures, $1.1 million of additional investments,
offset by a decrease of $2.7 million in deposits on asset commitments, $8.6 million of proceeds
from equipment sales and $3.9 million in insurance proceeds for a drilling rig destroyed by a
blow-out. Included in the $78.1 million for capital expenditures was $11.4 million for our
Oilfield Services segment, $38.5 million for two domestic drilling rigs and $19.9 million for
additional equipment in our Drilling and Completion segment and $8.2 million for drill pipe and
other equipment used in our Rental Services segment. We invested $2.4 million of cash and cash
expenditures for equipment into our investment into our Saudi Arabia joint venture and we received
$1.3 million from insurance proceeds related to a pre-acquisition contingency on BCH. The decrease
in other assets was due to the conversion of deposits on equipment purchases into capital
expenditures for the drilling rigs and assets used in our directional drilling services. We also
received $8.6 million from the sale of assets during the year ended December 31, 2009, comprised
mostly from equipment lost-in-hole from our Rental Services segment ($3.5 million) and our
Oilfield Services segment ($0.8 million) along with $3.9 million from the sale a plane in our
Rental Services segment. We also transferred $1.6 million of rental assets as part of our
investment into our Saudi Arabia joint venture in a non-cash transaction. In 2009, we reduced the
carrying value of goodwill on the BCH acquisition by $1.3 million due to the utilization of a
pre-acquisition tax asset.
Financing Activities
During the year ended December 31, 2010, financing activities used $7.3 million in cash. We
borrowed a net of $36.5 million under our revolving credit facility and an additional $4.0 million
under a term loan facility. We repaid $42.2 million of long-term debt, including a $20.8 million
repayment of the rig financing term loan from the proceeds of the two rigs sold in November 2010.
We also paid $2.5 million in preferred dividends during the year ended December 31, 2010. We
incurred $189,000 in debt issuance costs on the revolving credit facility, primarily to modify our
loan covenants. As the result of net exercises of restricted grant vesting, we had a net cash
outlay of $1.7 million related to the payment of payroll taxes on those exercises. We recorded an
income tax impact of $1.2 million as a result of the expense recorded on restricted stock grants
exceeding the actual tax deduction generated by those awards. In addition, we financed our renewal
of $2.9 million in insurance policy premiums in non-cash transactions.
During the year ended December 31, 2009, financing activities provided $42.7 million in cash.
We raised $120.2 million net of expenses from the issuance of common and preferred stock, and
borrowed $25.0 million under a loan facility to acquire two drilling rigs, offset in part by
repayments of $64.8 million of long-term debt, a net repayment on our revolving credit facility of
$36.5 million and $665,000 for preferred dividend payments. The repayments of long-term debt
consisted of $46.4 million on the senior notes as a result of a tender offer and $18.4 million of
scheduled debt repayment including a prepayment on our BCH loan facility. We also incurred
$658,000 in debt issuance costs consisting of $528,000 on the revolving credit facility, primarily
to modify our loan covenants, and $131,000 on the rig financing agreement. In addition, we
financed our renewal of $3.2 million in insurance policy premiums in non-cash transactions.
- 30 -
On January 18, 2006 and August 14, 2006, we closed on private offerings, to qualified
institutional buyers pursuant to Rule 144A under the Securities Act of 1933, of $160.0 and $95.0
million aggregate principal amount of our senior notes, respectively. The senior notes are due
January 15, 2014 and bear interest at 9.0%. The proceeds were used to fund the acquisitions of
Specialty Rental Tools, Inc. and DLS, to repay existing debt and for general corporate purposes.
On June 29, 2009, we closed on a tender offer in which we purchased $30.6 million aggregate
principal of our 9.0% senior notes for a total consideration of $650 per $1,000 principal amount.
In January 2007, we closed on a private offering, to qualified institutional buyers pursuant
to Rule 144A under the Securities Act of 1933, of $250.0 million principal amount of 8.5% senior
notes due 2017. The proceeds of the senior notes offering, together with a portion of the proceeds
of our concurrent common stock offering, were used to repay the debt outstanding under our $300.0
million bridge loan facility which we incurred to finance our acquisition of substantially all the
assets of Oil & Gas Rental Services, Inc. On June 29, 2009, we closed on a tender offer in which
we purchased $44.2 million aggregate principal of our 8.5% senior notes for a total consideration
of $600 per $1,000 principal amount.
We had a $90.0 million revolving line of credit with a final maturity date of April 26, 2012
pursuant to a revolving credit agreement that contains customary events of default and financial
covenants and limits our ability to incur additional indebtedness, make capital expenditures, pay
dividends or make other distributions, create liens and sell assets. On April 9, 2009, we amended
our revolving credit agreement to modify the leverage and interest coverage ratio covenants.
Effective December 31, 2009, we again amended the leverage and interest coverage ratio covenants of
the revolving credit agreement. This amendment relaxed the required financial ratios for the
quarter ended December 31, 2009 and for each of the quarters in 2010. Our obligations under the
amended and restated credit agreement were secured by substantially all of our assets located in
the United States. We were in compliance with all debt covenants as of December 31, 2010 and
December 31, 2009. As of December 31, 2010, we had $36.5 million of borrowings outstanding and
$4.1 million in outstanding letters of credit under our revolving credit facility. As of December
31, 2009, the only usage of our revolving credit facility consisted of $4.2 million in outstanding
letters of credit. The interest rate under our revolving credit facility was based on prime or
LIBOR plus a margin. The weighted-average interest rate was 7.8% at December 31, 2010. In
connection with merger with Seawell, this facility was repaid and cancelled.
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 were 2.0% and 2.1% as of December 31, 2010 and 2009, respectively. The
outstanding amount due under these bank loans as of December 31, 2010 and 2009 was $350,000 and
$1.1 million, respectively.
On February 15, 2008, through our DLS subsidiary in Argentina, we entered into a $25.0 million
import finance facility with a bank. Borrowings under this facility were used to fund a portion of
the purchase price of the new drilling and service rigs ordered for our Drilling and Completion
segment. The loan is repayable over four years in equal semi-annual installments beginning one
year after each disbursement with the final principal payment due not later than March 15, 2013.
The import finance facility is unsecured and contains customary events of default and financial
covenants and limits DLS ability to incur additional indebtedness, make capital expenditures,
create liens and sell assets. We were in compliance with all debt covenants as of December 31,
2010 and 2009. The bank loan rates are based on LIBOR plus a margin. The weighted average
interest rate was 4.2% and 4.4% at December 31, 2010 and 2009, respectively. The outstanding
amount under the import finance facility as of December 31, 2010 and 2009 was $14.4 million and
$20.1 million, respectively.
As part of our acquisition of BCH, we assumed a $23.6 million term loan credit facility with a
bank. The credit agreement was dated June 2007 and contains customary events of default and
financial covenants which were based on BCHs stand-alone financial statements. Obligations under
the facility were secured by substantially all of the BCH assets. BCH was in compliance with all
debt covenants as of December 31, 2009. The bank waived certain financial ratio covenants for the
September 30, 2010 and December 31, 2010 measurement periods. As we could not be certain that BCH
would attain compliance with the covenants within one year, we have classified the entire
outstanding balance of the loan in the current portion of long-term debt as of December 31, 2010.
The facility was repayable in quarterly principal installments plus interest with the final payment
due not later than August 2012. The interest rates were based on LIBOR plus a margin. At
December 31, 2010 and 2009, the outstanding amount of the loan was $7.0 million and $16.2 million
and the interest rate was 3.5%. At the time of the merger, this facility was prepaid.
On May 22, 2009, we drew down $25.0 million on a new term loan credit facility with a lending
institution. The facility was utilized to fund a portion of the purchase price of two new drilling
rigs. The loan was secured by the equipment and was repaid in November 2010 when the equipment was
sold to the manufacturer. The facility was repayable in quarterly installments of approximately
$1.4 million of principal and interest and was to mature in May 2015. The loan bore interest at a
fixed rate of 9.0%. At December 31, 2009, the outstanding amount of the loan was $23.4 million.
- 31 -
On February 9, 2010, through our DLS subsidiary, we entered into a $4.0 million term loan
facility. The loan is repayable in semi-annual installments beginning April 14, 2011 and bears
interest at 8.5% per annum. The final maturity date is April 14, 2014 and the loan is unsecured.
In 2010, we obtained insurance premium financings in the aggregate amount of $2.9 million with
a fixed weighted-average interest rate of 4.8%. Under terms of the agreements, amounts outstanding
are paid over eight and 11 month repayment schedules. The outstanding balance of these notes was
approximately $1.0 million at December 31, 2010. In 2009, we obtained insurance premium financings
in the aggregate amount of $3.2 million with a fixed weighted-average interest rate of 4.8%. Under
terms of these agreements, amounts outstanding are paid over 10 and 11 month repayment schedules.
The outstanding balance of these notes was approximately $0 and $997,000 at December 31, 2010 and
2009, 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 $0 and $254,000 at December
31, 2010 and 2009, respectively.
The following table summarizes our obligations and commitments to make future payments under
our notes payable, operating leases, employment contracts and consulting agreements for the periods
specified as of December 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments by Period |
|
|
|
|
|
|
|
Less Than |
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
1 Year |
|
|
1-3 Years |
|
|
3-5 Years |
|
|
After 5 Years |
|
|
|
(In thousands) |
|
Contractual Obligations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
$ |
493,440 |
|
|
$ |
15,215 |
|
|
$ |
10,907 |
|
|
$ |
261,518 |
|
|
$ |
205,800 |
|
Interest payments on long-term debt |
|
|
174,492 |
|
|
|
41,450 |
|
|
|
76,896 |
|
|
|
35,786 |
|
|
|
20,360 |
|
Operating leases |
|
|
11,218 |
|
|
|
3,376 |
|
|
|
4,095 |
|
|
|
2,026 |
|
|
|
1,721 |
|
Purchase obligations |
|
|
21,045 |
|
|
|
21,045 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Employment contracts |
|
|
2,846 |
|
|
|
1,915 |
|
|
|
931 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual cash obligations |
|
$ |
703,041 |
|
|
$ |
83,001 |
|
|
$ |
92,829 |
|
|
$ |
299,330 |
|
|
$ |
227,881 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Critical Accounting Policies
We have identified the policies below as critical to our business operations and the
understanding of our results of operations. The impact and any associated risks related to these
policies on our business operations is discussed throughout Managements Discussion and Analysis of
Financial Condition and Results of Operations where such policies affect our reported and expected
financial results. For a detailed discussion on the application of these and other accounting
policies, see Note 1 in the Notes to the Consolidated Financial Statements included elsewhere in
this document. Our preparation of this report requires us to make estimates and assumptions that
affect the reported amount of assets and liabilities, disclosure of contingent assets and
liabilities at the date of our financial statements, and the reported amounts of revenue and
expenses during the reporting period. There can be no assurance that actual results will not
differ from those estimates.
Allowance For Doubtful Accounts. The determination of the collectibility of amounts due from
our customers requires us to use estimates and make judgments regarding future events and trends,
including monitoring our customer payment history and current credit worthiness to determine that
collectibility is reasonably assured, as well as consideration of the overall business climate in
which our customers operate. Those uncertainties require us to make frequent judgments and
estimates regarding our customers ability to pay amounts due us in order to determine the
appropriate amount of valuation allowances required for doubtful accounts. Provisions for doubtful
accounts are recorded when it becomes evident that the customers will not be able to make the
required payments at either contractual due dates or in the future.
Revenue Recognition. We provide rental equipment, oilfield services and drilling services to
our customers at per day, or daywork, and per job contractual rates and recognize the drilling
related revenue as the work progresses and when collectibility is reasonably assured. Revenue from
daywork contracts is recognized when it is realized or realizable and earned. On daywork
contracts, revenue is recognized based on the number of days completed at fixed rates stipulated by
the contract. For certain contracts, we receive lump-sum and other fees for equipment and other
mobilization costs. Mobilization fees and the related costs are deferred and amortized over the
contract terms when material.
- 32 -
Impairment Of Long-Lived Assets. Long-lived assets, principally property, plant and
equipment, comprise a significant amount of our total assets. We make judgments and estimates in
conjunction with the carrying value of these assets, including amounts to be capitalized,
depreciation and amortization methods and useful lives. Additionally, the carrying values of these
assets are reviewed for impairment whenever events or changes in circumstances indicate that the
carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it
is determined that the carrying amount is not recoverable. This requires us to make long-term
forecasts of our future revenues and costs related to the assets subject to review. These
forecasts require assumptions about demand for our products and services, future market conditions
and technological developments. Significant and unanticipated changes to these assumptions could
require a provision for impairment in a future period.
Goodwill and Other Intangibles. As of December 31, 2010 we have recorded approximately $46.3
million of goodwill and $33.9 million of other identifiable intangible assets. We perform purchase
price allocations to intangible assets when we make a business combination. Business combinations
and purchase price allocations have been consummated for acquisitions in all of our reportable
segments. The excess of the purchase price after allocation of fair values to tangible assets is
allocated to identifiable intangibles and thereafter to goodwill. We make judgments and estimates
in conjunction with the carrying value of these assets, including amounts to be capitalized and
whether the asset has a finite life for amortization purposes.
Our annual impairment tests involve the use of different valuation techniques, including the
income approach and/or market approach, to determine the fair value of our reporting units.
Determining the fair value of a reporting unit is a matter of judgment and often involves the use
of significant estimates and assumptions. If the fair value of the reporting unit is less than its
carrying value, an impairment loss is recorded to the extent that the implied fair value of the
reporting units goodwill is less than its carrying value. We recorded an impairment charge of
$115.8 million in 2008 as a result of our test. At December 31, 2010 and 2009, no impairment was
deeded necessary. Significant and unanticipated changes to these assumptions could require an
additional provision for impairment in a future period.
Purchase Price Allocation of Acquired Businesses. We allocate the purchase price of acquired
businesses to the identifiable assets and liabilities of the businesses, post acquisition, based on
estimated fair values. The excess of the purchase price over the amount allocated to the assets
and liabilities, if any, is recorded as goodwill. We engage third-party appraisal firms and
valuation experts to assist in the determination of identifiable assets and liabilities. Our
judgments and estimates for the allocation of purchase price are based on information available
during the measurement period, these judgments and estimates can materially impact our financial
position as well as our results of operations.
Income Taxes. The determination and evaluation of our annual income tax provision involves
the interpretation of tax laws in various jurisdictions in which we operate and requires
significant judgment and the use of estimates and assumptions regarding significant future events
such as the amount, timing and character of income, deductions and tax credits. Changes in tax
laws, regulations and our level of operations or profitability in each jurisdiction may impact our
tax liability in any given year. While our annual tax provision is based on the information
available to us at the time, a number of years may elapse before the ultimate tax liabilities in
certain tax jurisdictions are determined. Current income tax expense (benefit) reflects an
estimate of our income tax liability for the current year, withholding taxes, changes in tax rates
and changes in prior year tax estimates as returns are filed. Deferred tax assets and liabilities
are recognized for the anticipated future tax effects of temporary differences between the
financial statement basis and the tax basis of our assets and liabilities using the enacted tax
rates in effect at year end. A valuation allowance for deferred tax assets is recorded when it is
more-likely-than-not that the benefit from the deferred tax asset will not be realized.
It is our intention to permanently reinvest all of the undistributed earnings of our
non-United States subsidiaries in such subsidiaries. Accordingly, we have not provided for United
States deferred taxes on the undistributed earnings of our non-United States subsidiaries. If a
distribution is made to us from the undistributed earnings of these subsidiaries, we could be
required to record additional taxes. Because we cannot predict when, if at all, we will make a
distribution of these undistributed earnings, we are unable to make a determination of the amount
of unrecognized deferred tax liability.
Recently Issued Accounting Standards
For a discussion of new accounting standards, see the applicable section in Note 1 to our
Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary
Data.
- 33 -
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, 2010, we had $36.5 million of borrowings on the
facility, and availability is reduced by outstanding letters of credit of $4.1 million. We do not
guarantee obligations of any unconsolidated entities.
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ITEM 7A. |
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES 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, 2010 we were exposed to interest rate fluctuations on approximately $58.2
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 $582,000. 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.
Foreign Currency Exchange Rate Risk
We have designated the United States dollar as the functional currency for our operations in
international locations as we contract with customers, purchase equipment and finance capital using
the United States 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, 2010, 2009 and 2008, we had a net foreign
exchange loss of $0.5 million, $0.7 million and $1.2 million, 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
United States dollars.
- 34 -
|
|
|
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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36 |
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|
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37 |
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39 |
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|
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|
40 |
|
|
|
|
41 |
|
|
|
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42 |
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|
|
|
43 |
|
|
|
|
73 |
|
- 35 -
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.
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.
Management initially assessed, concluded and disclosed in the Original Filing that
Allis-Chalmers maintained effective internal control over financial reporting as of December 31,
2010. However, after the Original Filing, we identified certain material adjustments in the
consolidated financial statements for which the Original Filing was amended and restated. In
connection with this amendment and restatement of the Original Filing, we have reassessed the
effectiveness of Allis-Chalmers internal control over financial reporting. In making the initial
assessment and the reassessment, we used the criteria in Internal Control Integral Framework issued
by the Committee of Sponsoring Organization of the Treadway Commission (COSO).
Based on the reassessment described above, we have concluded that Allis-Chalmers did not
maintain effective internal control over financial reporting as of December 31, 2010, based on
criteria in Internal Control-Integrated Framework issued by the COSO. Specifically, we did not
maintain effective controls over financial reporting over the calculation and valuation of deferred
tax assets, the related income tax provision and the related financial statement disclosures that
existed as of December 31, 2010.
As a result of the material weakness identified and the resulting amendments to the Original
Filing and amendments to Managements Report on Internal Control over Financial Reporting, UHY LLP,
an independent registered public accounting firm, has issued an updated attestation report on
Allis-Chalmers internal control over financial reporting.
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/A.
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ALLIS- CHALMERS ENERGY INC.
|
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By:
|
|
/s/ JORGEN RASMUSSEN
|
|
By:
|
|
/s/ CHRISTOPH BAUSCH |
|
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|
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Jorgen Rasmussen
|
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Christoph Bausch
|
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Chief Executive Officer
|
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|
Chief Financial Officer |
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|
- 36 -
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, 2010 and 2009, and the related consolidated
statements of operations, stockholders equity and cash flows for each of the three years in the
period ended December 31, 2010. Our audits also included the financial statement schedule listed
in the Index at Item 15. These consolidated financial statements and financial statement schedule
are the responsibility of the Companys management. Our responsibility is to express an opinion on
these consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audits to obtain
reasonable assurance about whether the consolidated financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all
material respects, the consolidated financial position of Allis-Chalmers Energy Inc. and
subsidiaries as of December 31, 2010 and 2009, and the consolidated results of their operations and
their cash flows for each of the three years in the period ended December 31, 2010, in conformity
with accounting principles generally accepted in the United States of America. Also, in our
opinion, the related financial statement schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents fairly in all material respects the
information set forth therein.
As discussed in Note 1, Note 2, Note 7, Note 14 and Note 16 to the consolidated financial
statements, the Company has restated its previously issued consolidated financial statements as of
and for the year ended December 31, 2010.
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, 2010, based on criteria established in Internal Control-Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated
March 15, 2011 (except for the effect of the material weakness described in Managements Report on
Internal Control Over Financial Reporting (Restated), as to which the
date is August 31, 2011),
expressed an adverse opinion on the effective operation of the Companys internal control over
financial reporting.
/s/ UHY LLP
Houston, Texas
March 15, 2011
(Except
for Note 1, Note 2, Note 7, Note 14 and Note 16, as to which the date
is August 31, 2011)
- 37 -
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, 2010, based on criteria established in Internal Control-Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria).
Allis-Chalmers Energy Inc.s management is responsible for maintaining effective internal control
over financial reporting, and for its assessment of the effectiveness of internal control over
financial reporting included in the accompanying Managements Report on Internal Control Over
Financial Reporting. Our responsibility is to express an opinion on the Companys internal control
over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk,
and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles. A
companys internal control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and
(3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
In our report dated March 15, 2011, we expressed an unqualified opinion on the effectiveness of
internal control over financial reporting. As described in the following paragraph the Company
subsequently identified a misstatement in its 2010 annual consolidated financial statements which
caused such financial statements to be restated. Management subsequently revised its assessment
due to the identification of a material weakness described in the following paragraph, which
resulted in the financial statement restatements. Accordingly, our opinion on the effectiveness of
the Companys internal control over financial reporting as of December 31, 2010, expressed herein
is different from that expressed in our initial report dated March 15, 2011.
A material weakness is a deficiency or a combination of deficiencies in internal control over
financial reporting, such that there is a reasonable possibility that a material misstatement of
the companys annual or interim financial statements will not be prevented or detected on a timely
basis. The following material weakness has been identified and included in managements restated
assessment; management did not have effective controls over the calculation and valuation of
deferred tax assets, the related income tax provision and the related consolidated financial
statement disclosure which resulted in a misstatement of and subsequent restatement of the
Companys consolidated financial statements for the year ended December 31, 2010. The material
weakness was considered in determining the nature, timing, and extent of audit tests applied in our
audit of the consolidated financial statements as of and for the year ended December 31, 2010 (as
restated) and this report does not affect our report on such restated financial statements.
In our opinion, because of the effect of the material weakness described above, the Company did not
maintain effective internal control over financial reporting as of December 31, 2010, based on the
criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated balance sheets of Allis-Chalmers Energy Inc. and
subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of
operations, stockholders equity, and cash flows for each of the three years in the period ended
December 31, 2010, and our report dated March 15, 2011 (Except for Note 1, Note 2, Note 7, Note 14
and Note 16, as to which the date is August 31, 2011) expressed an unqualified opinion and included
an explanatory paragraph related to the Companys restatement of the 2010 consolidated financial
statements.
/s/ UHY LLP
Houston, Texas
March 15, 2011 (except for the effect of the material weakness described in Managements Report on
Internal
Control Over Financial Reporting (Restated), as to which the date is
August 31, 2011)
- 38 -
ALLIS-CHALMERS
ENERGY INC.
CONSOLIDATED BALANCE SHEETS
|
|
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|
|
|
|
|
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(Restated) |
|
|
|
|
|
|
|
(In thousands, except for share and per |
|
|
|
share amounts) |
|
ASSETS |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
20,940 |
|
|
$ |
41,072 |
|
Trade receivables, net of allowance for
doubtful accounts of $4,361 and $4,923 at
December 31, 2010 and 2009, respectively |
|
|
144,960 |
|
|
|
105,059 |
|
Inventories |
|
|
42,140 |
|
|
|
34,528 |
|
Deferred income tax asset |
|
|
81 |
|
|
|
3,790 |
|
Prepaid expenses and other |
|
|
9,192 |
|
|
|
13,799 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
217,313 |
|
|
|
198,248 |
|
|
|
|
|
|
|
|
|
|
Property and equipment, at cost net of
accumulated depreciation of $286,062 and
$209,782 at December 31, 2010 and 2009,
respectively |
|
|
723,234 |
|
|
|
746,478 |
|
Goodwill |
|
|
46,333 |
|
|
|
40,639 |
|
Other intangible assets, net of accumulated
amortization of $16,835 and $13,973 at
December 31, 2010 and 2009, respectively |
|
|
33,899 |
|
|
|
32,649 |
|
Debt issuance costs, net of accumulated
amortization of $8,490 and $6,314 at December
31, 2010 and 2009, respectively |
|
|
7,405 |
|
|
|
9,545 |
|
Deferred income tax asset |
|
|
1,969 |
|
|
|
22,047 |
|
Other assets |
|
|
8,116 |
|
|
|
31,014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,038,269 |
|
|
$ |
1,080,620 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
Current maturities of long-term debt |
|
$ |
15,215 |
|
|
$ |
17,027 |
|
Trade accounts payable |
|
|
46,042 |
|
|
|
34,839 |
|
Accrued salaries, benefits and payroll taxes |
|
|
32,790 |
|
|
|
22,854 |
|
Accrued interest |
|
|
15,524 |
|
|
|
15,821 |
|
Accrued expenses |
|
|
30,676 |
|
|
|
21,918 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
140,247 |
|
|
|
112,459 |
|
|
|
|
|
|
|
|
|
|
Deferred income tax liability |
|
|
8,240 |
|
|
|
8,166 |
|
Long-term debt, net of current maturities |
|
|
478,225 |
|
|
|
475,206 |
|
Other long-term liabilities |
|
|
233 |
|
|
|
1,142 |
|
|
|
|
|
|
|
|
Total liabilities |
|
|
626,945 |
|
|
|
596,973 |
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity |
|
|
|
|
|
|
|
|
Preferred stock, $0.01 par value (25,000,000
shares authorized, 36,393 shares issued and
outstanding at December 31, 20010 and 2009) |
|
|
34,183 |
|
|
|
34,183 |
|
Common stock, $0.01 par value (200,000,000
shares authorized; 73,722,347 issued and
outstanding at December 31, 2010 and
71,378,529 issued and outstanding at December
31, 2009) |
|
|
737 |
|
|
|
714 |
|
Capital in excess of par value |
|
|
429,924 |
|
|
|
422,823 |
|
(Accumulated deficit) retained earnings |
|
|
(53,520 |
) |
|
|
25,927 |
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
411,324 |
|
|
|
483,647 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
1,038,269 |
|
|
$ |
1,080,620 |
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated Financial Statements.
- 39 -
ALLIS-CHALMERS
ENERGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(Restated) |
|
|
|
|
|
|
|
|
|
|
|
(In thousands, except per |
|
|
|
share amounts) |
|
Revenues |
|
$ |
659,665 |
|
|
$ |
506,253 |
|
|
$ |
675,948 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs |
|
|
498,120 |
|
|
|
379,437 |
|
|
|
443,414 |
|
Depreciation |
|
|
84,118 |
|
|
|
78,276 |
|
|
|
63,460 |
|
Selling, general and administrative |
|
|
60,434 |
|
|
|
50,763 |
|
|
|
62,774 |
|
Loss (gain) on asset dispositions |
|
|
10,624 |
|
|
|
1,602 |
|
|
|
(166 |
) |
Impairment of goodwill |
|
|
|
|
|
|
|
|
|
|
115,774 |
|
Amortization |
|
|
4,806 |
|
|
|
4,722 |
|
|
|
4,212 |
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses |
|
|
658,102 |
|
|
|
514,800 |
|
|
|
689,468 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations |
|
|
1,563 |
|
|
|
(8,547 |
) |
|
|
(13,520 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
(45,825 |
) |
|
|
(48,145 |
) |
|
|
(48,411 |
) |
Interest income |
|
|
537 |
|
|
|
72 |
|
|
|
5,617 |
|
Gain on debt extinguishment |
|
|
|
|
|
|
26,365 |
|
|
|
|
|
Other |
|
|
(3,211 |
) |
|
|
(798 |
) |
|
|
(563 |
) |
|
|
|
|
|
|
|
|
|
|
Total other expense |
|
|
(48,499 |
) |
|
|
(22,506 |
) |
|
|
(43,357 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes |
|
|
(46,936 |
) |
|
|
(31,053 |
) |
|
|
(56,877 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit (expense) |
|
|
(29,963 |
) |
|
|
9,863 |
|
|
|
17,413 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
|
(76,899 |
) |
|
|
(21,190 |
) |
|
|
(39,464 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividend |
|
|
(2,548 |
) |
|
|
(1,302 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss attributed to common stockholders |
|
$ |
(79,447 |
) |
|
$ |
(22,492 |
) |
|
$ |
(39,464 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(1.11 |
) |
|
$ |
(0.42 |
) |
|
$ |
(1.13 |
) |
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
(1.11 |
) |
|
$ |
(0.42 |
) |
|
$ |
(1.13 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
71,726 |
|
|
|
53,669 |
|
|
|
35,052 |
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
|
71,726 |
|
|
|
53,669 |
|
|
|
35,052 |
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated Financial Statements.
- 40 -
ALLIS-CHALMERS
ENERGY INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital in |
|
|
Retained |
|
|
Total |
|
|
|
Preferred Stock |
|
|
Common Stock |
|
|
Excess of |
|
|
Earnings |
|
|
Stockholders |
|
|
|
Shares |
|
|
Amount |
|
|
Shares |
|
|
Amount |
|
|
Par Value |
|
|
(Deficit) |
|
|
Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Restated) |
|
|
(Restated) |
|
|
|
|
|
|
|
(In thousands, except share amounts) |
|
Balances, December 31, 2007 |
|
|
|
|
|
$ |
|
|
|
|
35,116,035 |
|
|
$ |
351 |
|
|
$ |
326,095 |
|
|
$ |
87,883 |
|
|
$ |
414,329 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(39,464 |
) |
|
|
(39,464 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance under stock plans |
|
|
|
|
|
|
|
|
|
|
558,707 |
|
|
|
6 |
|
|
|
627 |
|
|
|
|
|
|
|
633 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,902 |
|
|
|
|
|
|
|
7,902 |
|
Tax benefits on stock plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2008 |
|
|
|
|
|
|
|
|
|
|
35,674,742 |
|
|
|
357 |
|
|
|
334,633 |
|
|
|
48,419 |
|
|
|
383,409 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21,190 |
) |
|
|
(21,190 |
) |
Preferred stock dividend |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,302 |
) |
|
|
(1,302 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rights offering, net of offering costs |
|
|
36,393 |
|
|
|
34,183 |
|
|
|
35,683,688 |
|
|
|
357 |
|
|
|
85,683 |
|
|
|
|
|
|
|
120,223 |
|
Issuance under stock plans |
|
|
|
|
|
|
|
|
|
|
20,099 |
|
|
|
|
|
|
|
43 |
|
|
|
|
|
|
|
43 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,799 |
|
|
|
|
|
|
|
4,799 |
|
Tax benefits on stock plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,335 |
) |
|
|
|
|
|
|
(2,335 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2009 |
|
|
36,393 |
|
|
|
34,183 |
|
|
|
71,378,529 |
|
|
|
714 |
|
|
|
422,823 |
|
|
|
25,927 |
|
|
|
483,647 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(76,899 |
) |
|
|
(76,899 |
) |
Preferred stock dividend |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,548 |
) |
|
|
(2,548 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Business acquisition |
|
|
|
|
|
|
|
|
|
|
1,000,000 |
|
|
|
10 |
|
|
|
1,990 |
|
|
|
|
|
|
|
2,000 |
|
Issuance under stock plans |
|
|
|
|
|
|
|
|
|
|
1,343,818 |
|
|
|
13 |
|
|
|
(1,735 |
) |
|
|
|
|
|
|
(1,722 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,030 |
|
|
|
|
|
|
|
8,030 |
|
Tax benefits on stock plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,184 |
) |
|
|
|
|
|
|
(1,184 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2010 |
|
|
36,393 |
|
|
$ |
34,183 |
|
|
|
73,722,347 |
|
|
$ |
737 |
|
|
$ |
429,924 |
|
|
$ |
(53,520 |
) |
|
$ |
411,324 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated Financial Statements.
- 41 -
ALLIS-CHALMERS
ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(Restated) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
Cash Flows from Operating Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(76,899 |
) |
|
$ |
(21,190 |
) |
|
$ |
(39,464 |
) |
Adjustments to reconcile net loss to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
88,924 |
|
|
|
82,998 |
|
|
|
67,672 |
|
Amortization and write-off of deferred issuance costs |
|
|
2,214 |
|
|
|
2,231 |
|
|
|
2,089 |
|
Gain on debt extinguishment |
|
|
|
|
|
|
(26,365 |
) |
|
|
|
|
Impairment of goodwill |
|
|
|
|
|
|
|
|
|
|
115,774 |
|
Stock-based compensation |
|
|
8,030 |
|
|
|
4,799 |
|
|
|
7,902 |
|
Allowance for bad debts |
|
|
368 |
|
|
|
2,835 |
|
|
|
3,283 |
|
Deferred income taxes |
|
|
20,310 |
|
|
|
(17,883 |
) |
|
|
(29,949 |
) |
Loss on investment |
|
|
1,466 |
|
|
|
|
|
|
|
|
|
Equity in loss of unconsolidated affiliates |
|
|
783 |
|
|
|
|
|
|
|
|
|
Loss (gain) on sale of property and equipment |
|
|
680 |
|
|
|
(948 |
) |
|
|
(1,762 |
) |
Loss (gain) on asset dispositions |
|
|
10,624 |
|
|
|
1,602 |
|
|
|
(166 |
) |
Changes in operating assets and liabilities, net of acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
Decrease (increase) in trade receivable |
|
|
(35,683 |
) |
|
|
49,977 |
|
|
|
(27,499 |
) |
Decrease (increase) in inventories |
|
|
(5,954 |
) |
|
|
4,559 |
|
|
|
(9,719 |
) |
Decrease (increase) in prepaid expenses and other assets |
|
|
11,142 |
|
|
|
4,628 |
|
|
|
(1,623 |
) |
Decrease in other assets |
|
|
1,746 |
|
|
|
1,648 |
|
|
|
1,224 |
|
(Decrease) increase in trade accounts payable |
|
|
11,061 |
|
|
|
(27,588 |
) |
|
|
21,903 |
|
(Decrease) increase in accrued interest |
|
|
(297 |
) |
|
|
(2,802 |
) |
|
|
567 |
|
(Decrease) increase in accrued expenses |
|
|
7,438 |
|
|
|
(4,607 |
) |
|
|
1,131 |
|
(Decrease) in other liabilities |
|
|
(909 |
) |
|
|
(1,051 |
) |
|
|
(1,130 |
) |
Increase in accrued salaries, benefits and payroll taxes |
|
|
9,872 |
|
|
|
2,662 |
|
|
|
3,452 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
54,916 |
|
|
|
55,505 |
|
|
|
113,685 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions, net of cash acquired |
|
|
(15,935 |
) |
|
|
|
|
|
|
(53,709 |
) |
Net sales (purchases) of investment interests |
|
|
368 |
|
|
|
(1,102 |
) |
|
|
1,374 |
|
Purchases of property and equipment |
|
|
(102,155 |
) |
|
|
(78,067 |
) |
|
|
(154,468 |
) |
Deposits on asset commitments |
|
|
18,347 |
|
|
|
2,685 |
|
|
|
(9,901 |
) |
Proceeds from asset dispositions |
|
|
25,000 |
|
|
|
3,916 |
|
|
|
3,000 |
|
Proceeds from sale of property and equipment |
|
|
6,638 |
|
|
|
8,581 |
|
|
|
11,480 |
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(67,737 |
) |
|
|
(63,987 |
) |
|
|
(202,224 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of long-term debt |
|
|
4,000 |
|
|
|
25,000 |
|
|
|
25,000 |
|
Payments on long-term debt |
|
|
(42,168 |
) |
|
|
(64,755 |
) |
|
|
(9,905 |
) |
Net borrowings (repayments) on lines of credit |
|
|
36,500 |
|
|
|
(36,500 |
) |
|
|
36,500 |
|
Proceeds from issuance of stock, net of offering costs |
|
|
|
|
|
|
120,223 |
|
|
|
|
|
Payment of preferred stock dividend |
|
|
(2,548 |
) |
|
|
(665 |
) |
|
|
|
|
Exercise of options and warrants |
|
|
(1,722 |
) |
|
|
43 |
|
|
|
633 |
|
Income tax impact of stock-based compensation plans |
|
|
(1,184 |
) |
|
|
|
|
|
|
9 |
|
Debt issuance costs |
|
|
(189 |
) |
|
|
(658 |
) |
|
|
(525 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash (used) provided by financing activities |
|
|
(7,311 |
) |
|
|
42,688 |
|
|
|
51,712 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
(20,132 |
) |
|
|
34,206 |
|
|
|
(36,827 |
) |
Cash and cash equivalents at beginning of year |
|
|
41,072 |
|
|
|
6,866 |
|
|
|
43,693 |
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year |
|
$ |
20,940 |
|
|
$ |
41,072 |
|
|
$ |
6,866 |
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated Financial Statements.
- 42 -
ALLIS-CHALMERS
ENERGY INC.
Notes to Consolidated Financial Statements
NOTE 1 NATURE OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization of Business
Allis-Chalmers Energy Inc. (Allis-Chalmers, we, our or us) was incorporated in
Delaware in 1913. We provide services and equipment to oil and natural gas exploration and
production companies throughout the United States including Texas, Louisiana, Pennsylvania, West
Virginia, Wyoming, Oklahoma, offshore in the Gulf of Mexico, and internationally, primarily in
Argentina, Brazil, Bolivia and Mexico. We operate in three sectors of the oil and natural gas
service industry: Oilfield Services; Drilling and Completion and Rental Services.
The nature of our operations and the many regions in which we operate subject us to changing
economic, regulatory and political conditions. We are vulnerable to near-term and long-term
changes in the demand for and prices of oil and natural gas and the related demand for oilfield
service operations.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally
accepted in the United States of America requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements, and the reported amounts of revenues and
expenses during the reporting period. Future events and their effects cannot be perceived with
certainty. Accordingly, our accounting estimates require the exercise of judgment. While
management believes that the estimates and assumptions used in the preparation of the consolidated
financial statements are appropriate, actual results could differ from those estimates. Estimates
are used for, but are not limited to, determining the following: allowance for doubtful accounts,
recoverability of long-lived assets and intangibles, useful lives used in depreciation and
amortization, income taxes and valuation allowances. The accounting estimates used in the
preparation of the consolidated financial statements may change as new events occur, as more
experience is acquired, as additional information is obtained and as our operating environment
changes.
Principles of Consolidation
The consolidated financial statements include the accounts of Allis-Chalmers and its
subsidiaries. Our subsidiaries at December 31, 2010 are AirComp LLC, Allis-Chalmers Tubular
Services LLC, Allis-Chalmers Directional Drilling Services LLC, Allis-Chalmers Rental Services LLC,
Allis-Chalmers Production Services LLC, Allis-Chalmers Management LLC, Allis-Chalmers Holdings
Inc., American Well Control LLC (AWC), DLS Drilling, Logistics & Services Company (DLS), DLS
Argentina Limited, Tanus Argentina S.A., Petro-Rentals LLC, Rebel Rentals LLC, Allis-Chalmers
Drilling LLC, BCH Ltd. (BCH), ALY do Brasil Servicos do Petroleo Ltda, Drilling Logistics and
Services de Mexico and BCH Energy do Brasil Servicos de Petroleo Ltda. All significant
inter-company transactions have been eliminated.
Revenue Recognition
We provide rental equipment, oilfield services and drilling services to our customers at per
day, or daywork, and per job contractual rates and recognize the drilling related revenue as the
work progresses and when collectibility is reasonably assured. Revenue from daywork contracts is
recognized when it is realized or realizable and earned. On daywork contracts, revenue is
recognized based on the number of days completed at fixed rates stipulated by the contract. For
certain contracts, we receive lump-sum and other fees for equipment and other mobilization costs.
Mobilization fees and the related costs are deferred and amortized over the contract terms when
material. We recognize reimbursements received for out-of-pocket expenses incurred as revenues and
account for out-of-pocket expenses as direct costs. Payments from customers for the cost of
oilfield rental equipment that is damaged or lost-in-hole are reflected as revenues. We recognized
revenue from damaged or lost-in-hole equipment of $5.9 million, $4.3 million and $10.6 million for
the years ended December 31, 2010, 2009 and 2008, respectively.
- 43 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
Allowance for Doubtful Accounts
Accounts receivable are customer obligations due under normal trade terms. We sell our
services to oil and natural gas exploration and production companies. We perform continuing credit
evaluations of its customers financial condition and although we generally do not require
collateral, letters of credit may be required from customers in certain circumstances.
The allowance for doubtful accounts represents our estimate of the amount of probable credit
losses existing in our accounts receivable. Significant individual accounts receivable balances
which have been outstanding greater than 90 days are reviewed individually for collectibility. We
have a limited number of customers with individually large amounts due at any given date. Any
unanticipated change in any one of these customers credit worthiness or other matters affecting
the collectibility of amounts due from such customers could have a material effect on the results
of operations in the period in which such changes or events occur. After all attempts to collect a
receivable have failed, the receivable is written off against the allowance. As of December 31,
2010 and 2009, we had recorded an allowance for doubtful accounts of $4.4 million and $4.9 million
respectively. Bad debt expense was $368,000, $2.8 million and $3.3 million for the years ended
December 31, 2010, 2009 and 2008, respectively.
Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less at
the time of purchase to be cash equivalents.
Inventories
Inventories are stated at the lower of cost or market. Cost is determined using the first -
in, first out (FIFO) method or the average cost method, which approximates FIFO, and includes
the cost of materials, labor and manufacturing overhead.
Property and Equipment
Property and equipment is recorded at cost less accumulated depreciation. Certain equipment
held under capital leases are classified as equipment and the related obligations are recorded as
liabilities.
Maintenance and repairs, which do not improve or extend the life of the related assets, are
charged to operations when incurred. Refurbishments and renewals are capitalized when the value of
the equipment is enhanced for an extended period. When property and equipment are sold or
otherwise disposed of, the asset account and related accumulated depreciation account are relieved,
and any gain or loss is included in operations. Interest is capitalized on construction in
progress at the weighted average cost of debt outstanding during the construction period or at the
interest rate on debt incurred for construction.
The cost of property and equipment currently in service is depreciated over the estimated
useful lives of the related assets, which range from two to twenty years. Depreciation is computed
on the straight-line method for financial reporting purposes. Capital leases are amortized using
the straight-line method over the estimated useful lives of the assets and lease amortization is
included in depreciation expense. Depreciation expense charged to operations was $84.1 million,
$78.3 million and $63.5 million for the years ended December 31, 2010, 2009 and 2008, respectively.
Goodwill, Intangible Assets and Amortization
Goodwill and other intangible assets with infinite lives are not amortized, but tested for
impairment annually or more frequently if circumstances indicate that impairment may exist.
Intangible assets with finite useful lives are amortized either on a straight-line basis over the
assets estimated useful life or on a basis that reflects the pattern in which the economic
benefits of the intangible assets are realized.
The impairment test requires the allocation of goodwill and all other assets and liabilities
to reporting units. Reporting units are at a business unit level and is one level below our
operating segments. We perform impairment tests on the carrying value of our goodwill on an annual
basis as of December 31st for each of our reportable segments. Our annual impairment tests involve
the use of different valuation techniques, including the income approach and/or market approach, to
determine the fair value of our reporting units. Determining the fair value of a reporting unit is
a matter of judgment and often involves the use of significant estimates and assumptions. If the
fair value of the reporting unit is less than its carrying value, an impairment loss is recorded to
the extent that the implied fair value of the reporting units goodwill is less than its carrying
value. As a result we recorded an impairment of $115.8 million at December 31, 2008. At December
31, 2010 and 2009, no impairment was deemed necessary. Significant and unanticipated changes to
these assumptions could require an additional provision for impairment in a future period.
- 44 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
Impairment of Long-Lived Assets
Long-lived assets, which include property, plant and equipment, and other intangible assets,
and certain other assets are reviewed for impairment whenever events or changes in circumstances
indicate that the carrying amount may not be recoverable. An impairment loss is recorded in the
period in which it is determined that the carrying amount is not recoverable. The determination of
recoverability is made based upon the estimated undiscounted future net cash flows, excluding
interest expense. The impairment loss is determined by comparing the fair value, as determined by
a discounted cash flow analysis, with the carrying value of the related assets.
Financial Instruments
Financial instruments consist of cash and cash equivalents, accounts receivable, accounts
payable and debt. The carrying value of cash and cash equivalents and accounts receivable and
payable approximate fair value due to their short-term nature. We believe the fair values and the
carrying value of our debt, excluding the senior notes, would not be materially different due to
the instruments interest rates approximating market rates for similar borrowings at December 31,
2010 and 2009. Our senior notes, in the aggregate amount of $430.2 million at both December 31,
2010 and 2009, 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 $436.1 million and
$394.2 million at December 31, 2010 and 2009, respectively. The price at which our senior notes
trade is based on many factors such as the level of interest rates, the economic environment, the
outlook for the oilfield services industry and the perceived credit risk. Additionally, due to the
turmoil in the financial markets of 2008 and 2009, and its impact on investors of our senior notes,
the price at which our senior notes trade may be affected by the investors financial distress and
need for liquidity.
Concentration of Credit and Customer Risk
Financial instruments that potentially subject us to concentrations of credit risk consist
principally of cash and cash equivalents and trade accounts receivable. As of December 31, 2010,
we have approximately $1.9 million and $2.7 million of cash and cash equivalents residing in
Argentina and Brazil, respectively. Cash and cash equivalents of $1.6 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 one financial institution
exceeded the $250,000 federally insured limit at December 31, 2010 by a total of $16.7 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 2010, 2009 and 2008, one of our customers, Pan
American Energy LLC Sucursal Argentina, or Pan American Energy, represented 31.1%, 35.5% and 28.5%
of our consolidated revenues, respectively. Revenues from Pan American Energy represented 52.5%,
56.6% and 62.0% of our international revenues in 2010, 2009 and 2008, respectively (see Note 15).
Debt Issuance Costs
The costs related to the issuance of debt are capitalized and amortized to interest expense
using the straight-line method, which approximates the interest method, over the maturity periods
of the related debt. Interest expense related to debt issuance costs were $2.2 million, $2.2
million and $2.1 million for the years ended December 31, 2010, 2009 and 2008, 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.
- 45 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
Current income tax expense reflects an estimate of our income tax liability for the current
year, withholding taxes, changes in tax rates and changes in prior year tax estimates as returns
are filed. Deferred tax assets and liabilities are recognized for the anticipated future tax
effects of temporary differences between the financial statement basis and the tax basis of our
assets and liabilities using the enacted tax rates in effect at year end. A valuation allowance
for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the
deferred tax asset will not be realized. For United States federal tax purposes, our tax returns
for the tax years 2007 through 2009 remain open for examination by the tax authorities. Our
foreign tax returns remain open for examination for the tax years 2002 through 2009. Generally,
for state tax purposes, our 2004 through 2009 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-United States subsidiaries in such subsidiaries. Accordingly, we have not provided for United
States deferred taxes on the $100.2 million of undistributed earnings of our non-United States
subsidiaries as of December 31, 2010. 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 recognize all share-based payments to employees, including grants of employee stock
options, in the financial statements based on their grant-date fair values. We utilize the
Black-Scholes model to determine fair value, which incorporates assumptions to value stock-based
awards. The dividend yield on our common stock is assumed to be zero as we have historically not
paid dividends and have no current plans to do so in the future. The expected volatility is based
on historical volatility of our common stock. The risk-free interest rate is the related United
States Treasury yield curve for periods within the expected term of the option at the time of
grant. We estimate forfeiture rates based on our historical experience.
Our net income (loss) for the years ended December 31, 2010, 2009 and 2008 includes
approximately $8.0 million, $4.8 million and $7.9 million of compensation costs related to
share-based payments, respectively. The tax benefit recorded in association with the share-based
payments was $9,000 for the year-ended December 31, 2008. Due to expired unexercised nonqualified
stock options and restricted stock vesting at market prices lower than the grant price, we adjusted
$1.2 million and $2.3 million of excess tax asset against additional paid in capital for the years
ended December 31, 2010 and 2009, respectively. As of December 31, 2010 there is $6.5 million of
unrecognized compensation expense related to non-vested stock based compensation grants.
No options were granted in 2008. See Note 11 for further disclosures regarding stock options.
The following assumptions were applied in determining the compensation costs for options granted
in 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
Expected dividend yield |
|
|
|
|
|
|
|
|
Expected price volatility |
|
|
89.81 |
% |
|
|
77.32 |
% |
Risk-free interest rate |
|
|
1.41 |
% |
|
|
1.37 |
% |
Expected life of options |
|
5 years |
|
5 years |
Weighted
average fair value of options granted at market value |
|
$ |
2.63 |
|
|
$ |
0.77 |
|
Income (Loss) Per Common Share
Basic earnings per share are computed on the basis of the weighted average number of shares of
common stock outstanding during the period. Diluted earnings per share is similar to basic
earnings per share, but presents the dilutive effect on a per share basis of potential common
shares (e.g., convertible preferred stock, stock options, etc.) as if they had been converted.
Restricted stock grants are legally considered issued and outstanding, but are included in basic
and diluted earnings per share only to the extent that they are vested. Unvested restricted stock
is included in the computation of diluted earnings per share using the treasury stock method.
Potential dilutive common shares that have an anti-dilutive effect (e.g., those that increase
income per share) are excluded from diluted earnings (deficit) per share.
- 46 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
The components of basic and diluted earnings (deficit) per share are as follows (in thousands,
except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(Restated) |
|
|
|
|
|
|
|
|
|
Numerator: |
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(76,899 |
) |
|
$ |
(21,190 |
) |
|
$ |
(39,464 |
) |
Preferred stock dividend |
|
|
(2,548 |
) |
|
|
(1,302 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss attributed to common stockholders |
|
$ |
(79,447 |
) |
|
$ |
(22,492 |
) |
|
$ |
(39,464 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding excluding nonvested restricted stock |
|
|
71,726 |
|
|
|
53,669 |
|
|
|
35,052 |
|
Effect of potentially dilutive common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
Warrants and share based compensation shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding and assumed conversions |
|
|
71,726 |
|
|
|
53,669 |
|
|
|
35,052 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(1.11 |
) |
|
$ |
(0.42 |
) |
|
$ |
(1.13 |
) |
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
(1.11 |
) |
|
$ |
(0.42 |
) |
|
$ |
(1.13 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Potentially dilutive securities excluded as anti-dilutive |
|
|
15,680 |
|
|
|
15,059 |
|
|
|
1,041 |
|
|
|
|
|
|
|
|
|
|
|
Convertible preferred stock and share based compensation shares of approximately 13.5 million,
7.5 million and 332,000 were excluded in the computation of diluted earnings per share for 2010,
2009 and 2008, respectively as the effect would have been anti-dilutive due to the net loss for the
year.
Segments of an Enterprise and Related Information
We designate the internal organization that is used by management for allocating resources and
assessing performance as the source of our reportable segments. Please see Note 16 for further
disclosure of segment information and disclosures by geographic region.
New Accounting Pronouncements
In June 2009, the Financial Accounting Standards Board, or the FASB, issued authoritative
guidance that eliminates the qualifying special purpose entity concept, changes the requirements
for derecognizing financial assets and requires enhanced disclosures about transfers of financial
assets. The guidance also revises earlier guidance for determining whether an entity is a variable
interest entity, requires a new approach for determining who should consolidate a variable interest
entity, changes when it is necessary to reassess who should consolidate a variable interest entity,
and requires enhanced disclosures related to an enterprises involvement in variable interest
entities. We adopted this guidance effective January 1, 2010, which did not have a material effect
on our financial statements.
In October 2009, the FASB issued authoritative guidance that amends earlier guidance
addressing the accounting for contractual arrangements in which an entity provides multiple
products or services (deliverables) to a customer. The amendments address the unit of accounting
for arrangements involving multiple deliverables and how arrangement consideration should be
allocated to the separate units of accounting, when applicable, by establishing a selling price
hierarchy for determining the selling price of a deliverable. The selling price used for each
deliverable will be based on vendor-specific objective evidence if available, third-party evidence
if vendor-specific objective evidence is not available, or estimated selling price if neither
vendor-specific nor third-party evidence is available. The amendments also require that
arrangement consideration be allocated at the inception of an arrangement to all deliverables using
the relative selling price method. This guidance is effective for fiscal years beginning on or
after June 15, 2010, with earlier application permitted. We adopted this guidance effective
January 1, 2011, which did not have a material effect on our financial statements.
- 47 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
In January 2010, the FASB issued authoritative guidance that changes the disclosure
requirements for fair value measurements. Specifically, the changes require a reporting entity to
disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair
value measurements and describe the reasons for the transfers. The changes also clarify existing
disclosure requirements related to how assets and liabilities should be grouped by class and
valuation techniques used for recurring and nonrecurring fair value measurements. We adopted this
guidance in the first quarter 2010, which did not have a material effect on our financial position,
results of operations or cash flows.
In February 2010, the FASB amended guidance on subsequent events to alleviate potential
conflicts between FASB guidance and SEC requirements. Under this amended guidance, SEC filers are
no longer required to disclose the date through which subsequent events have been evaluated in
originally issued and revised financial statements. This guidance was effective immediately and we
adopted these new requirements in the first quarter of 2010. The adoption of this guidance did not
have a material effect on our financial statements.
NOTE 2 RESTATEMENT OF THE CONSOLIDATED FINANCIAL STATEMENTS
On July 25, 2011, our management concluded that the previously filed consolidated financial
statements for the fourth quarter of 2010 and as of and for the year ended December 31, 2010 were
no longer reliable. The restatement is necessitated by our determination that positive evidence
available at year end 2010 was not sufficient to overcome the negative evidence around the deferred
tax assets and to justify not booking a valuation allowance against federal income tax assets and
foreign tax credits. The correction of this error resulted in a $37.4 million increase in the
deferred tax valuation allowance and income tax expense. As a result of this determination,
management concluded that a material weakness in the Companys internal control over financial
reporting over the calculation and valuation of deferred tax assets, the related income tax
provision and the related financial statement disclosures existed as of December 31, 2010.
The effects of the restatements on our consolidated financial statements for the year ended
December 31, 2010 follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2010 |
|
|
|
Previously |
|
|
|
|
|
|
|
|
|
Reported |
|
|
Adjustments |
|
|
Restated |
|
|
|
(In thousands, except per share amounts) |
|
Consolidated Balance Sheets |
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax asset current |
|
$ |
1,835 |
|
|
$ |
(1,754 |
) |
|
$ |
81 |
|
Deferred income tax asset noncurrent |
|
|
37,602 |
|
|
|
(35,633 |
) |
|
|
1,969 |
|
Accumulated deficit |
|
|
(16,133 |
) |
|
|
(37,387 |
) |
|
|
(53,520 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Statements of Operations |
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit (expense) |
|
$ |
7,424 |
|
|
$ |
(37,387 |
) |
|
$ |
(29,963 |
) |
Net loss |
|
|
(39,512 |
) |
|
|
(37,387 |
) |
|
|
(76,899 |
) |
Net loss attributed to common stockholders |
|
|
(42,060 |
) |
|
|
(37,387 |
) |
|
|
(79,447 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(0.59 |
) |
|
$ |
(0.52 |
) |
|
$ |
(1.11 |
) |
Diluted |
|
$ |
(0.59 |
) |
|
$ |
(0.52 |
) |
|
$ |
(1.11 |
) |
Weighted Average Shares Outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
71,726 |
|
|
|
|
|
|
|
71,726 |
|
Diluted |
|
|
71,726 |
|
|
|
|
|
|
|
71,726 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Statements of Cash Flows |
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(39,512 |
) |
|
$ |
(37,387 |
) |
|
$ |
(76,899 |
) |
Deferred income taxes |
|
|
(17,077 |
) |
|
|
37,387 |
|
|
|
20,310 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 48 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
NOTE 3 EMPLOYEE BENEFIT PLANS
On June 30, 2003, we adopted a 401(k) Profit Sharing Plan (the Plan). The Plan is a defined
contribution savings plan designed to provide retirement income to our eligible employees. The
Plan is intended to be qualified under Section 401(k) of the Internal Revenue Code of 1986, as
amended. It is funded by voluntary pre-tax contributions from eligible employees who may
contribute a percentage of their eligible compensation, limited and subject to statutory limits.
The Plan is also funded by discretionary matching employer contributions. Eligible employees
cannot participate in the Plan until they have attained the age of 21 and completed three-months of
service with us. Each participant is 100% vested with respect to the participants contributions
and our matching contributions. Contributions are invested, as directed by the participant, in
investment funds available under the Plan. Matching contributions of approximately $97,000,
$349,000 and $1.5 million were paid in 2010, 2009 and 2008, respectively.
NOTE 4 ACQUISITIONS AND ASSET DISPOSITIONS
On December 31 2008, we completed the acquisition of all of the outstanding stock of BCH for a
total consideration of approximately $56.1 million. Approximately $251,000 of costs were incurred
in relation to the BCH acquisition. BCH is a land drilling contractor operating in Brazil. The
following table summarizes the allocation of the purchase price and related acquisition costs to
the estimated fair value of the assets acquired at the date of acquisition (in thousands):
|
|
|
|
|
Current assets |
|
$ |
7,622 |
|
Property and equipment |
|
|
53,369 |
|
Intangible assets, including goodwill |
|
|
26,199 |
|
|
|
|
|
Total assets acquired |
|
|
87,190 |
|
|
|
|
|
Current liabilities |
|
|
14,456 |
|
Long-term debt, less current portion |
|
|
16,364 |
|
|
|
|
|
Total liabilities assumed |
|
|
30,820 |
|
|
|
|
|
Net assets acquired |
|
$ |
56,370 |
|
|
|
|
|
BCHs historical property and equipment values were decreased by approximately $2.8 million
based on third-party valuations. Intangible assets included approximately $18.5 million assigned
to goodwill, $4.9 million to customer contracts, $2.2 million assigned to trade name and $600,000
to non-competes based on third-party valuations. The amortizable intangibles have a
weighted-average useful life of 12.6 years. Goodwill was subsequently reduced in 2009 by $1.3
million of insurance proceeds that were received for a rig loss that occurred prior to acquisition
and by $1.3 million for the utilization of pre acquisition tax asset. The results of BCH since the
acquisition are included in our Drilling and Completion segment.
On July 12, 2010, we acquired AWC for a total consideration of approximately $19.2 million,
which included approximately $17.2 million in cash and 1.0 million shares of our common stock. AWC
is a leading manufacturer of premium high-pressure valves used in hydraulic fracturing in the
unconventional gas shale plays. The following table summarizes the allocation of the purchase
price and related acquisition costs to the estimated fair value of the assets acquired at the date
of acquisition (in thousands):
|
|
|
|
|
Current assets |
|
$ |
7,585 |
|
Property and equipment |
|
|
2,756 |
|
Intangible assets, including goodwill |
|
|
11,749 |
|
Other long-term assets |
|
|
2 |
|
|
|
|
|
Total assets acquired |
|
|
22,092 |
|
Current liabilities |
|
|
1,527 |
|
Long-term liabilities |
|
|
1,401 |
|
|
|
|
|
Net assets acquired |
|
$ |
19,164 |
|
|
|
|
|
AWCs historical property and equipment values were increased by approximately $27,000 based
on third-party valuations. Goodwill of $5.7 million was recognized for this acquisition and was
calculated as the excess of the consideration transferred over the fair value of the net assets
acquired. It includes the expected synergies and other benefits that we believe will result from
the combined operations and intangible assets that do not qualify for separate recognition such as
assembled workforce. Other intangible assets included approximately $5.6 million assigned to
customer lists, $400,000 to trade name and $55,000 to non-competes. None of
the intangibles are tax deductible. The amortizable intangibles have a weighted-average
useful life of 9.9 years. AWCs financial results since the acquisition are included in our Rental
Services segment.
All of the aforementioned acquisitions were accounted for using the purchase method of
accounting.
- 49 -
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.
During 2009, we recorded a $1.6 million loss on asset disposition in our Drilling and
Completion segment. The insurance proceeds of $3.9 million related to damages incurred on a
blow-out which destroyed one of our drilling rigs were not sufficient to cover the book value of
the rig and related assets.
During 2010, we recorded a $10.6 million loss on asset disposition in our Drilling and
Completion segment. We purchased two drilling rigs that we were unable to operate and returned the
rigs to the manufacturer. The loss includes an early repayment penalty of $311,000 on the
underlying debt and the write-off of $115,000 of deferred financing fees.
NOTE 5 INVENTORIES
Inventories are comprised of the following as of December 31 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
Manufactured |
|
|
|
|
|
|
|
|
Finished goods |
|
$ |
4,238 |
|
|
$ |
2,983 |
|
Work in process |
|
|
2,990 |
|
|
|
2,299 |
|
Raw materials |
|
|
3,600 |
|
|
|
884 |
|
|
|
|
|
|
|
|
Total manufactured |
|
|
10,828 |
|
|
|
6,166 |
|
Rig parts and related inventory |
|
|
11,565 |
|
|
|
10,654 |
|
Shop supplies and related inventory |
|
|
9,620 |
|
|
|
7,762 |
|
Chemicals and drilling fluids |
|
|
4,814 |
|
|
|
4,381 |
|
Rental supplies |
|
|
1,761 |
|
|
|
2,134 |
|
Hammers |
|
|
2,380 |
|
|
|
2,257 |
|
Coiled tubing and related inventory |
|
|
1,046 |
|
|
|
939 |
|
Drive pipe |
|
|
126 |
|
|
|
235 |
|
|
|
|
|
|
|
|
Total inventories |
|
$ |
42,140 |
|
|
$ |
34,528 |
|
|
|
|
|
|
|
|
NOTE 6 PROPERTY AND OTHER INTANGIBLE ASSETS
Property and equipment is comprised of the following as of December 31 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation |
|
|
|
|
|
|
|
|
|
Period |
|
|
2010 |
|
|
2009 |
|
Land |
|
|
|
|
|
$ |
2,452 |
|
|
$ |
2,211 |
|
Building and improvements |
|
15-20 years |
|
|
|
10,201 |
|
|
|
8,611 |
|
Transportation equipment |
|
2-10 years |
|
|
|
37,060 |
|
|
|
33,353 |
|
|
Drill pipe and rental equipment |
|
2-20 years |
|
|
|
390,263 |
|
|
|
380,185 |
|
Drilling, workover and pulling rigs |
|
20 years |
|
|
|
255,647 |
|
|
|
248,780 |
|
Machinery and equipment |
|
2-20 years |
|
|
|
245,609 |
|
|
|
226,601 |
|
Furniture, computers, software and leasehold improvements |
|
3-10 years |
|
|
|
10,839 |
|
|
|
9,128 |
|
Construction in progress equipment |
|
|
N/A |
|
|
|
57,225 |
|
|
|
47,391 |
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
1,009,296 |
|
|
|
956,260 |
|
Less: accumulated depreciation |
|
|
|
|
|
|
(286,062 |
) |
|
|
(209,782 |
) |
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net |
|
|
|
|
|
$ |
723,234 |
|
|
$ |
746,478 |
|
|
|
|
|
|
|
|
|
|
|
|
The net book value of equipment recorded under capital leases was $0.0 and $1.0 million as of
December 31, 2010 and 2009, respectively. Interest expense capitalized to property and equipment
was $827,000, $2.2 million and $1.9 million for the years ended December 31, 2010, 2009 and 2008,
respectively.
- 50 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
Other intangible assets are as follows as of December 31 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization |
|
|
|
|
|
|
|
|
|
Period |
|
|
2010 |
|
|
2009 |
|
Intellectual property |
|
10-20 years |
|
|
$ |
4,229 |
|
|
$ |
3,829 |
|
Non-compete agreements |
|
3-5 years |
|
|
|
895 |
|
|
|
2,640 |
|
Customer relationships |
|
10-15 years |
|
|
|
43,633 |
|
|
|
38,033 |
|
Patents |
|
12-15 years |
|
|
|
1,327 |
|
|
|
1,327 |
|
Other intangible assets |
|
2-10 years |
|
|
|
650 |
|
|
|
793 |
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
50,734 |
|
|
|
46,622 |
|
Less: accumulated amortization |
|
|
|
|
|
|
(16,835 |
) |
|
|
(13,973 |
) |
|
|
|
|
|
|
|
|
|
|
|
Other intangibles assets, net. |
|
|
|
|
|
$ |
33,899 |
|
|
$ |
32,649 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
|
Gross |
|
|
Accumulated |
|
|
Gross |
|
|
Accumulated |
|
|
|
Value |
|
|
Amortization |
|
|
Value |
|
|
Amortization |
|
Intellectual property |
|
$ |
4,229 |
|
|
$ |
1,157 |
|
|
$ |
3,829 |
|
|
$ |
823 |
|
Non-compete agreements |
|
|
895 |
|
|
|
576 |
|
|
|
2,640 |
|
|
|
1,879 |
|
Customer relationships |
|
|
43,633 |
|
|
|
13,998 |
|
|
|
38,033 |
|
|
|
10,209 |
|
Patents |
|
|
1,327 |
|
|
|
484 |
|
|
|
1,327 |
|
|
|
382 |
|
Other intangible assets |
|
|
650 |
|
|
|
620 |
|
|
|
793 |
|
|
|
680 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
50,734 |
|
|
$ |
16,835 |
|
|
$ |
46,622 |
|
|
$ |
13,973 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization expense related to other intangibles was $4.8 million, $4.7 million and $4.2
million for the years ended December 31, 2010, 2009 and 2008, respectively. Future amortization of
intangible assets at December 31, 2010 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible Amortization by Period |
|
|
|
Years Ended December 31, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 and |
|
|
|
2011 |
|
|
2012 |
|
|
2013 |
|
|
2014 |
|
|
Thereafter |
|
Intellectual property |
|
$ |
356 |
|
|
$ |
356 |
|
|
$ |
356 |
|
|
$ |
347 |
|
|
$ |
1,657 |
|
Non-compete agreements |
|
|
266 |
|
|
|
43 |
|
|
|
10 |
|
|
|
|
|
|
|
|
|
Customer relationships |
|
|
4,092 |
|
|
|
4,092 |
|
|
|
4,092 |
|
|
|
4,071 |
|
|
|
13,288 |
|
Patents |
|
|
102 |
|
|
|
102 |
|
|
|
102 |
|
|
|
102 |
|
|
|
435 |
|
Other intangible assets |
|
|
28 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total intangible amortization |
|
$ |
4,844 |
|
|
$ |
4,595 |
|
|
$ |
4,560 |
|
|
$ |
4,520 |
|
|
$ |
15,380 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 7 INCOME TAXES
As discussed in Note 2, management concluded that the previously filed consolidated financial
statements for the fourth quarter of 2010 and for the year ended December 31, 2010 were no longer
reliable. Our restated provision for income taxes and related balance sheet accounts for 2010 are
included in the following tables below. The restatement increased our income tax expense and
valuation allowance by $37.4 million.
We had a loss before income taxes of $58.2 million, $43.9 million and $95.3 million for United
States tax purposes for the years ended December 31, 2010, 2009 and 2008, respectively. We also
had income before income taxes of $11.3 million, $12.9 million and $38.4 million reported in
non-United States countries for the years ended December 31, 2010, 2009 and 2008, respectively. We
treat the withholding taxes incurred by our United States subsidiaries in foreign countries as
foreign tax, and we anticipate using those tax payments to offset United States tax. We are
required to file a consolidated United States federal income tax return. We file foreign income
tax returns in Argentina, Brazil, Bolivia and Canada related to our Drilling and Completion
operations.
We recognize the impact of uncertain tax positions in our financial statements, if a tax
position is challenged by a taxing authority and there is a more likely than not chance the tax
position will be disallowed, based on the technical merits of the position. We recognize interest
and penalties related to uncertain tax positions as a component of income tax expense. We
identified no uncertain tax positions for the three years in the period ended December 31, 2010.
- 51 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
The income tax provision consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(Restated) |
|
|
|
|
|
|
|
|
|
Current income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
$ |
(1,123 |
) |
|
$ |
8 |
|
|
$ |
(1,525 |
) |
State |
|
|
580 |
|
|
|
324 |
|
|
|
471 |
|
Foreign |
|
|
10,196 |
|
|
|
7,688 |
|
|
|
13,590 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,653 |
|
|
|
8,020 |
|
|
|
12,536 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
|
18,441 |
|
|
|
(15,185 |
) |
|
|
(28,462 |
) |
State |
|
|
1,570 |
|
|
|
(1,626 |
) |
|
|
(1,149 |
) |
Foreign |
|
|
299 |
|
|
|
(1,072 |
) |
|
|
(338 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
20,310 |
|
|
|
(17,883 |
) |
|
|
(29,949 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
29,963 |
|
|
$ |
(9,863 |
) |
|
$ |
(17,413 |
) |
|
|
|
|
|
|
|
|
|
|
Significant components of deferred income tax assets as of December 31, were as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
|
(Restated) |
|
|
|
|
|
Deferred income tax assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization |
|
$ |
27,473 |
|
|
$ |
30,902 |
|
Net operating loss carryforwards |
|
|
64,620 |
|
|
|
40,752 |
|
Share-based compensation |
|
|
1,055 |
|
|
|
2,199 |
|
Foreign tax credits |
|
|
6,106 |
|
|
|
992 |
|
A-C Product Liability Trust |
|
|
|
|
|
|
803 |
|
Other net future deductible items |
|
|
2,014 |
|
|
|
3,083 |
|
Valuation allowance |
|
|
(58,343 |
) |
|
|
(13,999 |
) |
|
|
|
|
|
|
|
Gross deferred income tax assets |
|
|
42,925 |
|
|
|
64,732 |
|
|
|
|
|
|
|
|
|
|
Deferred income tax liabilities |
|
|
|
|
|
|
|
|
Depreciation |
|
|
(48,115 |
) |
|
|
(46,050 |
) |
Other net future taxable items |
|
|
(1,000 |
) |
|
|
(1,011 |
) |
|
|
|
|
|
|
|
Gross deferred income tax liabilities |
|
|
(49,115 |
) |
|
|
(47,061 |
) |
|
|
|
|
|
|
|
Net deferred income tax assets (liabilities) |
|
$ |
(6,190 |
) |
|
$ |
17,671 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net current deferred income tax assets |
|
$ |
81 |
|
|
$ |
3,790 |
|
Net noncurrent deferred income tax assets |
|
|
1,969 |
|
|
|
22,047 |
|
Net noncurrent deferred income tax liabilities |
|
|
(8,240 |
) |
|
|
(8,166 |
) |
|
|
|
|
|
|
|
Net deferred income tax assets |
|
$ |
(6,190 |
) |
|
$ |
17,671 |
|
|
|
|
|
|
|
|
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.
- 52 -
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, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Statutory income tax rate |
|
|
34.0 |
% |
|
|
34.0 |
% |
|
|
34.0 |
% |
State taxes, net of federal benefit |
|
|
(0.3 |
) |
|
|
1.7 |
|
|
|
0.4 |
|
Foreign currency remeasurement |
|
|
1.1 |
|
|
|
0.3 |
|
|
|
2.1 |
|
Valuation allowance, permanent differences and other |
|
|
(98.6 |
) |
|
|
(4.2 |
) |
|
|
(5.9 |
) |
|
|
|
|
|
|
|
|
|
|
Effective tax rate |
|
|
(63.8 |
)% |
|
|
31.8 |
% |
|
|
30.6 |
% |
|
|
|
|
|
|
|
|
|
|
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, 2010 and 2009 were $115.7 million and $67.8 million, respectively,
expiring through 2030.
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, 2010 and 2009, the valuation allowance was $58.3 million and $14.0
million, respectively. The valuation allowance primarily relates to net operating losses and tax
credits in various jurisdictions and is deemed necessary as the assessed character and nature of
future taxable income may not allow us to realize the tax benefits of the net operating losses and
tax credits within the allowable carryforward period.
Approximately $6.3 million and $4.4 million of ad valorem, franchise, income, sales and other
tax accruals are included in our accrued expense balances of $30.7 million and $21.9 million as of
December 31, 2010 and 2009, respectively.
NOTE 8 DEBT
Our long-term debt consists of the following as of December 31 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
Senior notes |
|
$ |
430,238 |
|
|
$ |
430,238 |
|
Revolving line of credit |
|
|
36,500 |
|
|
|
|
|
Bank term loans |
|
|
25,723 |
|
|
|
60,744 |
|
Insurance premium financing notes |
|
|
979 |
|
|
|
997 |
|
Capital lease obligations |
|
|
|
|
|
|
254 |
|
|
|
|
|
|
|
|
Total debt |
|
|
493,440 |
|
|
|
492,233 |
|
Less: current maturities of long-term debt |
|
|
15,215 |
|
|
|
17,027 |
|
|
|
|
|
|
|
|
Long-term debt |
|
$ |
478,225 |
|
|
$ |
475,206 |
|
|
|
|
|
|
|
|
Our weighted average interest rate for current and total debt was approximately 4.2% and 8.5%
as of December 31, 2010 and 5.0% and 8.4% as of December 31, 2009, respectively.
Maturities of debt obligations as of December 31, 2010 are as follows (in thousands):
|
|
|
|
|
|
|
Total |
|
Year Ending: |
|
|
|
|
December 31, 2011 |
|
$ |
15,215 |
|
December 31, 2012 |
|
|
6,891 |
|
December 31, 2013 |
|
|
4,016 |
|
December 31, 2014 |
|
|
261,518 |
|
December 31, 2015 |
|
|
|
|
Thereafter |
|
|
205,800 |
|
|
|
|
|
Total |
|
$ |
493,440 |
|
|
|
|
|
- 53 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
Senior notes, term loans and line of credit agreements
On January 18, 2006 and August 14, 2006, we closed on private offerings, to qualified
institutional buyers pursuant to Rule 144A under the Securities Act of 1933, of $160.0 and $95.0
million aggregate principal amount of our senior notes, respectively. The senior notes are due
January 15, 2014 and bear interest at 9.0%. The proceeds were used to fund the acquisitions of
Specialty Rental Tools, Inc. and DLS, to repay existing debt and for general corporate purposes.
On June 29, 2009, we closed on a tender offer in which we purchased $30.6 million aggregate
principal of our 9.0% senior notes for a total consideration of $650 per $1,000 principal amount.
In January 2007, we closed on a private offering, to qualified institutional buyers pursuant
to Rule 144A under the Securities Act of 1933, of $250.0 million principal amount of 8.5% senior
notes due 2017. The proceeds of the senior notes offering, together with a portion of the proceeds
of our concurrent common stock offering, were used to repay the debt outstanding under our $300.0
million bridge loan facility which we incurred to finance our acquisition of substantially all the
assets of Oil & Gas Rental Services, Inc. On June 29, 2009, we closed on a tender offer in which
we purchased $44.2 million aggregate principal of our 8.5% senior notes for a total consideration
of $600 per $1,000 principal amount.
We had a $90.0 million revolving line of credit with a final maturity date of April 26, 2012
pursuant to a revolving credit agreement that contains customary events of default and financial
covenants and limits our ability to incur additional indebtedness, make capital expenditures, pay
dividends or make other distributions, create liens and sell assets. On April 9, 2009, we amended
our revolving credit agreement to modify the leverage and interest coverage ratio covenants.
Effective December 31, 2009, we again amended the leverage and interest coverage ratio covenants of
the revolving credit agreement. This amendment relaxed the required financial ratios for the
quarter ended December 31, 2009 and for each of the quarters in 2010. Our obligations under the
amended and restated credit agreement are secured by substantially all of our assets located in the
United States. We were in compliance with all debt covenants as of December 31, 2010 and December
31, 2009. As of December 31, 2010, we had $36.5 million of borrowings outstanding and $4.1 million
in outstanding letters of credit under our revolving credit facility. As of December 31, 2009, the
only usage of our revolving credit facility consisted of $4.2 million in outstanding letters of
credit. The interest rate under our revolving credit facility is based on prime or LIBOR plus a
margin. The weighted-average interest rate was 7.8% at December 31, 2010.
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 were 2.0% and 2.1% as of December 31, 2010 and 2009, respectively. The
outstanding amount due under these bank loans as of December 31, 2010 and 2009 was $350,000 and
$1.1 million, respectively.
On February 15, 2008, through our DLS subsidiary in Argentina, we entered into a $25.0 million
import finance facility with a bank. Borrowings under this facility were used to fund a portion of
the purchase price of the new drilling and service rigs ordered for our Drilling and Completion
segment. The loan is repayable over four years in equal semi-annual installments beginning one
year after each disbursement with the final principal payment due not later than March 15, 2013.
The import finance facility is unsecured and contains customary events of default and financial
covenants and limits DLS ability to incur additional indebtedness, make capital expenditures,
create liens and sell assets. We were in compliance with all debt covenants as of December 31,
2010 and 2009. The bank loan rates are based on LIBOR plus a margin. The weighted average
interest rate was 4.2% and 4.4% at December 31, 2010 and 2009, respectively. The outstanding
amount under the import finance facility as of December 31, 2010 and 2009 was $14.4 million and
$20.1 million, respectively.
As part of our acquisition of BCH, we assumed a $23.6 million term loan credit facility with a
bank. The credit agreement is dated June 2007 and contains customary events of default and
financial covenants which were based on BCHs stand-alone financial statements. Obligations under
the facility are secured by substantially all of the BCH assets. BCH was in compliance with all
debt covenants as of December 31, 2009. The bank has waived certain financial ratio covenants for
the September 30, 2010 and December 31, 2010 measurement periods. As we cannot be certain that BCH
would attain compliance with the covenants within one year, we have classified the entire
outstanding balance of the loan in the current portion of long-term debt as of December 31, 2010.
The facility is repayable in quarterly principal installments plus interest with the final payment
due not later than August 2012. The interest rates are based on LIBOR plus a margin. At December
31, 2010 and 2009, the outstanding amount of the loan was $7.0 million and $16.2 million and the
interest rate was 3.5%.
On May 22, 2009, we drew down $25.0 million on a new term loan credit facility with a lending
institution. The facility was utilized to fund a portion of the purchase price of two new drilling
rigs. The loan was secured by the equipment and was repaid in November 2010 when the equipment was
returned to the manufacturer. The facility was repayable in quarterly installments of approximately
$1.4 million of principal and interest and was to mature in May 2015. The loan bore interest at a
fixed rate of 9.0%. At December 31, 2009, the outstanding amount of the loan was $23.4 million.
- 54 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
On February 9, 2010, through our DLS subsidiary, we entered into a $4.0 million term loan
facility. The loan is repayable in semi-annual installments beginning April 14, 2011 and bears
interest at 8.5% per annum. The final maturity date is April 14, 2014 and the loan is unsecured.
Notes payable
In 2010, we obtained insurance premium financings in the aggregate amount of $2.9 million with
a fixed weighted-average interest rate of 4.8%. Under terms of the agreements, amounts outstanding
are paid over eight and 11 month repayment schedules. The outstanding balance of these notes was
approximately $1.0 million at December 31, 2010. In 2009, we obtained insurance premium financings
in the aggregate amount of $3.2 million with a fixed weighted-average interest rate of 4.8%. Under
terms of these agreements, amounts outstanding are paid over 10 and 11 month repayment schedules.
The outstanding balance of these notes was approximately $0 and $997,000 at December 31, 2010 and
2009, respectively.
Other debt
As part of our acquisition of BCH, we assumed various capital leases with terms of two to
three years. The outstanding balance under these capital leases was $0 and $254,000 at December
31, 2010 and 2009, respectively.
NOTE 9 COMMITMENTS AND CONTINGENCIES
We have placed orders for capital equipment totaling $21.0 million to be received and paid for
through 2011. Approximately $4.5 million is for drilling equipment for our Drilling and Completion
segment, $10.2 million is for drill pipe for our Rental Services segment and $6.3 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, 2010, 2009 and 2008 was $3.7
million, $3.3 million and $2.8 million, respectively.
At December 31, 2010, future minimum rental commitments for all operating leases are as
follows (in thousands):
|
|
|
|
|
Years Ending: |
|
|
|
|
December 31, 2011 |
|
$ |
3,376 |
|
December 31, 2012 |
|
|
2,278 |
|
December 31, 2013 |
|
|
1,817 |
|
December 31, 2014 |
|
|
1,188 |
|
December 31, 2015 |
|
|
838 |
|
Thereafter |
|
|
1,721 |
|
|
|
|
|
Total |
|
$ |
11,218 |
|
|
|
|
|
NOTE 10 STOCKHOLDERS EQUITY
During 2008, we had restricted stock award grants, and options exercised, which resulted in
558,707 shares of our common stock being issued for approximately $633,000. We recognized
approximately $7.9 million of compensation expense related to share based payments that was
recorded as capital in excess of par value (see Note 1). We also recorded approximately $9,000 of
tax benefit related to our stock compensation plans.
In June 2009, we closed our backstopped rights offering and private placement of convertible
preferred stock and received proceeds of approximately $120.2 million net of $5.4 million offering
expenses. Pursuant to an Investment Agreement, Lime Rock Partners V, L.P., or Lime Rock, agreed to
backstop the rights offering by purchasing, at the subscription price, shares of common stock not
purchased by our existing stockholders. We sold 15,794,644 shares of our common stock to existing
stockholders who exercised their rights through the rights offering and 19,889,044 shares of common
stock to Lime Rock, at a price of $2.50 per share. We issued 36,393 shares of 7.0% convertible
perpetual preferred stock to Lime Rock and received proceeds of approximately $34.2 million net of
$2.2 million offering expenses.
- 55 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
The preferred stock has an initial liquidation preference of $1,000 per share and is adjusted
to $3,000 per share upon certain liquidation events. Dividends on the preferred stock are declared
quarterly if approved by our Board of Directors and dividends accumulate if not paid. The
preferred stock is, with respect to dividend rights and rights upon liquidation, winding-up, or
dissolution: (1) senior to common stock and any other class or series of capital stock, the terms
of which do not expressly provide that such class or series ranks senior to or on parity with the
preferred stock; (2) on a parity with any other class or series of capital stock, the terms of
which provide that it will rank on a parity with the preferred stock; (3) junior to each class or
series of capital stock (other than common stock) established after the original issue date, the
terms of which expressly provide that it will rank senior to the preferred stock; and (4) junior to
all our existing and future debt obligations and other liabilities, including claims of trade
creditors.
During the year ended December 31, 2009, we declared $1.3 million in dividends on our
preferred stock. Accrued dividends of approximately $637,000 were included in our accrued expense
balance of $21.9 million as of December 31, 2009. The accrued dividends were paid in February
2010.
Each share of the preferred stock is convertible at the holders option, at any time into
390.2439 shares of our common stock under certain conditions, subject to specified adjustments.
This conversion rate represents an equivalent conversion price of approximately $2.56 per share.
Conversion is limited to the earlier of June 26, 2012 or the date on which the transfer
restrictions included in the Investment Agreement expire, unless immediately after giving effect to
such conversion, such person or group would not beneficially own a number of shares of our common
stock exceeding 35% of the total number of issued and outstanding shares of common stock, unless we
have given prior written consent to such conversion. In addition, we will be able to cause the
preferred stock to be converted into common stock five years after issuance if our common stock is
trading at a premium of 300% to the conversion price for 30 consecutive trading days prior to our
issuance of a press release announcing the mandatory conversion. Generally, holders of the
preferred stock vote together with the common stock on an as-converted basis, however, the
preferred stock voting rights held by any person or group when aggregated with common stock is
limited to 35% of all the votes to be cast by all stockholders, including holders of common stock.
During 2009, we had restricted stock award grants, and options exercised, which resulted in
20,099 shares of our common stock being issued for approximately $43,000. We recognized
approximately $4.8 million of compensation expense related to share based payments that was
recorded as capital in excess of par value (see Note 1). Due to expired unexercised nonqualified
stock options and restricted stock vesting at market prices lower than the grant price, we adjusted
$2.3 million of excess tax asset against additional paid in capital.
We issued 1.0 million shares of our common stock in connection with the acquisition of AWC in
July 2010 (see Note 4).
During 2010, we had restricted stock award grants, vested performance-based restricted stock
and options exercised, which resulted in 1,343,818 shares of our common stock being issued and due
to net exercise provisions of the grants, we paid $1.7 million for payroll taxes on those net
exercises. We recognized approximately $8.0 million of compensation expense related to share-based
payments that was recorded as capital in excess of par value (see Note 1). Due to restricted stock
vesting at market prices lower than the grant price, we adjusted $1.2 million of excess tax asset
against additional paid in capital.
During the year ended December 31, 2010, we declared $2.5 million in dividends on our
preferred stock. Accrued dividends of approximately $637,000 were included in our accrued expense
balance of $30.7 million as of December 31, 2010. The accrued dividends were paid in January 2011.
NOTE 11 STOCK OPTIONS
In 2000, we issued stock options and promissory notes to certain directors as compensation for
services as directors. 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 could have been exercised
any time prior to March 28, 2010. As of December 31, 2010, none of the stock options remain
outstanding. No compensation expense has been recorded for these options as they were issued with
an exercise price equal to the fair value of the common stock at the date of grant.
The 2003 Incentive Stock Plan, or 2003 Plan, as amended, permits us to grant to our key
employees and outside directors various forms of stock incentives, including, among others,
incentive and non-qualified stock options and restricted stock. The 2003 Plan is administered by
the Compensation Committee of the Board, which consists of two or more directors appointed by the
Board. The following benefits may be granted under the 2003 Plan: (a) stock appreciation rights;
(b) restricted stock; (c) performance awards; (d) incentive stock options; (e) nonqualified stock
options; and (f) other stock-based awards. Stock incentive terms are not to be in excess of ten
years. The maximum number of shares of our common stock that may be issued under the 2003 Plan
shall be the lesser of 3,000,000 shares or 15% of the total number of shares of common stock
outstanding.
- 56 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
The 2006 Incentive Plan, or 2006 Plan, was approved and amended by our stockholders in
November 2006 and 2009. The 2006 Plan is administered by the Compensation Committee of the Board.
The maximum number of shares of our common stock that may be issued under the 2006 Plan is equal to
8,500,000 shares, subject to adjustment in the event of stock splits and certain other corporate
events. The 2006 Plan provides for the grant of any or all of the following types of awards: (i)
stock options, including incentive stock options and non-qualified stock options; (ii) bonus stock;
(iii) restricted stock awards; (iv) performance awards; and (v) other stock-based awards. Except
with respect to awards of incentive stock options, all of our employees, consultants and
non-employee directors are eligible to participate in the 2006 Plan. The term of each Award shall
be for such period as may be determined by the Committee; provided, that in no event shall the term
of any Award exceed a period of ten years from the date of its grant.
A summary of our stock option activity and related information is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010 |
|
|
December 31, 2009 |
|
|
December 31, 2008 |
|
|
|
Shares |
|
|
Weighted Ave. |
|
|
Shares |
|
|
Weighted Ave. |
|
|
Shares |
|
|
Weighted Avg. |
|
|
|
Under |
|
|
Exercise |
|
|
Under |
|
|
Exercise |
|
|
Under |
|
|
Exercise |
|
|
|
Option |
|
|
Price |
|
|
Option |
|
|
Price |
|
|
Option |
|
|
Price |
|
Beginning balance |
|
|
701,732 |
|
|
$ |
6.31 |
|
|
|
901,732 |
|
|
$ |
10.95 |
|
|
|
986,763 |
|
|
$ |
10.77 |
|
Granted |
|
|
1,072,253 |
|
|
|
3.78 |
|
|
|
125,000 |
|
|
|
1.23 |
|
|
|
|
|
|
|
|
|
Canceled |
|
|
(21,967 |
) |
|
|
8.30 |
|
|
|
(305,000 |
) |
|
|
18.18 |
|
|
|
(13,328 |
) |
|
|
8.87 |
|
Exercised |
|
|
(1,000 |
) |
|
|
1.23 |
|
|
|
(20,000 |
) |
|
|
2.75 |
|
|
|
(71,703 |
) |
|
|
8.83 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance |
|
|
1,751,018 |
|
|
$ |
4.74 |
|
|
|
701,732 |
|
|
$ |
6.31 |
|
|
|
901,732 |
|
|
$ |
10.95 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 $5,000, $36,000 and $542,000 during the years ended December 31, 2010, 2009 and 2008,
respectively. As of December 31, 2010, there was approximately $2.2 million of total unrecognized
compensation cost related to stock options, with $535,000, $511,000, $506,000, $506,000 and
$129,000 to be recognized during the years ended December 31, 2011 through 2015, respectively.
The following table summarizes additional information about our stock options outstanding as
of December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding |
|
Options Exercisable |
|
|
|
|
|
|
Weighted Average |
|
Weighted |
|
|
|
|
|
Weighted Average |
|
Weighted |
Range of |
|
|
|
|
|
Remaining |
|
Average |
|
|
|
|
|
Remaining |
|
Average |
Exercise |
|
Number of |
|
Contractual Life |
|
Exercise |
|
Number of |
|
Contractual Life |
|
Exercise |
Prices |
|
options |
|
(in Years) |
|
Price |
|
options |
|
(in Years) |
|
Price |
$1.232.75
|
|
|
126,000 |
|
|
|
8.10 |
|
|
$ |
1.25 |
|
|
|
26,000 |
|
|
|
7.78 |
|
|
$ |
1.35 |
|
3.774.87
|
|
|
1,359,086 |
|
|
|
8.08 |
|
|
|
3.87 |
|
|
|
293,500 |
|
|
|
4.07 |
|
|
|
4.18 |
|
10.8514.74
|
|
|
265,932 |
|
|
|
4.96 |
|
|
|
10.86 |
|
|
|
265,932 |
|
|
|
4.96 |
|
|
|
10.86 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$1.2314.74
|
|
|
1,751,018 |
|
|
|
7.61 |
|
|
$ |
4.74 |
|
|
|
585,432 |
|
|
|
4.64 |
|
|
$ |
7.09 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The aggregate pretax intrinsic value of stock options outstanding and exercisable was
approximately $5.1 million and $1.0 million, respectively, at December 31, 2010. The amount
represents the value that would have been received by the option holders had the respective options
been exercised on December 31, 2010.
- 57 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
Restricted Stock Awards
In addition to stock options, our 2003 and 2006 Plans allow for the grant of restricted stock
awards, or RSA. A time-lapse RSA is an award of common stock, where each unit represents the right
to receive at the end of a stipulated period one unrestricted share of stock with no exercise
price. The time-lapse RSA restrictions lapse periodically over an extended period of time not
exceeding 10 years. We determine the fair value of RSAs based on the market price of our common
stock on the date of grant. Compensation cost for RSAs is primarily recognized on a straight-line
basis over the vesting or service period and is net of forfeitures. A performance-based RSA is an
award of common stock, where each unit represents the right to receive one unrestricted share of
stock with no exercise price at the attainment of established performance criteria. In connection
with performance-based RSAs, compensation cost is based on estimated number of shares expected to
be issued. During 2010, we granted 1,237,750 performance-based RSAs to executive officers and key
employees that vest upon meeting certain financial performance conditions over the next five years.
Effective December 29, 2010, we accelerated the vesting of 244,383 shares of time-based restricted
stock and 544,000 shares of performance-based restricted stock previously granted to employees. The
fair value of the performance-based RSAs were based on third-party valuations.
The following table summarizes activity in our nonvested restricted stock awards:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010 |
|
|
December 31, 2009 |
|
|
December 31, 2008 |
|
|
|
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 |
|
|
837,626 |
|
|
$ |
15.63 |
|
|
|
953,102 |
|
|
$ |
15.34 |
|
|
|
993,203 |
|
|
$ |
17.45 |
|
Granted |
|
|
2,061,750 |
|
|
|
3.78 |
|
|
|
17,000 |
|
|
|
1.23 |
|
|
|
258,670 |
|
|
|
9.47 |
|
Vested |
|
|
(1,193,976 |
) |
|
|
8.80 |
|
|
|
(122,276 |
) |
|
|
11.68 |
|
|
|
(298,771 |
) |
|
|
17.26 |
|
Forfeited |
|
|
(3,333 |
) |
|
|
3.77 |
|
|
|
(10,200 |
) |
|
|
12.05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance |
|
|
1,702,067 |
|
|
$ |
6.09 |
|
|
|
837,626 |
|
|
$ |
15.63 |
|
|
|
953,102 |
|
|
$ |
15.34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The total fair value of RSA shares that vested during 2010 and 2009 was approximately $6.8
million and $371,000, respectively. As of December 31, 2010, there was approximately $4.3 million
of total unrecognized compensation cost related to nonvested RSAs, with $1.7 million, $1.0 million,
$769,000, $739,000 and $71,000 to be recognized during the years ended December 31, 2011 through
2015, respectively.
NOTE 12 STOCK PURCHASE WARRANTS
In conjunction with BCH debt financing in January of 2007, BCH issued a common stock warrant
for 250,000 shares to a financial institution. The warrant entitles the holder to acquire up to
250,000 shares of common stock of BCH at an exercise price of $10.00 per share over a five-year
period.
NOTE 13 GAIN ON DEBT EXTINGUISHMENT
We recorded a gain of $26.4 million as a result of a tender offer that we completed on June
29, 2009. We purchased $30.6 million aggregate principal of our 9.0% senior notes and $44.2
million aggregate principal of our 8.5% senior notes for approximately $46.4 million. We also
wrote-off $1.5 million of debt issuance costs related to the retired notes and we incurred
approximately $466,000 in expenses related to the transactions.
NOTE 14 CONDENSED CONSOLIDATED FINANCIAL INFORMATION
Set forth on the following pages are the condensed consolidating financial statements of (i)
Allis-Chalmers Energy Inc., (ii) its subsidiaries that are guarantors of the senior notes and
revolving credit facility and (iii) the subsidiaries that are not guarantors of the senior notes
and revolving credit facility (in thousands):
- 58 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2010
(Restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiary |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors |
|
|
Adjustments |
|
|
Total |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
|
|
|
$ |
16,380 |
|
|
$ |
4,560 |
|
|
$ |
|
|
|
$ |
20,940 |
|
Trade receivables, net |
|
|
|
|
|
|
79,100 |
|
|
|
77,397 |
|
|
|
(11,537 |
) |
|
|
144,960 |
|
Inventories |
|
|
|
|
|
|
22,066 |
|
|
|
20,074 |
|
|
|
|
|
|
|
42,140 |
|
Intercompany receivables |
|
|
|
|
|
|
84,766 |
|
|
|
|
|
|
|
(84,766 |
) |
|
|
|
|
Note receivable from affiliate |
|
|
18,359 |
|
|
|
|
|
|
|
|
|
|
|
(18,359 |
) |
|
|
|
|
Prepaid expenses and other |
|
|
2,068 |
|
|
|
3,280 |
|
|
|
3,925 |
|
|
|
|
|
|
|
9,273 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
20,427 |
|
|
|
205,592 |
|
|
|
105,956 |
|
|
|
(114,662 |
) |
|
|
217,313 |
|
Property and equipment, net |
|
|
|
|
|
|
461,187 |
|
|
|
262,047 |
|
|
|
|
|
|
|
723,234 |
|
Goodwill |
|
|
|
|
|
|
28,944 |
|
|
|
17,389 |
|
|
|
|
|
|
|
46,333 |
|
Other intangible assets, net |
|
|
414 |
|
|
|
27,278 |
|
|
|
6,207 |
|
|
|
|
|
|
|
33,899 |
|
Debt issuance costs, net |
|
|
7,405 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,405 |
|
Note receivable from affiliates |
|
|
1,800 |
|
|
|
|
|
|
|
|
|
|
|
(1,800 |
) |
|
|
|
|
Investments in affiliates |
|
|
934,274 |
|
|
|
|
|
|
|
|
|
|
|
(934,274 |
) |
|
|
|
|
Other assets |
|
|
|
|
|
|
7,390 |
|
|
|
2,695 |
|
|
|
|
|
|
|
10,085 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
964,320 |
|
|
$ |
730,391 |
|
|
$ |
394,294 |
|
|
$ |
(1,050,736 |
) |
|
$ |
1,038,269 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders
Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term
debt |
|
$ |
|
|
|
$ |
979 |
|
|
$ |
14,236 |
|
|
$ |
|
|
|
$ |
15,215 |
|
Trade accounts payable |
|
|
|
|
|
|
18,634 |
|
|
|
38,945 |
|
|
|
(11,537 |
) |
|
|
46,042 |
|
Accrued salaries, benefits and
payroll taxes |
|
|
|
|
|
|
8,983 |
|
|
|
23,807 |
|
|
|
|
|
|
|
32,790 |
|
Accrued interest |
|
|
15,310 |
|
|
|
|
|
|
|
214 |
|
|
|
|
|
|
|
15,524 |
|
Accrued expenses |
|
|
1,192 |
|
|
|
18,504 |
|
|
|
10,980 |
|
|
|
|
|
|
|
30,676 |
|
Intercompany payables |
|
|
69,756 |
|
|
|
|
|
|
|
15,010 |
|
|
|
(84,766 |
) |
|
|
|
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
18,359 |
|
|
|
(18,359 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current
liabilities |
|
|
86,258 |
|
|
|
47,100 |
|
|
|
121,551 |
|
|
|
(114,662 |
) |
|
|
140,247 |
|
Long-term debt, net of current
maturities |
|
|
466,738 |
|
|
|
|
|
|
|
11,487 |
|
|
|
|
|
|
|
478,225 |
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
1,800 |
|
|
|
(1,800 |
) |
|
|
|
|
Other long-term liabilities |
|
|
|
|
|
|
|
|
|
|
8,473 |
|
|
|
|
|
|
|
8,473 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
|
552,996 |
|
|
|
47,100 |
|
|
|
143,311 |
|
|
|
(116,462 |
) |
|
|
626,945 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Stock |
|
|
34,183 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34,183 |
|
Common stock |
|
|
737 |
|
|
|
3,527 |
|
|
|
42,963 |
|
|
|
(46,490 |
) |
|
|
737 |
|
Capital in excess of par value |
|
|
429,924 |
|
|
|
589,676 |
|
|
|
137,439 |
|
|
|
(727,115 |
) |
|
|
429,924 |
|
Retained earnings (deficit) |
|
|
(53,520 |
) |
|
|
90,088 |
|
|
|
70,581 |
|
|
|
(160,669 |
) |
|
|
(53,520 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders
equity |
|
|
411,324 |
|
|
|
683,291 |
|
|
|
250,983 |
|
|
|
(934,274 |
) |
|
|
411,324 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
and stock holders
equity |
|
$ |
964,320 |
|
|
$ |
730,391 |
|
|
$ |
394,294 |
|
|
$ |
(1,050,736 |
) |
|
$ |
1,038,269 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 59 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Year Ended December 31, 2010
(Restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiary |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors |
|
|
Adjustments |
|
|
Total |
|
Revenues |
|
$ |
|
|
|
$ |
280,919 |
|
|
$ |
380,308 |
|
|
$ |
(1,562 |
) |
|
$ |
659,665 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs |
|
|
|
|
|
|
177,205 |
|
|
|
322,477 |
|
|
|
(1,562 |
) |
|
|
498,120 |
|
Depreciation |
|
|
|
|
|
|
58,066 |
|
|
|
26,052 |
|
|
|
|
|
|
|
84,118 |
|
Selling, general and
administrative |
|
|
7,168 |
|
|
|
38,005 |
|
|
|
15,261 |
|
|
|
|
|
|
|
60,434 |
|
Loss on asset dispositions |
|
|
|
|
|
|
10,624 |
|
|
|
|
|
|
|
|
|
|
|
10,624 |
|
Amortization |
|
|
46 |
|
|
|
4,014 |
|
|
|
746 |
|
|
|
|
|
|
|
4,806 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and
expenses |
|
|
7,214 |
|
|
|
287,914 |
|
|
|
364,536 |
|
|
|
(1,562 |
) |
|
|
658,102 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from
operations |
|
|
(7,214 |
) |
|
|
(6,995 |
) |
|
|
15,772 |
|
|
|
|
|
|
|
1,563 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in
affiliates, net of tax |
|
|
(27,269 |
) |
|
|
|
|
|
|
|
|
|
|
27,269 |
|
|
|
|
|
Interest, net |
|
|
(42,476 |
) |
|
|
(506 |
) |
|
|
(2,306 |
) |
|
|
|
|
|
|
(45,288 |
) |
Other |
|
|
60 |
|
|
|
(2,322 |
) |
|
|
(949 |
) |
|
|
|
|
|
|
(3,211 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income
(expense) |
|
|
(69,685 |
) |
|
|
(2,828 |
) |
|
|
(3,255 |
) |
|
|
27,269 |
|
|
|
(48,499 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income
taxes |
|
|
(76,899 |
) |
|
|
(9,823 |
) |
|
|
12,517 |
|
|
|
27,269 |
|
|
|
(46,936 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense |
|
|
|
|
|
|
(20,291 |
) |
|
|
(9,672 |
) |
|
|
|
|
|
|
(29,963 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
(76,899 |
) |
|
|
(30,114 |
) |
|
|
2,845 |
|
|
|
27,269 |
|
|
|
(76,899 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividend |
|
|
(2,548 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,548 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributed
to common stockholders |
|
$ |
(79,447 |
) |
|
$ |
(30,114 |
) |
|
$ |
2,845 |
|
|
$ |
27,269 |
|
|
$ |
(79,447 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 60 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Year Ended December 31, 2010
(Restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis- |
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
Chalmers |
|
|
|
|
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
(Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors) |
|
|
Adjustments |
|
|
Total |
|
Cash Flows from Operating Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(76,899 |
) |
|
$ |
(30,114 |
) |
|
$ |
2,845 |
|
|
$ |
27,269 |
|
|
$ |
(76,899 |
) |
Adjustments to reconcile net
income (loss) to net cash provided
by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation & amortization |
|
|
46 |
|
|
|
62,080 |
|
|
|
26,798 |
|
|
|
|
|
|
|
88,924 |
|
Amortization and write-off of
deferred financing fees |
|
|
2,192 |
|
|
|
22 |
|
|
|
|
|
|
|
|
|
|
|
2,214 |
|
Stock based compensation |
|
|
8,030 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,030 |
|
Allowance for bad debts |
|
|
|
|
|
|
368 |
|
|
|
|
|
|
|
|
|
|
|
368 |
|
Equity earnings in affiliates |
|
|
27,269 |
|
|
|
|
|
|
|
|
|
|
|
(27,269 |
) |
|
|
|
|
Deferred income taxes |
|
|
20,920 |
|
|
|
(1,003 |
) |
|
|
393 |
|
|
|
|
|
|
|
20,310 |
|
Loss on sale of equipment |
|
|
|
|
|
|
646 |
|
|
|
34 |
|
|
|
|
|
|
|
680 |
|
Loss on asset dispositions |
|
|
|
|
|
|
10,624 |
|
|
|
|
|
|
|
|
|
|
|
10,624 |
|
Loss on investment |
|
|
|
|
|
|
1,466 |
|
|
|
|
|
|
|
|
|
|
|
1,466 |
|
Equity in losses of
unconsolidated affiliates |
|
|
|
|
|
|
783 |
|
|
|
|
|
|
|
|
|
|
|
783 |
|
Changes in operating assets and
liabilities, net of
acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Increase) in trade receivables |
|
|
|
|
|
|
(17,248 |
) |
|
|
(18,435 |
) |
|
|
|
|
|
|
(35,683 |
) |
(Increase) in inventories |
|
|
|
|
|
|
(4,137 |
) |
|
|
(1,817 |
) |
|
|
|
|
|
|
(5,954 |
) |
Decrease (increase) in other
current assets |
|
|
(1,917 |
) |
|
|
7,533 |
|
|
|
5,526 |
|
|
|
|
|
|
|
11,142 |
|
Decrease in other assets |
|
|
|
|
|
|
426 |
|
|
|
1,320 |
|
|
|
|
|
|
|
1,746 |
|
(Decrease) increase in
accounts payable |
|
|
|
|
|
|
(3,979 |
) |
|
|
15,040 |
|
|
|
|
|
|
|
11,061 |
|
(Decrease) in accrued interest |
|
|
(62 |
) |
|
|
(228 |
) |
|
|
(7 |
) |
|
|
|
|
|
|
(297 |
) |
Increase in accrued expenses |
|
|
440 |
|
|
|
5,577 |
|
|
|
1,421 |
|
|
|
|
|
|
|
7,438 |
|
(Decrease) in other liabilities |
|
|
|
|
|
|
|
|
|
|
(909 |
) |
|
|
|
|
|
|
(909 |
) |
Increase in accrued salaries,
benefits and payroll taxes |
|
|
|
|
|
|
6,157 |
|
|
|
3,715 |
|
|
|
|
|
|
|
9,872 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used)
by operating activities |
|
|
(19,981 |
) |
|
|
38,973 |
|
|
|
35,924 |
|
|
|
|
|
|
|
54,916 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition, net of cash acquired |
|
|
|
|
|
|
(15,935 |
) |
|
|
|
|
|
|
|
|
|
|
(15,935 |
) |
Proceeds from sale of investments |
|
|
|
|
|
|
368 |
|
|
|
|
|
|
|
|
|
|
|
368 |
|
Purchase of property and equipment |
|
|
|
|
|
|
(75,488 |
) |
|
|
(26,667 |
) |
|
|
|
|
|
|
(102,155 |
) |
Deposits on asset commitments |
|
|
|
|
|
|
18,604 |
|
|
|
(257 |
) |
|
|
|
|
|
|
18,347 |
|
Investment in affiliates |
|
|
(17,165 |
) |
|
|
|
|
|
|
|
|
|
|
17,165 |
|
|
|
|
|
Notes receivable from affiliates |
|
|
13,820 |
|
|
|
|
|
|
|
|
|
|
|
(13,820 |
) |
|
|
|
|
Proceeds from asset dispositions |
|
|
|
|
|
|
25,000 |
|
|
|
|
|
|
|
|
|
|
|
25,000 |
|
Proceeds from sale of equipment |
|
|
|
|
|
|
6,181 |
|
|
|
457 |
|
|
|
|
|
|
|
6,638 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used)
in investing activities |
|
|
(3,345 |
) |
|
|
(41,270 |
) |
|
|
(26,467 |
) |
|
|
3,345 |
|
|
|
(67,737 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 61 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis- |
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
Chalmers |
|
|
|
|
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
(Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors) |
|
|
Adjustments |
|
|
Total |
|
Cash Flows from Financing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of
long-term debt |
|
|
|
|
|
|
|
|
|
|
4,000 |
|
|
|
|
|
|
|
4,000 |
|
Payments on long-term debt |
|
|
|
|
|
|
(26,281 |
) |
|
|
(15,887 |
) |
|
|
|
|
|
|
(42,168 |
) |
Borrowings under line of credit |
|
|
36,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36,500 |
|
Payment of preferred stock dividend |
|
|
(2,548 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,548 |
) |
Proceeds from parent contributions |
|
|
|
|
|
|
17,165 |
|
|
|
|
|
|
|
(17,165 |
) |
|
|
|
|
Accounts receivable from affiliates |
|
|
|
|
|
|
(4,065 |
) |
|
|
|
|
|
|
4,065 |
|
|
|
|
|
Accounts payable to affiliates |
|
|
(7,531 |
) |
|
|
|
|
|
|
11,596 |
|
|
|
(4,065 |
) |
|
|
|
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
(13,820 |
) |
|
|
13,820 |
|
|
|
|
|
Proceeds from exercise of options |
|
|
(1,722 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,722 |
) |
Income tax impact of stock-based
compensation plans |
|
|
(1,184 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,184 |
) |
Debt issuance costs |
|
|
(189 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(189 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used)
by financing activities |
|
|
23,326 |
|
|
|
(13,181 |
) |
|
|
(14,111 |
) |
|
|
(3,345 |
) |
|
|
(7,311 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash
and cash equivalents |
|
|
|
|
|
|
(15,478 |
) |
|
|
(4,654 |
) |
|
|
|
|
|
|
(20,132 |
) |
Cash and cash equivalents at
beginning of year |
|
|
|
|
|
|
31,858 |
|
|
|
9,214 |
|
|
|
|
|
|
|
41,072 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end
of year |
|
$ |
|
|
|
$ |
16,380 |
|
|
$ |
4,560 |
|
|
$ |
|
|
|
$ |
20,940 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 62 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiary |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors |
|
|
Adjustments |
|
|
Total |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
|
|
|
$ |
31,858 |
|
|
$ |
9,214 |
|
|
$ |
|
|
|
$ |
41,072 |
|
Trade receivables, net |
|
|
|
|
|
|
47,358 |
|
|
|
58,962 |
|
|
|
(1,261 |
) |
|
|
105,059 |
|
Inventories |
|
|
|
|
|
|
16,271 |
|
|
|
18,257 |
|
|
|
|
|
|
|
34,528 |
|
Intercompany receivables |
|
|
|
|
|
|
79,521 |
|
|
|
767 |
|
|
|
(80,288 |
) |
|
|
|
|
Note receivable from affiliate |
|
|
28,379 |
|
|
|
|
|
|
|
|
|
|
|
(28,379 |
) |
|
|
|
|
Prepaid expenses and other |
|
|
891 |
|
|
|
6,826 |
|
|
|
9,872 |
|
|
|
|
|
|
|
17,589 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
29,270 |
|
|
|
181,834 |
|
|
|
97,072 |
|
|
|
(109,928 |
) |
|
|
198,248 |
|
Property and equipment, net |
|
|
|
|
|
|
489,921 |
|
|
|
256,557 |
|
|
|
|
|
|
|
746,478 |
|
Goodwill |
|
|
|
|
|
|
23,251 |
|
|
|
17,388 |
|
|
|
|
|
|
|
40,639 |
|
Other intangible assets, net |
|
|
460 |
|
|
|
25,236 |
|
|
|
6,953 |
|
|
|
|
|
|
|
32,649 |
|
Debt issuance costs, net |
|
|
9,408 |
|
|
|
137 |
|
|
|
|
|
|
|
|
|
|
|
9,545 |
|
Note receivable from affiliates |
|
|
4,415 |
|
|
|
|
|
|
|
|
|
|
|
(4,415 |
) |
|
|
|
|
Investments in affiliates |
|
|
942,378 |
|
|
|
|
|
|
|
|
|
|
|
(942,378 |
) |
|
|
|
|
Other assets |
|
|
24,366 |
|
|
|
25,039 |
|
|
|
3,656 |
|
|
|
|
|
|
|
53,061 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,010,297 |
|
|
$ |
745,418 |
|
|
$ |
381,626 |
|
|
$ |
(1,056,721 |
) |
|
$ |
1,080,620 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders
Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term
debt |
|
$ |
|
|
|
$ |
4,444 |
|
|
$ |
12,583 |
|
|
$ |
|
|
|
$ |
17,027 |
|
Trade accounts payable |
|
|
|
|
|
|
12,195 |
|
|
|
23,905 |
|
|
|
(1,261 |
) |
|
|
34,839 |
|
Accrued salaries, benefits and
payroll taxes |
|
|
|
|
|
|
2,762 |
|
|
|
20,092 |
|
|
|
|
|
|
|
22,854 |
|
Accrued interest |
|
|
15,372 |
|
|
|
228 |
|
|
|
221 |
|
|
|
|
|
|
|
15,821 |
|
Accrued expenses |
|
|
752 |
|
|
|
11,608 |
|
|
|
9,558 |
|
|
|
|
|
|
|
21,918 |
|
Intercompany payables |
|
|
80,288 |
|
|
|
|
|
|
|
|
|
|
|
(80,288 |
) |
|
|
|
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
28,379 |
|
|
|
(28,379 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current
liabilities |
|
|
96,412 |
|
|
|
31,237 |
|
|
|
94,738 |
|
|
|
(109,928 |
) |
|
|
112,459 |
|
Long-term debt, net of current
maturities |
|
|
430,238 |
|
|
|
19,941 |
|
|
|
25,027 |
|
|
|
|
|
|
|
475,206 |
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
4,415 |
|
|
|
(4,415 |
) |
|
|
|
|
Other long-term liabilities |
|
|
|
|
|
|
|
|
|
|
9,308 |
|
|
|
|
|
|
|
9,308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
|
526,650 |
|
|
|
51,178 |
|
|
|
133,488 |
|
|
|
(114,343 |
) |
|
|
596,973 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Stock |
|
|
34,183 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34,183 |
|
Common stock |
|
|
714 |
|
|
|
3,526 |
|
|
|
42,963 |
|
|
|
(46,489 |
) |
|
|
714 |
|
Capital in excess of par value |
|
|
422,823 |
|
|
|
570,512 |
|
|
|
137,439 |
|
|
|
(707,951 |
) |
|
|
422,823 |
|
Retained earnings |
|
|
25,927 |
|
|
|
120,202 |
|
|
|
67,736 |
|
|
|
(187,938 |
) |
|
|
25,927 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders
equity |
|
|
483,647 |
|
|
|
694,240 |
|
|
|
248,138 |
|
|
|
(942,378 |
) |
|
|
483,647 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
and stock holders
equity |
|
$ |
1,010,297 |
|
|
$ |
745,418 |
|
|
$ |
381,626 |
|
|
$ |
(1,056,721 |
) |
|
$ |
1,080,620 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 63 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiary |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors |
|
|
Adjustments |
|
|
Total |
|
Revenues |
|
$ |
|
|
|
$ |
202,727 |
|
|
$ |
303,579 |
|
|
$ |
(53 |
) |
|
$ |
506,253 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs |
|
|
|
|
|
|
133,629 |
|
|
|
245,861 |
|
|
|
(53 |
) |
|
|
379,437 |
|
Depreciation |
|
|
|
|
|
|
56,886 |
|
|
|
21,390 |
|
|
|
|
|
|
|
78,276 |
|
Selling, general and
administrative |
|
|
4,054 |
|
|
|
32,592 |
|
|
|
14,117 |
|
|
|
|
|
|
|
50,763 |
|
Loss on asset dispositions |
|
|
|
|
|
|
|
|
|
|
1,602 |
|
|
|
|
|
|
|
1,602 |
|
Amortization |
|
|
46 |
|
|
|
3,907 |
|
|
|
769 |
|
|
|
|
|
|
|
4,722 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and
expenses |
|
|
4,100 |
|
|
|
227,014 |
|
|
|
283,739 |
|
|
|
(53 |
) |
|
|
514,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from
operations |
|
|
(4,100 |
) |
|
|
(24,287 |
) |
|
|
19,840 |
|
|
|
|
|
|
|
(8,547 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in
affiliates, net of tax |
|
|
1,051 |
|
|
|
|
|
|
|
|
|
|
|
(1,051 |
) |
|
|
|
|
Interest, net |
|
|
(44,568 |
) |
|
|
(25 |
) |
|
|
(3,480 |
) |
|
|
|
|
|
|
(48,073 |
) |
Gain on debt
extinguishment |
|
|
26,365 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,365 |
|
Other |
|
|
62 |
|
|
|
(155 |
) |
|
|
(705 |
) |
|
|
|
|
|
|
(798 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income
(expense) |
|
|
(17,090 |
) |
|
|
(180 |
) |
|
|
(4,185 |
) |
|
|
(1,051 |
) |
|
|
(22,506 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income
taxes |
|
|
(21,190 |
) |
|
|
(24,467 |
) |
|
|
15,655 |
|
|
|
(1,051 |
) |
|
|
(31,053 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit
(expense) |
|
|
|
|
|
|
15,590 |
|
|
|
(5,727 |
) |
|
|
|
|
|
|
9,863 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
(21,190 |
) |
|
|
(8,877 |
) |
|
|
9,928 |
|
|
|
(1,051 |
) |
|
|
(21,190 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividend |
|
|
(1,302 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,302 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributed
to common stockholders |
|
$ |
(22,492 |
) |
|
$ |
(8,877 |
) |
|
$ |
9,928 |
|
|
$ |
(1,051 |
) |
|
$ |
(22,492 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 64 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis- |
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
Chalmers |
|
|
|
|
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
(Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors) |
|
|
Adjustments |
|
|
Total |
|
Cash Flows from Operating Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(21,190 |
) |
|
$ |
(8,877 |
) |
|
$ |
9,928 |
|
|
$ |
(1,051 |
) |
|
$ |
(21,190 |
) |
Adjustments to reconcile net income
(loss) to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation & amortization |
|
|
46 |
|
|
|
60,793 |
|
|
|
22,159 |
|
|
|
|
|
|
|
82,998 |
|
Amortization and write-off of
deferred financing fees |
|
|
2,215 |
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
2,231 |
|
Gain on debt extinguishment |
|
|
(26,365 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(26,365 |
) |
Stock based compensation |
|
|
4,799 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,799 |
|
Allowance for bad debts |
|
|
|
|
|
|
2,835 |
|
|
|
|
|
|
|
|
|
|
|
2,835 |
|
Equity earnings in affiliates |
|
|
(1,051 |
) |
|
|
|
|
|
|
|
|
|
|
1,051 |
|
|
|
|
|
Deferred income taxes |
|
|
(18,173 |
) |
|
|
1,569 |
|
|
|
(1,279 |
) |
|
|
|
|
|
|
(17,883 |
) |
(Gain) loss on sale of equipment |
|
|
|
|
|
|
(957 |
) |
|
|
9 |
|
|
|
|
|
|
|
(948 |
) |
Loss on asset dispositions |
|
|
|
|
|
|
|
|
|
|
1,602 |
|
|
|
|
|
|
|
1,602 |
|
Changes in operating assets and
liabilities, net of acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in accounts receivables |
|
|
|
|
|
|
38,074 |
|
|
|
11,903 |
|
|
|
|
|
|
|
49,977 |
|
Decrease in inventories |
|
|
|
|
|
|
3,111 |
|
|
|
1,448 |
|
|
|
|
|
|
|
4,559 |
|
Decrease (increase) in other
current assets |
|
|
7,369 |
|
|
|
3,279 |
|
|
|
(6,020 |
) |
|
|
|
|
|
|
4,628 |
|
Decrease (increase) in other assets |
|
|
(111 |
) |
|
|
223 |
|
|
|
1,536 |
|
|
|
|
|
|
|
1,648 |
|
(Decrease) in accounts payable |
|
|
|
|
|
|
(13,346 |
) |
|
|
(14,242 |
) |
|
|
|
|
|
|
(27,588 |
) |
(Decrease) increase in accrued
interest |
|
|
(2,560 |
) |
|
|
228 |
|
|
|
(470 |
) |
|
|
|
|
|
|
(2,802 |
) |
(Decrease) in accrued expenses |
|
|
(632 |
) |
|
|
(2,233 |
) |
|
|
(1,742 |
) |
|
|
|
|
|
|
(4,607 |
) |
(Decrease) in other liabilities |
|
|
|
|
|
|
(64 |
) |
|
|
(987 |
) |
|
|
|
|
|
|
(1,051 |
) |
(Decrease) increase in accrued
salaries, benefits and payroll
taxes |
|
|
|
|
|
|
(1,171 |
) |
|
|
3,833 |
|
|
|
|
|
|
|
2,662 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by
operating activities |
|
|
(55,653 |
) |
|
|
83,480 |
|
|
|
27,678 |
|
|
|
|
|
|
|
55,505 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales (purchases) of investment
interests |
|
|
(2,393 |
) |
|
|
|
|
|
|
1,291 |
|
|
|
|
|
|
|
(1,102 |
) |
Purchase of property and equipment |
|
|
|
|
|
|
(58,142 |
) |
|
|
(19,925 |
) |
|
|
|
|
|
|
(78,067 |
) |
Deposits on asset commitments |
|
|
|
|
|
|
1,995 |
|
|
|
690 |
|
|
|
|
|
|
|
2,685 |
|
Investment in affiliates |
|
|
(4,100 |
) |
|
|
|
|
|
|
|
|
|
|
4,100 |
|
|
|
|
|
Notes receivable from affiliates |
|
|
(2,069 |
) |
|
|
|
|
|
|
|
|
|
|
2,069 |
|
|
|
|
|
Proceeds from asset dispositions |
|
|
|
|
|
|
|
|
|
|
3,916 |
|
|
|
|
|
|
|
3,916 |
|
Proceeds from sale of equipment |
|
|
|
|
|
|
8,400 |
|
|
|
181 |
|
|
|
|
|
|
|
8,581 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) in
investing activities |
|
|
(8,562 |
) |
|
|
(47,747 |
) |
|
|
(13,847 |
) |
|
|
6,169 |
|
|
|
(63,987 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 65 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis- |
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
Chalmers |
|
|
|
|
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
(Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors) |
|
|
Adjustments |
|
|
Total |
|
Cash Flows from Financing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of
long-term debt |
|
|
|
|
|
|
25,000 |
|
|
|
|
|
|
|
|
|
|
|
25,000 |
|
Payments on long-term debt |
|
|
(47,167 |
) |
|
|
(4,811 |
) |
|
|
(12,777 |
) |
|
|
|
|
|
|
(64,755 |
) |
Net repayments on lines of credit |
|
|
(36,500 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(36,500 |
) |
Proceeds from issuance of stock,
net of offering costs |
|
|
120,223 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
120,223 |
|
Payment of preferred stock dividend |
|
|
(665 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(665 |
) |
Proceeds from parent contributions |
|
|
|
|
|
|
|
|
|
|
4,100 |
|
|
|
(4,100 |
) |
|
|
|
|
Accounts receivable from affiliates |
|
|
|
|
|
|
(26,834 |
) |
|
|
(1,952 |
) |
|
|
28,786 |
|
|
|
|
|
Accounts payable to affiliates |
|
|
28,786 |
|
|
|
|
|
|
|
|
|
|
|
(28,786 |
) |
|
|
|
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
2,069 |
|
|
|
(2,069 |
) |
|
|
|
|
Proceeds from exercise of options |
|
|
43 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
43 |
|
Debt issuance costs |
|
|
(505 |
) |
|
|
(153 |
) |
|
|
|
|
|
|
|
|
|
|
(658 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used)
by financing activities |
|
|
64,215 |
|
|
|
(6,798 |
) |
|
|
(8,560 |
) |
|
|
(6,169 |
) |
|
|
42,688 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash
equivalents |
|
|
|
|
|
|
28,935 |
|
|
|
5,271 |
|
|
|
|
|
|
|
34,206 |
|
Cash and cash equivalents at
beginning of year |
|
|
|
|
|
|
2,923 |
|
|
|
3,943 |
|
|
|
|
|
|
|
6,866 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end
of year |
|
$ |
|
|
|
$ |
31,858 |
|
|
$ |
9,214 |
|
|
$ |
|
|
|
$ |
41,072 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 66 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiary |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors |
|
|
Adjustments |
|
|
Total |
|
Revenues |
|
$ |
|
|
|
$ |
384,649 |
|
|
$ |
291,335 |
|
|
$ |
(36 |
) |
|
$ |
675,948 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs |
|
|
|
|
|
|
217,360 |
|
|
|
226,090 |
|
|
|
(36 |
) |
|
|
443,414 |
|
Depreciation |
|
|
|
|
|
|
49,177 |
|
|
|
14,283 |
|
|
|
|
|
|
|
63,460 |
|
Selling, general and
administrative |
|
|
6,924 |
|
|
|
45,147 |
|
|
|
10,703 |
|
|
|
|
|
|
|
62,774 |
|
Gain on asset dispositions |
|
|
|
|
|
|
(166 |
) |
|
|
|
|
|
|
|
|
|
|
(166 |
) |
Impairment of goodwill |
|
|
|
|
|
|
115,774 |
|
|
|
|
|
|
|
|
|
|
|
115,774 |
|
Amortization |
|
|
46 |
|
|
|
4,133 |
|
|
|
33 |
|
|
|
|
|
|
|
4,212 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and
expenses |
|
|
6,970 |
|
|
|
431,425 |
|
|
|
251,109 |
|
|
|
(36 |
) |
|
|
689,468 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from
operations |
|
|
(6,970 |
) |
|
|
(46,776 |
) |
|
|
40,226 |
|
|
|
|
|
|
|
(13,520 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in
affiliates, net of tax |
|
|
9,161 |
|
|
|
|
|
|
|
|
|
|
|
(9,161 |
) |
|
|
|
|
Interest, net |
|
|
(41,727 |
) |
|
|
57 |
|
|
|
(1,124 |
) |
|
|
|
|
|
|
(42,794 |
) |
Other |
|
|
72 |
|
|
|
88 |
|
|
|
(723 |
) |
|
|
|
|
|
|
(563 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income
(expense) |
|
|
(32,494 |
) |
|
|
145 |
|
|
|
(1,847 |
) |
|
|
(9,161 |
) |
|
|
(43,357 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income
taxes |
|
|
(39,464 |
) |
|
|
(46,631 |
) |
|
|
38,379 |
|
|
|
(9,161 |
) |
|
|
(56,877 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit
(expense) |
|
|
|
|
|
|
29,580 |
|
|
|
(12,167 |
) |
|
|
|
|
|
|
17,413 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(39,464 |
) |
|
$ |
(17,051 |
) |
|
$ |
26,212 |
|
|
$ |
(9,161 |
) |
|
$ |
(39,464 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 67 -
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 and amortization |
|
|
46 |
|
|
|
53,310 |
|
|
|
14,316 |
|
|
|
|
|
|
|
67,672 |
|
Amortization and write-off of debt
issuance costs |
|
|
2,089 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,089 |
|
Impairment of goodwill |
|
|
|
|
|
|
115,774 |
|
|
|
|
|
|
|
|
|
|
|
115,774 |
|
Stock based compensation |
|
|
7,902 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,902 |
|
Allowance for bad debts |
|
|
|
|
|
|
3,283 |
|
|
|
|
|
|
|
|
|
|
|
3,283 |
|
Equity earnings in affiliates |
|
|
(9,161 |
) |
|
|
|
|
|
|
|
|
|
|
9,161 |
|
|
|
|
|
Deferred income taxes |
|
|
(13,620 |
) |
|
|
(16,959 |
) |
|
|
630 |
|
|
|
|
|
|
|
(29,949 |
) |
(Gain) on sale of equipment |
|
|
|
|
|
|
(1,485 |
) |
|
|
(277 |
) |
|
|
|
|
|
|
(1,762 |
) |
(Gain) on asset dispositions |
|
|
|
|
|
|
(166 |
) |
|
|
|
|
|
|
|
|
|
|
(166 |
) |
Changes in operating assets and
liabilities, net of acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Increase) in trade receivables |
|
|
|
|
|
|
(7,168 |
) |
|
|
(20,331 |
) |
|
|
|
|
|
|
(27,499 |
) |
(Increase) in inventories |
|
|
|
|
|
|
(7,037 |
) |
|
|
(2,682 |
) |
|
|
|
|
|
|
(9,719 |
) |
(Increase) decrease in other
current assets |
|
|
211 |
|
|
|
219 |
|
|
|
(2,053 |
) |
|
|
|
|
|
|
(1,623 |
) |
(Increase) decrease in other assets |
|
|
(138 |
) |
|
|
(83 |
) |
|
|
1,445 |
|
|
|
|
|
|
|
1,224 |
|
Increase in accounts payable |
|
|
|
|
|
|
9,427 |
|
|
|
12,476 |
|
|
|
|
|
|
|
21,903 |
|
(Decrease) increase in accrued
interest |
|
|
223 |
|
|
|
(33 |
) |
|
|
377 |
|
|
|
|
|
|
|
567 |
|
(Decrease) increase in accrued
expenses |
|
|
(1,379 |
) |
|
|
3,823 |
|
|
|
(1,313 |
) |
|
|
|
|
|
|
1,131 |
|
(Decrease) in other liabilities |
|
|
(31 |
) |
|
|
(178 |
) |
|
|
(921 |
) |
|
|
|
|
|
|
(1,130 |
) |
Increase in accrued salaries,
benefits and payroll taxes |
|
|
|
|
|
|
221 |
|
|
|
3,231 |
|
|
|
|
|
|
|
3,452 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by
operating activities |
|
|
(53,322 |
) |
|
|
135,897 |
|
|
|
31,110 |
|
|
|
|
|
|
|
113,685 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions, net of cash acquired |
|
|
|
|
|
|
|
|
|
|
(53,709 |
) |
|
|
|
|
|
|
(53,709 |
) |
Net sales 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 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 68 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis- |
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
Chalmers |
|
|
|
|
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
(Non- |
|
|
Consolidated |
|
|
Consolidating |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors) |
|
|
Adjustments |
|
|
Total |
|
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 increase (decrease) 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 year |
|
$ |
|
|
|
$ |
2,923 |
|
|
$ |
3,943 |
|
|
$ |
|
|
|
$ |
6,866 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 69 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
NOTE 15 RELATED PARTY TRANSACTIONS
Our largest customer is Pan American Energy, or PAE. PAE is now wholly owned by Bridas
Corporation, and Bridas Corporation is owned 50% by Bridas Energy Holdings Ltd and 50% by CNOOC
International Limited. Alejandro P. Bulgheroni, one of the directors of our parent company, may be
deemed to indirectly beneficially own 50% of the outstanding capital stock of Bridas Energy
Holdings Ltd and is a member of the Management Committee of PAE. In 2010, 2009 and 2008, PAE
represented 31.1%, 35.5%, and 28.5% of our consolidated revenues, respectively. At December 31,
2010 and 2009, we had trade receivables with PAE of $22.0 million and $11.0 million, respectively.
In 2010, 2009 and 2008, we derived revenue of approximately $5.2 million, $3.3 million and
$1.0 million from BEUSA Energy, Inc., or BEUSA, a company controlled by Alejandro P. Bulgheroni.
At December 31, 2010 and 2009, we had trade receivables from BEUSA of approximately $1.0 million
and $1.2 million, respectively.
Lime Rock Partners III, L.P., an affiliated fund of Lime Rock Partners V, L.P., owns a
majority stake in the parent company of GES Global Energy Services, Inc., or Global Energy, a
Houston based global supplier of drilling rigs and rig components. In 2008, we ordered two
drilling rigs from Global Energy for an aggregate value of approximately $34.7 million. We took
delivery of these rigs during 2010. Saad Bargach and John Reynolds are each a Managing Director of
Lime Rock Management LP, the manager for Lime Rock Partners III, L.P. and Lime Rock Partners V,
L.P. Messrs. Bargach and Reynolds are also directors of our parent company. As of December 31,
2010, Lime Rock Partners V, L.P. held 19,889,044 shares of our common stock, representing
approximately 27.0% of our issued and outstanding shares. In addition, at December 31, 2010, Lime
Rock Partners V, L.P. owned 36,393 shares of preferred stock which are convertible into 14,202,146
shares of our common stock. At December 31, 2010, through its ownership of common and preferred
stock, Lime Rock Partners V, L.P. controlled, in the aggregate, 35% of our stockholders voting
power.
NOTE 16 SEGMENT INFORMATION
All of our segments provide services to the energy industry. The revenues, operating income
(loss), depreciation and amortization, capital expenditures and assets of each of the reporting
segments plus the corporate function are reported below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
210,617 |
|
|
$ |
143,564 |
|
|
$ |
280,835 |
|
Drilling & Completion |
|
|
378,154 |
|
|
|
303,975 |
|
|
|
291,335 |
|
Rental Services |
|
|
70,894 |
|
|
|
58,714 |
|
|
|
103,778 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
659,665 |
|
|
$ |
506,253 |
|
|
$ |
675,948 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss): |
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
15,393 |
|
|
$ |
(14,691 |
) |
|
$ |
38,643 |
|
Drilling & Completion |
|
|
4,369 |
|
|
|
19,222 |
|
|
|
40,226 |
|
Rental Services |
|
|
4,115 |
|
|
|
140 |
|
|
|
(74,361 |
) |
General corporate |
|
|
(22,314 |
) |
|
|
(13,218 |
) |
|
|
(18,028 |
) |
|
|
|
|
|
|
|
|
|
|
Total income (loss) from operations |
|
$ |
1,563 |
|
|
$ |
(8,547 |
) |
|
$ |
(13,520 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and Amortization Expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
32,294 |
|
|
$ |
30,589 |
|
|
$ |
24,725 |
|
Drilling & Completion |
|
|
26,422 |
|
|
|
22,321 |
|
|
|
14,316 |
|
Rental Services |
|
|
29,927 |
|
|
|
29,791 |
|
|
|
28,131 |
|
General corporate |
|
|
281 |
|
|
|
297 |
|
|
|
500 |
|
|
|
|
|
|
|
|
|
|
|
Total depreciation and amortization expense |
|
$ |
88,924 |
|
|
$ |
82,998 |
|
|
$ |
67,672 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures: |
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
26,586 |
|
|
$ |
11,357 |
|
|
$ |
58,400 |
|
Drilling & Completion |
|
|
60,214 |
|
|
|
58,393 |
|
|
|
73,362 |
|
Rental Services |
|
|
14,626 |
|
|
|
8,230 |
|
|
|
22,550 |
|
General corporate |
|
|
729 |
|
|
|
87 |
|
|
|
156 |
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures |
|
$ |
102,155 |
|
|
$ |
78,067 |
|
|
$ |
154,468 |
|
|
|
|
|
|
|
|
|
|
|
- 70 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(Restated) |
|
|
|
|
|
|
|
|
|
Goodwill: |
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
23,250 |
|
|
$ |
23,250 |
|
|
$ |
23,250 |
|
Drilling & Completion |
|
|
17,389 |
|
|
|
17,389 |
|
|
|
20,023 |
|
Rental Services |
|
|
5,694 |
|
|
|
|
|
|
|
|
|
General corporate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total goodwill |
|
$ |
46,333 |
|
|
$ |
40,639 |
|
|
$ |
43,273 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
267,091 |
|
|
$ |
255,899 |
|
|
$ |
309,901 |
|
Drilling & Completion |
|
|
426,633 |
|
|
|
441,482 |
|
|
|
411,486 |
|
Rental Services |
|
|
309,315 |
|
|
|
307,283 |
|
|
|
360,376 |
|
General corporate |
|
|
35,230 |
|
|
|
75,956 |
|
|
|
33,288 |
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,038,269 |
|
|
$ |
1,080,620 |
|
|
$ |
1,115,051 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
268,883 |
|
|
$ |
188,436 |
|
|
$ |
365,529 |
|
Argentina |
|
|
307,194 |
|
|
|
243,913 |
|
|
|
288,792 |
|
Brazil |
|
|
40,716 |
|
|
|
43,564 |
|
|
|
|
|
Other international |
|
|
42,872 |
|
|
|
30,340 |
|
|
|
21,627 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
659,665 |
|
|
$ |
506,253 |
|
|
$ |
675,948 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(Restated) |
|
|
|
|
|
|
|
|
|
Long Lived Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
501,117 |
|
|
$ |
572,727 |
|
|
$ |
573,975 |
|
Argentina |
|
|
167,137 |
|
|
|
168,681 |
|
|
|
212,456 |
|
Brazil |
|
|
86,949 |
|
|
|
82,477 |
|
|
|
79,568 |
|
Other international |
|
|
65,753 |
|
|
|
58,487 |
|
|
|
23,814 |
|
|
|
|
|
|
|
|
|
|
|
Total long lived assets |
|
$ |
820,956 |
|
|
$ |
882,372 |
|
|
$ |
889,813 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield |
|
|
Drilling & |
|
|
Rental |
|
|
|
|
|
|
Services |
|
|
Completion |
|
|
Services |
|
|
Total |
|
Goodwill: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2007 |
|
$ |
30,493 |
|
|
$ |
1,523 |
|
|
$ |
106,382 |
|
|
$ |
138,398 |
|
Goodwill acquired during period |
|
|
3,000 |
|
|
|
18,500 |
|
|
|
|
|
|
|
21,500 |
|
Asset dispositions |
|
|
(851 |
) |
|
|
|
|
|
|
|
|
|
|
(851 |
) |
Impairment charges |
|
|
(9,392 |
) |
|
|
|
|
|
|
(106,382 |
) |
|
|
(115,774 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2008 |
|
|
23,250 |
|
|
|
20,023 |
|
|
|
|
|
|
|
43,273 |
|
Purchase price and other adjustments |
|
|
|
|
|
|
(2,634 |
) |
|
|
|
|
|
|
(2,634 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2009 |
|
|
23,250 |
|
|
|
17,389 |
|
|
|
|
|
|
|
40,639 |
|
Goodwill acquired during period |
|
|
|
|
|
|
|
|
|
|
5,694 |
|
|
|
5,694 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2010 |
|
$ |
23,250 |
|
|
$ |
17,389 |
|
|
$ |
5,694 |
|
|
$ |
46,333 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 71 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
NOTE 17 SUPPLEMENTAL CASH FLOWS INFORMATION (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Interest paid |
|
$ |
43,940 |
|
|
$ |
49,605 |
|
|
$ |
46,541 |
|
|
|
|
|
|
|
|
|
|
|
Income taxes paid |
|
$ |
3,575 |
|
|
$ |
6,242 |
|
|
$ |
20,670 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other non-cash investing and financing transactions: |
|
|
|
|
|
|
|
|
|
|
|
|
Insurance premiums financed |
|
$ |
2,875 |
|
|
$ |
3,204 |
|
|
$ |
2,995 |
|
Assets transferred as investment in joint venture |
|
|
|
|
|
|
1,639 |
|
|
|
|
|
Receivable related to sale of investment |
|
|
274 |
|
|
|
|
|
|
|
|
|
Preferred stock dividend |
|
|
2,548 |
|
|
|
637 |
|
|
|
|
|
Tax benefit on stock plans |
|
|
|
|
|
|
2,335 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash investing and financing transactions in connection with acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of Property and equipment |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Fair value of goodwill and other intangibles |
|
|
2,000 |
|
|
|
(1,343 |
) |
|
|
3,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2,000 |
|
|
$ |
(1,343 |
) |
|
$ |
3,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued expense |
|
$ |
|
|
|
$ |
(1,343 |
) |
|
$ |
3,000 |
|
Stockholders equity |
|
|
2,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2,000 |
|
|
$ |
(1,343 |
) |
|
$ |
3,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
NOTE 18 LEGAL MATTERS
Shortly following the announcement of the merger agreement, ten putative stockholder
class-action petitions and compliants were filed against various combinations of us, members of our
board of directors, Seawell, and Wellco. Seven of the lawsuits were filed in the District Court of
Harris County, Texas, which we refer to as the Texas Actions, and three lawsuits were filed in the
Court of Chancery of the State of Delaware, which we refer to as the Delaware Actions. These
lawsuits challenge the proposed merger and generally allege, among other things, that our directors
have breached their fiduciary duties owed to our public stockholders by approving the proposed
merger and failing to take steps to maximize our value to our public stockholders, that we,
Seawell, and Wellco aided and abetted such breaches of fiduciary duties, and that the merger
agreement unreasonably dissuades potential suitors from making competing offers and restricts us
from considering competing offers. The lawsuits generally seek, among other things, compensatory
damages, attorneys and experts fees, declaratory and injunctive relief concerning the alleged
breaches of fiduciary duties, and injunctive relief prohibiting the defendants from consummating
the merger.
Various plaintiffs in the Texas Actions filed competing motions to consolidate the suits, to
appoint their counsel as interim class counsel and to compel expedited discovery. On September 16,
2010, the defendants filed joint motions to stay the Texas Actions in favor of a first-filed
Delaware lawsuit, and opposing the motions for expedited discovery. There is no hearing date set
for these motions. The parties to the Texas State Court actions have agreed that the various
defendants need not respond to the petitions until after lead counsel is appointed, a consolidated
amended petition is filed and served or, alternatively, an active petition is designated by lead
counsel.
- 72 -
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements-(Continued)
On September 21, 2010, the plaintiffs in the Delaware Actions wrote the court seeking
consolidation of the Delaware cases. Defendants did not oppose consolidation and took no position
regarding lead plaintiff. On September 29, 2010, the Delaware court granted the motion to
consolidate. Previously, on September 16, 2010, Seawell and Wellco answered the first-filed Girard
Complaint, which is the operative complaint post-consolidation. We answered the consolidated
complaint on October 4, 2010. On January 26, 2011, the plaintiffs in the Delaware Actions filed an
amended complaint that included, among other claims, allegations that the disclosures made by
Defendants concerning the merger are incomplete and misleading. Also on January 26, 2011, the
plaintiffs in the Delaware Actions filed a motion to expedite proceedings for discovery and
briefing and to set a date and time to hear their application for a preliminary injunction to
enjoin the merger. Following a hearing, on February 3, 2011, the Delaware court denied plaintiffs
motion.
We believe all of these lawsuits are without merit and intend to defend them vigorously.
We are named from time to time in legal proceedings related to our activities prior to our
bankruptcy in 1988. However, we believe that we were discharged from liability for all such claims
in the bankruptcy and believe the likelihood of a material loss relating to any such legal
proceeding is remote. We are also involved in various other legal proceedings in the ordinary
course of business. The legal proceedings are at different stages; however, we believe that the
likelihood of material loss relating to any such legal proceeding is remote.
NOTE 19 SUBSEQUENT EVENT
On August 12, 2010, we entered into a merger agreement with Seawell Limited, or Seawell, and
Wellco Sub Company, a wholly owned subsidiary of Seawell. On February 23, 2011, the merger
transactions closed and we merged with and into Wellco Sub Company, becoming a wholly owned
subsidiary of Seawell under the name Allis-Chalmers Energy Inc. Following the merger, Seawell
and its subsidiaries, including us, have begun operating under the name Archer; however, our legal
name will remain Allis-Chalmers Energy Inc. until further notice.
In connection with the merger we repaid and cancelled our $90.0 million revolving credit
facility as well as the BCH term loan. Vesting of all outstanding options and restricted stock
were accelerated upon the closing of the merger.
NOTE 20 SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED) (in thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Restated) |
|
Year 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
140,370 |
|
|
$ |
158,644 |
|
|
$ |
174,288 |
|
|
$ |
186,363 |
|
Operating income (loss) |
|
|
(752 |
) |
|
|
4,134 |
|
|
|
11,545 |
|
|
|
(13,364 |
) |
Net loss attributed to common stockholders |
|
$ |
(10,168 |
) |
|
$ |
(6,016 |
) |
|
$ |
(3,203 |
) |
|
$ |
(60,060 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(0.14 |
) |
|
$ |
(0.08 |
) |
|
$ |
(0.04 |
) |
|
$ |
(0.83 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
(0.14 |
) |
|
$ |
(0.08 |
) |
|
$ |
(0.04 |
) |
|
$ |
(0.83 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
Year 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
145,103 |
|
|
$ |
112,505 |
|
|
$ |
120,016 |
|
|
$ |
128,629 |
|
Operating income (loss) |
|
|
7,771 |
|
|
|
(12,543 |
) |
|
|
(3,070 |
) |
|
|
(705 |
) |
Net loss attributed to common stockholders |
|
$ |
(2,605 |
) |
|
$ |
(125 |
) |
|
$ |
(10,280 |
) |
|
$ |
(9,482 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(0.07 |
) |
|
$ |
0.00 |
|
|
$ |
(0.14 |
) |
|
$ |
(0.13 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
(0.07 |
) |
|
$ |
0.00 |
|
|
$ |
(0.14 |
) |
|
$ |
(0.13 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
- 73 -
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
(a) Evaluation Of Disclosure Controls And Procedures
Our management, with the participation of our Chief Executive Officer and Chief Financial
Officer, evaluated the effectiveness of our disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)), as of December 31, 2010. Management recognizes that
any disclosure controls and procedures no matter how well designed and operated, can only provide
reasonable assurance of achieving their objectives and management necessarily applies its judgment
in evaluating the cost-benefit relationship of possible controls and procedures.
At the time of our Original Filing, our Chief Executive Officer and Chief Financial Officer
concluded that our disclosure controls and procedures as of December 31, 2010 were effective at
reaching a reasonable level of assurance of achieving the desired objective. On July 25, 2011, our
management, including our Chief Executive Office and Chief Financial Officer, concluded that our
disclosure controls and procedures were not effective 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 as of December 31, 2010
because of a material weakness in our internal control over financial reporting described below.
Notwithstanding the material weakness described below, management, based upon the work performed
during the restatement process, has concluded that our consolidated financial statements for the
periods included in this Amendment are fairly stated in all material respects in accordance with
generally accepted accounting principles for each of the periods presented herein
(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 United States generally accepted accounting principles. Our control
environment is the foundation for our system of internal control over financial reporting and is an
integral part of our Code of Business Ethics and Conduct for the Chief Executive Officer, Chief
Financial Officer and Chief Accounting Officer, which sets the tone of our company. Our internal
control over financial reporting includes those policies and procedures that (i) pertain to the
maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions
and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of our financial statements in accordance with generally accepted
accounting principles, and that our receipts and expenditures are being made only in accordance
with authorizations of our management and directors; and (iii) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use or disposition of our
assets that could have a material effect on our financial statements.
In order to evaluate the effectiveness of our internal control over financial reporting as of
December 31, 2010, 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
ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (the COSO Framework). A material weakness is a deficiency, or a combination of
deficiencies, in internal control over financial reporting, such that there is a reasonable
possibility that a material misstatement of the companys annual or interim financial statements
will not be prevented or detected on a timely basis. 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.
In managements original Report on Internal Control Over Financial Reporting included in our
Original Filing, management, including our Chief Executive Officer and Chief Financial Officer,
concluded that we maintained effective internal control over financial reporting as of December 31,
2010. In connection with the restatement discussed below and in Note 2 to our consolidated
financial statements in this Amendment, management, including our Chief Executive Officer and Chief
Financial Officer, reassessed the effectiveness of our internal control over financial reporting as
of December 31, 2010. Based on this reassessment, management
- 74 -
has concluded that we did not maintain effective internal control over financial reporting as
of December 31, 2010, because of a material weakness relating to accounting for income taxes.
Specifically, we did not maintain effective controls over the identification and proper accounting
treatment of the calculation and valuation of deferred tax assets. This material weakness resulted
in a material misstatement of our income tax expense, deferred tax asset, net loss and accumulated
deficit with accompanying notes and the restatement of our consolidated financial statements for
the year ended December 31, 2010 as discussed below and in Note 2 to the consolidated financial
statements included in this Amendment. Additionally, this deficiency could result in misstatements
of the aforementioned accounts and disclosures that would result in a material misstatement of the
consolidated financial statements that would not be prevented or detected.
Restatement of the Consolidated Financial Statements
On July 25, 2011, our management concluded that the previously filed consolidated financial
statements for the fourth quarter and for the year ended December 31, 2010 were no longer reliable.
The restatement is necessitated by our determination that positive evidence available at year end
2010 was not sufficient to overcome the negative evidence around the deferred tax assets and to
justify not booking a valuation allowance against deferred federal income tax assets and foreign
tax credits. The correction of this error resulted in a $37.4 million increase in the deferred tax
valuation allowance and income tax expense.
Plan for Remediation of Material Weakness
Management has developed a plan to remediate the material weakness noted above. Controls over
the preparation of tax calculations and associated deferred tax balances have been enhanced through
the implementation of external advisory services from an independent source, under the oversight of
management. In the third quarter the Company has hired a dedicated employee with tax expertise to
oversee this area, along with enhanced procedural and review controls.
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, 2010, 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
Omitted pursuant to Instruction I of Form 10-K. (Omission of Information by Certain Wholly
Owned Subsidiaries).
ITEM 11. EXECUTIVE COMPENSATION
Omitted pursuant to Instruction I of Form 10-K. (Omission of Information by Certain Wholly
Owned Subsidiaries).
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS
Omitted pursuant to Instruction I of Form 10-K. (Omission of Information by Certain Wholly
Owned Subsidiaries).
- 75 -
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Omitted pursuant to Instruction I of Form 10-K. (Omission of Information by Certain Wholly
Owned Subsidiaries).
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The following table shows the aggregate fees for professional services rendered by UHY LLP
during the years ended December 31, 2010 and 2009.
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year |
|
Fee Category |
|
2010 |
|
|
2009 |
|
Audit Fees(1) |
|
$ |
813,661 |
|
|
$ |
863,096 |
|
Audit Related Fees(2) |
|
|
171,022 |
|
|
|
20,026 |
|
Tax Fees |
|
|
|
|
|
|
|
|
All Other Fees |
|
|
|
|
|
|
|
|
|
|
$ |
984,683 |
|
|
$ |
883,122 |
|
|
|
|
(1) |
|
Includes fees and out-of-pocket charges paid for audit of our annual financial statements
and reviews of the related quarterly financial statements. |
|
(2) |
|
Includes fees paid for assurance and related services that are reasonably related to the
performance of the audit or review of our financial statements and are not reported under Audit
Fees. These services include accounting and reporting consultations. |
UHY LLP leases all its personnel, who work under the control of UHY LLP partners, from
wholly-owned subsidiaries of UHY Advisors, Inc. in an alternative practice structure.
Pre-Approval Policies and Procedures
Prior to our merger with Seawell, we had a policy that the Audit Committee must approve in
advance all audit and non-audit services provided by our independent accountants. All of the audit
and audit-related services, and the fees therefor, provided by UHY LLP in 2010 and 2009 were
pre-approved by the Audit Committee. As a result of the merger with Seawell, our company no longer
has an Audit Committee.
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, 2010 and 2009. |
|
|
|
Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and 2008. |
|
|
|
Consolidated Statement of Stockholders Equity for the years ended December 31, 2010, 2009
and 2008. |
|
|
|
Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008. |
|
|
|
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. |
- 76 -
(2) |
|
Financial Statement Schedule: |
Schedule II Valuation and Qualifying Accounts
Allis-Chalmers Energy Inc.
Valuation and Qualifying Accounts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions |
|
|
Additions |
|
|
|
|
|
|
|
|
|
|
Balance at |
|
|
Charged to |
|
|
Charged to |
|
|
|
|
|
|
Balance at |
|
|
|
Beginning |
|
|
Costs and |
|
|
Other |
|
|
|
|
|
|
End of |
|
Description |
|
of Period |
|
|
Expense |
|
|
Account |
|
|
Deductions |
|
|
Period |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts |
|
$ |
4,923 |
|
|
$ |
368 |
|
|
$ |
|
|
|
$ |
(930 |
) |
|
$ |
4,361 |
|
Deferred tax assets valuation allowance |
|
|
13,999 |
|
|
|
44,344 |
|
|
|
|
|
|
|
|
|
|
|
58,343 |
|
Year Ended December 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts |
|
|
4,205 |
|
|
|
2,835 |
|
|
|
|
|
|
|
(2,117 |
) |
|
|
4,923 |
|
Deferred tax assets valuation allowance |
|
|
13,265 |
|
|
|
2,076 |
|
|
|
(1,342 |
) |
|
|
|
|
|
|
13,999 |
|
Year Ended December 31, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts |
|
|
1,924 |
|
|
|
3,283 |
|
|
|
|
|
|
|
(1,002 |
) |
|
|
4,205 |
|
Deferred tax assets valuation allowance |
|
|
|
|
|
|
|
|
|
|
13,265 |
|
|
|
|
|
|
|
13,265 |
|
The deferred tax asset valuation allowance established in the year ended December 31, 2008 was an
acquisition related allowance. At the time of the acquisition of BCH, we had no expectation to
utilize their net operating loss carryforwards or foreign tax credit carryfowards. Subsequent to
2008, we determined that we would utilize $1.3 million of the deferred tax assets related to the
acquisition of BCH.
- 77 -
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 August 31, 2011.
|
|
|
|
|
|
ALLIS-CHALMERS ENERGY INC.
|
|
|
|
/s/ JORGEN RASMUSSEN
|
|
|
|
Jorgen Rasmussen |
|
|
|
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/ JORGEN RASMUSSEN
Jorgen Rasmussen
|
|
Chairman and Chief Executive Officer
(Principal Executive Officer)
|
|
August 31, 2011 |
|
|
|
|
|
/s/ CHRISTOPH BAUSCH
Christoph Bausch
|
|
Chief Financial Officer
(Principal Financial Officer)
|
|
August 31, 2011 |
|
|
|
|
|
/s/ THORLEIF EGELI
Thorleif Egeli
|
|
Director
|
|
August 31, 2011 |
|
|
|
|
|
/s/ LARS BETHUELSEN
Lars Bethuelsen
|
|
Director
|
|
August 31, 2011 |
|
|
|
|
|
/s/ MAX BOUTHILLETTE
Max Bouthillette
|
|
Director
|
|
August 31, 2011 |
- 78 -
EXHIBIT INDEX
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Exhibit |
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Description |
2.1
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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). |
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2.2
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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). |
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2.3
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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). |
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2.4
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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). |
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2.5
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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). |
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2.6
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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). |
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2.7
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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). |
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2.8
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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). |
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2.9
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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). |
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2.10
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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). |
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2.11
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Stock Purchase Agreement dated April 1, 2005, by and among
the Registrant, 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). |
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2.12
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Stock Purchase Agreement effective May 1, 2005, by and among
the Registrant, 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). |
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2.13
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Purchase Agreement dated July 11, 2005 among the Registrant,
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). |
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2.14
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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). |
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Exhibit |
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Description |
2.15
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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). |
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2.16
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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). |
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2.17
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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) |
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2.18
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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). |
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2.19
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Asset Purchase Agreement, dated as of October 25, 2006, by
and between the Registrant 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). |
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2.20
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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). |
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2.21
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First Amendment, dated as of June 1, 2008, to the Agreement
and Plan of Merger, by and among the Registrant, 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). |
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2.22
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Stock Purchase Agreement, dated December 19, 2008, by and
between the Registrant and BrazAlta Resources Corp.
(incorporated by reference to Exhibit 2.22 to the
Registrants Annual Report on Form 10-K filed on March 9,
2009). |
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2.23
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Agreement and Plan of Merger, dated as of August 12, 2010, by
and among Seawell Limited, Wellco Sub Company and
Allis-Chalmers Energy Inc. (incorporated by reference to
Exhibit 2.1 to the Registrants Current Report on Form 8-K
filed August 13, 2010). |
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2.24
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Amendment Agreement, dated as of October 1, 2010, by and
among Seawell Limited, Wellco Sub Company and Allis-Chalmers
Energy Inc. (incorporated by reference to Exhibit 2.1 to the
Registrants Current Report on Form 8-K filed October 5,
2010). |
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3.1
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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). |
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3.2
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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). |
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3.3
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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). |
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3.4
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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). |
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3.5
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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). |
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3.6
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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). |
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Exhibit |
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Description |
3.7
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Certificate of Amendment to Amended and Restated Certificate
of Incorporation filed with the Delaware Secretary of State
on November 9, 2009 (incorporated by reference to Exhibit 3.7
to the Registrants Annual Report of Form 10-K for the year
ended December 31, 2009). |
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3.8
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Certificate of Designations of 7% Convertible Perpetual
Preferred Stock (incorporated by reference to Exhibit 3.1 to
the Registrants Current Report on Form 8-K filed July 1,
2009). |
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3.9
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Certificate of Amendment to Certificate of Designations of
7.0% Convertible Perpetual Preferred Stock of the Registrant,
dated February 23, 2011 (incorporated by reference to Exhibit
3.2 to the Registrants Current Report on Form 8-K filed
March 1, 2011). |
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3.10
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Certificate of Merger of the Registrant with and into Wellco
Sub Company, dated February 23, 2011 (incorporated by
reference to Exhibit 3.1 to the Registrants Current Report
on Form 8-K filed March 1, 2011). |
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4.1
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Specimen Stock Certificate of Common Stock of the Registrant
(incorporated by reference to Exhibit 4.1 to the Registrants
Quarterly Report on Form 10-Q for the quarter ended June 30,
2004). |
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4.2
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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). |
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4.3
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Registration Rights Agreement dated as of January 29, 2007 by
and among the Registrant, 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). |
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4.4
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Registration Rights Agreement dated as of January 18, 2006 by
and among the Registrant, 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). |
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4.5
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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). |
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4.6
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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). |
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4.7
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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). |
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4.8
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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). |
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4.9
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Third Supplemental Indenture, dated February 23, 2011, by and
among the Registrant, the other Guarantors parties thereto
and Wells Fargo Bank N.A., as Trustee, relating to the 9.0%
Senior Notes due 2014 (incorporated by reference to Exhibit
10.1 to the Registrants Current Report on Form 8-K filed
March 1, 2011). |
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4.10
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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). |
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4.11
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Supplemental Indenture, dated February 23, 2011, by and among
the Registrant, the other Guarantors parties thereto and
Wells Fargo Bank N.A., as Trustee, relating to the 8.5%
Senior Notes due 2017 (incorporated by reference to Exhibit
10.2 to the Registrants Current Report on Form 8-K filed
March 1, 2011). |
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Exhibit |
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Description |
4.12
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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). |
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4.13
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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). |
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4.14
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Investment Agreement, dated May 20, 2009, between the
Registrant and Lime Rock Partners V, L.P. (incorporated by
reference to Exhibit 4.1 to the Registrants Current Report
on Form 8-K filed on May 27, 2009). |
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4.15
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First Amendment to Investment Agreement, dated June 25, 2009,
between the Registrant and Lime Rock Partners V, L.P.
(incorporated by reference to Exhibit 4.1 to the Registrants
Current Report on Form 8-K filed on July 1, 2009). |
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4.16
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Second Amendment to Investment Agreement, dated September 1,
2009, between the Registrant and Lime Rock Partners V, L.P.
(incorporated by reference to Exhibit 4.1 to the Registrants
Current Report on Form 8-K filed on September 2, 2009). |
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4.17
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Third Amendment to Investment Agreement, dated September 1,
2009, between the Registrant and Lime Rock Partners V, L.P.
(incorporated by reference to Exhibit 4.1 to the Registrants
Current Report on Form 8-K filed on January 5, 2010). |
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4.18
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Fourth Amendment to Investment Agreement, dated July 14,
2010, between the Registrant and Lime Rock Partners V, L.P.
(incorporated by reference to Exhibit 4.1 to the Registrants
Current Report on Form 8-K filed on July 14, 2010). |
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4.19
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Fifth Amendment to Investment Agreement, dated September 27,
2010, between the Registrant and Lime Rock Partners V, L.P.
(incorporated by reference to Exhibit 4.1 to the Registrants
Current Report on Form 8-K filed on September 30, 2010). |
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4.20
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Registration Rights Agreement, dated June 26, 2009, between
the Registrant and Lime Rock Partners V, L.P. (incorporated
by reference to Exhibit 4.2 to the Registrants Current
Report on Form 8-K filed on July 1, 2009). |
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10.1
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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). |
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10.2
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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). |
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10.3
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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). |
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10.4*
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Allis-Chalmers Savings Plan (incorporated by reference to
Registrants Annual Report on Form 10-K for the year ended
December 31, 1988). |
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10.5*
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Allis-Chalmers Consolidated Pension Plan (incorporated by
reference to Registrants Annual Report on Form 10-K for the
year ended December 31, 1988). |
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10.6
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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). |
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Exhibit |
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Description |
10.7
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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). |
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10.8
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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). |
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10.9*
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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). |
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10.10*
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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). |
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10.11*
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Amended and Restated Employment Agreement, dated August 5,
2009, between the Registrant and Victor M. Perez.
(incorporated by reference to Exhibit 10.1 to the
Registrants Current Report on Form 8-K filed on August 11,
2009). |
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10.12*
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Employment Agreement, effective April 1, 2010, by and between
the Registrant and Victor M. Perez (incorporated by reference
to Exhibit 10.1 to the Registrants Current Report on Form
8-K filed on August 17, 2010). |
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10.13*
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Amendment to Executive Employment Agreement, dated effective
as of February 22, 2011, by and between the Registrant and
Victor M. Perez (incorporated by reference to Exhibit 10.2 to
the Registrants Current Report on Form 8-K filed on February
28, 2011). |
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10.14*
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Employment Agreement, effective April 1, 2010, by and between
the Registrant and Theodore F. Pound (incorporated by
reference to Exhibit 10.2 to the Registrants Current Report
on Form 8-K filed on August 17, 2010). |
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10.15*
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Amendment to Executive Employment Agreement, dated effective
as of February 22, 2011, by and between the Registrant and
Theodore F. Pound III (incorporated by reference to Exhibit
10.1 to the Registrants Current Report on Form 8-K filed on
February 28, 2011). |
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10.16*
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Employment Agreement, effective April 1, 2010, by and between
the Registrant and Terrence P. Keane (incorporated by
reference to Exhibit 10.3 to the Registrants Current Report
on Form 8-K filed on August 17, 2010). |
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10.17*
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Employment Agreement, effective April 1, 2010, by and between
the Registrants and Mark Patterson (incorporated by reference
to Exhibit 10.4 to the Registrants Current Report on Form
8-K filed on August 17, 2010). |
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10.18*
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Employment Agreement, effective April 1, 2010, by and between
Allis-Chalmers Directional Drilling Services LLC and David K.
Bryan (incorporated by reference to Exhibit 10.5 to the
Registrants Current Report on Form 8-K filed on August 17,
2010). |
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10.19*
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Employment Agreement, effective April 21, 2010, by and
between DLS Argentina Limited and Carlos F. Etcheverry
(incorporated by reference to Exhibit 10.1 to the
Registrants Current Report on Form 8-K filed May 20, 2010). |
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10.20
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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). |
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10.21
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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). |
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10.22
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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). |
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Exhibit |
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Description |
10.23
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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). |
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10.24
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First Amendment to Investor Rights Agreement, by and among the Registrant 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). |
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10.25
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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). |
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10.26*
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2003 Incentive Stock Plan (incorporated by reference to Exhibit 4.12 to the Registrants Current
Report on Form 8-K filed August 17, 2005). |
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10.27*
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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). |
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10.28*
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Second Amended and Restated 2006 Incentive Plan (incorporated by reference to Exhibit 10.1 to the
Registrants Current Report on Form 8-K filed on November 12, 2009). |
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10.29*
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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). |
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10.30*
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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). |
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10.31*
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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). |
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10.32*
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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). |
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10.33*
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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). |
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10.34*
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Form of Performance Award Agreement, as amended and restated effective March 3, 2010, pursuant to
the Registrants 2006 Incentive Plan (incorporated by reference to Exhibit 10.1 to the
Registrants Current Report on Form 8-K filed on March 9, 2010). |
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10.35
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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). |
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10.36
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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). |
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10.37
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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). |
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10.38
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Third Amendment to Second Amended and Restated Credit Agreement, dated as of April 9, 2009, by and
among the Company, as borrower, certain subsidiaries of the Company, as guarantors, Royal Bank of
Canada, as administrative agent, and the lenders named thereto (incorporated by reference to
Exhibit 10.1 to the Registrants Current Report on Form 8-K filed on April 9, 2009). |
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Exhibit |
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Description |
10.39
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Fourth Amendment to Second Amended and Restated Credit Agreement, dated May 20, 2009, by and among
Allis-Chalmers Energy Inc., the subsidiary guarantors party thereto, Royal Bank of Canada, as
Administrative Agent and Collateral Agent, and the lenders party thereto (incorporated by
reference to Exhibit 10.1 to the Registrants Current Report on Form 8-K filed on May 27, 2009). |
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10.40
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Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of October 13, 2009, by
and among the Company, as borrower, certain subsidiaries of the Company, as guarantors, Royal Bank
of Canada, as administrative agent, and the lenders named thereto (incorporated by reference to
Exhibit 10.1 to the Registrants Current Report on Form 8-K filed on October 16, 2009). |
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10.41
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Sixth Amendment to Second Amended and Restated Credit Agreement, dated as of February 25, 2010, by
and among the Company, as borrower, certain subsidiaries of the Company as guarantors, Royal Bank
of Canada, as administrative agent, and the lenders named thereto (incorporated by reference to
Exhibit 10.1 to the Registrants Current Report on Form 8-K filed on March 2, 2010). |
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10.42
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Seventh Amendment to Second Amended and Restated Credit Agreement, dated as of November 12, 2010,
by and among the Company, as borrower, certain subsidiaries of the Company, as guarantors, Royal
Bank of Canada, as administrative agent, and the lenders named thereto (incorporated by reference
to Exhibit 10.1 to the Registrants Current Report on Form 8-K filed on November 12, 2010). |
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10.43*
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Amended and Restated Performance award Agreement, dated March 11, 2009, between Allis-Chalmers
Energy Inc. and Munawar H. Hidayatallah (incorporated by reference to Exhibit 10.1 to the
Registrants Current Report on Form 8-K filed on March 13, 2009). |
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10.44*
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Amended and Restated Performance Award Agreement, dated August 5, 2009, between Allis-Chalmers
Energy Inc. and Victor M. Perez (incorporated by reference to Exhibit 10.2 to the Registrants
Current Report on Form 8-K filed on August 11, 2009). |
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10.45*
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Letter agreements dated March 9, 2009, by each of Munawar H. Hidayatallah, Victor M. Perez,
Theodore F. Pound III, David Bryan, Terrence P. Keane and Mark Patterson (incorporated by
reference to Exhibit 10.2 to the Registrants Current Report on Form 8-K filed on March 13, 2009). |
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23.1
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Consent of UHY LLP. |
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31.1
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Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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31.2
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Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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32.1
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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. |
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* |
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Compensation Plan or Agreement |
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Filed herewith. |
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