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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date of Earliest Event Reported): July 25, 2008
ALLIS-CHALMERS ENERGY INC.
(Exact name of registrant as specified in its charter)
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Delaware
(State or other jurisdiction
of incorporation)
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001-02199
(Commission
File Number)
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39-0126090
(IRS Employer Identification
Number) |
5075 Westheimer, Suite 890
Houston, Texas 77056
(Address of principal executive offices)
(713) 369-0550
(Registrants telephone number, including area code)
Not applicable
(Former name or former address, if changed since last report)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the
filing obligation of the registrant under any of the following provisions:
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Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
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Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
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Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
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Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Item 8.01. Other Events
ANNUAL REPORT UPDATE
Unless the context requires otherwise, references in this Current Report to Allis-Chalmers,
we, us, our and ours refer to Allis-Chalmers Energy Inc., together with its subsidiaries.
We are filing this Current Report on Form 8-K to update certain historical information
included in our Annual Report on Form 10-K for the year ended December 31, 2007 filed March 7, 2008
(Form 10-K). In particular, we are updating historical results to reflect the reorganization of
our reporting segments.
Segment Reporting
As reported in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, we
reviewed our reporting segments during the first quarter of 2008. Based on this review, we
determined that our operational performance would be segmented and reviewed by the Oilfield
Services, Drilling and Completion and Rental Services segments. The Oilfield Services segment
includes our underbalanced drilling, directional drilling, tubular services and production services
operations. The Drilling and Completion segment includes our international drilling operations.
As a result, we realigned our financial reporting segments and report the following operations as
separate, distinct reporting segments: (1) Oilfield Services, (2) Drilling and Completion and (3)
Rental Services.
The following items of the Form 10-K are being adjusted retrospectively to reflect our
reorganization of our reporting segments:
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Business (Part I, Item 1); |
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Property (Part I, Item 2); |
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Managements Discussion and Analysis of Financial Condition and Results of Operations
(MD&A)(Part II, Item 7); and |
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Financial Statements and Supplementary Data (Part II, Item 8). |
This new presentation has no effect on our reported net income for any reporting period. The
revised sections of the Form 10-K included in this Current Report on Form 8-K have not been
otherwise updated for events occurring after the date of the consolidated financial statements,
which were originally presented in the Form 10-K. This Current Report on Form 8-K should be read
in conjunction with the Form 10-K (except for Part I, Items 1
and 2, and Part II, Items 7 and 8)
and our other periodic reports on Form 10-Q and Form 8-K.
Important Additional Information
In connection with the proposed merger transaction between Allis-Chalmers and Bronco Drilling
Company, Inc., Allis-Chalmers and Bronco Drilling have filed a joint proxy statement/prospectus and
both companies will file other relevant documents concerning the proposed merger transaction with
the SEC. INVESTORS ARE URGED TO READ THE JOINT PROXY STATEMENT/PROSPECTUS, AND ANY OTHER RELEVANT
DOCUMENTS FILED WITH THE SEC, BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION REGARDING THE MERGER.
Investors and security holders may obtain a free copy of the joint proxy statement/prospectus and
the other documents free of charge at the website maintained by the SEC at www.sec.gov.
The documents filed with the SEC by Allis-Chalmers may be obtained free of charge from
Allis-Chalmers website at www.alchenergy.com or by calling Allis-Chalmers Investor Relations
department at (713) 369-0550. The documents filed with the SEC by Bronco Drilling may be obtained
free of charge from Bronco Drillings website at www.broncodrill.com or by calling Bronco
Drillings Investor Relations department at (405) 242-4444. Investors and security holders are
urged to read the joint proxy statement/prospectus and the other relevant materials before making
any voting or investment decision with respect to the proposed merger transaction. Allis-Chalmers
and Bronco Drilling and their respective directors and executive officers may be deemed to be
participants in the solicitation of proxies from the respective stockholders of each company in
connection with the merger transaction. Information about the directors and executive officers of
Allis-Chalmers and their ownership of Allis-Chalmers common stock is set forth in its amended
annual report on Form 10-K/A filed with the SEC on April 29, 2008 and in subsequent statements of
changes in beneficial ownership on file with the SEC. Information about the directors and executive
officers of Bronco Drilling and their ownership of Bronco Drilling common stock is set forth in its
amended annual report on Form 10-K/A filed with the SEC on April 29, 2008 and in subsequent
statements of changes in beneficial ownership on file with the SEC. Investors may obtain
additional information regarding the interests of such participants by reading the joint proxy
statement/prospectus for the merger.
ITEM 1. BUSINESS
We provide services and equipment to oil and natural gas exploration and production companies
throughout the United States including Texas, Louisiana, New Mexico, Colorado, Oklahoma,
Mississippi, Wyoming, Arkansas, West Virginia, offshore in the Gulf of Mexico, and internationally
primarily in Argentina and Mexico. We operate in three sectors of the oil and natural gas service
industry: Oilfield Services; Drilling and Completion and Rental Services. Our central operating
strategy is to provide high-quality, technologically advanced services and equipment. As a result
of our commitment to customer service, we have developed strong relationships with many of the
leading oil and natural gas companies, including both independents and majors.
Our growth strategy is focused on identifying and pursuing opportunities in markets we believe
are growing faster than the overall oilfield services industry in which we believe we can
capitalize on our competitive strengths. Over the past several years, we have significantly
expanded the geographic scope of our operations and the range of services we provide through
strategic acquisitions and organic growth. Our organic growth has primarily been achieved through
expanding our geographic scope, acquiring complementary property and equipment, hiring personnel to
service new regions and cross-selling our products and services. Since 2001, we have completed 23
acquisitions, including six in 2005, six in 2006 and four in 2007.
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K
and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended, or the Exchange Act, are made available free of charge
on our website at www.alchenergy.com as soon as reasonably practicable after we electronically file
or furnish them to the Securities and Exchange Commission, or SEC.
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We have adopted a Code of Business Ethics and Conduct to provide guidance to our directors,
officers and employees on matters of business ethics and conduct. Our Code of Business Ethics and
Conduct is available on the investor relations section of our website.
Information contained on or connected to our website is not incorporated by reference into
this annual report on Form 10-K and should not be considered part of this report or any other
filing we make with the SEC.
Divisional and geographic financial information appears in Item 8. Financial Information
Notes to Consolidated Financial Statements Note 14.
Our History
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We were incorporated in 1913 under Delaware law. |
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We reorganized in bankruptcy in 1988 and sold all of our major businesses. From 1988 to
May 2001 we had only one operating company in the equipment repair business. |
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In May 2001, under new management we consummated a merger in which we acquired Oil Quip
Rentals, Inc., or Oil Quip, and its wholly-owned subsidiary, Mountain Compressed Air, Inc.,
or MCA. |
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In December 2001, we sold Houston Dynamic Services, Inc., our last pre-bankruptcy
business. |
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In February 2002, we acquired approximately 81% of the capital stock of Allis-Chalmers
Tubular Services Inc., or Tubular, formerly known as Jens Oilfield Service, Inc. and
substantially all of the capital stock of Strata Directional Technology, Inc., or Strata. |
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In July 2003, we entered into a limited liability company operating agreement with M-I
L.L.C., or M-I, a joint venture between Smith International and Schlumberger N.V., to form a
Delaware limited liability company named AirComp LLC, or AirComp. Pursuant to this
agreement, we owned 55% and M-I owned 45% of AirComp. |
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In September 2004, we acquired the remaining 19% of the capital stock of Tubular. |
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In September 2004, we acquired all of the outstanding stock of Safco-Oil Field Products,
Inc., or Safco. |
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In November 2004, AirComp acquired substantially all of the assets of Diamond Air
Drilling Services, Inc. and Marquis Bit Co., LLC, which we refer to collectively as Diamond
Air. |
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In December 2004, we acquired Downhole Injection Services, LLC, or Downhole. |
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In April 2005, we acquired all of the outstanding stock of Delta Rental Service, Inc., or
Delta. |
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In May 2005, we acquired all of the outstanding stock of Capcoil Tubing Services, Inc.,
or Capcoil. |
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In July 2005, we acquired M-Is interest in AirComp, and acquired the compressed air
drilling assets of W. T. Enterprises, Inc., or W.T. |
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Effective August 2005, we acquired all of the outstanding stock of Target Energy Inc., or
Target. |
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In September 2005, we acquired the casing and tubing assets of IHS/Spindletop, a division
of Patterson Services, Inc., a subsidiary of RPC, Inc. |
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In January 2006, we acquired all of the outstanding stock of Specialty Rental Tools,
Inc., or Specialty. |
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In April 2006, we acquired all of the outstanding stock of Rogers Oil Tool Services,
Inc., or Rogers. |
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In August 2006, we acquired all of the outstanding stock of DLS Drilling, Logistics &
Services Corporation, or DLS. |
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In October 2006, we acquired all of the outstanding stock of Petro-Rentals, Incorporated,
or Petro Rentals. |
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In December 2006, we acquired all of the outstanding stock of Tanus Argentina S.A., or
Tanus. |
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In December 2006, we acquired substantially all of the assets of Oil & Gas Rental
Services, Inc., or OGR. |
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In June 2007, we acquired Coker Directional, Inc., or Coker and merged it with Strata. |
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In July 2007, we acquired Diggar Tools, LLC, or Diggar and merged it with Strata. |
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In October 2007, we acquired Rebel Rentals, Inc., or Rebel. |
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In November 2007, we acquired substantially all the assets Diamondback Oilfield Services,
Inc. or Diamondback. |
As a result of these transactions, our prior results may not be indicative of current or
future operations of those sectors.
Industry Overview
We provide products and services primarily to domestic onshore and offshore oil and natural
gas exploration and production companies. The main factor influencing demand for our products and
services is the level of drilling activity by oil and natural gas companies, which, in turn,
depends largely on current and anticipated future crude oil and natural gas prices and production
depletion rates. Current industry forecasts suggest an increasing demand for oil and natural gas
coupled with flat or declining production curve, which we believe should result in the continuation
of historically high crude oil and natural gas commodity prices. The EIA forecasts that U.S. oil
and natural gas consumption will increase at an average annual rate of 0.8% and 0.3% through 2030,
respectively. The EIA estimates that U.S. oil and natural gas production will increase at an
average annual rate of 0.4% and 0.3% respectively.
We anticipate that oil and natural exploration and production companies will continue to
increase capital spending for their exploration and drilling programs. According to Lehman Bros.
Survey of E&P Spending, U.S. spending in 2008 will increase by 3.5% to $78.5 billion while
international spending will increase by 16.16% to $230.24 billion. Baker Hughes rig count data
indicates that the average total rig count in the United States increased 92% from an average of
918 in 2000 to 1,763 as of February 29, 2008, while the average natural gas rig count increased 97%
from an average of 720 in 2000 to 1,418 as of February 29, 2008. While the number of rigs drilling
for natural gas has increased significantly since the beginning of 1996, natural gas production has
remained relatively flat over the same period of time. This is largely a function of increasing
decline rates for natural gas wells in the United States. The offshore Gulf of Mexico rig count,
however, decreased to 58 rigs at February 29, 2008 from 90 rigs in the comparable 2007 period due
to the relocation of rigs to the more attractive international markets. We believe that a
continued increase in capital expenditure will be required for the natural gas industry to help
meet the expected increased demand for natural gas in the United States.
We believe oil and natural gas producers are becoming increasingly focused on their core
competencies in identifying reserves and reducing burdensome capital and maintenance costs. In
addition, we believe our customers are currently consolidating their supplier bases to streamline
their purchasing operations and benefit from economies of scale.
Competitive Strengths
We believe the following competitive strengths will enable us to capitalize on future
opportunities:
Strategic position in high growth markets. We focus on markets we believe are growing faster
than the overall oilfield services industry and in which we can capitalize on our competitive
strengths. Pursuant to this strategy, we have become a significant provider of products and
services in directional drilling, underbalanced drilling and rental services. We employ
approximately 105 full-time directional drillers, own 30 measurement-while-drilling tools and a
fleet of 300 downhole motors. We believe our ability to attract and retain experienced drillers has
made us a leader in the segment. We also believe we are one of the largest underbalanced drillers
based on amount of air drilling equipment with approximately 260 compressors, boosters and foam
units enabling us to provide customized packages. In addition, we have significant operations in
what we believe will be among the higher growth oil and natural gas producing regions within the
United States and internationally, including the Barnett Shale in North Texas, the Arkoma, Woodford
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Shale and Anadarko Basins in Oklahoma, the Fayetteville Shale in Arkansas, onshore and
offshore Louisiana, the Piceance Basin in Southern Colorado, all five oil and natural gas producing
regions in Mexico, and all five major oil and natural gas producing regions of Argentina.
Strong relationships with diversified customer base. We have strong relationships with many
of the major and independent oil and natural gas producers and service companies in Texas,
Louisiana, New Mexico, Colorado, Oklahoma, Mississippi, Utah, Wyoming, Arkansas, offshore in the
Gulf of Mexico, Argentina and Mexico. Our largest customers include Pan American Energy,
Repsol-YPF, Apache Corporation, BP, Anadarko Petroleum, Oxy, ConocoPhilips, Chesapeake Energy,
Newfield Exploration, Nexen Petroleum, XTO Energy, El Paso Corporation, Materiales y Equipo
Petroleo, or Matyep and Devon Energy. Since 2002, we have broadened our customer base as a result
of our acquisitions, technical expertise and reputation for quality customer service and by
providing customers with technologically advanced equipment and highly skilled operating personnel.
Successful execution of growth strategy. Over the past six years, we have grown both
organically and through successful acquisitions of competing businesses. Since 2001, we have
completed 23 acquisitions. We strive to improve the operating performance of our acquired
businesses by increasing their asset utilization and operating efficiency. These acquisitions and
organic growth have expanded our geographic presence and customer base and, in turn, have enabled
us to cross-sell various products and services.
Diversified and increased cash flow sources. We operate as a diversified oilfield service
company through our three business segments. We believe that our product and service offerings and
geographical presence through our three business segments provide us with diverse sources of cash
flow. Our acquisition of DLS in August 2006 increased our international presence and provides
stable long-term contracts. Our acquisition of Petro Rentals in October 2006 significantly
enhanced our production-related services provided by our Oilfield Services segment and equipment,
and our acquisition of substantially all the assets of OGR in December 2006 expanded our Rental
Services segment and increased our offshore and international operations.
Experienced management team. Our executive management team has extensive experience in the
energy sector, and consequently has developed strong and longstanding relationships with many of
the major and independent exploration and production companies. We believe that our management
team has demonstrated its ability to grow our businesses organically, make strategic acquisitions
and successfully integrate these acquired businesses into our operations.
Business Strategy
The key elements of our growth strategy include:
Mitigate cyclical risk through balanced operations. We strive to mitigate cyclical risk in
the industries we operate by balancing our operations between onshore versus offshore; drilling
versus production; rental tools versus service; domestic versus international; and natural gas
versus crude oil. We will continue to shape our organic and acquisition growth efforts to provide
further balance across these five categories. Part of our strategy is to further increase our
international operations because they increase our exposure to crude oil and provide opportunities
for long-term contracts.
Expand geographically to provide greater access and service to key customer segments. We have
locations in Texas, New Mexico, Colorado, Wyoming, Arkansas, Oklahoma and Louisiana in order to
enhance our proximity to customers and more efficiently serve their needs. Our acquisition of DLS
expanded our geographic footprint into Argentina and Bolivia. We plan to continue to establish new
locations in the United States and internationally. In 2007, we expanded our presence domestically
into non-traditional geographic regions experiencing strong growth and new drilling activity.
Prudently pursue strategic acquisitions. To complement our organic growth, we have pursued
strategic acquisitions which we believe are accretive to earnings, complement our products and
services, provide new equipment and technology, expand our geographic footprint and market
presence, and further diversify our customer base.
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Expand products and services provided in existing operating locations. Since the beginning of
2004, we have invested approximately $175.2 million in capital expenditures to grow our business
organically by investing in new, technologically advanced equipment and by expanding our product
and service offerings. This strategy is consistent with our belief that our customers favor modern
equipment emphasizing efficiency and safety and integrated suppliers that can provide a broad
product and service offering in many geographic locations.
Increase utilization of assets. We seek to increase revenues and enhance margins by
increasing the utilization of our assets with new and existing customers. We expect to accomplish
this through leveraging longstanding relationships with our customers and cross-selling our suite
of services and equipment, while taking advantage of continued improvements in industry
fundamentals. We also expect to continue to implement this strategy in our recently expanded
Rental Services segment, thus improving the utilization and profitability of this newly acquired
business with minimal additional investment.
Business Segments
Oilfield Services. We utilize state-of-the-art equipment to provide well planning and
engineering services, directional drilling packages, downhole motor technology, well site
directional supervision, exploratory and development re-entry drilling, downhole guidance services
and other drilling services to our customers, including logging-while-drilling and
measurement-while-drilling (MWD) services. We provide specialized equipment and trained operators
to perform a variety of pipe handling services, including installing casing and tubing, changing
out drill pipe and retrieving production tubing for both onshore and offshore drilling and workover
operations, which we refer to as tubular services We also provide compressed air equipment,
chemicals and other specialized products for underbalanced drilling and production applications.
In addition, we provide a variety of quality production-related rental tools and equipment and
services, including wire line services, land and offshore pumping services and coil tubing. In
addition, we perform workover services with coil tubing units.
According to Baker Hughes, as of February 29, 2008, 46% of all wells in the United States are
drilled directionally and/or horizontally. Management believes directional drilling offers several
advantages over conventional drilling including:
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improvement of total cumulative recoverable reserves; |
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improved reservoir production performance beyond conventional vertical wells; and |
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reduction of the number of field development wells. |
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. There is a trend in the industry to drill, complete and workover
wells with underbalanced operations and we expect the market to continue to grow. With a combined
fleet of approximately 260 compressors, boosters and foam units, we believe we are one of the
worlds largest providers of underbalanced drilling services in the United States. We also provide
premium air hammers and bits to oil and natural gas companies for use in underbalanced drilling.
Our broad and diversified product line enables us to compete in the underbalanced market with
equipment and services packages engineered and customized to specifically meet customer
requirements.
In 2007, we expanded our directional drilling capability by completing three acquisitions for
approximately $37.3 million in total. These were Coker (June 2007), Diggar (July 2007) and
Diamondback (November 2007). These acquisitions provided additional directional drillers, downhole
motors, and MWD tools and enabled us to expand our presence in the Northern Rockies and the
Mid-Continent areas. We now have a team of approximately 105 full-time directional drillers and
maintain an inventory of approximately 300 drilling motors. Our straight-hole motors offer an
opportunity to capture additional market share. We currently provide our directional drilling
services in Texas, Louisiana, Oklahoma, Colorado, Wyoming and West Virginia.
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We expanded our tubular services in September 2005 by acquiring the casing and tubing assets
of IHS/Spindletop, a division of Patterson Services, Inc., a subsidiary of RPC, Inc. We paid $15.7
million for RPC, Inc.s casing and tubing assets, which consisted of casing and tubing installation
equipment, including hammers, elevators, trucks, pickups, power units, laydown machines, casing
tools and torque turn equipment. The acquisition of RPC, Inc.s casing and tubing assets increased
our capability in tubular services and expanded our geographic capability. We opened new field
offices in Corpus Christi, Texas, Kilgore, Texas, Lafayette, Louisiana and Houma, Louisiana. The
acquisition allowed us to enter the East Texas and Louisiana market for casing and tubing services
as well as offshore in the Gulf of Mexico. Additionally, the acquisition greatly expanded our
premium tubing services. In April 2006 we acquired Rogers for $13.7 million. Historically, Rogers
rented, sold and serviced power drill pipe tongs and accessories and rental tongs for snubbing and
well control applications and provided specialized tong operators for rental jobs. In October 2007
we acquired Rebel Rentals, Inc. for $7.3 million. Rebel owns an inventory of equipment used
primarily for tubing installation services in the South Louisiana and Gulf Coast regions.
In July 2005, we purchased the compressed air drilling assets of W. T., operating in West
Texas and acquired the remaining 45% equity interest in AirComp from M-I. The acquired assets
include air compressors, boosters, mist pumps, rolling stock and other equipment. We currently
provide compressed air drilling services in Alabama, Arkansas, Colorado, Mississippi, New Mexico,
Oklahoma, Texas, Utah, West Virginia and Wyoming.
We provide a variety of quality production-related rental tools and equipment and services,
including wire line services, land and offshore pumping services and coiled tubing. In addition,
we perform workover services with coiled tubing units. We started offering these services with the
acquisition of Downhole, in December 2004, and the acquisition of Capcoil, in May 2005. In October
2006, we expanded our production services with the acquisition of Petro Rentals. Petro Rentals
served both the onshore and offshore markets, providing a variety of quality rental tools and
equipment and services, with an emphasis on production-related equipment and services, including
wire line services and equipment, land and offshore pumping services and coiled tubing. On June
29, 2007, we sold our capillary tubing units and related equipment for approximately $16.3 million.
We reported a gain of approximately $8.9 million. The assets sold represented a small portion of
our Oilfield Services segment. We currently provide production services in Texas, Louisiana,
Arkansas and Oklahoma.
Drilling and Completion. We provide drilling, completion, workover and related services for
oil and natural gas wells. Headquartered in Buenos Aires, Argentina, we operate out of the San
Jorge, Cuyan, Neuquen, Austral and Noroeste basins of Argentina. We also offer a wide variety of
other oilfield services such as drilling fluids and completion fluids and engineering and logistics
to complement our customers field organization.
Our Drilling and Completion segment was established with acquisition of DLS in August 2006 for
approximately $117.9 million. We operate a fleet of 56 rigs, including 20 drilling rigs and 35
service rigs (workover and pulling units) in Argentina and one drilling rig in Bolivia. Argentine
rig operations are generally conducted in remote regions of the country and require substantial
infrastructure and support. In 2007, we placed orders for four drilling rigs and 16 service rigs.
Four of the service rigs were delivered in the fourth quarter of 2007, while the remaining rigs are
expected to be delivered throughout the first three quarters of 2008. As of February 29, 2008, all
of our rig fleet was actively marketed, except for one drilling rig that is presently inactive and
would require approximately $6.4 million in capital expenditures to become operational.
Rental Services. We provide specialized rental equipment, including premium drill pipe,
spiral heavy weight drill pipe, tubing work strings, blow out preventors, choke manifolds and
various valves and handling tools, for both onshore and offshore well drilling, completion and
workover operations. Most wells drilled for oil and natural gas require some form of rental
equipment in both the drilling and completion of a well. We have an inventory of specialized
equipment, which includes double studded adapters, test plugs, wear bushings, adaptor spools,
baskets, spacer spools and other assorted handling tools in various sizes to meet our customers
demands. We charge customers for rental equipment on a daily basis. Our customers are liable for
the cost of inspection, repairs and lost or damaged equipment. We currently provide rental
equipment in Texas, Oklahoma, Louisiana, Mississippi, Colorado, offshore in the Gulf of Mexico and
internationally in Malaysia, Colombia, Russia, Mexico and Canada.
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Our Rental Services segment was established with the acquisition of Safco in September 2004
and Delta in April 2005. We significantly expanded our Rental Services segment in January 2006
with the acquisition of Specialty. Specialty had been in the rental business for over 25 years,
providing oil and natural gas operators and oilfield services companies with rental equipment. The
acquisition of Specialty gave us a broader scope of rental equipment to offer our existing customer
base, and allowed us to better compete in deep water drilling operations in the area of premium
drill pipe and handling equipment. The acquisition of Specialty added new customer relationships
and enhanced our relationships with key existing customers. We further expanded this segment with
the acquisition of substantially all the assets of OGR in December 2006. The assets we acquired
included an extensive inventory of premium rental equipment, including drill pipe, spiral heavy
weight drill pipe, tubing work strings, landing strings, blow out preventors, choke manifolds and
various valves and handling tools for oil and natural gas drilling. Included in the acquisition
were OGRs facilities in Morgan City, Louisiana and Victoria, Texas.
Cyclical Nature Of The Oilfield 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 peaks and valleys of demand are further apart than those of many other cyclical
industries. This is primarily a result of the industry being driven by commodity demand and
corresponding price increases. As demand increases, producers raise their prices. The price
escalation enables producers to increase their capital expenditures. The increased capital
expenditures ultimately result in greater revenues and profits for services and equipment
companies. The increased capital expenditures also ultimately result in greater production which
historically has resulted in increased supplies and reduced prices.
Demand for our services has been strong throughout 2004, 2005 and 2006. The market in 2007 was
generally positive with some areas of weakness and some areas of growth. Certain customers slowed
their drilling activity in 2007 in response to increased availability of drilling rigs and
volatility of natural gas prices, while others remained very active. Activity in the U.S. Gulf of
Mexico decreased in the second half of 2007 due to the hurricane season and relocation of rigs to
more attractive international markets. Management believes demand will generally remain stable in
2008 due to high oil and natural gas prices and the capital expenditure plans of the exploration
and production companies, however, activity in the U.S. Gulf of Mexico may remain low for the next
year. Because of these market fundamentals for oil and natural gas, management believes the
long-term trend of activity in our markets is favorable. However, these factors could be more than
offset by other developments affecting the worldwide supply and demand for oil and natural gas
products and developments in the U.S. economy.
Customers
In 2007 and 2006, one of our customers, Pan American Energy LLC Sucursal Argentina, or Pan
American Energy, represented approximately 20.7% and 11.7% of our consolidated revenues,
respectively. Pan America Energy is a joint venture that is owned 60% by British Petroleum and 40%
by Bridas Corporation. Alejandro P. Bulgheroni and Carlos A. Bulgheroni, two of our directors, may
be deemed to indirectly beneficially own all of the outstanding capital stock of Bridas Corporation
and are members of the Management Committee of Pan American Energy. In 2005, none of our customers
accounted for more than 10% of our revenues. Our primary customers are the major and independent
oil and natural gas companies operating in the United States, Argentina and Mexico. The loss
without replacement of our larger existing customers could have a material adverse effect on our
results of operations.
Suppliers
The equipment utilized in our business is generally available new from manufacturers or at
auction. Currently, due to the high level of activity in the oilfield industry, there is a high
demand for new and used equipment. Consequently, there is a limited amount of many types of
equipment available at auction and significant backlogs on new equipment. However, the cost of
acquiring new equipment to expand our business could increase as a result of the high demand for
equipment in the industry.
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Competition
We experience significant competition in all areas of our business. In general, the markets
in which we compete are highly fragmented, and a large number of companies offer services that
overlap and are competitive with our services and products. We believe that the principal
competitive factors are technical and mechanical capabilities, management experience, past
performance and price. While we have considerable experience, there are many other companies that
have comparable skills. Many of our competitors are larger and have greater financial resources
than we do.
We believe that there are five major directional drilling companies, Schlumberger,
Halliburton, Baker Hughes, W-H Energy Services (Pathfinder) and Weatherford, that market both
worldwide and in the United States as well as numerous small regional players. Significant
competitors in the tubular markets we serve include Franks Casing Crew and Rental Tools,
Weatherford, BJ Services, Tesco and Premier. These markets remain highly competitive and
fragmented with numerous casing and tubing crew companies working in the United States. Our
primary competitors in Mexico are South American Enterprises and Weatherford, both of which provide
similar products and services. Our largest competitor for underbalanced drilling services is
Weatherford. Weatherford focuses on large projects, but also competes in the more common
compressed air, mist, foam and aerated mud drilling applications. Other competition comes from
smaller regional companies. In the production services market there are numerous competitors, most
of which have larger coiled tubing services operations than us.
Our five largest competitors in the Drilling and Completion segment, which operate primarily
in Argentina, are Pride International, Servicios WellTech, Ensign Energy Services, Nabors and
Helmerich & Payne.
The Rental Services business is highly fragmented with hundreds of companies offering various
rental tool services. Our largest competitors include Weatherford, Quail Rental Tools, Knight
Rental Tools and W-H Energy Services (Thomas Tools).
Backlog
We do not view backlog of orders as a significant measure for our business because our jobs
are short-term in nature, typically one to 30 days, without significant on-going commitments.
Employees
Our strategy includes acquiring companies with strong management and entering into long-term
employment contracts with key employees in order to preserve customer relationships and assure
continuity following acquisition. In general, we believe we have good relations with our
employees. None of our employees, other than our Drilling and Completion employees, are
represented by a union. We actively train employees across various functions, which we believe is
crucial to motivate our workforce and maximize efficiency. Employees showing a higher level of
skill are trained on more technologically complex equipment and given greater responsibility. All
employees are responsible for on-going quality assurance. At February 29, 2008, we had
approximately 3,050 employees. Almost all of our Drilling and Completion operations 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.
9
Seasonality
Oil and natural gas operations of our customers located offshore and onshore in the Gulf of
Mexico and in Mexico may be adversely affected by hurricanes and tropical storms, resulting in
reduced demand for our services. For example, in the summer of 2005, the Gulf of Mexico suffered
an unusually high number of hurricanes with unusual intensity. Additionally, in August to October
of 2007 we witnessed a decline in offshore drilling rig operations in the Gulf of Mexico in
anticipation of the hurricane season. Many of those rigs have not returned to the U.S. Gulf and
have been relocated to the international markets. In addition, our customers operations in the
Mid-Continent and Rocky Mountain regions of the United States are also adversely affected by
seasonal weather conditions. These weather conditions limit our access to these job sites and our
ability to service wells in these areas. These constraints decrease drilling activity and the
resulting shortages or high costs could delay our operations and materially increase our operating
and capital costs.
Federal Regulations and Environmental Matters
Our operations are subject to federal, state and local laws and regulations relating to the
energy industry in general and the environment in particular. Environmental laws have in recent
years become more stringent and have generally sought to impose greater liability on a larger
number of potentially responsible parties. Because we provide services to companies producing oil
and natural gas, which are toxic substances, we may become subject to claims relating to the
release of such substances into the environment. While we are not currently aware of any situation
involving an environmental claim that would likely have a material adverse effect on us, it is
possible that an environmental claim could arise that could cause our business to suffer. We do
not anticipate any material expenditures to comply with environmental regulations affecting our
operations.
In addition to claims based on our current operations, we are from time to time named in
environmental claims relating to our activities prior to our reorganization in 1988 (See Item 3.
Legal Proceedings).
Intellectual Property Rights
Except for our relationships with our customers and suppliers described above, we do not own
any patents, trademarks, licenses, franchises or concessions which we believe are material to the
success of our business.
10
ITEM 2. PROPERTIES
The following table describes the location and general character of the principal physical
properties used in each of our companys businesses as of February 29, 2008. Our principal
executive office is rented and located in Houston, Texas and the table below presents all of our
operating locations and whether the property is owned or leased.
|
|
|
|
|
Business Segment |
|
Location |
|
Owned/Leased |
Oilfield Services
|
|
Searcy, Arkansas
|
|
Leased |
|
|
Denver, Colorado
|
|
Leased |
|
|
Grand Junction, Colorado
|
|
Leased |
|
|
Broussard, Louisiana
|
|
Owned 1 location
& 3 leased |
|
|
Houma, Louisiana
|
|
Leased 2 locations |
|
|
Youngsville, Louisiana
|
|
Owned |
|
|
Carlsbad, New Mexico
|
|
Leased |
|
|
Farmington, New Mexico
|
|
Leased |
|
|
Elk City, Oklahoma
|
|
Leased |
|
|
Oklahoma City, Oklahoma
|
|
Leased |
|
|
Wilburton, Oklahoma
|
|
Leased |
|
|
Mt Morris, Pennsylvania
|
|
Leased |
|
|
Alvin, Texas
|
|
Leased |
|
|
Conroe, Texas
|
|
Leased |
|
|
Corpus Christi, Texas
|
|
Leased 2 locations |
|
|
Edinburg, Texas
|
|
Owned |
|
|
Fort Stockton, Texas
|
|
Leased |
|
|
Grandbury, Texas
|
|
Leased |
|
|
Houston, Texas
|
|
Leased 2 locations |
|
|
Kilgore, Texas
|
|
Leased |
|
|
Longview, Texas
|
|
Leased |
|
|
Midland, Texas
|
|
Leased |
|
|
Pearsall, Texas
|
|
Leased |
|
|
San Angelo, Texas
|
|
Leased |
|
|
Sonora, Texas
|
|
Leased |
|
|
Casper, Wyoming
|
|
Leased |
Drilling and Completion
|
|
Buenos Aires, Argentina
|
|
Leased |
|
|
Comodoro Rivadavia, Argentina
|
|
Owned |
|
|
Neuquen, Argentina
|
|
Owned |
|
|
Rincon de los Sauces, Argentina
|
|
Owned |
|
|
Tartagal, Argentina
|
|
Owned |
|
|
Santa Cruz, Bolivia
|
|
Leased |
Rental Services
|
|
Houston, Texas
|
|
Leased 2 locations |
|
|
Victoria, Texas
|
|
Owned |
|
|
Broussard, Louisiana
|
|
Leased |
|
|
Lafayette, Louisiana
|
|
Leased |
|
|
Morgan City, Louisiana
|
|
Owned |
11
ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our selected
historical financial data and our accompanying financial statements and the notes to those
financial statements included elsewhere in this document. The following discussion contains
forward-looking statements within the meaning of the Private Securities Litigation Reform Act of
1995 that reflect our plans, estimates and beliefs. Our actual results could differ materially
from those anticipated in these forward-looking statements as a result of risks and uncertainties,
including, but not limited to, those discussed under Item 1A. Risk Factors.
Overview of Our Business
We are a multi-faceted oilfield services company that provides services and equipment to oil
and natural gas exploration and production companies throughout the United States, including Texas,
Louisiana, New Mexico, Colorado, Oklahoma, Mississippi, Wyoming, Arkansas, West Virginia, offshore
in the Gulf of Mexico, and internationally, primarily in Argentina and Mexico. We operate in three
sectors of the oil and natural gas service industry: Oilfield Services; Drilling and Completion and
Rental Services.
We derive operating revenues from rates per job that we charge for the labor and equipment
required to provide a service and rates per day for equipment and tools that we rent to our
customers. The price we charge for our services depends upon several factors, including the level
of oil and natural gas drilling activity and the competitive environment in the particular
geographic regions in which we operate. Contracts are awarded based on the price, quality of
service and equipment, and the general reputation and experience of our personnel. The demand for
drilling services has historically been volatile and is affected by the capital expenditures of oil
and natural gas exploration and development companies, which can fluctuate based upon the prices of
oil and natural gas or the expectation for the prices of oil and natural gas.
The number of working drilling rigs, typically referred to as the rig count, is an important
indicator of activity levels in the oil and natural gas industry. The rig count in the United
States increased from 862 as of December 31, 2002 to 1,763 as of February 29, 2008, according to
the Baker Hughes rig count. Furthermore, directional and horizontal rig counts increased from 283
as of December 31, 2002 to 817 as of February 29, 2008, which accounted for 33% and 46% of the
total U.S. rig count, respectively. The offshore Gulf of Mexico rig count, however, decreased to
58 rigs at February 29, 2008 from 90 rigs one year earlier. We believe this is due to the
relocation of rigs to international markets as a result of the high oil prices.
Our cost of revenues represents all direct and indirect costs associated with the operation
and maintenance of our equipment. The principal elements of these costs are direct and indirect
labor and benefits, repairs and maintenance of our equipment, insurance, equipment rentals, fuel
and depreciation. Operating expenses do not fluctuate in direct proportion to changes in revenues
because, among other factors, we have a fixed base of inventory of equipment and facilities to
support our operations, and in periods of low drilling activity we may also seek to preserve labor
continuity to market our services and maintain our equipment.
Results of Operations
Our Oilfield Services segment includes the following acquisitions completed in 2005:
|
|
|
In May 2005, we acquired all of the outstanding stock of Capcoil. |
|
|
|
|
In July 2005, we acquired the 45% interest of M-I in AirComp, making us the 100% owner
of AirComp. |
|
|
|
|
In addition, in July 2005, we acquired the underbalanced drilling assets of W. T. |
|
|
|
|
On August 1, 2005, we acquired all of the outstanding capital stock of Target. |
|
|
|
|
On September 1, 2005, we acquired the casing and tubing service assets of Patterson
Services, Inc. |
In April 2005, we acquired all of the outstanding stock of Delta and we report the operations
in our Rental Services Segment.
12
In April 2006, we acquired all of the outstanding stock of Rogers and in October 2006, we
acquired all of the outstanding stock of Petro Rentals, and the results for the operations of both
acquired companies are included in our Oilfield Services segment. In August 2006, we acquired all
of the outstanding stock of DLS and in December 2006, we acquired all of the outstanding stock of
Tanus. We report the operations of DLS and Tanus in our Drilling and Completion segment. In
January 2006, we acquired all of the outstanding stock of Specialty and in December 2006, we
acquired substantially all of the assets of OGR. We report the operations of Specialty and OGR in
our Rental Services segment.
In June 2007, we acquired all of the outstanding stock of Coker and in July 2007, we acquired
all of the outstanding stock of Diggar and in November 2007, we acquired substantially all of the
assets of Diamondback. In October 2007, we acquired all of the outstanding stock of Rebel. We
report the operations of these four acquisitions in our Oilfield Services segment.
We consolidated the results of all of these acquisitions from the day they were acquired.
The foregoing acquisitions affect the comparability from period to period of our historical
results, and our historical results may not be indicative of our future results.
Comparison of Years Ended December 31, 2007 and December 31, 2006
Our revenues for the year ended December 31, 2007 were $571.0 million, an increase of 83.6%
compared to $311.0 million for the year ended December 31, 2006. Revenues increased in all of our
business segments due principally to the acquisitions completed during the two year period ended
December 31, 2007, the investment in new equipment and the opening of new operating locations. The
most significant increase in revenues was due to the acquisition of DLS on August 14, 2006 which
established our Drilling and Completion segment. The International Drilling segment generated
$215.8 million in revenues for the twelve months ended December 31, 2007 compared to $69.5 million
for the period from the date of the DLS acquisition to December 31, 2006. Revenues also increased
significantly at our Rental Services segment due to the acquisition of the OGR assets on December
18, 2006. The OGR assets, including its two rental yards, expanded out assets available for rent.
The OGR assets generated revenues of $82.2 million for the twelve months ended December 31, 2007
compared to $2.1 million for the period from the date of acquisition of the OGR assets to December
31, 2006. We experienced a decline in demand for our Rental Services in the last half of 2007 due
to a reduction of drilling activity in the U.S. Gulf of Mexico as rigs departed the U.S. Gulf in
favor of the international markets. Our Oilfield Services segment revenues increased in the 2007
period compared to the 2006 period due to acquisitions completed in the third and fourth quarters
of 2007 which added downhole motors, measurement-while-drilling, or MWD, tools, and directional
drilling personnel resulting in increased capacity and increased market penetration. Revenues also
increased at our Oilfield Services segment due to the acquisition of Petro-Rentals in October 2006
and the purchase of additional equipment, principally new compressor packages for our underbalanced
operations, and expansion of operations into new geographic regions. The impact of the additional
MWD tools, downhole motors and the acquisitions of Diggar and Coker completed in the last half of
2007 are not easily identifiable as they were quickly integrated with our pre-existing operations.
The acquisition of the Diamondback assets provided $3.1 million in revenues from the date of
acquisition to December 31, 2007. The Petro-Rentals acquisition and additional coil tubing
equipment provided an additional $20.6 million in revenues for the year ended December 31, 2007
compared to 2006. These gains in revenues were partly offset by a reduction of $6.7 million in
revenues from our capillary assets compared to 2006 as the assets were sold on June 29, 2007.
Except for our Rental Services segment, we believe these gains in revenues are sustainable
dependent on a favorable oil and natural gas price environment, a stable rig count and the level of
capital expenditures of our customers. Future growth or a continuation of 2007 revenues in our
Rental Services segment is contingent upon achieving success in marketing our rental assets to the
U.S. land drilling and international markets, and improvement in the offshore U.S. Gulf of Mexico
activity.
13
Our gross margin for the year ended December 31, 2007 increased 69.9% to $178.6 million, or
31.3% of revenues, compared to $105.1 million, or 33.8%, of revenues for the year ended December
31, 2006. The increase in gross profit is due to the increase in revenues in all of our business
segments. The decrease in gross profit as a percentage of revenues is primarily due to the 151.3%
increase in depreciation expense to $50.9 million in 2007 from $20.3 million in 2006. The primary
increase in depreciation expense is due to the acquisitions of the OGR assets, DLS and
Petro-Rentals and our capital expenditures. The increase in our depreciation expense related to
the OGR assets was $15.9 million to $16.6 million for the year ended December 31, 2007 compared to
$650,000 for the period from the date of the acquisition of the OGR assets to December 31, 2006.
Depreciation expense for DLS increased $7.2 million to $11.3 million for the year ended December
31, 2007 from $4.1 million for the period from the date of acquisition of DLS to December 31, 2006.
Depreciation expense for Petro-Rentals for the year ended December 31, 2007 was $3.6 million
compared to $688,000 for the period from the date of acquisition of Petro-Rentals to December 31,
2006. Our cost of revenues consists principally of our labor costs and benefits, equipment
rentals, maintenance and repairs of our equipment, depreciation, insurance and fuel. Because many
of our costs are fixed, our gross profit as a percentage of revenues is generally affected by our
level of revenues. The sustainability and growth in our gross margin is principally dependent upon
the sustainability and growth in our revenues. However, factors affecting the performance of our
Rental Services segment in 2007 as discussed previously have a negative impact on our gross margin
percentages as our Rental Services segment operates at a higher gross margin than our other
segments. Therefore, the level of revenues and gross margin from our Rental Services segment has a
significant impact on our overall gross margin and gross margin percentage. We expect our
depreciation expense to increase as we continue to purchase capital equipment to strengthen and
enhance our existing operations.
General and administrative expense was $58.6 million for the year ended December 31, 2007
compared to $35.5 million for the year ended December 31, 2006. General and administrative expense
increased due to the acquisitions, and the hiring of additional sales, operations, accounting and
administrative personnel. As a percentage of revenues, general and administrative expenses were
10.3% in 2007 compared to 11.4% in 2006. General and administrative expense includes share-based
compensation expense of $4.7 million in 2007 and $3.0 million in 2006. Without any significant
acquisitions, we expect the growth of our general and administrative expense to decrease in the
near future as our share-based compensation expense for future years is currently expected to
decrease.
On June 29, 2007, we sold our capillary tubing assets that were part of our Oilfield Services
segment. The total consideration was approximately $16.3 million in cash. We recognized a gain of
$8.9 million related to the sale of these assets.
Amortization expense was $4.1 million for the year ended December 31, 2007 compared to $1.9
million for the year ended December 31, 2006. The increase in amortization expense is primarily
due to the amortization of intangible assets in connection with our acquisition of the OGR assets,
which increased $2.2 million to $2.3 million for the year ended December 31, 2007 compared to
$96,000 for the period from the date of the acquisition of the OGR assets to December 31, 2006.
Without any significant acquisitions, we expect a slight increase in amortization expense as future
years will include a full year of amortization of intangible assets related to acquisitions
completed in 2007.
Income from operations for the year ended December 31, 2007 totaled $124.8 million, an 84.2%
increase over the $67.7 million in income from operations for the year ended December 31, 2006,
reflecting the increase in our revenues of $260.0 million and the resulting increase in our gross
profit of $73.5 million, offset in part by increased general and administrative expense of $23.1
million and increased amortization expense of $2.2 million. Our income from operations as a
percentage of revenues increased slightly to 21.9% in 2007 from 21.8% in 2006. Income from
operations in the 2007 period includes an $8.9 million gain from the sale of our capillary tubing
assets in the second quarter of 2007.
Our net interest expense was $46.3 million for the year ended December 31, 2007, compared to
$20.3 million for the year ended December 31, 2006. Interest expense increased in 2007 due to our
increased debt. In August 2006 we issued $95.0 million of senior notes bearing interest at 9.0% to
fund a portion of the acquisition of DLS. In January 2007 we issued $250.0 million of senior notes
bearing interest at 8.5% to pay off, in part, the $300.0 million bridge loan utilized to complete
the OGR acquisition and for working capital. This bridge loan was repaid on January 29, 2007. The
average interest rate on the bridge loan was approximately 10.6%. Interest expense for 2007
includes the write-off of deferred financing fees of $1.2 million related to the repayment of the
bridge loan. Interest expense includes amortization expense of deferred financing costs of $1.9
million and $1.5 million for 2007 and 2006, respectively. Our net increase is dependent upon our
level of debt and cash on hand, which are principally dependent upon acquisitions we complete, our
capital expenditures and our cash flows from operations.
14
Our provision for income taxes for the year ended December 31, 2007 was $28.8 million, or
36.4% of our net income before income taxes, compared to $11.4 million, or 24.3% of our net income
before income taxes for 2006. The increase in our provision for income taxes is attributable to
the increase in our operating income and a higher effective tax rate. The effective tax rate in
2006 was favorably impacted by the reversal of our valuation allowance on our deferred tax assets.
The valuation allowance was reversed due to operating results that allowed for the realization of
our deferred tax assets.
We had net income attributed to common stockholders of $50.4 million for the year ended
December 31, 2007, an increase of 41.6%, compared to net income attributed to common stockholders
of $35.6 million for the year ended December 31, 2006.
The following table compares revenues and income from operations for each of our business
segments for the years ended December 31, 2007 and December 31, 2006. Income from operations
consists of our revenues less cost of revenues, general and administrative expenses, and
depreciation and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
Income (Loss) from Operations |
|
|
|
2007 |
|
|
2006 |
|
|
Change |
|
|
2007 |
|
|
2006 |
|
|
Change |
|
|
|
(In thousands) |
|
Oilfield Services |
|
$ |
233,986 |
|
|
$ |
189,953 |
|
|
$ |
44,033 |
|
|
$ |
53,218 |
|
|
$ |
43,157 |
|
|
$ |
10,061 |
|
Drilling & Completion |
|
|
215,795 |
|
|
|
69,490 |
|
|
|
146,305 |
|
|
|
38,839 |
|
|
|
12,233 |
|
|
|
26,606 |
|
Rental Services |
|
|
121,186 |
|
|
|
51,521 |
|
|
|
69,665 |
|
|
|
49,139 |
|
|
|
26,293 |
|
|
|
22,846 |
|
General Corporate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16,414 |
) |
|
|
(13,953 |
) |
|
|
(2,461 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
570,967 |
|
|
$ |
310,964 |
|
|
$ |
260,003 |
|
|
$ |
124,782 |
|
|
$ |
67,730 |
|
|
$ |
57,052 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services. Revenues for the year ended December 31, 2007 for our Oilfield Services
segment were $234.0 million, an increase of 23.2% from the $190.0 million in revenues for the year
ended December 31, 2006. The increase in revenues is due to the purchase of additional MWD tools,
new compressors and new foam units for our underbalanced drilling operations and the benefit of
acquisitions completed in the last half of 2007 which added downhole motors, MWDs, and directional
drillers and the acquisition of Petro-Rentals completed in the last half of 2006. The additional
equipment and personnel enabled us to strengthen our presence in new geographic markets and
increase our market penetration. The impact of the acquisitions of Diggar and Coker completed in
the last half of 2007 and of the additional MWD tools are not easily identifiable as they were
quickly integrated with our pre-existing operations. The acquisition of Diamondback provided $3.1
million of revenues from the date of acquisition to December 31, 2007. Income from operations
increased 23.3% to $53.2 million for 2007 from $43.2 million for 2006. Income from operations as a
percentage of revenues remained constant at 22.7%. Income from operations includes a $8.9 million
gain on sale of our capillary tubing assets. We believe the gain in revenues is sustainable
assuming a stable rig count, continued strength in demand for directional and horizontal drilling
services, a favorable oil and natural gas price environment in the U.S. and the absence of
significant weather disruptions in the U.S. and in Mexico. We expect operating income to be lower
in 2008 if revenues do not increase as the operating income for the year ended December 31, 2007
was favorably impacted from the gain on sale of the capillary tubing assets in June 2007. Future
growth will be dependent on our ability to penetrate the new land drilling markets and our future
investment in capital equipment.
Drilling and Completion. On August 14, 2006, we acquired DLS which established our Drilling
and Completion segment. Our Drilling and Completion revenues were $215.8 million for the year
ended December 31, 2007, an increase from the $69.5 million in revenues for the period from the
date of the DLS acquisition until December 31, 2006. Income from operations increased to $38.8
million in 2007 compared to $12.2 million from the date of the DLS acquisition until December 31,
2006. Income from operations as percentage of revenue increased to 18.0% for 2007 compared to
17.6% for 2006. We believe the increase in the percentage was primarily due to the price increases
implemented in 2007. During 2007 we placed orders for 16 service rigs (workover rigs and pulling
rigs) and four drilling rigs. Four of the service rigs were delivered in the fourth quarter of
2007. We expect all the rigs to be placed in service during the first three quarters of 2008. We
believe these levels in revenues and operating income are sustainable assuming a stable rig count
and a favorable oil and natural gas price environment in Argentina, labor-related disruptions
affecting the oil and natural gas industry in Argentina and resulting cost increases can affect our
revenues and operating margins until we are able to increase rig rates to offset such costs. We
expect to benefit from the activation of the new rigs as they are delivered throughout 2008.
15
Rental Services. Our Rental Services revenues were $121.2 million for the year ended December
31, 2007, an increase of 135.2% from the $51.5 million in revenues for the year ended December 31,
2006. Income from operations increased 86.9% to $49.1 million in 2007 compared to $26.3 million in
2006. The increase in revenue and operating income is primarily attributable to the acquisition of
the OGR assets in December 2006. The OGR assets, including its two rental yards, expanded our
assets available for rent. We generated $82.2 million for the twelve months ended December 31,
2007 compared to $2.1 million for the period from the date of acquisition of the OGR assets to
December 31, 2006. Income from operations as a percentage of revenues decreased to 40.5% for 2007
compared to 51.0% for the prior year as a result of higher depreciation expense associated with the
OGR acquisition and capital expenditures. Our depreciation expense for the OGR assets increased
$15.9 million to $16.6 million for the year ended December 31, 2007 compared to $650,000 for the
period from the date of acquisition of the OGR assets to December 31, 2006. Rental Services
revenues and operating income was impacted by a more competitive market environment due to the
decreased U.S. Gulf of Mexico drilling activity in the last half of 2007 attributed to the
hurricane season and the departure of drilling rigs in favor of the international markets. Future
growth or a continuation of 2007 revenues in our Rental Services segment is contingent upon
achieving success in marketing our rental assets to the U.S. land drilling and international
markets, and improvement in the offshore U.S. Gulf of Mexico activity.
Comparison of Years Ended December 31, 2006 and December 31, 2005
Our revenues for the year ended December 31, 2006 was $311.0 million, an increase of 187.9%
compared to $108.0 million for the year ended December 31, 2005. Revenues increased in all of our
business segments due to the successful integration of acquisitions completed in the third quarter
of 2005 and during 2006, the investment in new equipment, improved pricing for our services, the
addition of operations and sales personnel and the opening of new operations offices. Revenues
increased most significantly due to the acquisition of DLS on August 14, 2006 which expanded our
operations to a new operating segment, Drilling and Completion. Revenues also increased
significantly at our Rental Services segment due to the acquisition of Specialty effective January
1, 2006. Our Oilfield Services segment also had a substantial increase in revenue, primarily due
to the acquisitions of the casing and tubing assets of Patterson Services, Inc. on September 1,
2005, and the acquisition of Rogers as of April 1, 2006, along with the investment in additional
equipment, improved market conditions and increased market penetration for our services in South
Texas, East Texas, Louisiana and the U.S. Gulf of Mexico. Revenues also increased at our Oilfield
Services segment due to the August 2005 acquisition of Target which provides MWD tools and the
purchase of additional down-hole motors and MWDs which increased our capacity and market presence.
The impact of the acquisitions of DLS, Rogers and Target, including the additional MWDs was to
increase consolidated revenues by $69.5 million, $10.8 million and $7.6 million, respectively. The
impact of the acquisitions of Specialty and the casing and tubing assets of Patterson Services,
Inc. are not easily identifiable as they were quickly integrated with our pre-existing operations,
but our Rental Services revenues improved to $51.5 million for the year ended December 31, 2006
compared to $5.1million for the year ended December 31, 2005 and revenues for our tubular service
product line increased to $50.9 million compared to $20.9 million for the same period.
Our gross margin for the year ended December 31, 2006 increased 243.8% to $105.1 million, or
33.8% of revenues, compared to $30.6 million, or 28.3%, of revenues for the year ended December 31,
2005. The increase in gross profit is due to the increase in revenues in all of our business
segments. The increase in gross profit as a percentage of revenues is primarily due to the
acquisition of Specialty as of January 1, 2006, in the high margin Rental Services business, the
improved pricing for our services generally and the investments in new capital equipment. Also
contributing to our improved gross profit margin was the acquisition of Target, the purchase of
additional MWDs and the acquisition of Rogers. The increase in gross profit was partially offset
by an increase in depreciation expense of 315.7% to $20.3 million compared to $4.9 million for
2005. The increase is due to additional depreciable assets resulting from acquisitions and capital
expenditures. The acquisitions of DLS, Petro-Rentals, Rogers and Target, including additional MWDs
increased depreciation expense by $4.1 million, $688,000, $530,000 and $439,000, respectively.
While we cannot specifically identify the impact that the Specialty acquisition had on our gross
margin due to the reason described in the preceding paragraph, the gross margin on our total Rental
Services segment increased $28.9 million to $32.1 million for the year ended December 31, 2006 from
$3.2 million for the year ended December 31, 2005 after the impact of an increase in depreciation
expense of $6.7 million to $7.1 million for 2006 from $385,000 for 2005. The gross margin provided
from the acquisitions of Rogers and Target, including additional MWDs was $4.7 million and $3.3
million, respectively. Our cost of revenues consists principally of our labor costs and benefits,
equipment rentals, maintenance and repairs of our equipment, depreciation, insurance and fuel.
Because many of our costs are fixed, our gross profit as a percentage of revenues is generally
affected by our level of revenues.
16
General and administrative expense was $35.5 million for the year ended December 31, 2006
compared to $15.6 million for the year ended December 31, 2005. General and administrative expense
increased due to additional expenses associated with the acquisitions, and the hiring of additional
sales, operations and administrative personnel. General and administrative expense also increased
because of increased accounting and consulting fees and other expenses in connection with
initiatives to strengthen our internal control processes, costs related to Sarbanes Oxley
compliance efforts and increased corporate accounting and administrative staff. As a percentage of
revenues, general and administrative expenses were 11.4% in 2006 compared to 14.4% in 2005.
We adopted SFAS No. 123R, Share-Based Payment, effective January 1, 2006. This statement
requires all share-based payments to employees, including grants of employee stock options, to be
recognized in the financial statements based on their grant-date fair values. We adopted SFAS No.
123R using the modified prospective transition method, utilizing the Black-Scholes option pricing
model for the calculation of the fair value of our employee stock options. Under the modified
prospective method, we record compensation cost related to unvested stock awards as of December 31,
2005 by recognizing the unamortized grant date fair value of these awards over the remaining
vesting periods of those awards with no change in historical reported earnings. Therefore, we
recorded an expense of $3.4 million related to stock awards for the year ended December 31, 2006 of
which $3.0 million was recorded in general and administrative expense with the balance being
recorded as a direct cost. Prior to January 1, 2006, we accounted for our stock-based compensation
using Accounting Principle Board Opinion No. 25, or APB No. 25. Under APB No. 25, compensation
expense is recognized for stock options with an exercise price that is less than the market price
on the grant date of the option. Accordingly, no compensation cost was recognized under APB No.
25.
Amortization expense was $1.9 million for the year ended December 31, 2006 compared to $1.5
million for the year ended December 31, 2005. The increase in amortization expense is due to the
amortization of intangible assets in connection with our acquisitions. The 2006 acquisitions of
Rogers, the OGR assets, Petro and DLS resulted in amortization expense of $166,000. $96,000,
$63,000 and $11,000, respectively.
Income from operations for the year ended December 31, 2006 totaled $67.7 million, a 401.0%
increase over the $13.5 million in income from operations for the year ended December 31, 2005,
reflecting the increase in our revenues of $202.9 million and the resulting increase in our gross
profit of $74.5 million, offset in part by increased general and administrative expenses of $20.0
million. Our income from operations as a percentage of revenues increased to 21.8% in 2006 from
12.5% in 2005 due to the increase in our gross margin which offset the increases in amortization
expense and general and administrative expenses.
Our net interest expense was $20.3 million for the year ended December 31, 2006, compared to
$4.7 million for the year ended December 31, 2005. Interest expense increased in 2006 due to our
increased debt. In January of 2006 we issued $160.0 million of senior notes bearing interest at
9.0% to fund the acquisition of Specialty, pay off other outstanding debt and for working capital.
In August 2006 we issued an additional $95.0 million of senior notes bearing interest at 9.0% to
fund a portion of the acquisition of DLS. On December 18, 2006, we borrowed $300.0 million in a
senior unsecured bridge loan to fund the acquisition of OGR. The average interest rate on the
bridge loan was approximately 10.6%. Interest expense for 2006 includes the write-off of $453,000
related to financing fees on the bridge loan. This bridge loan was repaid on January 29, 2007 and
the remaining $1.2 million of financing fees were written off in 2007. In the third quarter of
2005, we incurred debt retirement expense of $1.1 million related to the refinancing of our debt.
This amount includes prepayment penalties and the write-off of deferred financing fees from a
previous financing.
Minority interest in income of subsidiaries for the year ended December 31, 2006 was $0
compared to $488,000 for the corresponding period in 2005 due to the our acquisition of the
minority interest at AirComp on July 11, 2005.
Our provision for income taxes for the year ended December 31, 2006 was $11.4 million, or
24.3% of our net income before income taxes, compared to $1.3 million, or 15.8% of our net income
before income taxes for 2005. The increase in our provision for income taxes is attributable to
the significant increase in our operating income which resulted in the utilization of our deferred
tax assets including our net operating losses, and the increase in percentage of income taxes to
net income before income taxes attributable to our operations in Argentina which are taxed at
35.0%.
We had net income attributed to common stockholders of $35.6 million for the year ended
December 31, 2006, an increase of 396.5%, compared to net income attributed to common stockholders
of $7.2 million for the year ended December 31, 2005.
17
The following table compares revenues and income from operations for each of our business
segments for the years ended December 31, 2006 and December 31, 2005. Income from operations
consists of our revenues less cost of revenues, general and administrative expenses, and
depreciation and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
Income (Loss) from Operations |
|
|
|
2006 |
|
|
2005 |
|
|
Change |
|
|
2006 |
|
|
2005 |
|
|
Change |
|
|
|
(In thousands) |
|
Oilfield Services |
|
$ |
189,953 |
|
|
$ |
102,963 |
|
|
$ |
86,990 |
|
|
$ |
43,157 |
|
|
$ |
17,896 |
|
|
$ |
25,261 |
|
Drilling & Completion |
|
|
69,490 |
|
|
|
|
|
|
|
69,490 |
|
|
|
12,233 |
|
|
|
|
|
|
|
12,233 |
|
Rental Services |
|
|
51,521 |
|
|
|
5,059 |
|
|
|
46,462 |
|
|
|
26,293 |
|
|
|
1,300 |
|
|
|
24,993 |
|
General Corporate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13,953 |
) |
|
|
(5,678 |
) |
|
|
(8,275 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
310,964 |
|
|
$ |
108,022 |
|
|
$ |
202,942 |
|
|
$ |
67,730 |
|
|
$ |
13,518 |
|
|
$ |
54,212 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services Segment. Revenues for the year ended December 31, 2006 for our Oilfield
Services segment were $190.0 million, an increase of 84.5% from the $103.0 million in revenues for
the year ended December 31, 2005. Income from operations increased 141.2% to $43.2 million for
2006 from $17.9 million for 2005. The improved results for this segment are due to the increase in
drilling activity in the Texas and Gulf Coast areas; improved pricing; the acquisition of Rogers,
Target and Petro-Rentals; the acquisition of the casing and tubing assets of Patterson Services,
Inc.; the acquisition of the air drilling assets of W.T.; and investment in new equipment. The
acquisitions of Rogers and Target and the additional MWDs provided an additional $10.8 million and
$7.6 million of revenues, respectively. The impact of the acquisitions of the casing and tubing
assets of Patterson Services, Inc. and the air drilling assets of W.T. are not easily identifiable
as the assets were quickly integrated into our pre-existing operations. Our increased operating
expenses as a result of the addition of operations and personnel were more than offset by the
growth in revenues and improved pricing for our services
Drilling and Completion Segment. Our international drilling revenues were $69.5 million for
the year ended December 31, 2006, and our income from operations was $12.2 million. This segment
of our operations was created with the acquisition of DLS in August of 2006.
Rental Services Segment. Our rental services revenues were $51.5 million for the year ended
December 31, 2006, an increase from the $5.1 million in revenues for the year ended December 31,
2005. Income from operations increased to $26.3 million in 2006 compared to $1.3 million in 2005.
The increase in revenue and operating income is primarily attributable to the acquisition of
Specialty effective January 1, 2006, improved pricing, improved utilization of our inventory of
rental equipment and to a lesser extent, the acquisition of the OGR assets in December 2006. The
impact of the Specialty acquisition is not easily identifiable as the acquisition was quickly
integrated with our pre-existing operations. The acquisition of the OGR assets provided $2.1
million in revenues in 2006.
Liquidity and Capital Resources
Our on-going capital requirements arise primarily from our need to service our debt, to
acquire and maintain equipment, to fund our working capital requirements and to complete
acquisitions. Our primary sources of liquidity are proceeds from the issuance of debt and equity
securities and cash flows from operations. We had cash and cash equivalents of $43.7 million at
December 31, 2007 compared to $39.7 million at December 31, 2006.
Operating Activities
In the year ended December 31, 2007, we generated $103.5 million in cash from operating
activities. Net income for the year ended December 31, 2007 was $50.4 million. Non-cash additions
to net income totaled $60.6 million in the 2007 period consisting primarily of $55.0 million of
depreciation and amortization, $4.9 million related to the expensing of stock options as required
under SFAS No. 123R, $8.0 million of deferred income tax, $730,000 for a provision for bad debts
and $3.2 million of amortization and write-off of deferred financing fees, partially offset by $2.3
million of gain from the disposition of equipment and a $8.9 million gain from the sale of
capillary assets.
18
During the year ended December 31, 2007, changes in working capital used $7.6 million in cash,
principally due to an increase of $30.8 million in accounts receivable, an increase of $4.5 million
in other assets and an increase in inventories of $5.4 million, offset by a decrease of $8.2
million in other current assets, an increase of $10.7 million in accounts payable, an increase of
$6.0 million in accrued interest, an increase of $4.0 million in accrued employee benefits and
payroll taxes, an increase of $1.5 million in accrued expenses and an increase in other long-term
liabilities of $2.7 million. Our accounts receivables increased at December 31, 2007 primarily due
to the increase in our revenues in 2007. Other assets increase primarily due to the contract costs
related to the deployment of new rigs for our Drilling and Completion segment. The decrease in
other current assets is principally due to the collection of the working capital adjustment from
the OGR acquisition for approximately $7.1 million in the first quarter of 2007. Accrued interest
increased at December 31, 2007 due principally to interest accrued on our 8.5% senior notes issued
in January 2007 and our 9.0% senior notes issued in August 2006 which are both payable
semi-annually. Our accounts payable, accrued employee benefits and payroll taxes and other accrued
expenses increased primarily due to the increase in costs due to our growth in revenues and
acquisition completed in 2007. Other long-term liabilities increased primarily due to the deferral
of contract revenue related to our new rigs being constructed in the International drilling
segment.
In the year ended December 31, 2006, we generated $53.7 million in cash from operating
activities. Net income for the year ended December 31, 2006 was $35.6 million. Non-cash additions
to net income totaled $27.6 million in the 2006 period consisting primarily of $22.1 million of
depreciation and amortization, $3.4 million related to the expensing of stock options as required
under SFAS No. 123R, $2.2 million of deferred income tax, $781,000 for a provision for bad debts
and $1.5 million for amortization of finance fees, including the bridge loan fees, partially offset
by $2.4 million of gain from the disposition of equipment.
During the year ended December 31, 2006, changes in working capital used $9.9 million in cash,
principally due to an increase of $23.2 million in accounts receivable, an increase of $2.6 million
in inventories, a decrease of $2.3 million in accounts payable, offset in part by a decrease in
other current assets of $2.5 million, an increase of $11.4 million in accrued interest, an increase
of $3.4 million in accrued employee benefits and payroll taxes and an increase of $872,000 in
accrued expenses. Our accounts receivables increased at December 31, 2006 primarily due to the
increase in our revenues in 2006. Accrued interest increased at December 31, 2006 due principally
to interest accrued on our 9.0% senior notes, which are payable semi-annually. Our accrued
employee benefits and payroll taxes and other accrued expenses increased primarily due to the
increase in costs due to our growth in revenues and acquisition completed in 2006.
In the year ended December 31, 2005, we generated $3.6 million in cash from operating
activities. Net income for the year ended December 31, 2005 was $7.2 million. Non-cash additions
to net income totaled $7.4 million in the 2005 period consisting primarily of $6.4 million of
depreciation and amortization, $488,000 of minority interest in the income of a subsidiary,
$962,000 in amortization and write-off of financing fees in conjunction with a refinancing and
$219,000 for a provision for bad debts, partially offset by $669,000 of gain from the disposition
of equipment.
During the year ended December 31, 2005, changes in working capital used $11.0 million in
cash, principally due to an increase of $10.7 million in accounts receivable, an increase of $3.1
million in inventories, an increase in other assets of $936,000, a decrease in other liabilities of
$266,000 and a decrease of $97,000 in accrued expenses, offset in part by a decrease in other
current assets of $929,000, an increase of $2.4 million in accounts payable, an increase of
$324,000 in accrued interest and a increase of $443,000 in accrued employee benefits and payroll
taxes. Our accounts receivables increased at December 31, 2005 due primarily to the increase in
our revenues in 2005. Accounts payable increased by $2.4 million at December 31, 2005 due to the
increase in our cost of sales associated with the increase in our revenues and the acquisitions
completed in 2005 and 2004.
Investing Activities
During the year ended December 31, 2007, we used $137.1 million in investing activities
consisting of four acquisitions and our capital expenditures. During the year ended December 31,
2007, we completed the following acquisitions for a total net cash outlay of $41.0 million,
consisting of the purchase price and acquisition costs less cash acquired:
|
|
|
In June 2007, we acquired Coker for a purchase price of approximately $3.6 million in
cash and a promissory note for $350,000. |
|
|
|
|
In July 2007, we acquired Diggar for a purchase price of approximately $6.7 million in
cash, the payment of approximately $2.8 million of debt and a promissory note for $750,000. |
19
|
|
|
In October 2007, we acquired Rebel for a purchase price of approximately $5.0 million in
cash, the payment of approximately $1.8 million of debt and escrow, and promissory notes for
an aggregate of $500,000. |
|
|
|
In November 2007, we acquired substantially all of the assets of Diamondback for a
purchase price of approximately $23.1 million in cash. |
In addition we made capital expenditures of approximately $113.2 million during the year ended
December 31, 2007, including $48.6 million to purchase and upgrade our equipment for our Oilfield
Services segment, $34.9 million to increase our inventory of equipment and replace lost-in-hole
equipment in the Rental Services segment and $28.9 million to purchase, improve and replace
equipment in our Drilling and Completion segment. We received proceeds of $16.3 million from the
sale of our capillary assets. We also received $12.8 million from the sale of assets during the
year ended December 31, 2007, comprised mostly from equipment lost-in-hole from our Rental
Services segment ($11.0 million) and our Oilfield Services segment ($1.4 million). We also made
advance payments of $11.5 million on the purchase of new drilling and service rigs to be delivered
in 2008 for our Drilling and Completion segment.
During the year ended December 31, 2006, we used $559.4 million in investing activities
consisting of six acquisitions and our capital expenditures. During the year ended December 31,
2006, we completed the following acquisitions for a total net cash outlay of $526.6 million,
consisting of the purchase price and acquisition costs less cash acquired:
|
|
|
Effective January 1, 2006, we acquired Specialty for a purchase price of approximately
$95.3 million in cash. |
|
|
|
Effective April 1, 2006, we acquired Rogers for a purchase price of approximately $11.3
million in cash, 125,285 shares of our common stock and a promissory note for $750,000. |
|
|
|
On August 14, 2006, we acquired DLS for a purchase price of approximately $93.7 million
in cash, 2.5 million shares of our common stock and the assumption of $9.1 million of
indebtedness. |
|
|
|
On October 16, 2006, we acquired Petro Rentals for a purchase price of approximately
$20.2 million in cash, 246,761 shares of our common stock and the payment of approximately
$9.6 million of debt. |
|
|
|
Effective December 1, 2006, we acquired Tanus for a purchase price of $2.5 million in
cash. |
|
|
|
On December 18, 2006, we acquired substantially all of the assets of OGR for a purchase
price of approximately $291.0 million in cash and 3.2 million shares of our common stock. |
In addition we made capital expenditures of approximately $39.7 million during the year ended
December 31, 2006, including $29.1 million to purchase and upgrade equipment for our Oilfield
Services segment, $5.8 million to purchase, improve and replace equipment in our Drilling and
Completion segment and $4.5 million to replace lost-in-hole equipment and to increase our
inventory of equipment in the Rental Services segment. We also received $6.9 million from the sale
of assets during the year ended December 31, 2006, comprised mostly from equipment lost-in-hole
from our Rental Services segment ($3.8 million) and our Oilfield Services segment ($1.8 million).
During the year ended December 31, 2005, we used $53.1 million in investing activities.
During the year ended December 31, 2005, we completed the following acquisitions for a total net
cash outlay of $36.9 million, consisting of the purchase price and acquisition costs less cash
acquired:
|
|
|
On April 1, 2005 we acquired Delta for a purchase price of approximately $4.6 million in
cash, 223,114 shares of our common stock and two promissory notes totaling $350,000. |
|
|
|
On May 1, 2005, we acquired Capcoil for a purchase price of approximately $2.7 million in
cash, 168,161 shares of our common stock and the payment or assumption of approximately $1.3
million of debt. |
|
|
|
On July 11, 2005, we acquired the compressed air drilling assets of W.T. for a purchase
price of $6.0 million in cash. |
20
|
|
|
On July 11, 2005, we acquired from M-I its 45% interest in AirComp and subordinated note
in the principal amount of $4.8 million issued by AirComp, for which we paid M-I $7.1
million in cash and reissued a $4.0 million subordinated note. |
|
|
|
Effective August 1, 2005, we acquired Target for a purchase price of approximately $1.3
million in cash and forgiveness of a lease receivable of $592,000. |
|
|
|
On September 1, 2005, we acquired the casing and tubing service assets of Patterson
Services, Inc. for a purchase price of approximately $15.6 million. |
In addition we made capital expenditures of approximately $17.8 million during the year ended
December 31, 2005, all of which was spent to improve and expand our Oilfield Services segment. We
also received $1.6 million from the sale of assets during the year ended December 31, 2005,
comprised mostly from equipment lost in the hole from our Oilfield Services segment ($1.0 million)
and our Rental Services segment ($408,000).
Financing Activities
During the year ended December 31, 2007, financing activities provided a net of $37.6 million
in cash. We received $250.0 million in borrowings from the issuance of our 8.5% senior notes due
2017. We also received $100.1 million in net proceeds from the issuance of 6,000,000 shares of our
common stock, $1.7 million on the tax benefit of stock compensation plans and $3.3 million from the
proceeds of warrant and option exercises for 882,624 shares of our common stock. The proceeds were
used to repay long-term debt totaling $309.7 million and to pay $7.8 million in debt issuance
costs. The repayment of long-term debt consisted primarily of the repayment of our $300.0 million
bridge loan which was used to fund the acquisition of the OGR assets.
During the year ended December 31, 2006, financing activities provided a net of $543.6 million
in cash. We received $557.8 million in borrowings under long-term debt facilities, consisting
primarily of the issuance of $255.0 million of our 9.0% senior notes due 2014 and a $300.0 million
senior unsecured bridge loan. The bridge loan, which was repaid on January 29, 2007, was used to
fund the acquisition of the OGR assets. We also received $46.3 million in net proceeds from the
issuance of 3,450,000 shares of our common stock, $6.4 million on the tax benefit of options and
$6.3 million from the proceeds of warrant and option exercises for 1,851,377 shares of our common
stock. The proceeds were used to repay long-term debt totaling $54.0 million, repay $6.4 million
in net borrowings under our revolving lines of credit, repay related party debt of $3.0 million and
to pay $9.9 million in debt issuance costs.
During the year ended December 31, 2005, financing activities provided a net of $44.1 million
in cash. We received $56.3 million in borrowings under long-term debt facilities, $15.5 million in
net proceeds from the issuance of 1,761,034 shares of our common stock, $2.5 million in net
borrowings under our revolving lines of credit and $1.4 million from the proceeds of warrant and
option exercises for 1,076,154 shares of our common stock. The proceeds were used to repay
long-term debt totaling $28.2 million, repay related party debt of $1.5 million and to pay $1.8
million in debt issuance costs.
On January 18, 2006 and August 14, 2006, we closed on private offerings, to qualified
institutional buyers pursuant to Rule 144A under the Securities Act, of $160.0 million and $95.0
million aggregate principal amount of our senior notes, respectively. The senior notes are due
January 15, 2014 and bear interest at 9.0%. The proceeds were used to fund the acquisitions of
Specialty and DLS, to repay existing debt and for general corporate purposes. Debt repaid included
all outstanding balances under our credit agreement, including a $42.1 million term loan and $6.4
million in working capital advances, a $4.0 million subordinated note issued in connection with
acquisition of AirComp, approximately $3.0 million subordinated note issued in connection with the
acquisition of Tubular, approximately $548,000 on a real estate loan and approximately $350,000 on
outstanding equipment financing.
On December 18, 2006, we closed on a $300.0 million senior unsecured bridge loan. The bridge
loan was due 18 months after closing and had a weighted average interest rate of 10.6%. The bridge
loan, which was repaid on January 29, 2007, was used to fund the acquisition of OGR.
In January 2007, we closed on a private offering, to qualified institutional buyers pursuant
to Rule 144A under the Securities Act, of $250.0 million principal amount of 8.5% senior notes due
2017. The proceeds of the senior notes offering, together with a portion of the proceeds of our
concurrent common stock offering, were used to repay the debt outstanding under our $300.0 million
bridge loan facility which we incurred to finance our acquisition of substantially all the assets
of OGR.
21
On January 18, 2006, we also executed an amended and restated credit agreement which provides
for a $25.0 million revolving line of credit with a maturity of January 2010. This agreement
contains customary events of default and financial covenants and limits our ability to incur
additional indebtedness, make capital expenditures, pay dividends or make other distributions,
create liens and sell assets. Our obligations under the agreement are secured by substantially all
of our assets excluding the DLS assets, but including 2/3 of our shares of DLS. On April 26, 2007,
we entered into a Second Amended and Restated Credit Agreement, which increased our revolving line
of credit to $62.0 million, and has a final maturity date of April 26, 2012. On December 3, 2007,
we entered into a First Amendment to Second Amended and Restated Credit Agreement, which increased
our revolving line of credit to $90.0 million. The amended and restated credit agreement contains
customary events of default and financial covenants and limits our ability to incur additional
indebtedness, make capital expenditures, pay dividends or make other distributions, create liens
and sell assets. Our obligations under the amended and restated credit agreement are secured by
substantially all of our assets located in the United States. At December 31, 2007 and 2006, no
amounts were borrowed on the facility but availability is reduced by outstanding letters of credit
of $8.4 million and $9.7 million, respectively.
As part of our acquisition of DLS, we assumed various bank loans with floating interest rates
based on LIBOR plus a margin and terms ranging from 2 to 5 years. The weighted average interest
rates on these loans was 6.7% and 7.0% at December 31, 2007 and 2006, respectively. The bank loans
are denominated in U.S. dollars and the outstanding amount due as of December 31, 2007 and 2006 was
$4.9 million and $7.3 million, respectively.
As part of the acquisition of MCA in 2001, we issued a note to the sellers of MCA in the
original amount of $2.2 million accruing interest at a rate of 5.75% per annum. The note was
reduced to $1.5 million as a result of the settlement of a legal action against the sellers in
2003. In March 2005, we reached an agreement with the sellers and holders of the note as a result
of an action brought against us by the sellers. Under the terms of the agreement, we paid the
holders of the note $1.0 million in cash, and agreed to pay an additional $350,000 on June 1, 2006,
and an additional $150,000 on June 1, 2007, in settlement of all claims. At December 31, 2007 and
2006 the outstanding amounts due were $0 and $150,000, respectively.
In connection with the purchase of Delta, we issued to the sellers a note in the amount of
$350,000. The note bore interest at 2% and the principal and accrued interest was repaid on its
maturity of April 1, 2006. In connection with the acquisition of Rogers, we issued to the seller a
note in the amount of $750,000. The note bears interest at 5.0% and is due April 3, 2009. In
connection with the purchase of Coker, we issued to the seller a note in the amount of $350,000.
The note bears interest at 8.25% and is due June 29, 2008. In connection with the purchase of
Diggar, we issued to the seller a note in the amount of $750,000. The note bears interest at 6.0%
and is due July 26, 2008. In connection with the purchase of Rebel, we issued to the sellers notes
in the amount of $500,000. The notes bear interest at 5.0% and are due October 23, 2008.
In connection with the purchase of Tubular, we agreed to pay a total of $1.2 million to the
seller in exchange for a non-compete agreement. Monthly payments of $20,576 were due under this
agreement through January 31, 2007. In connection with the purchase of Safco-Oil Field Products,
Inc., or Safco, we also agreed to pay a total of $150,000 to the sellers in exchange for a
non-compete agreement. We were required to make annual payments of $50,000 through September 30,
2007. In connection with the purchase of Capcoil, we agreed to pay a total of $500,000 to two
management employees in exchange for non-compete agreements. We are required to make annual
payments of $110,000 through May 2008. Total amounts due under these non-compete agreements at
December 31, 2007 and 2006 were $110,000 and $270,000, respectively.
In 2000 we compensated directors, including current directors Nederlander and Toboroff, who
served on the board of directors from 1989 to March 31, 1999 without compensation, by issuing
promissory notes totaling $325,000. The notes bear interest at the rate of 5.0%. At December 31,
2007 and 2006, the principal and accrued interest on these notes totaled approximately $32,000.
We have various rig and equipment financing loans with interest rates ranging from 7.8% to
8.7% and terms of 2 to 5 years. As of December 31, 2007 and 2006, the outstanding balances for rig
and equipment financing loans were $595,000 and $3.5 million, respectively. In January 2006, we
prepaid $350,000 of the outstanding equipment loans with proceeds from our senior notes offering.
In April 2006 and August 2006, we obtained insurance premium financings in the amount of $1.9
million and $896,000 with fixed interest rates of 5.6% and 6.0%, respectively. Under terms of the
agreements, amounts outstanding are paid over 10 month and 11 month repayment schedules. The
outstanding balance of these notes was approximately $1.0 million as of December 31, 2006. In
April 2007 and August 2007, we obtained insurance premium financings in the amount of $3.2 million
and $1.3 with fixed interest rates of 5.9% and 5.7%, respectively. Under terms of the agreements,
amounts outstanding are paid over 11 month repayment schedules. The outstanding balance of these
notes was approximately $1.7 million as of December 31, 2007.
22
We also have various capital leases with terms that expire in 2008. As of December 31, 2007
and 2006, amounts outstanding under capital leases were $14,000 and $414,000, respectively.
The following table summarizes our obligations and commitments to make future payments under
our notes payable, operating leases, employment contracts and consulting agreements for the periods
specified as of December 31, 2007.
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Payments by Period |
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Less Than |
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Total |
|
|
1 Year |
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|
1-3 Years |
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|
3-5 Years |
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|
After 5 Years |
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|
|
(In thousands) |
|
Contractual Obligations |
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|
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|
|
|
|
|
|
Long-term debt |
|
$ |
514,720 |
|
|
$ |
6,420 |
|
|
$ |
2,950 |
|
|
$ |
350 |
|
|
$ |
505,000 |
|
Capital leases |
|
|
14 |
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest payments on long-term debt |
|
|
334,018 |
|
|
|
44,588 |
|
|
|
88,577 |
|
|
|
88,406 |
|
|
|
112,447 |
|
Operating leases |
|
|
5,941 |
|
|
|
2,618 |
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|
|
2,354 |
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|
|
593 |
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|
|
376 |
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Employment contracts |
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|
7,511 |
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|
|
3,543 |
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|
|
3,968 |
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Total contractual cash obligations. |
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$ |
862,204 |
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|
$ |
57,183 |
|
|
$ |
97,849 |
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|
$ |
89,349 |
|
|
$ |
617,823 |
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|
|
|
|
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|
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|
We have identified capital expenditure projects that will require up to approximately $140.0
million in 2008, exclusive of any acquisitions, of which $82.7 million is committed as of December
31, 2007. We believe that our cash generated from operations, cash on hand and cash available
under our credit facilities will provide sufficient funds for our identified projects.
We intend to implement a growth strategy of increasing the scope of services through both
internal growth and acquisitions. We are regularly involved in discussions with a number of
potential acquisition candidates. We expect to make capital expenditures to acquire and to
maintain our existing equipment. Our performance and cash flow from operations will be determined
by the demand for our services which in turn are affected by our customers expenditures for oil
and natural gas exploration and development and industry perceptions and expectations of future oil
and natural gas prices in the areas where we operate. We will need to refinance our existing debt
facilities as they become due and provide funds for capital expenditures and acquisitions. To
effect our expansion plans, we will require additional equity or debt financing in excess of our
current working capital and amounts available under credit facilities. There can be no assurance
that we will be successful in raising the additional debt or equity capital or that we can do so on
terms that will be acceptable to us.
Recent Developments
On January 23, 2008, we entered into an Agreement and Plan of Merger with Bronco Drilling
Company, Inc., or Bronco, whereby Bronco will become a wholly-owned subsidiary of Allis-Chalmers.
The merger agreement, which was approved by our Board of Directors and the Board of Directors of
Bronco, provides that the Bronco stockholders will receive aggregate merger consideration with a
value of approximately $437.8 million, consisting of (a) $280.0 million in cash and (b) shares of
our common stock, par value $0.01 per share, having an aggregate value of approximately $157.8
million. The number of shares of our common stock to be issued will be based on the average
closing price of our common stock for the ten-trading day period ending two days prior to the
closing. Completion of the merger is conditioned upon, among other things, adoption of the merger
agreement by Broncos stockholders and approval by our stockholders of the issuance of shares of
our common stock to be used as merger consideration.
In order to finance some or all of the cash component of the merger consideration, the
repayment of outstanding Bronco debt and transaction expenses, we expect to incur debt of up to
$350.0 million. We intend to obtain up to $350.0 million from either (1) a permanent debt
financing of up to $350.0 million or (2) if the permanent debt financing cannot be consummated
prior to the closing date of the merger, the draw down under a senior unsecured bridge loan
facility in an aggregate principal amount of up to $350.0 million to be arranged by RBC Capital
Markets Corporation and Goldman Sachs Credit Partners L.P., acting as joint lead arrangers and
joint bookrunners. We executed a commitment letter, dated January 28, 2008, with Royal Bank of
Canada and Goldman Sachs who have each, subject to certain conditions, severally committed to
provide 50% of the loans under the senior unsecured bridge facility to us. This commitment for the
bridge loan facility will terminate on July 31, 2008, if we have not drawn the bridge facility by
such date and the merger is not consummated by such date. The commitment may also terminate prior
to July 31, 2008, if the merger is abandoned or a material condition to the merger is not satisfied
or we breach our obligations under the commitment letter. We may use the proceeds of the bridge
facility to finance the cash component of the merger consideration, repay outstanding Bronco debt
and pay transaction expenses.
23
On January 29, 2008, Burt A. Adams resigned as our President and Chief Operating Officer,
effective February 28, 2008. Mr. Adams will remain as a member of our Board of Directors. On
January 29, 2008, Mark C. Patterson was elected our Senior Vice-President Rental Services. On
January 29, 2008, Terrence P. Keane was elected our Senior Vice-President Oilfield Services.
On January 31, 2008, we entered into an agreement with BCH Ltd., or BCH, to invest $40.0
million in cash in BCH in the form of a 15% Convertible Subordinated Secured debenture. The
debenture is convertible, at any time, at our option into 49% of the common equity of BCH. At the
end of two years, we have the option to acquire the remaining 51% of BCH from its parent, BrazAlta
Resources Corp., or BrazAlta, based on an independent valuation from a mutually acceptable
investment bank. BCH is a Canadian-based oilfield services company engaged in contract drilling
operations exclusively in Brazil.
On February 15, 2008, through our DLS subsidiary in Argentina, we entered into a $25.0 million
import finance facility with a bank. Borrowings under this facility will be used to fund a portion
of the purchase price of the new drilling and service rigs ordered for our Drilling and Completion
segment. The facility is available for borrowings until December 31, 2008. Each drawdown shall be
repaid over four years in equal semi-annual instalments beginning one year after each disbursement
with the final principal payment due not later than March 15, 2013. Interest is payable every six
months. The import finance facility is unsecured and contains customary events of default and
financial covenants and limits DLS ability to incur additional indebtedness, make capital
expenditures, create liens and sell assets.
Critical Accounting Policies
We have identified the policies below as critical to our business operations and the
understanding of our results of operations. The impact and any associated risks related to these
policies on our business operations is discussed throughout Managements Discussion and Analysis of
Financial Condition and Results of Operations where such policies affect our reported and expected
financial results. For a detailed discussion on the application of these and other accounting
policies, see Note 1 in the Notes to the Consolidated Financial Statements included elsewhere in
this document. Our preparation of this report requires us to make estimates and assumptions that
affect the reported amount of assets and liabilities, disclosure of contingent assets and
liabilities at the date of our financial statements, and the reported amounts of revenue and
expenses during the reporting period. There can be no assurance that actual results will not
differ from those estimates.
Allowance For Doubtful Accounts. The determination of the collectibility of amounts due from
our customers requires us to use estimates and make judgments regarding future events and trends,
including monitoring our customer payment history and current credit worthiness to determine that
collectibility is reasonably assured, as well as consideration of the overall business climate in
which our customers operate. Those uncertainties require us to make frequent judgments and
estimates regarding our customers ability to pay amounts due us in order to determine the
appropriate amount of valuation allowances required for doubtful accounts. Provisions for doubtful
accounts are recorded when it becomes evident that the customers will not be able to make the
required payments at either contractual due dates or in the future.
Revenue Recognition. We provide rental equipment and drilling services to our customers at
per day, or daywork, and per job contractual rates and recognize the drilling related revenue as
the work progresses and when collectibility is reasonably assured. Revenue from daywork contracts
is recognized when it is realized or realizable and earned. On daywork contracts, revenue is
recognized based on the number of days completed at fixed rates stipulated by the contract. For
certain contracts, we receive lump-sum and other fees for equipment and other mobilization costs.
Mobilization fees and the related costs are deferred and amortized over the contract terms when
material. The Securities and Exchange Commissions Staff Accounting Bulletin No. 104, Revenue
Recognition in Financial Statements, provides guidance on the SEC staffs views on application of
generally accepted accounting principles to selected revenue recognition issues. Our revenue
recognition policy is in accordance with generally accepted accounting principles and SAB No. 104.
Impairment Of Long-Lived Assets. Long-lived assets, which include property, plant and
equipment, goodwill and other intangibles, comprise a significant amount of our total assets. We
make judgments and estimates in conjunction with the carrying value of these assets, including
amounts to be capitalized, depreciation and amortization methods and useful lives. Additionally,
the carrying values of these assets are reviewed for impairment or whenever events or changes in
circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is
recorded in the period in which it is determined that the carrying amount is not recoverable. This
requires us to make long-term forecasts of our future revenues and costs related to the assets
subject to review. These forecasts require assumptions about demand for our products and services,
future market conditions and technological developments. Significant and unanticipated changes to
these assumptions could require a provision for impairment in a future period.
24
Goodwill And Other Intangibles. As of December 31, 2007, we have recorded approximately
$138.4 million of goodwill and $35.2 million of other identifiable intangible assets. We perform
purchase price allocations to intangible assets when we make a business combination. Business
combinations and purchase price allocations have been consummated for acquisitions in all of our
reportable segments. The excess of the purchase price after allocation of fair values to tangible
assets is allocated to identifiable intangibles and thereafter to goodwill. Subsequently, we
perform our initial impairment tests and annual impairment tests in accordance with Financial
Accounting Standards Board No. 141, Business Combinations, and Financial Accounting Standards Board
No. 142, Goodwill and Other Intangible Assets. These initial valuations used two approaches to
determine the carrying amount of the individual reporting units. The first approach is the
Discounted Cash Flow Method, which focuses on our expected cash flow. In applying this approach,
the cash flow available for distribution is projected for a finite period of years. Cash flow
available for distribution is defined as the amount of cash that could be distributed as a dividend
without impairing our future profitability or operations. The cash flow available for distribution
and the terminal value (our value at the end of the estimation period) are then discounted to
present value to derive an indication of value of the business enterprise. This valuation method
is dependent upon the assumptions made regarding future cash flow and cash requirements. The
second approach is the Guideline Company Method which focuses on comparing us to selected
reasonably similar publicly traded companies. Under this method, valuation multiples are: (i)
derived from operating data of selected similar companies; (ii) evaluated and adjusted based on our
strengths and weaknesses relative to the selected guideline companies; and (iii) applied to our
operating data to arrive at an indication of value. This valuation method is dependent upon the
assumption that our value can be evaluated by analysis of our earnings and our strengths and
weaknesses relative to the selected similar companies. Significant and unanticipated changes to
these assumptions could require a provision for impairment in a future period.
Income Taxes. The determination and evaluation of our annual income tax provision involves
the interpretation of tax laws in various jurisdictions in which we operate and requires
significant judgment and the use of estimates and assumptions regarding significant future events
such as the amount, timing and character of income, deductions and tax credits. Changes in tax
laws, regulations and our level of operations or profitability in each jurisdiction may impact our
tax liability in any given year. While our annual tax provision is based on the information
available to us at the time, a number of years may elapse before the ultimate tax liabilities in
certain tax jurisdictions are determined. Current income tax expense reflects an estimate of our
income tax liability for the current year, withholding taxes, changes in tax rates and changes in
prior year tax estimates as returns are filed. Deferred tax assets and liabilities are recognized
for the anticipated future tax effects of temporary differences between the financial statement
basis and the tax basis of our assets and liabilities using the enacted tax rates in effect at year
end. A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not
that the benefit from the deferred tax asset will not be realized. We provide for uncertain tax
positions pursuant to FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes an
Interpretation of FASB Statement No. 109.
It is our intention to permanently reinvest all of the undistributed earnings of our non-U.S.
subsidiaries in such subsidiaries. Accordingly, we have not provided for U.S. deferred taxes on
the undistributed earnings of our non-U.S. subsidiaries. If a distribution is made to us from the
undistributed earnings of these subsidiaries, we could be required to record additional taxes.
Because we cannot predict when, if at all, we will make a distribution of these undistributed
earnings, we are unable to make a determination of the amount of unrecognized deferred tax
liability.
Recently Issued Accounting Standards
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157
clarifies the principle that fair value should be based on the assumptions that market participants
would use when pricing an asset or liability and establishes a fair value hierarchy that
prioritizes the information used to develop those assumptions. Under the standard, fair value
measurements would be separately disclosed by level within the fair value hierarchy. SFAS No. 157
is effective for financial statements issued for fiscal years beginning after November 15, 2007,
and interim periods within those fiscal years, with early adoption permitted. Subsequently, the
FASB provided for a one-year deferral of the provisions of Statement No. 157 for non-financial
assets and liabilities that are recognized or disclosed at fair value in the consolidated financial
statements on a non-recurring basis. We believe that the adoption of SFAS No. 157 will not have a
material impact on our financial position, results of operations or cash flows.
25
In December 2007, the FASB issued SFAS No. 141(R), Business Combinations. This statement
retains the fundamental requirements in SFAS No. 141, Business Combinations that the acquisition
method of accounting be used for all business combinations and expands the same method of
accounting to all transactions and other events in which one entity obtains control over one or
more other businesses or assets at the acquisition date and in subsequent periods. This statement
replaces SFAS No. 141 by requiring measurement at the acquisition date of the fair value of assets
acquired, liabilities assumed and any non-controlling interest. Additionally, SFAS No. 141(R)
requires that acquisition-related costs, including restructuring costs, be recognized as expense
separately from the acquisition. SFAS No. 141(R) applies prospectively to business combinations
for fiscal years beginning after December 15, 2008. We will adopt SFAS No. 141(R) beginning
January 1, 2009 and apply to future acquisitions.
In February 2007, the FASB issued Statement No. 159, The Fair Value Option for Financial
Assets and Financial Liabilities, which permits entities to elect to measure many financial
instruments and certain other items at fair value. Upon adoption of SFAS No. 159, an entity may
elect the fair value option for eligible items that exist at the adoption date. Subsequent to the
initial adoption, the election of the fair value option should only be made at the initial
recognition of the asset or liability or upon a re-measurement event that gives rise to the
new-basis of accounting. All subsequent changes in fair value for that instrument are reported in
earnings. SFAS No. 159 does not affect any existing accounting literature that requires certain
assets and liabilities to be recorded at fair value nor does it eliminate disclosure requirements
included in other accounting standards. SFAS No. 159 is effective as of the beginning of each
reporting entitys first fiscal year that begins after November 15, 2007. We are currently
evaluating the provisions of SFAS No. 159 and have not yet determined the impact, if any, on our
financial statements.
In December 2007, the FASB issued SFAS No. 160, Non-controlling Interests in Consolidated
Financial Statements an amendment of ARB No. 51. SFAS No. 160 requires (i) that non-controlling
(minority) interests be reported as a component of shareholders equity, (ii) that net income
attributable to the parent and to the non-controlling interest be separately identified in the
consolidated statement of operations, (iii) that changes in a parents ownership interest while the
parent retains its controlling interest be accounted for as equity transactions, (iv) that any
retained non-controlling equity investment upon the deconsolidation of a subsidiary be initially
measured at fair value, and (v) that sufficient disclosures are provided that clearly identify and
distinguish between the interests of the parent and the interests of the non-controlling owners.
SFAS No. 160 is effective for annual periods beginning after December 15, 2008 and should be
applied prospectively. The presentation and disclosure requirements of the statement shall be
applied retrospectively for all periods presented. We believe the adoption of SFAS No. 160 will
not have a material impact on our financial position or results of operations.
Off-Balance Sheet Arrangements
We have no off balance sheet arrangements, other than normal operating leases and employee
contracts, that have or are likely to have a current or future material effect on our financial
condition, changes in financial condition, revenues, expenses, results of operations, liquidity,
capital expenditures or capital resources. We have a $90.0 million revolving line of credit with a
maturity of January 2010. At December 31, 2007, no amounts were borrowed on the facility but
availability is reduced by outstanding letters of credit of $8.4 million. We do not guarantee
obligations of any unconsolidated entities.
26
ITEM 8. FINANCIAL STATEMENTS.
INDEX TO FINANCIAL STATEMENTS
ALLIS-CHALMERS ENERGY INC. AND SUBSIDIARIES
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Supplemental Information to Consolidated Financial StatementsSummarized Quarterly Financial Data |
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27
MANAGEMENTS REPORT TO THE STOCKHOLDERS OF ALLIS-CHALMERS ENERGY INC.
Managements Report on Internal Control Over Financial Reporting
As management, we are responsible for establishing and maintaining adequate internal control
over financial reporting for Allis-Chalmers Energy Inc. and its subsidiaries, or Allis-Chalmers.
In order to evaluate the effectiveness of internal control over financial reporting, as required by
Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing,
using the criteria in Internal Control-Integral Framework issued by the Committee of Sponsoring
Organization of the Treadway Commission (COSO). Allis-Chalmers system of internal control over
financial reporting is designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance
with accounting principles generally accepted in the United States of America. Because of its
inherent limitation, internal control over financial reporting may not prevent or detect
misstatements.
Based on our assessment, we have concluded that Allis-Chalmers maintained effective internal
control over financial reporting as of December 31, 2007, based on criteria in Internal
Control-Integrated Framework issued by the COSO. The effectiveness of Allis-Chalmers internal
control over financial reporting as of December 31, 2007 has been audited by UHY LLP, an
independent registered public accounting firm, as stated in their report, which is included herein.
Managements Certifications
The certifications of Allis-Chalmers Chief Executive Officer and Chief Financial Officer required
by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Allis-Chalmers Form
10-K.
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ALLIS-CHALMERS ENERGY INC. |
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By:
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/s/ MUNAWAR H. HIDAYATALLAH |
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By:
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/s/ VICTOR M. PEREZ |
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Munawar H. Hidayatallah
Chief Executive Officer
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Victor Perez
Chief Financial Officer
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28
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Allis-Chalmers Energy Inc.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Allis-Chalmers Energy Inc. and
subsidiaries (the Company) as of December 31, 2007 and 2006, and the related consolidated
statements of operations, stockholders equity and cash flows for each of the three years in the
period ended December 31, 2007. These consolidated financial statements are the responsibility of
the Companys management. Our responsibility is to express an opinion on these consolidated
financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audits to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material
respects, the consolidated financial position of Allis-Chalmers Energy Inc. and subsidiaries as of
December 31, 2007 and 2006, and the consolidated results of their operations and their cash flows
for each of the three years in the period ended December 31, 2007, in conformity with accounting
principles generally accepted in the United States of America.
As discussed in Note 6 to the consolidated financial statements, effective January 1, 2007, the
Company adopted FASB Interpretation No. 48. Accounting for Uncertainty in Income Taxes an
Interpretation of FASB Statement No. 109 and, as discussed in Note 1, effective January 1, 2006,
the Company adopted Statement of Financial Accounting Standards
No. 123 (Revised 2004). Share Based
Payment.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), Allis-Chalmers Energy Inc.s internal control over financial reporting as of
December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated
March 6, 2008 expressed an unqualified opinion thereon.
Houston, Texas
March 6,
2008, except for the updated disclosures pertaining to the
Companys change in operating segments occurring in
2008 as described in Notes 1 and 14, as to which the date is June 13, 2008.
29
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and
Stockholders of Allis-Chalmers Energy Inc.:
We have audited Allis-Chalmers Energy Inc.s internal control over financial reporting as of
December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria).
Allis-Chalmers Energy Inc.s management is responsible for maintaining effective internal control
over financial reporting, and for its assessment of the effectiveness of internal control over
financial reporting included in the accompanying Managements Report on Internal Control Over
Financial Reporting. Our responsibility is to express an opinion on the Companys internal control
over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting of
Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk,
and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles. A
companys internal control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and
(3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Allis-Chalmers Energy Inc. and subsidiaries maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2007, based on the COSO
criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated balance sheets of Allis-Chalmers Energy Inc. and
subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of
operations, stockholders equity, and cash flows for each of the three years in the period ended
December 31, 2007, and our report dated March 6, 2008 expressed an unqualified opinion thereon.
Houston, Texas
March 6, 2008
30
ALLIS-CHALMERS ENERGY INC.
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(In thousands, except for share and per share amounts) |
|
ASSETS |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
43,693 |
|
|
$ |
39,745 |
|
Trade receivables, net of allowance for doubtful accounts of $1,924 and
$826 at December 31, 2007 and 2006, respectively |
|
|
130,094 |
|
|
|
95,766 |
|
Inventories |
|
|
32,209 |
|
|
|
28,615 |
|
Prepaid expenses and other |
|
|
11,898 |
|
|
|
16,636 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
217,894 |
|
|
|
180,762 |
|
|
|
|
|
|
|
|
|
|
Property and equipment, at cost net of accumulated depreciation of $77,008
and $29,743 at December 31, 2007 and 2006, respectively |
|
|
626,668 |
|
|
|
554,258 |
|
Goodwill |
|
|
138,398 |
|
|
|
125,835 |
|
Other intangible assets, net of accumulated amortization of $6,218 and
$4,475 at December 31, 2007 and 2006, respectively |
|
|
35,180 |
|
|
|
32,840 |
|
Debt issuance costs, net of accumulated amortization of $2,718 and $1,501
at December 31, 2007 and 2006, respectively |
|
|
14,228 |
|
|
|
9,633 |
|
Other assets |
|
|
21,217 |
|
|
|
4,998 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,053,585 |
|
|
$ |
908,326 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
Current maturities of long-term debt |
|
$ |
6,434 |
|
|
$ |
6,999 |
|
Trade accounts payable |
|
|
37,464 |
|
|
|
25,666 |
|
Accrued salaries, benefits and payroll taxes |
|
|
15,283 |
|
|
|
10,888 |
|
Accrued interest |
|
|
17,817 |
|
|
|
11,867 |
|
Accrued expenses |
|
|
20,545 |
|
|
|
16,951 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
97,543 |
|
|
|
72,371 |
|
|
|
|
|
|
|
|
|
|
Deferred income tax liability |
|
|
30,090 |
|
|
|
19,953 |
|
Long-term debt, net of current maturities |
|
|
508,300 |
|
|
|
561,446 |
|
Other long-term liabilities |
|
|
3,323 |
|
|
|
623 |
|
|
|
|
|
|
|
|
Total liabilities |
|
|
639,256 |
|
|
|
654,393 |
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity |
|
|
|
|
|
|
|
|
Preferred stock, $0.01 par value (25,000,000 shares authorized, none issued) |
|
|
|
|
|
|
|
|
Common stock, $0.01 par value (100,000,000 shares authorized; 35,116,035
issued and outstanding at December 31, 2007 and 28,233,411 issued and
outstanding at December 31, 2006) |
|
|
351 |
|
|
|
282 |
|
Capital in excess of par value |
|
|
326,095 |
|
|
|
216,208 |
|
Retained earnings |
|
|
87,883 |
|
|
|
37,443 |
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
414,329 |
|
|
|
253,933 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
1,053,585 |
|
|
$ |
908,326 |
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated Financial Statements.
31
ALLIS-CHALMERS ENERGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
(In thousands, except per share amounts) |
|
Revenues |
|
$ |
570,967 |
|
|
$ |
310,964 |
|
|
$ |
108,022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs |
|
|
341,450 |
|
|
|
185,579 |
|
|
|
72,567 |
|
Depreciation |
|
|
50,914 |
|
|
|
20,261 |
|
|
|
4,874 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin |
|
|
178,603 |
|
|
|
105,124 |
|
|
|
30,581 |
|
|
General and administrative expenses |
|
|
58,622 |
|
|
|
35,536 |
|
|
|
15,576 |
|
Gain on capillary asset sale |
|
|
(8,868 |
) |
|
|
|
|
|
|
|
|
Amortization |
|
|
4,067 |
|
|
|
1,858 |
|
|
|
1,487 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations |
|
|
124,782 |
|
|
|
67,730 |
|
|
|
13,518 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
(49,534 |
) |
|
|
(21,309 |
) |
|
|
(4,746 |
) |
Interest income |
|
|
3,259 |
|
|
|
972 |
|
|
|
49 |
|
Other |
|
|
776 |
|
|
|
(347 |
) |
|
|
186 |
|
|
|
|
|
|
|
|
|
|
|
Total other expense |
|
|
(45,499 |
) |
|
|
(20,684 |
) |
|
|
(4,511 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before minority interest and income taxes |
|
|
79,283 |
|
|
|
47,046 |
|
|
|
9,007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority interest in income of subsidiaries |
|
|
|
|
|
|
|
|
|
|
(488 |
) |
Provision for income taxes |
|
|
(28,843 |
) |
|
|
(11,420 |
) |
|
|
(1,344 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
50,440 |
|
|
$ |
35,626 |
|
|
$ |
7,175 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
1.48 |
|
|
$ |
1.73 |
|
|
$ |
0.48 |
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
1.45 |
|
|
$ |
1.66 |
|
|
$ |
0.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
34,158 |
|
|
|
20,548 |
|
|
|
14,832 |
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
|
34,701 |
|
|
|
21,410 |
|
|
|
16,238 |
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated Financial Statements.
32
ALLIS-CHALMERS ENERGY INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital in |
|
|
Retained |
|
|
Total |
|
|
|
Common Stock |
|
|
Excess of |
|
|
Earnings |
|
|
Stockholders |
|
|
|
Shares |
|
|
Amount |
|
|
Par Value |
|
|
(Deficit) |
|
|
Equity |
|
|
|
(In thousands, except share amounts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2004 |
|
|
13,611,525 |
|
|
$ |
136 |
|
|
$ |
40,331 |
|
|
$ |
(5,358 |
) |
|
$ |
35,109 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,175 |
|
|
|
7,175 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions |
|
|
411,275 |
|
|
|
4 |
|
|
|
1,746 |
|
|
|
|
|
|
|
1,750 |
|
Secondary public offering, net of offering costs |
|
|
1,761,034 |
|
|
|
18 |
|
|
|
15,441 |
|
|
|
|
|
|
|
15,459 |
|
Stock options and warrants exercised |
|
|
1,076,154 |
|
|
|
11 |
|
|
|
1,371 |
|
|
|
|
|
|
|
1,382 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2005 |
|
|
16,859,988 |
|
|
|
169 |
|
|
|
58,889 |
|
|
|
1,817 |
|
|
|
60,875 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35,626 |
|
|
|
35,626 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions |
|
|
6,072,046 |
|
|
|
61 |
|
|
|
94,919 |
|
|
|
|
|
|
|
94,980 |
|
Secondary public offering, net of offering costs |
|
|
3,450,000 |
|
|
|
34 |
|
|
|
46,263 |
|
|
|
|
|
|
|
46,297 |
|
Issuance under stock plans |
|
|
1,851,377 |
|
|
|
18 |
|
|
|
6,303 |
|
|
|
|
|
|
|
6,321 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|
3,394 |
|
|
|
|
|
|
|
3,394 |
|
Tax benefits on stock plans |
|
|
|
|
|
|
|
|
|
|
6,440 |
|
|
|
|
|
|
|
6,440 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2006 |
|
|
28,233,411 |
|
|
|
282 |
|
|
|
216,208 |
|
|
|
37,443 |
|
|
|
253,933 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50,440 |
|
|
|
50,440 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Secondary public offering, net of offering costs |
|
|
6,000,000 |
|
|
|
60 |
|
|
|
99,995 |
|
|
|
|
|
|
|
100,055 |
|
Issuance under stock plans |
|
|
882,624 |
|
|
|
9 |
|
|
|
3,310 |
|
|
|
|
|
|
|
3,319 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|
4,863 |
|
|
|
|
|
|
|
4,863 |
|
Tax benefits on stock plans |
|
|
|
|
|
|
|
|
|
|
1,719 |
|
|
|
|
|
|
|
1,719 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2007 |
|
|
35,116,035 |
|
|
$ |
351 |
|
|
$ |
326,095 |
|
|
$ |
87,883 |
|
|
$ |
414,329 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated Financial Statements.
33
ALLIS-CHALMERS ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Operating Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
50,440 |
|
|
$ |
35,626 |
|
|
$ |
7,175 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
54,981 |
|
|
|
22,119 |
|
|
|
6,361 |
|
Amortization and write-off of deferred financing fees |
|
|
3,197 |
|
|
|
1,527 |
|
|
|
962 |
|
Stock-based compensation |
|
|
4,863 |
|
|
|
3,394 |
|
|
|
|
|
Allowance for bad debts |
|
|
730 |
|
|
|
781 |
|
|
|
219 |
|
Imputed interest |
|
|
|
|
|
|
355 |
|
|
|
|
|
Deferred taxes |
|
|
8,017 |
|
|
|
2,215 |
|
|
|
|
|
Minority interest in income of subsidiaries |
|
|
|
|
|
|
|
|
|
|
488 |
|
Gain on sale of property and equipment |
|
|
(2,323 |
) |
|
|
(2,444 |
) |
|
|
(669 |
) |
Gain on capillary asset sale |
|
|
(8,868 |
) |
|
|
|
|
|
|
|
|
Changes in operating assets and liabilities, net of acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
Increase in accounts receivable |
|
|
(30,825 |
) |
|
|
(23,175 |
) |
|
|
(10,656 |
) |
Increase in inventories |
|
|
(5,375 |
) |
|
|
(2,637 |
) |
|
|
(3,072 |
) |
Decrease in prepaid expenses and other assets |
|
|
8,202 |
|
|
|
2,505 |
|
|
|
929 |
|
(Increase) decrease in other assets |
|
|
(4,492 |
) |
|
|
308 |
|
|
|
(936 |
) |
Increase (decrease) in trade accounts payable |
|
|
10,732 |
|
|
|
(2,337 |
) |
|
|
2,373 |
|
Increase in accrued interest |
|
|
5,950 |
|
|
|
11,382 |
|
|
|
324 |
|
Increase (decrease) in accrued expenses |
|
|
1,508 |
|
|
|
872 |
|
|
|
(97 |
) |
Increase (decrease) in other liabilities |
|
|
2,700 |
|
|
|
(224 |
) |
|
|
(266 |
) |
Increase in accrued salaries, benefits and payroll taxes |
|
|
4,031 |
|
|
|
3,392 |
|
|
|
443 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
103,468 |
|
|
|
53,659 |
|
|
|
3,578 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions, net of cash acquired |
|
|
(41,000 |
) |
|
|
(526,572 |
) |
|
|
(36,888 |
) |
Purchase of investment interests |
|
|
(498 |
) |
|
|
|
|
|
|
|
|
Purchase of property and equipment |
|
|
(113,151 |
) |
|
|
(39,697 |
) |
|
|
(17,767 |
) |
Deposits on asset commitments |
|
|
(11,488 |
) |
|
|
|
|
|
|
|
|
Proceeds from sale of capillary assets |
|
|
16,250 |
|
|
|
|
|
|
|
|
|
Proceeds from sale of property and equipment |
|
|
12,811 |
|
|
|
6,881 |
|
|
|
1,579 |
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(137,076 |
) |
|
|
(559,388 |
) |
|
|
(53,076 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of long-term debt |
|
|
250,000 |
|
|
|
557,820 |
|
|
|
56,251 |
|
Payments on long-term debt |
|
|
(309,745 |
) |
|
|
(54,030 |
) |
|
|
(28,202 |
) |
Payments on related party debt |
|
|
|
|
|
|
(3,031 |
) |
|
|
(1,522 |
) |
Net (repayments) borrowings on lines of credit |
|
|
|
|
|
|
(6,400 |
) |
|
|
2,527 |
|
Proceeds from issuance of common stock, net of offering costs |
|
|
100,055 |
|
|
|
46,297 |
|
|
|
15,459 |
|
Proceeds from exercise of options and warrants |
|
|
3,319 |
|
|
|
6,321 |
|
|
|
1,382 |
|
Tax benefit on stock plans |
|
|
1,719 |
|
|
|
6,440 |
|
|
|
|
|
Debt issuance costs |
|
|
(7,792 |
) |
|
|
(9,863 |
) |
|
|
(1,821 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
37,556 |
|
|
|
543,554 |
|
|
|
44,074 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
3,948 |
|
|
|
37,825 |
|
|
|
(5,424 |
) |
Cash and cash equivalents at beginning of year |
|
|
39,745 |
|
|
|
1,920 |
|
|
|
7,344 |
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year |
|
$ |
43,693 |
|
|
$ |
39,745 |
|
|
$ |
1,920 |
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated Financial Statements.
34
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements
NOTE 1 NATURE OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization of Business
Allis-Chalmers Energy Inc. (Allis-Chalmers, we, our or us) was incorporated in
Delaware in 1913. We provide services and equipment to oil and natural gas exploration and
production companies throughout the United States including Texas, Louisiana, New Mexico, Colorado,
Oklahoma, Mississippi, Wyoming, Arkansas, West Virginia, offshore in the Gulf of Mexico, and
internationally, primarily in Argentina and Mexico. We operate in 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, 2007 are AirComp LLC (AirComp), Allis-Chalmers
Tubular Services LLC (Tubular), Strata Directional Technology LLC (Strata), Allis-Chalmers
Rental Services LLC (Rental), Allis-Chalmers Production Services LLC (Production),
Allis-Chalmers Management LLC, Allis-Chalmers Holdings Inc., DLS Drilling, Logistics & Services
Corporation (DLS), DLS Argentina Limited, Tanus Argentina S.A. (Tanus), Petro-Rentals LLC
(Petro-Rental) and Rebel Rentals LLC (Rebel). All significant inter-company transactions have
been eliminated.
Revenue Recognition
We provide rental equipment and drilling services to our customers at per day, or daywork, and
per job contractual rates and recognize the drilling related revenue as the work progresses and
when collectibility is reasonably assured. Revenue from daywork contracts is recognized when it is
realized or realizable and earned. On daywork contracts, revenue is recognized based on the number
of days completed at fixed rates stipulated by the contract. For certain contracts, we receive
lump-sum and other fees for equipment and other mobilization costs. Mobilization fees and the
related costs are deferred and amortized over the contract terms when material. We recognize
reimbursements received for out-of-pocket expenses incurred as revenues and account for
out-of-pocket expenses as direct costs. Payments from customers for the cost of oilfield rental
equipment that is damaged or lost-in-hole are reflected as revenues. We recognized revenue from
damaged or lost-in-hole equipment of $12.6 million, $2.4 million and $970,000 for the years ended
December 31, 2007, 2006 and 2005, respectively. The Securities and Exchange Commissions (SEC)
Staff Accounting Bulletin (SAB) No. 104, Revenue Recognition In Financial Statements (SAB No.
104), provides guidance on the SEC staffs views on the application of generally accepted
accounting principles to selected revenue recognition issues. Our revenue recognition policy is in
accordance with generally accepted accounting principles and SAB No. 104.
35
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,
2007 and 2006, we had recorded an allowance for doubtful accounts of $1.9 million and $826,000
respectively. Bad debt expense was $1.3 million, $781,000 and $219,000 for the years ended
December 31, 2007, 2006 and 2005, respectively.
Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less at
the time of purchase to be cash equivalents.
Inventories
Inventories are stated at the lower of cost or market. Cost is determined using the first
in, first out (FIFO) method or the average cost method, which approximates FIFO, and includes
the cost of materials, labor and manufacturing overhead.
Property and Equipment
Property and equipment is recorded at cost less accumulated depreciation. Certain equipment
held under capital leases are classified as equipment and the related obligations are recorded as
liabilities.
Maintenance and repairs, which do not improve or extend the life of the related assets, are
charged to operations when incurred. Refurbishments and renewals are capitalized when the value of
the equipment is enhanced for an extended period. When property and equipment are sold or
otherwise disposed of, the asset account and related accumulated depreciation account are relieved,
and any gain or loss is included in operations.
The cost of property and equipment currently in service is depreciated over the estimated
useful lives of the related assets, which range from three to twenty years. Depreciation is
computed on the straight-line method for financial reporting purposes. Capital leases are
amortized using the straight-line method over the estimated useful lives of the assets and lease
amortization is included in depreciation expense. Depreciation expense charged to operations was
$50.9 million, $20.3 million and $4.9 million for the years ended December 31, 2007, 2006 and 2005,
respectively.
Goodwill, Intangible Assets and Amortization
Goodwill, including goodwill associated with equity method investments, and other intangible
assets with infinite lives are not amortized, but tested for impairment annually or more frequently
if circumstances indicate that impairment may exist. Intangible assets with finite useful lives
are amortized either on a straight-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.
36
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
The impairment test requires the allocation of goodwill and all other assets and liabilities
to reporting units. Reporting units are at a business unit level and is one level below our
operating segments. If the fair value of the reporting unit is less than the book value (including
goodwill) then goodwill is reduced to its implied fair value and the amount of the write-down is
charged against earnings. We perform impairment tests on the carrying value of our goodwill on an
annual basis as of December 31st for each of our reportable segments. As of December 31, 2007 and
2006, no impairment was deemed necessary. Increases in estimated future costs or decreases in
projected revenues could lead to an impairment of all or a portion of our goodwill in future
period.
Impairment of Long-Lived Assets
Long-lived assets, which include property, plant and equipment, and other intangible assets,
and certain other assets are reviewed for impairment whenever events or changes in circumstances
indicate that the carrying amount may not be recoverable. An impairment loss is recorded in the
period in which it is determined that the carrying amount is not recoverable. The determination of
recoverability is made based upon the estimated undiscounted future net cash flows, excluding
interest expense. The impairment loss is determined by comparing the fair value, as determined by
a discounted cash flow analysis, with the carrying value of the related assets.
Financial Instruments
Financial instruments consist of cash and cash equivalents, accounts receivable and payable,
and debt. The carrying value of cash and cash equivalents and accounts receivable and payable
approximate fair value due to their short-term nature. We believe the fair values and the carrying
value of our debt would not be materially different due to the instruments interest rates
approximating market rates for similar borrowings at December 31, 2007 and 2006.
Concentration of Credit and Customer Risk
Financial instruments that potentially subject us to concentrations of credit risk consist
principally of cash and cash equivalents and trade accounts receivable. As of December 31, 2007,
we have approximately $2.5 million of cash and cash equivalents residing in Argentina. We transact
our business with several financial institutions. However, the amount on deposit in six financial
institutions exceeded the $100,000 federally insured limit at December 31, 2007 by a total of $13.2
million. Management believes that the financial institutions are financially sound and the risk of
loss is minimal.
We sell our services to major and independent domestic and international oil and natural gas
companies. We perform ongoing credit valuations of our customers and provide allowances for
probable credit losses where appropriate. In 2007 and 2006, one of our customers, Pan American
Energy LLC Sucursal Argentina, or Pan American Energy, represented 20.7% and 11.7% of our
consolidated revenues, respectively. In 2005 none of our customers accounted for more than 10% of
our consolidated revenues. Revenues from Materiales y Equipo Petroleo, or Matyep, represented
3.4%, 8.3% and 94.5% of our international revenues in 2007, 2006 and 2005, respectively. Revenues
from Pan American Energy represented 51.0% and 45.6% of our international revenues in 2007 and
2006, respectively.
Debt Issuance Costs
The costs related to the issuance of debt are capitalized and amortized to interest expense
using the straight-line method, which approximates the interest method, over the maturity periods
of the related debt.
Income Taxes
Our income tax expense is based on our income, statutory tax rates and tax planning
opportunities available to us in the various jurisdictions in which we operate. We provide for
income taxes based on the tax 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.
37
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
The determination and evaluation of our annual income tax provision involves the
interpretation of tax laws in various jurisdictions in which we operate and requires significant
judgment and the use of estimates and assumptions regarding significant future events such as the
amount, timing and character of income, deductions and tax credits. Changes in tax laws,
regulations and our level of operations or profitability in each jurisdiction may impact our tax
liability in any given year. While our annual tax provision is based on the information available
to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax
jurisdictions are determined.
Current income tax expense reflects an estimate of our income tax liability for the current
year, withholding taxes, changes in tax rates and changes in prior year tax estimates as returns
are filed. Deferred tax assets and liabilities are recognized for the anticipated future tax
effects of temporary differences between the financial statement basis and the tax basis of our
assets and liabilities using the enacted tax rates in effect at year end. A valuation allowance
for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the
deferred tax asset will not be realized. We provide for uncertain tax positions pursuant to FASB
Interpretation No. 48, Accounting for Uncertainty in Income Taxes an Interpretation of FASB
Statement No. 109 (FIN 48). Our policy is that we recognize interest and penalties accrued on
any unrecognized tax benefits as a component of income tax expense. As of the date of adoption of
FIN 48, we did not have any accrued interest or penalties associated with any unrecognized tax
benefits. For United States federal tax purposes, our tax returns for the tax years 2001 through
2006 remain open for examination by the tax authorities. Our foreign tax returns remain open for
examination for the tax years 2001 through 2006. Generally, for state tax purposes, our 2002
through 2006 tax years remain open for examination by the tax authorities under a four year statute
of limitations, however, certain states may keep their statute open for six to ten years.
It is our intention to permanently reinvest all of the undistributed earnings of our non-U.S.
subsidiaries in such subsidiaries. Accordingly, we have not provided for U.S. deferred taxes on
the undistributed earnings of our non-U.S. subsidiaries. If a distribution is made to us from the
undistributed earnings of these subsidiaries, we could be required to record additional taxes.
Because we cannot predict when, if at all, we will make a distribution of these undistributed
earnings, we are unable to make a determination of the amount of unrecognized deferred tax
liability.
Stock-Based Compensation
We adopted SFAS No. 123R, Share-Based Payment (SFAS No. 123R), effective January 1, 2006.
This statement requires all share-based payments to employees, including grants of employee stock
options, to be recognized in the financial statements based on their grant-date fair values.
Compensation cost for awards granted prior to, but not vested, as of January 1, 2006 would be based
on the grant date attributes originally used to value those awards for pro forma purposes under
SFAS No. 123, Accounting for Stock-Based Compensation (SFAS No. 123). We adopted SFAS No. 123R
using the modified prospective transition method, utilizing the Black-Scholes option pricing model
for the calculation of the fair value of our employee stock options. Under the modified
prospective method, we record compensation cost related to unvested stock awards as of December 31,
2005 by recognizing the unamortized grant date fair value of these awards over the remaining
vesting periods of those awards with no change in historical reported earnings. We estimated
forfeiture rates for 2007 and 2006 based on our historical experience.
The Black-Scholes model incorporates assumptions to value stock-based awards. The risk-free
rate of interest is the related U.S. Treasury yield curve for periods within the expected term of
the option at the time of grant. The dividend yield on our common stock is assumed to be zero as
we have historically not paid dividends and have no current plans to do so in the future. The
expected volatility is based on historical volatility of our common stock.
Prior to January 1, 2006, we accounted for our stock-based compensation using Accounting
Principle Board Opinion No. 25 (APB No. 25). Under APB No. 25, compensation expense is
recognized for stock options with an exercise price that is less than the market price on the grant
date of the option. For stock options with exercise prices at or above the market value of the
stock on the grant date, we adopted the disclosure-only provisions of SFAS No. 123. We also
adopted the disclosure-only provisions of SFAS No. 123 for the stock options granted to our
employees and directors. Accordingly, no compensation cost was recognized under APB No. 25. Our
net income for the years ended December 31, 2007 and 2006 includes approximately $4.9 million and
$3.4 million of compensation costs related to share-based payments, respectively. The tax benefit
recorded in association with the share-based payments was $1.7 million and $6.4 million for the
years-ended December 31, 2007 and 2006, respectively. As of December 31, 2007 there is $16.3
million of unrecognized compensation expense related to non-vested stock based compensation grants.
38
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
Had compensation expense for the options granted been recorded based on the fair value at the
grant date for the options, consistent with the provisions of SFAS 123, our net income and net
income per common share for the year ended December 31, 2005 would have been decreased to the pro
forma amounts indicated below (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year |
|
|
|
|
|
|
|
Ended |
|
|
|
|
|
|
|
December 31, |
|
|
|
|
|
|
|
2005 |
|
Net income attributed to common stockholders as reported: |
|
|
|
|
|
$ |
7,175 |
|
Less total stock based employee compensation expense
determined under fair value based method for all awards
net of tax related effects |
|
|
|
|
|
|
(4,284 |
) |
|
|
|
|
|
|
|
|
Pro-forma net income attributed to common stockholders |
|
|
|
|
|
$ |
2,891 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share: |
|
|
|
|
|
|
|
|
Basic |
|
As reported |
|
$ |
0.48 |
|
|
|
Pro forma |
|
$ |
0.19 |
|
Diluted |
|
As reported |
|
$ |
0.44 |
|
|
|
Pro forma |
|
$ |
0.18 |
|
Options were granted in 2007, 2006 and 2005. See Note 10 for further disclosures regarding
stock options. The following assumptions were applied in determining the compensation costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Expected dividend yield |
|
|
|
|
|
|
|
|
|
|
|
|
Expected price volatility |
|
|
66.21 |
% |
|
|
72.28 |
% |
|
|
84.28 |
% |
Risk-free interest rate |
|
|
4.8 |
% |
|
|
5.1 |
% |
|
|
5.6 |
% |
Expected life of options |
|
5 years |
|
7 years |
|
7 years |
Weighted average fair value of options
granted at market value |
|
$ |
12.86 |
|
|
$ |
10.58 |
|
|
$ |
5.02 |
|
Segments of an Enterprise and Related Information
We disclose the results of our segments in accordance with SFAS No. 131, Disclosures About
Segments Of An Enterprise And Related Information (SFAS No. 131). We designate the internal
organization that is used by management for allocating resources and assessing performance as the
source of our reportable segments. SFAS No. 131 also requires disclosures about products and
services, geographic areas and major customers. Please see Note 14 for further disclosure of
segment information in accordance with SFAS No. 131.
Income Per Common Share
We compute income per common share in accordance with the provisions of SFAS No. 128, Earnings
Per Share (SFAS No. 128). SFAS No. 128 requires companies with complex capital structures to
present basic and diluted earnings per share. Basic earnings per share are computed on the basis
of the weighted average number of shares of common stock outstanding during the period. Diluted
earnings per share is similar to basic earnings per share, but presents the dilutive effect on a
per share basis of potential common shares (e.g., convertible preferred stock, stock options, etc.)
as if they had been converted. Restricted stock grants are legally considered issued and
outstanding, but are included in basic and diluted earnings per share only to the extent that they
are vested. Unvested restricted stock is included in the computation of diluted earnings per share
using the treasury stock method. Potential dilutive common shares that have an anti-dilutive effect
(e.g., those that increase income per share) are excluded from diluted earnings per share.
39
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
The components of basic and diluted earnings per share are as follows (in thousands, except
per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Numerator: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
50,440 |
|
|
$ |
35,626 |
|
|
$ |
7,175 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding excluding nonvested restricted stock |
|
|
34,158 |
|
|
|
20,548 |
|
|
|
14,832 |
|
Effect of potentially dilutive common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
Warrants and employee and director stock options and restricted shares |
|
|
543 |
|
|
|
862 |
|
|
|
1,406 |
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding and assumed conversions |
|
|
34,701 |
|
|
|
21,410 |
|
|
|
16,238 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
1.48 |
|
|
$ |
1.73 |
|
|
$ |
0.48 |
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
1.45 |
|
|
$ |
1.66 |
|
|
$ |
0.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Potentially dilutive securities excluded as anti-dilutive |
|
|
1,108 |
|
|
|
53 |
|
|
|
599 |
|
|
|
|
|
|
|
|
|
|
|
Reclassification
Certain prior period balances have been reclassified to conform to current year presentation.
On January 31, 2008, we created the positions of Senior Vice President Oilfield Services
and Senior Vice President Rental Services. In conjunction with this organizational change, we
reviewed the presentation of our reporting segments during the first quarter of 2008. Based on
this review, we determined that our operational performance would be segmented and reviewed by the
Oilfield Services, Drilling and Completion and Rental Services segments. The Oilfield Services
segment includes our underbalanced drilling, directional drilling, tubular services and production
services operations. The Drilling and Completion segment includes our international drilling
operations. As a result, we realigned our financial reporting segments and will now report the
following operations as separate, distinct reporting segments: (1) Oilfield Services, (2) Drilling
and Completion and (3) Rental Services. Our historical segment data previously reported for the
years ended December 31, 2007, 2006 and 2005 have been restated to conform to the new presentation
(see Note 14).
New Accounting Pronouncements
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS 157). SFAS
157 clarifies the principle that fair value should be based on the assumptions that market
participants would use when pricing an asset or liability and establishes a fair value hierarchy
that prioritizes the information used to develop those assumptions. Under the standard, fair value
measurements would be separately disclosed by level within the fair value hierarchy. SFAS 157 is
effective for financial statements issued for fiscal years beginning after November 15, 2007, and
interim periods within those fiscal years, with early adoption permitted. Subsequently, the FASB
provided for a one-year deferral of the provisions of SFAS 157 for non-financial assets and
liabilities that are recognized or disclosed at fair value in the consolidated financial statements
on a non-recurring basis. We believe that the adoption of SFAS 157 will not have a material impact
on our financial position, results of operations or cash flows.
In December 2007, the FASB issued SFAS No. 141(R), Business Combinations (SFAS 141(R)). This
statement retains the fundamental requirements in SFAS No. 141, Business Combinations that the
acquisition method of accounting be used for all business combinations and expands the same method
of accounting to all transactions and other events in which one entity obtains control over one or
more other businesses or assets at the acquisition date and in subsequent periods. This statement
replaces SFAS No. 141 by requiring measurement at the acquisition date of the fair value of assets
acquired, liabilities assumed and any non-controlling interest. Additionally, SFAS 141(R) requires
that acquisition-related costs, including restructuring costs, be recognized as expense separately
from the acquisition. SFAS 141(R) applies prospectively to business combinations for fiscal years
beginning after December 15, 2008. We will adopt SFAS 141(R) beginning January 1, 2009 and apply
to future acquisitions.
40
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
In February 2007, the FASB issued Statement No. 159, The Fair Value Option for Financial
Assets and Financial Liabilities (SFAS 159), which permits entities to elect to measure many
financial instruments and certain other items at fair value. Upon adoption of SFAS 159, an entity
may elect the fair value option for eligible items that exist at the adoption date. Subsequent to
the initial adoption, the election of the fair value option should only be made at the initial
recognition of the asset or liability or upon a re-measurement event that gives rise to the
new-basis of accounting. All subsequent changes in fair value for that instrument are reported in
earnings. SFAS 159 does not affect any existing accounting literature that requires certain assets
and liabilities to be recorded at fair value nor does it eliminate disclosure requirements included
in other accounting standards. SFAS 159 is effective as of the beginning of each reporting
entitys first fiscal year that begins after November 15, 2007. We are currently evaluating the
provisions of SFAS 159 and have not yet determined the impact, if any, on our financial statements.
In December 2007, the FASB issued SFAS No. 160, Non-controlling Interests in Consolidated
Financial Statements an amendment of ARB No. 51 (SFAS 160). SFAS 160 requires (i) that
non-controlling (minority) interests be reported as a component of shareholders equity, (ii) that
net income attributable to the parent and to the non-controlling interest be separately identified
in the consolidated statement of operations, (iii) that changes in a parents ownership interest
while the parent retains its controlling interest be accounted for as equity transactions, (iv)
that any retained non-controlling equity investment upon the deconsolidation of a subsidiary be
initially measured at fair value, and (v) that sufficient disclosures are provided that clearly
identify and distinguish between the interests of the parent and the interests of the
non-controlling owners. SFAS 160 is effective for annual periods beginning after December 15, 2008
and should be applied prospectively. The presentation and disclosure requirements of the statement
shall be applied retrospectively for all periods presented. We believe the adoption of SFAS 160
will not have a material impact on our financial position or results of operations.
NOTE 2 POST RETIREMENT BENEFIT OBLIGATIONS
Medical And Life
Pursuant to the Plan of Reorganization that was confirmed by the Bankruptcy Court after
acceptances by our creditors and stockholders and was consummated on December 2, 1988, we assumed
the contractual obligation to Simplicity Manufacturing, Inc. (SMI) to reimburse SMI for 50% of the
actual cost of medical and life insurance claims for a select group of retirees (SMI Retirees) of
the prior Simplicity Manufacturing Division of Allis-Chalmers. The actuarial present value of the
expected retiree benefit obligation is determined by an actuary and is the amount that results from
applying actuarial assumptions to (1) historical claims-cost data, (2) estimates for the time value
of money (through discounts for interest) and (3) the probability of payment (including decrements
for death, disability, withdrawal, or retirement) between today and expected date of benefit
payments. As of December 31, 2007 and 2006, we have post-retirement benefit obligations of $31,000
and $304,000, respectively.
401(k) Savings Plan
On June 30, 2003, we adopted the 401(k) Profit Sharing Plan (the Plan). The Plan is a
defined contribution savings plan designed to provide retirement income to our eligible employees.
The Plan is intended to be qualified under Section 401(k) of the Internal Revenue Code of 1986, as
amended. It is funded by voluntary pre-tax contributions from eligible employees who may
contribute a percentage of their eligible compensation, limited and subject to statutory limits.
The Plan is also funded by discretionary matching employer contributions from us. Eligible
employees cannot participate in the Plan until they have attained the age of 21 and completed
three-months of service with us. Each participant is 100% vested with respect to the participants
contributions while our matching contributions are vested over a three-year period in accordance
with the Plan document. Contributions are invested, as directed by the participant, in investment
funds available under the Plan. Matching contributions of approximately $1.8 million, $735,000 and
$114,000 were paid in 2007, 2006 and 2005, respectively.
NOTE 3 ACQUISITIONS AND SALE OF CAPILLARY ASSETS
On April 1, 2005, we acquired 100% of the outstanding stock of Delta Rental Service, Inc., or
Delta, for approximately $4.6 million in cash, 223,114 shares of our common stock and two
promissory notes totaling $350,000. The purchase price was allocated to fixed assets and
inventory. Delta, located in Lafayette, Louisiana, was a rental tool company providing specialty
rental items to the oil and gas industry such as spiral heavy weight drill pipe, test plugs used to
test blow-out preventors, well head retrieval tools, spacer spools and assorted handling tools.
The results of Delta since the acquisition are included in our Rental Services segment.
41
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
On May 1, 2005, we acquired 100% of the outstanding capital stock of Capcoil Tubing Services,
Inc., or Capcoil, for approximately $2.7 million in cash, 168,161 shares of our common stock and
the payment or assumption of approximately $1.3 million of debt. Capcoil, located in Kilgore,
Texas, is engaged in downhole well servicing by providing coil tubing services to enhance
production from existing wells. Goodwill of $184,000 and other identifiable intangible assets of
$1.4 million were recorded in connection with the acquisition. The results of Capcoil since the
acquisition are included in our Oilfield Services segment.
On July 11, 2005, we acquired the compressed air drilling assets of W.T Enterprises, Inc., or
W.T., based in South Texas, for $6.0 million in cash. The equipment includes compressors,
boosters, mist pumps and vehicles. Goodwill of $82,000 and other identifiable intangible assets of
$1.5 million were recorded in connection with the acquisition. The results of the W.T. assets
since their acquisition are included in our Oilfield Services segment.
On July 11, 2005, we acquired from M-I L.L.C. (M-I) its 45% interest in AirComp and
subordinated note in the principal amount of $4.8 million issued by AirComp, for which we paid M-I
$7.1 million in cash and issued to M-I a $4.0 million subordinated note bearing interest at 5% per
annum. As a result, we now own 100% of AirComp. The results of AirComp are included in our
Oilfield Services segment.
Effective August 1, 2005, we acquired 100% of the outstanding capital stock of Target Energy
Inc., or Target, for approximately $1.3 million in cash and forgiveness of a lease receivable of
approximately $0.6 million. The purchase price was allocated to the fixed assets of Target. The
results of Target are included in our Oilfield Services segment as their Measure While Drilling
equipment is utilized in that segment.
On September 1, 2005, we acquired the casing and tubing service assets of Patterson Services,
Inc. for approximately $15.6 million. These assets are located in Corpus Christi, Texas; Kilgore,
Texas; Lafayette, Louisiana and Houma, Louisiana. The results of these assets since their
acquisition are included in our Oilfield Services segment.
Effective January 1, 2006, we acquired 100% of the outstanding stock of Specialty Rental
Tools, Inc., or Specialty, for approximately $95.3 million in cash. In addition, approximately
$588,000 of costs were incurred in relation to the Specialty acquisition. Specialty, located in
Lafayette, Louisiana, was engaged in the rental of high quality drill pipe, heavy weight spiral
drill pipe, tubing work strings, blow-out preventors, choke manifolds and various valves and
handling tools for oil and natural gas drilling. The following table summarizes the allocation of
the purchase price and related acquisition costs to the estimated fair value of the assets
acquired and liabilities assumed at the date of acquisition (in thousands):
|
|
|
|
|
Current assets |
|
$ |
7,645 |
|
Property and equipment |
|
|
90,622 |
|
|
|
|
|
Total assets acquired |
|
|
98,267 |
|
|
|
|
|
Current liabilities |
|
|
2,193 |
|
Long-term debt |
|
|
74 |
|
|
|
|
|
Total liabilities assumed |
|
|
2,267 |
|
|
|
|
|
Net assets acquired |
|
$ |
96,000 |
|
|
|
|
|
Specialtys historical property and equipment values were increased by approximately $71.6
million based on third-party valuations. The results of Specialty since the acquisition are
included in our Rental Services segment.
42
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
Effective April 1, 2006, we acquired 100% of the outstanding stock of Rogers Oil Tools, Inc.,
or Rogers, based in Lafayette, Louisiana, for a total consideration of approximately $13.7 million,
which includes approximately $11.3 million in cash, $1.6 million in our common stock and a $750,000
three-year promissory note. In addition, approximately $380,000 of costs were incurred in relation
to the Rogers acquisition. Rogers sells, services and rents power drill pipe tongs and accessories
and rental tongs for snubbing and well control applications. Rogers also provides specialized tong
operators for rental jobs. The following table summarizes the allocation of the purchase price and
related acquisition costs to the estimated fair value of the assets acquired and liabilities
assumed at the date of acquisition (in thousands):
|
|
|
|
|
Current assets |
|
$ |
4,520 |
|
Property and equipment |
|
|
9,866 |
|
Intangible assets, including goodwill |
|
|
4,941 |
|
|
|
|
|
Total assets acquired |
|
|
19,327 |
|
|
|
|
|
Current liabilities |
|
|
1,376 |
|
Deferred income tax liabilities |
|
|
3,760 |
|
Other long-term liabilities |
|
|
150 |
|
|
|
|
|
Total liabilities assumed |
|
|
5,286 |
|
|
|
|
|
Net assets acquired |
|
$ |
14,041 |
|
|
|
|
|
Rogers historical property and equipment values were increased by approximately $8.4 million
based on third-party valuations. Intangible assets include approximately $2.4 million assigned to
goodwill, $1.2 million assigned to patents, $1.1 million assigned to customer list and $150,000
assigned to non-compete based on third-party valuations and employment contracts. The amortizable
intangibles have a weighted-average useful life of 10.5 years. The results of Rogers since the
acquisition are included in our Oilfield Services segment.
Effective August 14, 2006, we acquired 100% of the outstanding stock of DLS, based in
Argentina, for a total consideration of approximately $114.5 million, which includes approximately
$93.7 million in cash, $38.1 million in our common stock, less approximately $17.3 million of debt
assigned to us. In addition, approximately $3.4 million of costs were incurred in relation to the
DLS acquisition. DLS operates a fleet of 51 rigs, including 20 drilling rigs, 18 workover rigs
and 12 pulling rigs in Argentina and one drilling rig in Bolivia. The following table summarizes
the allocation of the purchase price and related acquisition costs to the estimated fair value of
the assets acquired and liabilities assumed at the date of acquisition (in thousands):
|
|
|
|
|
Current assets |
|
$ |
52,033 |
|
Property and equipment |
|
|
130,389 |
|
Other long-term assets |
|
|
21 |
|
|
|
|
|
Total assets acquired |
|
|
182,443 |
|
|
|
|
|
Current liabilities |
|
|
34,386 |
|
Long-term debt, less current portion |
|
|
5,921 |
|
Intercompany note |
|
|
17,256 |
|
Deferred tax liabilities |
|
|
6,948 |
|
|
|
|
|
Total liabilities assumed |
|
|
64,511 |
|
|
|
|
|
Net assets acquired |
|
$ |
117,932 |
|
|
|
|
|
DLS historical property and equipment values were increased by approximately $22.7 million
based on third-party valuations. The results of DLS since the acquisition are included in our
Drilling and Completion segment.
43
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
On October 16, 2006, we acquired 100% of the outstanding stock of Petro Rental, based in
Lafayette, Louisiana, for a total consideration of approximately $33.6 million, which includes
approximately $20.2 million in cash, $3.8 million in our common stock and repaid $9.6 million of
existing Petro Rental debt. In addition, approximately $82,000 of costs were incurred in relation
to the Petro-Rental acquisition. Petro-Rental provides a variety of production-related rental
tools and equipment and services, including wire line services and equipment, land and offshore
pumping services and coiled tubing. The following table summarizes the allocation of the purchase
price and related acquisition costs to the estimated fair value of the assets acquired and
liabilities assumed at the date of acquisition (in thousands):
|
|
|
|
|
Current assets |
|
$ |
8,175 |
|
Property and equipment |
|
|
28,792 |
|
Intangible assets, including goodwill |
|
|
5,811 |
|
Other long-term assets |
|
|
2 |
|
|
|
|
|
Total assets acquired |
|
|
42,780 |
|
|
|
|
|
Current liabilities |
|
|
2,135 |
|
Deferred tax liabilities |
|
|
6,954 |
|
|
|
|
|
Total liabilities assumed |
|
|
9,089 |
|
|
|
|
|
Net assets acquired |
|
$ |
33,691 |
|
|
|
|
|
Petro Rentals historical property and equipment values were increased by approximately $13.4
million based on third-party valuations. Intangible assets include approximately $3.6 million
assigned to goodwill and $2.2 million assigned to customer relationships based on third-party
valuations. The amortizable intangibles have a weighted-average useful life of 10 years. The
results of Petro-Rental since the acquisition are included in our Oilfield Services segment.
Effective December 1, 2006, we acquired 100% of the outstanding stock of Tanus, based in
Argentina, for a total consideration of $2.5 million. In addition, approximately $17,000 of costs
were incurred in relation to the Tanus acquisition. Tanus is engaged in the research and
manufacturing of additives for the oil, natural gas and water well drilling and completion fluids
in Argentina. The following table summarizes the allocation of the purchase price and related
acquisition costs to the estimated fair value of the assets acquired and liabilities assumed at the
date of the acquisition (in thousands).
|
|
|
|
|
Current assets |
|
$ |
2,254 |
|
Property and equipment |
|
|
2 |
|
Goodwill |
|
|
1,504 |
|
|
|
|
|
Total assets acquired |
|
|
3,760 |
|
Current liabilities |
|
|
1,243 |
|
|
|
|
|
Net assets acquired |
|
$ |
2,517 |
|
|
|
|
|
The results of Tanus are reported with DLS under our Drilling and Completion segment.
On December 18, 2006, we acquired substantially all of the assets of Oil & Gas Rental
Services, Inc, or OGR, based in Morgan City, Louisiana, for a total consideration of approximately
$342.4 million, which includes approximately $291.0 million in cash, and $51.4 million in our
common stock. In addition, approximately $3.0 million of costs were incurred in relation to the
acquisition of the assets of OGR The following table summarizes the allocation of the purchase
price and related acquisition costs to the estimated fair value of the assets acquired at the date
of acquisition (in thousands):
|
|
|
|
|
Current assets |
|
$ |
12,735 |
|
Property and equipment |
|
|
199,015 |
|
Investments |
|
|
4,618 |
|
Intangible assets, including goodwill |
|
|
128,976 |
|
|
|
|
|
Total assets acquired |
|
$ |
345,344 |
|
|
|
|
|
OGRs historical property and equipment values were increased by approximately $168.9 million
based on third-party valuations. Intangible assets include approximately $106.1 million assigned
to goodwill, $22.0 million to customer relations, $831,000 to patents and $35,000 assigned to
employment agreements based on third-party valuations. The amortizable intangibles have a
weighted-average useful life of 10.1 years. The results of the OGR assets since their acquisition
are included in our Rental Services segment.
44
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
On June 29 2007, we acquired Coker Directional, Inc., or Coker, for a total consideration of
approximately $3.9 million, which includes approximately $3.6 million in cash and a promissory note
for $350,000. In addition, approximately $5,000 of costs were incurred in relation to the Coker
acquisition. The following table summarizes the preliminary allocation of the purchase price and
related acquisition costs to the estimated fair value of the assets acquired and liabilities
assumed at the date of the acquisition (in thousands):
|
|
|
|
|
Property and equipment |
|
|
3 |
|
Intangible assets, including goodwill |
|
|
3,902 |
|
|
|
|
|
Net assets acquired |
|
$ |
3,905 |
|
|
|
|
|
Intangible assets include approximately $1.8 million assigned to goodwill and $2.1 million
assigned to customer relationships and non-compete. The amortizable intangibles have a
weighted-average useful life of 9.4 years. The results of Coker since the acquisition are included
in our Oilfield Services segment. We do not expect any material differences from the preliminary
allocation of the purchase price and the final purchase price allocations.
On July 26, 2007, we acquired Diggar Tools, LLC, or Diggar, for a total consideration of
approximately $10.3 million, which includes approximately $6.7 million in cash, a promissory note
for $750,000 and payment of approximately $2.8 million of existing Diggar debt. In addition,
approximately $29,000 of costs were incurred in relation to the Diggar acquisition. The following
table summarizes the preliminary allocation of the purchase price and related acquisition costs to
the estimated fair value of the assets acquired at the date of acquisition (in thousands):
|
|
|
|
|
Current assets |
|
$ |
1,113 |
|
Property and equipment |
|
|
7,204 |
|
Intangible assets, including goodwill |
|
|
2,675 |
|
|
|
|
|
Total assets acquired |
|
|
10,992 |
|
|
|
|
|
Current liabilities |
|
|
622 |
|
|
|
|
|
Net assets acquired |
|
$ |
10,370 |
|
|
|
|
|
Diggars historical property and equipment values were increased by approximately $3.4 million
based on third-party valuations. Intangible assets include approximately $2.7 million assigned to
goodwill. The results of Diggar since the acquisition are included in our Oilfield Services
segment. We do not expect any material differences from the preliminary allocation of the purchase
price and the final purchase price allocations.
On October 23, 2007, we acquired Rebel for a total consideration of approximately $7.3
million, which includes approximately $5.0 million in cash, promissory notes for an aggregate of
$500,000, payment of approximately $1.5 million of existing Rebel debt and the deposit of $305,000
in escrow to cover distributions owed under the Rebel Defined Benefit Pension Plan & Trust. In
addition, approximately $214,000 of costs were incurred in relation to the Rebel acquisition. The
following table summarizes the preliminary allocation of the purchase price and related acquisition
costs to the estimated fair value of the assets acquired at the date of acquisition (in thousands):
|
|
|
|
|
Current assets |
|
$ |
944 |
|
Land, Property and equipment |
|
|
8,736 |
|
Intangible assets, including goodwill |
|
|
1,144 |
|
|
|
|
|
Total assets acquired |
|
|
10,824 |
|
|
|
|
|
Current liabilities |
|
|
218 |
|
Deferred tax liabilities |
|
|
3,095 |
|
|
|
|
|
Total liabilities assumed |
|
|
3,313 |
|
|
|
|
|
Net assets acquired |
|
$ |
7,511 |
|
|
|
|
|
Rebels historical property and equipment values were increased by approximately $8.5 million
based on third-party valuations. Intangible assets include approximately $461,000 assigned to
goodwill and $683,000 assigned to customer relations. The amortizable intangibles have a useful
life of 15 years. The results of Rebel since the acquisition are included in our Oilfield Services
segment. We do not expect any material differences from the preliminary allocation of the purchase
price and the final purchase price allocations.
45
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
On November 1, 2007, we acquired substantially all the assets Diamondback Oilfield Services,
Inc. or Diamondback, for a total consideration of approximately $23.1 million in cash.
Approximately $89,000 of costs were incurred in relation to the Diamondback acquisition. The
following table summarizes the preliminary allocation of the purchase price and related acquisition
costs to the estimated fair value of the assets acquired at the date of acquisition (in thousands):
|
|
|
|
|
Current assets |
|
$ |
3,350 |
|
Property and equipment |
|
|
8,701 |
|
Intangible assets, including goodwill |
|
|
12,232 |
|
Other noncurrent assets |
|
|
10 |
|
|
|
|
|
Total assets acquired |
|
|
24,293 |
|
|
|
|
|
Current liabilities |
|
|
1,160 |
|
|
|
|
|
Net assets acquired |
|
$ |
23,133 |
|
|
|
|
|
Diamondbacks historical property and equipment values were increased by approximately $2.0
million based on third-party valuations. Intangible assets include approximately $7.6 million
assigned to goodwill, $650,000 assigned to non-compete, $620,000 assigned to trade name and $3.4
million assigned to customer relations based on third-party valuations. The amortizable
intangibles have a weighted-average useful life of 13.3 years. The sellers are entitled to a
future cash earn-out payment upon the business attaining certain earning objectives. The results
of the Diamondback assets since their acquisition are included in our Oilfield Services segment.
We do not expect any material differences from the preliminary allocation of the purchase price and
the final purchase price allocations.
The acquisitions were accounted for using the purchase method of accounting. The results of
operations of the acquired entities since the date of acquisition are included in our consolidated
income statement.
On June 29, 2007, we sold our capillary tubing units and related equipment for approximately
$16.3 million. We reported a gain of approximately $8.9 million. The assets sold represented a
small portion of our Oilfield Services segment.
The following unaudited pro forma consolidated summary financial information for the year
ended December 31, 2006 illustrates the effects of the acquisitions and the related public
offerings of debt and equity for Rogers, DLS, Petro-Rental and OGR as if the acquisitions occurred
as of January 1, 2006, based on the historical results of the acquisitions. The following
unaudited pro forma consolidated summary financial information for the year ended December 31, 2005
illustrates the effects of the acquisitions and the related public offerings of debt and equity for
Delta, Capcoil, W.T., the minority interest in AirComp, Specialty, Rogers, DLS, Petro-Rental and
OGR as if the acquisitions had occurred as of January 1, 2005, based on the historical results of
the acquisitions. The historical results for OGR are based on their historical year end of October
31 (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
2006 |
|
2005 |
Revenues |
|
$ |
502,418 |
|
|
$ |
346,230 |
|
Operating income |
|
$ |
93,082 |
|
|
$ |
49,868 |
|
Net income |
|
$ |
32,358 |
|
|
$ |
1,264 |
|
Net income per common share
Basic |
|
$ |
0.96 |
|
|
$ |
0.04 |
|
Diluted |
|
$ |
0.94 |
|
|
$ |
0.04 |
|
46
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
NOTE 4 INVENTORIES
Inventories are comprised of the following as of December 31 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
Manufactured |
|
|
|
|
|
|
|
|
Finished goods |
|
$ |
2,198 |
|
|
$ |
1,476 |
|
Work in process |
|
|
1,781 |
|
|
|
2,266 |
|
Raw materials |
|
|
4,464 |
|
|
|
2,638 |
|
|
|
|
|
|
|
|
Total manufactured |
|
|
8,443 |
|
|
|
6,380 |
|
Hammers |
|
|
1,434 |
|
|
|
1,016 |
|
Drive pipe |
|
|
420 |
|
|
|
716 |
|
Rental supplies |
|
|
2,261 |
|
|
|
1,845 |
|
Chemicals and drilling fluids |
|
|
3,236 |
|
|
|
2,673 |
|
Rig parts and related inventory |
|
|
9,985 |
|
|
|
9,762 |
|
Coiled tubing and related inventory |
|
|
1,014 |
|
|
|
1,627 |
|
Shop supplies and related inventory |
|
|
5,416 |
|
|
|
4,596 |
|
|
|
|
|
|
|
|
Total inventories |
|
$ |
32,209 |
|
|
$ |
28,615 |
|
|
|
|
|
|
|
|
NOTE 5 PROPERTY AND OTHER INTANGIBLE ASSETS
Property and equipment is comprised of the following as of December 31 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation |
|
|
|
|
|
|
|
|
|
Period |
|
|
2007 |
|
|
2006 |
|
Land |
|
|
|
|
|
$ |
2,040 |
|
|
$ |
1,810 |
|
Building and improvements |
|
15-20 years |
|
|
|
6,986 |
|
|
|
5,392 |
|
Transportation equipment |
|
3-10 years |
|
|
|
26,132 |
|
|
|
22,744 |
|
Drill pipe and rental equipment |
|
3-20 years |
|
|
|
350,202 |
|
|
|
321,821 |
|
Drilling, workover and pulling rigs |
|
20 years |
|
|
|
127,725 |
|
|
|
120,517 |
|
Machinery and equipment |
|
3-20 years |
|
|
|
157,626 |
|
|
|
105,926 |
|
Furniture, computers, software and leasehold improvements |
|
3-10 years |
|
|
|
5,817 |
|
|
|
3,522 |
|
Construction in progress equipment |
|
|
N/A |
|
|
|
27,148 |
|
|
|
2,269 |
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
703,676 |
|
|
|
584,001 |
|
Less: accumulated depreciation |
|
|
|
|
|
|
(77,008 |
) |
|
|
(29,743 |
) |
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net |
|
|
|
|
|
$ |
626,668 |
|
|
$ |
554,258 |
|
|
|
|
|
|
|
|
|
|
|
|
The net book value of equipment recorded under capital leases was $285,000 and $1.0 million as
of December 31, 2007 and 2006, respectively.
Other intangible assets are as follows as of December 31 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization |
|
|
|
|
|
|
|
|
|
|
|
Period |
|
|
2007 |
|
|
2006 |
|
Intellectual property |
|
10-20 years |
|
|
$ |
1,629 |
|
|
$ |
1,009 |
|
Non-compete agreements |
|
3-5 years |
|
|
|
2,852 |
|
|
|
4,580 |
|
Customer relationships |
|
10-15 years |
|
|
|
33,528 |
|
|
|
27,552 |
|
Patents |
|
12-15 years |
|
|
|
2,560 |
|
|
|
3,327 |
|
Other intangible assets |
|
2-10 years |
|
|
|
829 |
|
|
|
847 |
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
41,398 |
|
|
|
37,315 |
|
Less: accumulated amortization |
|
|
|
|
|
|
(6,218 |
) |
|
|
(4,475 |
) |
|
|
|
|
|
|
|
|
|
|
|
Other intangibles assets, net |
|
|
|
|
|
$ |
35,180 |
|
|
$ |
32,840 |
|
|
|
|
|
|
|
|
|
|
|
|
47
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
|
Gross |
|
|
Accumulated |
|
|
Gross |
|
|
Accumulated |
|
|
|
Value |
|
|
Amortization |
|
|
Value |
|
|
Amortization |
|
Intellectual property |
|
$ |
1,629 |
|
|
$ |
410 |
|
|
$ |
1,009 |
|
|
$ |
349 |
|
Non-compete agreements |
|
|
2,852 |
|
|
|
1,367 |
|
|
|
4,580 |
|
|
|
2,707 |
|
Customer relationships |
|
|
33,528 |
|
|
|
3,497 |
|
|
|
27,552 |
|
|
|
789 |
|
Patents |
|
|
2,560 |
|
|
|
423 |
|
|
|
3,327 |
|
|
|
203 |
|
Other intangible assets |
|
|
829 |
|
|
|
521 |
|
|
|
847 |
|
|
|
427 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
41,398 |
|
|
$ |
6,218 |
|
|
$ |
37,315 |
|
|
$ |
4,475 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization expense related to other intangibles was $4.1 million, $1.9 million and $1.5
million for the years ended December 31, 2007, 2006 and 2005, respectively. Future amortization of
intangible assets at December 31, 2007 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible Amortization by Period |
|
|
|
Years Ended December 31, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012 and |
|
|
|
2008 |
|
|
2009 |
|
|
2010 |
|
|
2011 |
|
|
Thereafter |
|
Intellectual property |
|
$ |
96 |
|
|
$ |
96 |
|
|
$ |
96 |
|
|
$ |
96 |
|
|
$ |
835 |
|
Non-compete agreements |
|
|
627 |
|
|
|
494 |
|
|
|
291 |
|
|
|
48 |
|
|
|
25 |
|
Customer relationships |
|
|
3,227 |
|
|
|
3,227 |
|
|
|
3,227 |
|
|
|
3,227 |
|
|
|
17,123 |
|
Patents |
|
|
202 |
|
|
|
202 |
|
|
|
202 |
|
|
|
202 |
|
|
|
1,329 |
|
Other intangible assets |
|
|
107 |
|
|
|
90 |
|
|
|
79 |
|
|
|
30 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Intangible Amortization |
|
$ |
4,259 |
|
|
$ |
4,109 |
|
|
$ |
3,895 |
|
|
$ |
3,603 |
|
|
$ |
19,314 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 6 INCOME TAXES
We had income before income taxes of $41.7 million, $35.9 million and $8.5 million for U.S.
tax purposes for the years ended December 31, 2007, 2006 and 2005, respectively. We also had
income before income taxes of $37.6 million and $11.1 million reported in non-U.S. countries for
the years ended December 31, 2007 and 2006, respectively. We treat the withholding taxes incurred
by our U.S. subsidiaries in foreign countries as foreign tax, and we anticipate using those tax
payments to offset U.S. tax.
The income tax provision consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Current income tax expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
$ |
6,814 |
|
|
$ |
5,865 |
|
|
$ |
123 |
|
State |
|
|
1,053 |
|
|
|
898 |
|
|
|
595 |
|
Foreign |
|
|
12,959 |
|
|
|
2,442 |
|
|
|
626 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,826 |
|
|
|
9,205 |
|
|
|
1,344 |
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
|
7,081 |
|
|
|
(946 |
) |
|
|
|
|
State |
|
|
349 |
|
|
|
573 |
|
|
|
|
|
Foreign |
|
|
587 |
|
|
|
2,588 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,017 |
|
|
|
2,215 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
28,843 |
|
|
$ |
11,420 |
|
|
$ |
1,344 |
|
|
|
|
|
|
|
|
|
|
|
We are required to file a consolidated U.S. federal income tax return. We pay foreign income
taxes in Argentina related to our Drilling and Completion operations and in Mexico related to
Oilfield Services revenues from Matyep.
48
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
The following table reconciles the U.S. statutory tax rate to our actual tax rate:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Statutory income tax rate |
|
|
35.0 |
% |
|
|
35.0 |
% |
|
|
34.0 |
% |
State taxes, net of federal benefit |
|
|
1.8 |
|
|
|
2.1 |
|
|
|
6.1 |
|
Valuation allowances |
|
|
|
|
|
|
(57.7 |
) |
|
|
(98.7 |
) |
Nondeductible items, permanent differences and other |
|
|
(0.4 |
) |
|
|
44.9 |
|
|
|
74.4 |
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate |
|
|
36.4 |
% |
|
|
24.3 |
% |
|
|
15.8 |
% |
|
|
|
|
|
|
|
|
|
|
Significant components of deferred income tax assets as of December 31, were as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
Deferred income tax assets: |
|
|
|
|
|
|
|
|
Net future (taxable) deductible items |
|
$ |
874 |
|
|
$ |
899 |
|
Share-based compensation |
|
|
1,898 |
|
|
|
578 |
|
Net operating loss carryforwards |
|
|
2,681 |
|
|
|
1,698 |
|
Foreign tax credits |
|
|
|
|
|
|
2,420 |
|
A-C Reorganization Trust and Product Liability Trust |
|
|
4,099 |
|
|
|
5,500 |
|
|
|
|
|
|
|
|
Total deferred income tax assets |
|
|
9,552 |
|
|
|
11,095 |
|
|
Deferred income tax liabilities |
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
(37,795 |
) |
|
|
(28,226 |
) |
|
|
|
|
|
|
|
Net deferred income tax liabilities |
|
$ |
(28,243 |
) |
|
$ |
(17,131 |
) |
|
|
|
|
|
|
|
|
Net current deferred income tax asset |
|
$ |
1,847 |
|
|
$ |
2,822 |
|
Net noncurrent deferred income tax liability |
|
|
(30,090 |
) |
|
|
(19,953 |
) |
|
|
|
|
|
|
|
Net deferred income tax liabilities |
|
$ |
(28,243 |
) |
|
$ |
(17,131 |
) |
|
|
|
|
|
|
|
Net future tax-deductible items relate primarily to timing differences. Timing differences
are differences between the tax basis of assets and liabilities and their reported amounts in the
financial statements that will result in differences between income for tax purposes and income for
financial statement purposes in future years.
The Tax Reform Act of 1986 contains provisions that limit the utilization of net operating
loss and tax credit carry forwards if there has been a change of ownership as described in
Section 382 of the Internal Revenue Code. Such a change of ownership may limit our utilization of
our net operating loss and tax credit carryforwards, and could be triggered by a public offering or
by subsequent sales of securities by us or our stockholders. This provision has limited the amount
of net operating losses available to us currently. Net operating loss carryforwards for tax
purposes at December 31, 2007 and 2006 were $7.7 million and $4.9 million, respectively, expiring
through 2024.
Prior to 2006, we did not record an asset for the U.S. foreign tax credits as we believed they
would not be recoverable based on our taxable income. We now project that all of the U.S. foreign
tax credits will be utilized against U.S. income tax.
Our 1988 Plan of Reorganization established the A-C Reorganization Trust to settle claims and
to make distributions to creditors and certain stockholders. We transferred cash and certain other
property to the A-C Reorganization Trust on December 2, 1988. Payments made by us to the A-C
Reorganization Trust did not generate tax deductions for us upon the transfer but generate
deductions for us as the A-C Reorganization Trust makes payments to holders of claims and for
administrative expenses. The Plan of Reorganization also created a trust to process and liquidate
product liability claims. Payments made by the A-C Reorganization Trust to the Product Liability
Trust did not generate current tax deductions for us upon the payment but generates deductions for
us as the Product Liability Trust makes payments to liquidate claims or incurs administrative
expenses. We believe the aforementioned trusts are grantor trusts and therefore we include the
income or loss of these trusts in our income or loss for tax purposes. The income or loss of these
trusts is not included in our results of operations for financial reporting purposes.
A valuation allowance is established for deferred tax assets when management, based upon
available information, considers it more likely than not that a benefit from such assets will not
be realized. As of December 31, 2007 and 2006, the valuation allowance was zero.
49
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
Approximately $9.7 million and $5.5 million of ad valorem, franchise, income, sales and other
tax accruals are included in our accrued expense balances of $20.5 million and $17.0 million as of
December 31, 2007 and 2006, respectively.
We adopted the provisions of FIN 48 on January 1, 2007. This interpretation clarifies the
accounting for uncertain tax positions and requires companies to recognize the impact of a tax
position in their financial statements, if that position is more likely than not of being sustained
on audit, based on the technical merits of the position. The adoption of FIN 48 did not have any
impact on the total liabilities or stockholders equity.
NOTE 7 DEBT
Our long-term debt consists of the following as of December 31 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
Senior notes |
|
$ |
505,000 |
|
|
$ |
255,000 |
|
Bridge loan |
|
|
|
|
|
|
300,000 |
|
Bank term loans |
|
|
4,926 |
|
|
|
7,302 |
|
Revolving line of credit |
|
|
|
|
|
|
|
|
Seller notes |
|
|
2,350 |
|
|
|
900 |
|
Notes payable to former directors |
|
|
32 |
|
|
|
32 |
|
Equipment & vehicle installment notes |
|
|
595 |
|
|
|
3,502 |
|
Insurance premium financing notes |
|
|
1,707 |
|
|
|
1,025 |
|
Obligations under non-compete agreements |
|
|
110 |
|
|
|
270 |
|
Capital lease obligations |
|
|
14 |
|
|
|
414 |
|
|
|
|
|
|
|
|
Total debt |
|
|
514,734 |
|
|
|
568,445 |
|
Less: current maturities of long-term debt |
|
|
6,434 |
|
|
|
6,999 |
|
|
|
|
|
|
|
|
Long-term debt |
|
$ |
508,300 |
|
|
$ |
561,446 |
|
|
|
|
|
|
|
|
Our weighted average interest rate for all of our outstanding debt was approximately 8.7% as
of December 31, 2007 and 9.8% as of December 31, 2006.
Maturities of debt obligations as of December 31, 2007 are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt |
|
|
Capital Leases |
|
|
Total |
|
Year Ending: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008 |
|
$ |
6,420 |
|
|
$ |
14 |
|
|
$ |
6,434 |
|
December 31, 2009 |
|
|
2,250 |
|
|
|
|
|
|
|
2,250 |
|
December 31, 2010 |
|
|
700 |
|
|
|
|
|
|
|
700 |
|
December 31, 2011 |
|
|
350 |
|
|
|
|
|
|
|
350 |
|
December 31, 2012 |
|
|
|
|
|
|
|
|
|
|
|
|
Thereafter |
|
|
505,000 |
|
|
|
|
|
|
|
505,000 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
514,720 |
|
|
$ |
14 |
|
|
$ |
514,734 |
|
|
|
|
|
|
|
|
|
|
|
Senior notes, bank loans and line of credit agreements
On January 18, 2006 and August 14, 2006, we closed on private offerings, to qualified
institutional buyers pursuant to Rule 144A under the Securities Act of 1933, of $160.0 and $95.0
million aggregate principal amount of our senior notes, respectively. The senior notes are due
January 15, 2014 and bear interest at 9.0%. The proceeds were used to fund the acquisitions of
Specialty and DLS, to repay existing debt and for general corporate purposes.
In January 2007, we closed on a private offering, to qualified institutional buyers pursuant
to Rule 144A under the Securities Act, of $250.0 million principal amount of 8.5% senior notes due
2017. The proceeds of the senior notes offering, together with a portion of the proceeds of our
concurrent common stock offering, were used to repay the debt outstanding under our $300.0 million
bridge loan facility which we incurred to finance our acquisition of substantially all the assets
of OGR.
On December 18, 2006, we closed on a $300.0 million senior unsecured bridge loan. The bridge
loan was due 18 months after closing and had a weighted average interest rate of 10.6%. The bridge
loan, which was repaid on January 29, 2007, was used to fund the acquisition of OGR.
50
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
On January 18, 2006, we also executed an amended and restated credit agreement which provided
for a $25.0 million revolving line of credit with a maturity of January 2010. Our January 2006
amended and restated credit agreement contained customary events of default and financial covenants
and limits our ability to incur additional indebtedness, make capital expenditures, pay dividends
or make other distributions, create liens and sell assets. Our obligations under the January 2006
amended and restated credit agreement are secured by substantially all of our assets excluding the
DLS assets, but including 2/3 of our shares of DLS. On April 26, 2007, we entered into a Second
Amended and Restated Credit Agreement, which increased our revolving line of credit to $62.0
million, and had a final maturity date of April 26, 2012. On December 3, 2007, we entered into a
First Amendment to Second Amended and Restated Credit Agreement, which increased our revolving line
of credit to $90.0 million. The amended and restated credit agreement contains customary events of
default and financial covenants and limits our ability to incur additional indebtedness, make
capital expenditures, pay dividends or make other distributions, create liens and sell assets. Our
obligations under the amended and restated credit agreement are secured by substantially all of our
assets located in the United States. As of December 31, 2007 and 2006, no amounts were borrowed on
the facility but availability is reduced by outstanding letters of credit of $8.4 million and $9.7
million, respectively.
As part of our acquisition of DLS, we assumed various bank loans with floating interest rates
based on LIBOR plus a margin and terms ranging from 2 to 5 years. The weighted average interest
rates on these loans was 6.7% and 7.0% as of December 31, 2007 and 2006, respectively. The bank
loans are denominated in U.S. dollars and the outstanding amount due as of December 31, 2007 and
2006 was $4.9 million and $7.3 million, respectively.
Notes payable
As part of the acquisition of Mountain Compressed Air, Inc., or MCA, in 2001, we issued a note
to the sellers of MCA in the original amount of $2.2 million accruing interest at a rate of 5.75%
per annum. The note was reduced to $1.5 million as a result of the settlement of a legal action
against the sellers in 2003. In March 2005, we reached an agreement with the sellers and holders
of the note as a result of an action brought against us by the sellers. Under the terms of the
agreement, we paid the holders of the note $1.0 million in cash, and agreed to pay an additional
$350,000 on June 1, 2006, and an additional $150,000 on June 1, 2007, in settlement of all claims.
As of December 31, 2007 and 2006 the outstanding amounts due were $0 and $150,000, respectively.
In connection with the acquisition of Rogers, we issued to the seller a note in the amount of
$750,000. The note bears interest at 5.0% and is due April 3, 2009. In connection with the
purchase of Coker, we issued to the seller a note in the amount of $350,000. The note bears
interest at 8.25% and is due June, 29, 2008. In connection with the purchase of Diggar, we issued
to the seller a note in the amount of $750,000. The note bears interest at 6.0% and is due July
26, 2008. In connection with the purchase of Rebel, we issued to the sellers notes in the amount
of $500,000. The notes bear interest at 5.0% and are due October 23, 2008
In 2000 we compensated directors, including current directors Nederlander and Toboroff, who
served on the board of directors from 1989 to March 31, 1999 without compensation, by issuing
promissory notes totaling $325,000. The notes bear interest at the rate of 5.0%. As of December
31, 2007 and 2006, the principal and accrued interest on these notes totaled approximately $32,000.
We have various rig and equipment financing loans with interest rates ranging from 7.8% to
8.7% and terms of 2 to 5 years. As of December 31, 2007 and 2006, the outstanding balances for rig
and equipment financing loans were $595,000 and $3.5 million, respectively.
In April 2006 and August 2006, we obtained insurance premium financings in the amount of $1.9
million and $896,000 with fixed interest rates of 5.6% and 6.0%, respectively. Under terms of the
agreements, amounts outstanding are paid over 10 month and 11 month repayment schedules. The
outstanding balance of these notes was approximately $1.0 million as of December 31, 2006. In
April 2007 and August 2007, we obtained insurance premium financings in the amount of $3.2 million
and $1.3 with fixed interest rates of 5.9% and 5.7%, respectively. Under terms of the agreements,
amounts outstanding are paid over 11 month repayment schedules. The outstanding balance of these
notes was approximately $1.7 million as of December 31, 2007.
51
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
Other debt
In connection with the purchase of Tubular, we agreed to pay a total of $1.2 million to the
seller in exchange for a non-compete agreement. Monthly payments of $20,576 were due under this
agreement through January 31, 2007. In connection with the purchase of Safco-Oil Field Products,
Inc., or Safco, we also agreed to pay a total of $150,000 to the sellers in exchange for a
non-compete agreement. We were required to make annual payments of $50,000 through September 30,
2007. In connection with the purchase of Capcoil, we agreed to pay a total of $500,000 to two
management employees in exchange for non-compete agreements. We are required to make annual
payments of $110,000 through May 2008. Total amounts due under these non-compete agreements as of
December 31, 2007 and 2006 were $110,000 and $270,000, respectively.
We also have various capital leases with terms that expire in 2008. As of December 31, 2007
and 2006, amounts outstanding under capital leases were $14,000 and $414,000, respectively.
NOTE 8 COMMITMENTS AND CONTINGENCIES
We have placed orders for capital equipment totaling $82.7 million to be received and paid for
through 2008. Approximately $46.2 million is for drilling and service rigs for our Drilling and
Completion segment, $26.0 million is for six new coiled tubing units and related equipment for our
Oilfield Services segment, $5.3 million is for rental equipment, principally drill pipe, for our
Rental Services segment and $5.2 million is for casing and tubing tools and equipment. The orders
are subject to cancellation with minimal loss of prior cash deposits, if any.
We rent office space and certain other facilities and shop yards for equipment storage and
maintenance. Facility rent expense for the years ended December 31, 2007, 2006 and 2005 was $2.7
million, $1.6 million and $987,000, respectively.
At December 31, 2007, future minimum rental commitments for all operating leases are as
follows (in thousands):
|
|
|
|
|
Years Ending: |
|
|
|
|
December 31, 2008 |
|
$ |
2,618 |
|
December 31, 2009 |
|
|
1,633 |
|
December 31, 2010 |
|
|
721 |
|
December 31, 2011 |
|
|
437 |
|
December 31, 2012 |
|
|
156 |
|
Thereafter |
|
|
376 |
|
|
|
|
|
Total |
|
$ |
5,941 |
|
|
|
|
|
NOTE 9 STOCKHOLDERS EQUITY
As of January 1, 2005, in relation to the acquisition of Downhole Injection Services, LLC, or
Downhole, we executed a business development agreement with CTTV Investments LLC, an affiliate of
ChevronTexaco Inc., whereby we issued 20,000 shares of our common stock to CTTV and further agreed
to issue up to an additional 60,000 shares to CTTV contingent upon our subsidiaries receiving
certain levels of revenues in 2005 from ChevronTexaco and its affiliates. CTTV was a minority
owner of Downhole, which we acquired in 2004. Based on the terms of the agreement, no additional
shares have been issued.
During 2005, we issued 223,114 and 168,161 shares of our common stock in relation to the Delta
and Capcoil acquisitions, respectively (see Note 3).
In August 2005, our stockholders approved an amendment to our certificate of incorporation to
increase the authorized number of shares of our common stock from 20 million to 100 million and to
increase our authorized preferred stock from 10 million shares to 25 million shares and, we completed a secondary public offering in which we sold 1,761,034
shares for approximately $15.5 million, net of expenses.
We also had options and warrants exercised during 2005. Those exercises resulted in 1,076,154
shares of our common stock being issued for approximately $1.4 million.
52
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
During 2006, we issued 125,285, 2.5 million, 246,761 and 3.2 million shares of our common
stock in relation to the Rogers, DLS, Petro Rental and OGR asset acquisitions, respectively (see
Note 3).
On August 14, 2006 we closed on a public offering of 3,450,000 shares of our common stock at a
public offering price of $14.50 per share. Net proceeds from the public offering of approximately
$46.3 million were used to fund a portion of our acquisition of DLS.
During 2006, we had options and warrants exercised in 2006, which resulted in 1,851,377 shares
of our common stock being issued for approximately $6.3 million. We recognized approximately $3.4
million of compensation expense related to stock options in 2006 that was recorded as capital in
excess of par value (see Note 1). We also recorded approximately $6.4 million of tax benefit
related to our stock compensation plans.
In January 2007 we closed on a public offering of 6.0 million shares of our common stock at a
public offering price of $17.65 per share. Net proceeds from the public offering, together with
the proceeds of our concurrent senior notes offering, were used to repay the debt outstanding under
our $300.0 million bridge loan facility, which we incurred to finance the OGR acquisition and for
general corporate purposes.
We also had restricted stock award grants, and options and warrants exercised during 2007,
which resulted in 882,624 shares of our common stock being issued for approximately $3.3 million.
We recognized approximately $4.9 million of compensation expense related to share based payments
that was recorded as capital in excess of par value (see Note 1). We also recorded approximately
$1.7 million of tax benefit related to our stock compensation plans.
NOTE 10 STOCK OPTIONS
In 2000, we issued stock options and promissory notes to certain current and former directors
as compensation for services as directors (See Note 7), and our Board of Directors granted stock
options to these same individuals. Options to purchase 4,800 shares of our common stock were
granted with an exercise price of $13.75 per share. These options vested immediately and may be
exercised any time prior to March 28, 2010. As of December 31, 2007, 4,000 of the stock options
remain outstanding. No compensation expense has been recorded for these options that were issued
with an exercise price equal to the fair value of the common stock at the date of grant.
On May 31, 2001, the Board granted to Leonard Toboroff, one of our directors, an option to
purchase 100,000 shares of our common stock at $2.50 per share, exercisable for 10 years from
October 15, 2001. The option was granted for services provided by Mr. Toboroff to Oil Quip
Rentals, Inc., or Oil Quip, prior to the merger, including providing financial advisory services,
assisting in Oil Quips capital structure and assisting Oil Quip in finding strategic acquisition
opportunities. We recorded compensation expense of $500,000 for the issuance of the option for the
year ended December 31, 2001. As of December 31, 2007, all of the stock options have been
exercised.
The 2003 Incentive Stock Plan (2003 Plan), as amended, permits us to grant to our key
employees and outside directors various forms of stock incentives, including, among others,
incentive and non-qualified stock options and restricted stock. The 2003 Plan is administered by
the Compensation Committee of the Board, which consists of two or more directors appointed by the
Board. The following benefits may be granted under the 2003 Plan: (a) stock appreciation rights;
(b) restricted stock; (c) performance awards; (d) incentive stock options; (e) nonqualified stock
options; and (f) other stock-based awards. Stock incentive terms are not to be in excess of ten
years. The maximum number of shares that may be issued under the 2003 Plan shall be the lesser of
3,000,000 shares and 15% of the total number of shares of common stock outstanding.
The 2006 Incentive Plan (2006 Plan), was approved by our stockholders in November 2006. The
2006 Plan is administered by the Compensation Committee of the Board, which consists of two or more
directors appointed by the Board. The maximum number of shares of the Companys common stock, par
value $0.01 per share (Common Stock), that may be issued under the 2006 Plan is equal to
1,500,000 shares, subject to adjustment in the event of stock splits and certain other corporate
events. The 2006 Plan provides for the grant of any or all of the following types of awards: (i)
stock options, including incentive stock options and non-qualified stock options; (ii) bonus stock;
(iii) restricted stock awards; (iv) performance awards; and (v) other stock-based awards. Except
with respect to awards of incentive stock options, all employees, consultants and non-employee
directors of the Company and its affiliates are eligible to participate in the 2006 Plan. The term
of each Award shall be for such period as may be determined by the Committee; provided, that in no
event shall the term of any Award exceed a period of ten (10) years from the date of its grant.
53
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
A summary of our stock option activity and related information is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
|
|
December 31, 2006 |
|
|
December 31, 2005 |
|
|
|
Shares |
|
|
Weighted Ave. |
|
|
Shares |
|
|
Weighted Ave. |
|
|
Shares |
|
|
Weighted Avg. |
|
|
|
Under |
|
|
Exercise |
|
|
Under |
|
|
Exercise |
|
|
Under |
|
|
Exercise |
|
|
|
Option |
|
|
Price |
|
|
Option |
|
|
Price |
|
|
Option |
|
|
Price |
|
Beginning balance |
|
|
1,350,365 |
|
|
$ |
6.88 |
|
|
|
2,860,867 |
|
|
$ |
5.10 |
|
|
|
1,215,000 |
|
|
$ |
3.20 |
|
Granted |
|
|
220,000 |
|
|
|
21.83 |
|
|
|
15,000 |
|
|
|
14.74 |
|
|
|
1,695,000 |
|
|
|
6.44 |
|
Canceled |
|
|
(17,334 |
) |
|
|
8.45 |
|
|
|
(54,567 |
) |
|
|
5.97 |
|
|
|
(15,300 |
) |
|
|
3.33 |
|
Exercised |
|
|
(566,268 |
) |
|
|
5.86 |
|
|
|
(1,470,935 |
) |
|
|
3.54 |
|
|
|
(33,833 |
) |
|
|
2.80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance |
|
|
986,763 |
|
|
$ |
10.77 |
|
|
|
1,350,365 |
|
|
$ |
6.88 |
|
|
|
2,860,867 |
|
|
$ |
5.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The total intrinsic value of stock options (the amount by which the market price of the
underlying stock on the date of exercise exceeds the exercise price of the option) exercised was
approximately $6.6 million, $18.8 million and $343,000 during the years ended December 31, 2007,
2006 and 2005, respectively. As of December 31, 2007, there was approximately $2.4 million of
total unrecognized compensation cost related to stock option, with $939,000, $918,000 and $532,000
to be recognized during the years ended December 31, 2008, 2009 and 2010, respectively.
The following table summarizes additional information about our stock options outstanding as
of December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding |
|
Options Exercisable |
|
|
|
|
|
|
|
|
Weighted Average |
|
Weighted |
|
|
|
|
|
Weighted Average |
|
Weighted |
Range of |
|
|
|
|
|
Remaining |
|
Average |
|
|
|
|
|
Remaining |
|
Average |
Exercise |
|
Number of |
|
Contractual Life |
|
Exercise |
|
Number of |
|
Contractual Life |
|
Exercise |
Prices |
|
options |
|
(in Years) |
|
Price |
|
options |
|
(in Years) |
|
Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2.75-4.87
|
|
|
|
380,699 |
|
|
|
7.02 |
|
|
$ |
4.14 |
|
|
|
380,699 |
|
|
|
7.02 |
|
|
$ |
4.14 |
|
|
10.85-14.74
|
|
|
|
386,064 |
|
|
|
7.92 |
|
|
|
11.01 |
|
|
|
381,069 |
|
|
|
7.92 |
|
|
|
10.96 |
|
|
16.50-21.95
|
|
|
|
220,000 |
|
|
|
9.59 |
|
|
|
21.83 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.75-21.95
|
|
|
|
986,763 |
|
|
|
7.95 |
|
|
$ |
10.77 |
|
|
|
761,768 |
|
|
|
7.47 |
|
|
$ |
7.55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The aggregate pretax intrinsic value of stock options outstanding and exercisable was
approximately $5.5 million at December 31, 2007. The amount represents the value that would have
been received by the option holders had the respective options been exercised on December 31, 2007.
Restricted Stock Awards
In addition to stock options, our 2003 and 2006 Plans allow for the grant of restricted stock
awards (RSA). A time-lapse RSA is an award of common stock, where each unit represents the right
to receive at the end of a stipulated period one unrestricted share of stock with no exercise
price. The time-lapse RSA restrictions lapse periodically over an extended period of time not
exceeding 10 years. We determine the fair value of RSAs based on the market price of our common
stock on the date of grant. Compensation cost for RSAs is primarily recognized on a straight-line
basis over the vesting or service period and is net of forfeitures. A performance-based RSA is an
award of common stock, where each unit represents the right to receive one unrestricted share of
stock with no exercise price at the attainment of established performance criteria. During 2007, we granted
710,000 performance based RSAs with market conditions. The performance-based RSAs are granted, but
not earned and issued until certain annual total shareholder return criteria are attained over the
next 3 years. The fair value of the performance-based RSAs were based on third-party valuations.
54
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
The following table summarizes activity in our nonvested restricted stock awards:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
|
|
December 31, 2006 |
|
|
|
Number |
|
|
Weighted Ave. |
|
|
Number |
|
|
Weighted Ave. |
|
|
|
of |
|
|
Grant Date Fair |
|
|
of |
|
|
Grant Date Fair |
|
|
|
Shares |
|
|
Value Per Share |
|
|
Shares |
|
|
Value Per Share |
|
Beginning balance |
|
|
27,000 |
|
|
$ |
18.30 |
|
|
|
|
|
|
$ |
|
|
Granted |
|
|
996,203 |
|
|
|
17.44 |
|
|
|
27,000 |
|
|
|
18.30 |
|
Vested |
|
|
(30,000 |
) |
|
|
18.01 |
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance |
|
|
993,203 |
|
|
$ |
17.45 |
|
|
|
27,000 |
|
|
$ |
18.30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The total fair value of RSA shares that vested during 2007 was approximately $577,000. As of
December 31, 2007, there was approximately $13.9 million of total unrecognized compensation cost
related to nonvested RSAs, with $6.6 million, $5.0 million, $1.8 million, $278,000 and $208,000 to
be recognized during the years ended December 31, 2008, 2009, 2010, 2011 and 2012, respectively.
NOTE 11 STOCK PURCHASE WARRANTS
In conjunction with the MCA purchase by Oil Quip in February of 2001, MCA issued a common
stock warrant for 620,000 shares to a third-party investment firm that assisted us in its initial
identification and purchase of the MCA assets. The warrant entitles the holder to acquire up to
620,000 shares of common stock of MCA at an exercise price of $.01 per share over a nine-year
period commencing on February 7, 2001.
We issued two warrants (Warrants A and B) for the purchase of 233,000 total shares of our
common stock at an exercise price of $0.75 per share and one warrant for the purchase of 67,000
shares of our common stock at an exercise price of $5.00 per share (Warrant C) in connection with
our subordinated debt financing for MCA in 2001. Warrants A and B were paid off on December 7,
2004. Warrant C was exercised during November 2006.
On February 6, 2002, in connection with the acquisition of substantially all of the
outstanding stock of Strata, we issued a warrant for the purchase of 87,500 shares of our common
stock at an exercise price of $0.75 per share over the term of four years. The warrants were
exercised in August of 2005.
In connection with the Strata Acquisition, on February 19, 2003, we issued Energy Spectrum an
additional warrant to purchase 175,000 shares of our common stock at an exercise price of $0.75 per
share. The warrants were exercised in August of 2005.
In March 2004, we issued a warrant to purchase 340,000 shares of our common stock at an
exercise price of $2.50 per share to Morgan Joseph & Co., in consideration of financial advisory
services to be provided by Morgan Joseph pursuant to a consulting agreement. The warrants were
exercised in August 2005.
In April 2004, we issued warrants to purchase 20,000 shares of common stock at an exercise
price of $0.75 per share to Wells Fargo Credit, Inc., in connection with the extension of credit by
Wells Fargo Credit Inc. The warrants were exercised in August 2005.
In April 2004, we completed a private placement of 620,000 shares of common stock and warrants
to purchase 800,000 shares of common stock to the following investors: Christopher Engel; Donald
Engel; the Engel Defined Benefit Plan; RER Corp., a corporation wholly-owned by director Robert
Nederlander; and Leonard Toboroff, a director. The investors invested $1,550,000 in exchange for
620,000 shares of common stock for a purchase price equal to $2.50 per share, and invested $450,000
in exchange for warrants to purchase 800,000 shares of common stock at an exercise of $2.50 per
share, expiring on April 1, 2006. A total of 486,557 of these warrants were exercised in 2005 with
the remaining portion exercised during 2006.
55
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
In May 2004, we issued a warrant to purchase 3,000 shares of our common stock at an exercise
price of $4.75 per share to a consultant in consideration of financial advisory services to be
provided pursuant to a consulting agreement. The warrants were exercised in May 2004. This
consultant was also granted 16,000 warrants in May of 2004 exercisable at $4.65 per share. These
warrants were exercised in November of 2005. Warrants for 4,000 shares of our common stock at an
exercise price of $4.65 were also issued to this consultant in May 2004 and were exercised in
January 2007.
NOTE 12 CONDENSED CONSOLIDATED FINANCIAL INFORMATION
Set forth on the following pages are the condensed consolidating financial statements of (i)
Allis-Chalmers Energy Inc., (ii) its subsidiaries that are guarantors of the senior notes and
revolving credit facility and (iii) the subsidiaries that are not guarantors of the senior notes
and revolving credit facility (in thousands). Prior to the acquisition of DLS, all of our
subsidiaries were guarantors of our senior notes and revolving credit facility, the parent company
had no independent assets or operations, the guarantees were full and unconditional and joint and
several.
56
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiary |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors |
|
|
Adjustments |
|
|
Total |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
|
|
|
$ |
41,176 |
|
|
$ |
2,517 |
|
|
$ |
|
|
|
$ |
43,693 |
|
Trade receivables, net |
|
|
|
|
|
|
83,126 |
|
|
|
46,973 |
|
|
|
(5 |
) |
|
|
130,094 |
|
Inventories |
|
|
|
|
|
|
15,699 |
|
|
|
16,510 |
|
|
|
|
|
|
|
32,209 |
|
Intercompany receivables |
|
|
76,583 |
|
|
|
|
|
|
|
|
|
|
|
(76,583 |
) |
|
|
|
|
Note receivable from affiliate |
|
|
8,270 |
|
|
|
|
|
|
|
|
|
|
|
(8,270 |
) |
|
|
|
|
Prepaid expenses and other |
|
|
7,731 |
|
|
|
2,564 |
|
|
|
1,603 |
|
|
|
|
|
|
|
11,898 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
92,584 |
|
|
|
142,565 |
|
|
|
67,603 |
|
|
|
(84,858 |
) |
|
|
217,894 |
|
Property and equipment, net |
|
|
|
|
|
|
477,055 |
|
|
|
149,613 |
|
|
|
|
|
|
|
626,668 |
|
Goodwill |
|
|
|
|
|
|
136,875 |
|
|
|
1,523 |
|
|
|
|
|
|
|
138,398 |
|
Other intangible assets, net |
|
|
552 |
|
|
|
34,572 |
|
|
|
56 |
|
|
|
|
|
|
|
35,180 |
|
Debt issuance costs, net |
|
|
14,228 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,228 |
|
Note receivable from affiliates |
|
|
16,380 |
|
|
|
|
|
|
|
|
|
|
|
(16,380 |
) |
|
|
|
|
Investments in affiliates |
|
|
824,410 |
|
|
|
|
|
|
|
|
|
|
|
(824,410 |
) |
|
|
|
|
Other assets |
|
|
15 |
|
|
|
4,977 |
|
|
|
16,225 |
|
|
|
|
|
|
|
21,217 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
948,169 |
|
|
$ |
796,044 |
|
|
$ |
235,020 |
|
|
$ |
(925,648 |
) |
|
$ |
1,053,585 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt |
|
$ |
32 |
|
|
$ |
4,026 |
|
|
$ |
2,376 |
|
|
$ |
|
|
|
$ |
6,434 |
|
Trade accounts payable |
|
|
|
|
|
|
16,815 |
|
|
|
20,654 |
|
|
|
(5 |
) |
|
|
37,464 |
|
Accrued salaries, benefits and payroll taxes |
|
|
|
|
|
|
3,712 |
|
|
|
11,571 |
|
|
|
|
|
|
|
15,283 |
|
Accrued interest |
|
|
17,709 |
|
|
|
33 |
|
|
|
75 |
|
|
|
|
|
|
|
17,817 |
|
Accrued expenses |
|
|
1,660 |
|
|
|
7,127 |
|
|
|
11,758 |
|
|
|
|
|
|
|
20,545 |
|
Intercompany payables |
|
|
|
|
|
|
433,116 |
|
|
|
1,185 |
|
|
|
(434,301 |
) |
|
|
|
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
8,270 |
|
|
|
(8,270 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
19,401 |
|
|
|
464,829 |
|
|
|
55,889 |
|
|
|
(442,576 |
) |
|
|
97,543 |
|
Long-term debt, net of current maturities |
|
|
505,750 |
|
|
|
|
|
|
|
2,550 |
|
|
|
|
|
|
|
508,300 |
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
16,380 |
|
|
|
(16,380 |
) |
|
|
|
|
Deferred income tax liability |
|
|
8,658 |
|
|
|
13,809 |
|
|
|
7,623 |
|
|
|
|
|
|
|
30,090 |
|
Other long-term liabilities |
|
|
31 |
|
|
|
242 |
|
|
|
3,050 |
|
|
|
|
|
|
|
3,323 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
|
533,840 |
|
|
|
478,880 |
|
|
|
85,492 |
|
|
|
(458,956 |
) |
|
|
639,256 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock |
|
|
351 |
|
|
|
3,526 |
|
|
|
42,963 |
|
|
|
(46,489 |
) |
|
|
351 |
|
Capital in excess of par value |
|
|
326,095 |
|
|
|
167,508 |
|
|
|
74,969 |
|
|
|
(242,477 |
) |
|
|
326,095 |
|
Retained earnings |
|
|
87,883 |
|
|
|
146,130 |
|
|
|
31,596 |
|
|
|
(177,726 |
) |
|
|
87,883 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
414,329 |
|
|
|
317,164 |
|
|
|
149,528 |
|
|
|
(466,692 |
) |
|
|
414,329 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stock
holders equity |
|
$ |
948,169 |
|
|
$ |
796,044 |
|
|
$ |
235,020 |
|
|
$ |
(925,648 |
) |
|
$ |
1,053,585 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
57
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Year Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiary |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors |
|
|
Adjustments |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
|
|
|
$ |
355,172 |
|
|
$ |
215,795 |
|
|
$ |
|
|
|
$ |
570,967 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs |
|
|
|
|
|
|
185,617 |
|
|
|
155,833 |
|
|
|
|
|
|
|
341,450 |
|
Depreciation |
|
|
|
|
|
|
39,659 |
|
|
|
11,255 |
|
|
|
|
|
|
|
50,914 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin |
|
|
|
|
|
|
129,896 |
|
|
|
48,707 |
|
|
|
|
|
|
|
178,603 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative |
|
|
4,349 |
|
|
|
44,439 |
|
|
|
9,834 |
|
|
|
|
|
|
|
58,622 |
|
Gain on capillary asset sale |
|
|
|
|
|
|
(8,868 |
) |
|
|
|
|
|
|
|
|
|
|
(8,868 |
) |
Amortization |
|
|
46 |
|
|
|
3,988 |
|
|
|
33 |
|
|
|
|
|
|
|
4,067 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from
operations |
|
|
(4,395 |
) |
|
|
90,337 |
|
|
|
38,840 |
|
|
|
|
|
|
|
124,782 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in
affiliates, net of tax |
|
|
102,208 |
|
|
|
|
|
|
|
|
|
|
|
(102,208 |
) |
|
|
|
|
Interest, net |
|
|
(47,677 |
) |
|
|
2,796 |
|
|
|
(1,394 |
) |
|
|
|
|
|
|
(46,275 |
) |
Other |
|
|
304 |
|
|
|
336 |
|
|
|
136 |
|
|
|
|
|
|
|
776 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income
(expense) |
|
|
54,835 |
|
|
|
3,132 |
|
|
|
(1,258 |
) |
|
|
(102,208 |
) |
|
|
(45,499 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
50,440 |
|
|
|
93,469 |
|
|
|
37,582 |
|
|
|
(102,208 |
) |
|
|
79,283 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes |
|
|
|
|
|
|
(16,085 |
) |
|
|
(12,758 |
) |
|
|
|
|
|
|
(28,843 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
50,440 |
|
|
$ |
77,384 |
|
|
$ |
24,824 |
|
|
$ |
(102,208 |
) |
|
$ |
50,440 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
58
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Year Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis- |
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
Chalmers |
|
|
|
|
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
(Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors) |
|
|
Adjustments |
|
|
Total |
|
Cash Flows from Operating Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
50,440 |
|
|
$ |
77,384 |
|
|
$ |
24,824 |
|
|
$ |
(102,208 |
) |
|
$ |
50,440 |
|
Adjustments to reconcile net income
(loss) to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation & amortization |
|
|
46 |
|
|
|
43,647 |
|
|
|
11,288 |
|
|
|
|
|
|
|
54,981 |
|
Amortization and write-off of
deferred financing fees |
|
|
3,197 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,197 |
|
Stock based compensation |
|
|
4,863 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,863 |
|
Allowance for bad debts |
|
|
|
|
|
|
730 |
|
|
|
|
|
|
|
|
|
|
|
730 |
|
Equity earnings in affiliates |
|
|
(102,208 |
) |
|
|
|
|
|
|
|
|
|
|
102,208 |
|
|
|
|
|
Deferred taxes |
|
|
7,430 |
|
|
|
|
|
|
|
587 |
|
|
|
|
|
|
|
8,017 |
|
Gain on sale of equipment |
|
|
|
|
|
|
(2,182 |
) |
|
|
(141 |
) |
|
|
|
|
|
|
(2,323 |
) |
Gain on capillary asset sale |
|
|
|
|
|
|
(8,868 |
) |
|
|
|
|
|
|
|
|
|
|
(8,868 |
) |
Changes in operating assets and
liabilities, net of acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in accounts receivables |
|
|
|
|
|
|
(17,823 |
) |
|
|
(13,002 |
) |
|
|
|
|
|
|
(30,825 |
) |
Increase in inventories |
|
|
|
|
|
|
(4,286 |
) |
|
|
(1,089 |
) |
|
|
|
|
|
|
(5,375 |
) |
(Increase) Decrease in other
current assets |
|
|
(3,003 |
) |
|
|
12,075 |
|
|
|
(870 |
) |
|
|
|
|
|
|
8,202 |
|
(Increase) decrease in other assets |
|
|
242 |
|
|
|
|
|
|
|
(4,734 |
) |
|
|
|
|
|
|
(4,492 |
) |
(Decrease) increase in accounts
payable |
|
|
(31 |
) |
|
|
2,234 |
|
|
|
8,529 |
|
|
|
|
|
|
|
10,732 |
|
(Decrease) increase in accrued
interest |
|
|
5,954 |
|
|
|
33 |
|
|
|
(37 |
) |
|
|
|
|
|
|
5,950 |
|
(Decrease) increase in accrued
expenses |
|
|
1,525 |
|
|
|
(3,912 |
) |
|
|
3,895 |
|
|
|
|
|
|
|
1,508 |
|
(Decrease) increase in other
liabilities |
|
|
(273 |
) |
|
|
(77 |
) |
|
|
3,050 |
|
|
|
|
|
|
|
2,700 |
|
Increase in accrued salaries,
benefits and payroll taxes |
|
|
|
|
|
|
355 |
|
|
|
3,676 |
|
|
|
|
|
|
|
4,031 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by
operating activities |
|
|
(31,818 |
) |
|
|
99,310 |
|
|
|
35,976 |
|
|
|
|
|
|
|
103,468 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions, net of cash acquired |
|
|
|
|
|
|
(41,000 |
) |
|
|
|
|
|
|
|
|
|
|
(41,000 |
) |
Purchase of investment interests |
|
|
|
|
|
|
(498 |
) |
|
|
|
|
|
|
|
|
|
|
(498 |
) |
Purchase of property and equipment |
|
|
|
|
|
|
(84,240 |
) |
|
|
(28,911 |
) |
|
|
|
|
|
|
(113,151 |
) |
Deposits on asset commitments |
|
|
|
|
|
|
|
|
|
|
(11,488 |
) |
|
|
|
|
|
|
(11,488 |
) |
Notes receivable from affiliates |
|
|
(6,809 |
) |
|
|
|
|
|
|
|
|
|
|
6,809 |
|
|
|
|
|
Proceeds from sale of capillary assets |
|
|
|
|
|
|
16,250 |
|
|
|
|
|
|
|
|
|
|
|
16,250 |
|
Proceeds from sale of property and
equipment |
|
|
|
|
|
|
12,666 |
|
|
|
145 |
|
|
|
|
|
|
|
12,811 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) in
investing activities |
|
|
(6,809 |
) |
|
|
(96,822 |
) |
|
|
(40,254 |
) |
|
|
6,809 |
|
|
|
(137,076 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
59
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Other Subsidiaries |
|
|
Consolidating |
|
|
|
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
(Non-Guarantors) |
|
|
Adjustments |
|
|
Consolidated Total |
|
|
Cash Flows from Financing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of
long-term debt |
|
|
250,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
250,000 |
|
Payments on long-term debt |
|
|
(300,000 |
) |
|
|
(6,587 |
) |
|
|
(3,158 |
) |
|
|
|
|
|
|
(309,745 |
) |
Accounts receivable from affiliates |
|
|
(8,674 |
) |
|
|
|
|
|
|
|
|
|
|
8,674 |
|
|
|
|
|
Accounts payable to affiliates |
|
|
|
|
|
|
7,506 |
|
|
|
1,168 |
|
|
|
(8,674 |
) |
|
|
|
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
6,809 |
|
|
|
(6,809 |
) |
|
|
|
|
Proceeds from issuance of common
stock, net of offering costs |
|
|
100,055 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100,055 |
|
Proceeds from exercise of options
and warrants |
|
|
3,319 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,319 |
|
Tax benefit on stock plans |
|
|
1,719 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,719 |
|
Debt issuance costs |
|
|
(7,792 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,792 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used)
by financing activities |
|
|
38,627 |
|
|
|
919 |
|
|
|
4,819 |
|
|
|
(6,809 |
) |
|
|
37,556 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash
equivalents |
|
|
|
|
|
|
3,407 |
|
|
|
541 |
|
|
|
|
|
|
|
3,948 |
|
Cash and cash equivalents at
beginning of year |
|
|
|
|
|
|
37,769 |
|
|
|
1,976 |
|
|
|
|
|
|
|
39,745 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end
of period |
|
$ |
|
|
|
$ |
41,176 |
|
|
$ |
2,517 |
|
|
$ |
|
|
|
$ |
43,693 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
60
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Subsidiary |
|
|
Consolidating |
|
|
|
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Non-Guarantors |
|
|
Adjustments |
|
|
Consolidated Total |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
|
|
|
$ |
37,769 |
|
|
$ |
1,976 |
|
|
$ |
|
|
|
$ |
39,745 |
|
Trade receivables, net |
|
|
|
|
|
|
62,089 |
|
|
|
33,971 |
|
|
|
(294 |
) |
|
|
95,766 |
|
Inventories |
|
|
|
|
|
|
13,194 |
|
|
|
15,421 |
|
|
|
|
|
|
|
28,615 |
|
Intercompany receivables |
|
|
67,909 |
|
|
|
|
|
|
|
|
|
|
|
(67,909 |
) |
|
|
|
|
Note receivable from affiliate |
|
|
5,502 |
|
|
|
|
|
|
|
|
|
|
|
(5,502 |
) |
|
|
|
|
Prepaid expenses and other |
|
|
5,703 |
|
|
|
10,200 |
|
|
|
733 |
|
|
|
|
|
|
|
16,636 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
79,114 |
|
|
|
123,252 |
|
|
|
52,101 |
|
|
|
(73,705 |
) |
|
|
180,762 |
|
Property and equipment, net |
|
|
|
|
|
|
422,297 |
|
|
|
131,961 |
|
|
|
|
|
|
|
554,258 |
|
Goodwill |
|
|
|
|
|
|
124,331 |
|
|
|
1,504 |
|
|
|
|
|
|
|
125,835 |
|
Other intangible assets, net |
|
|
598 |
|
|
|
32,153 |
|
|
|
89 |
|
|
|
|
|
|
|
32,840 |
|
Debt issuance costs, net |
|
|
9,633 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,633 |
|
Note receivable from affiliates |
|
|
12,339 |
|
|
|
|
|
|
|
|
|
|
|
(12,339 |
) |
|
|
|
|
Investments in affiliates |
|
|
722,202 |
|
|
|
|
|
|
|
|
|
|
|
(722,202 |
) |
|
|
|
|
Other assets |
|
|
257 |
|
|
|
4,719 |
|
|
|
22 |
|
|
|
|
|
|
|
4,998 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
824,143 |
|
|
$ |
706,752 |
|
|
$ |
185,677 |
|
|
$ |
(808,246 |
) |
|
$ |
908,326 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt |
|
$ |
32 |
|
|
$ |
3,809 |
|
|
$ |
3,158 |
|
|
$ |
|
|
|
$ |
6,999 |
|
Trade accounts payable |
|
|
31 |
|
|
|
13,510 |
|
|
|
12,125 |
|
|
|
|
|
|
|
25,666 |
|
Accrued salaries, benefits and
payroll taxes |
|
|
|
|
|
|
2,993 |
|
|
|
7,895 |
|
|
|
|
|
|
|
10,888 |
|
Accrued interest |
|
|
11,755 |
|
|
|
|
|
|
|
112 |
|
|
|
|
|
|
|
11,867 |
|
Accrued expenses |
|
|
135 |
|
|
|
9,247 |
|
|
|
7,863 |
|
|
|
(294 |
) |
|
|
16,951 |
|
Intercompany payables |
|
|
|
|
|
|
425,610 |
|
|
|
17 |
|
|
|
(425,627 |
) |
|
|
|
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
5,502 |
|
|
|
(5,502 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
11,953 |
|
|
|
455,169 |
|
|
|
36,672 |
|
|
|
(431,423 |
) |
|
|
72,371 |
|
Long-term debt, net of current
maturities |
|
|
555,750 |
|
|
|
770 |
|
|
|
4,926 |
|
|
|
|
|
|
|
561,446 |
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
12,339 |
|
|
|
(12,339 |
) |
|
|
|
|
Deferred income tax liability |
|
|
2,203 |
|
|
|
10,714 |
|
|
|
7,036 |
|
|
|
|
|
|
|
19,953 |
|
Other long-term liabilities |
|
|
304 |
|
|
|
319 |
|
|
|
|
|
|
|
|
|
|
|
623 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
|
570,210 |
|
|
|
466,972 |
|
|
|
60,973 |
|
|
|
(443,762 |
) |
|
|
654,393 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock |
|
|
282 |
|
|
|
3,526 |
|
|
|
42,963 |
|
|
|
(46,489 |
) |
|
|
282 |
|
Capital in excess of par value |
|
|
216,208 |
|
|
|
167,508 |
|
|
|
74,969 |
|
|
|
(242,477 |
) |
|
|
216,208 |
|
Retained earnings |
|
|
37,443 |
|
|
|
68,746 |
|
|
|
6,772 |
|
|
|
(75,518 |
) |
|
|
37,443 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders
equity |
|
|
253,933 |
|
|
|
239,780 |
|
|
|
124,704 |
|
|
|
(364,484 |
) |
|
|
253,933 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and
stock holders equity |
|
$ |
824,143 |
|
|
$ |
706,752 |
|
|
$ |
185,677 |
|
|
$ |
(808,246 |
) |
|
$ |
908,326 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Year Ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Subsidiary |
|
|
Consolidating |
|
|
|
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Non-Guarantors |
|
|
Adjustments |
|
|
Consolidated Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
|
|
|
$ |
241,474 |
|
|
$ |
69,490 |
|
|
$ |
|
|
|
$ |
310,964 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs |
|
|
|
|
|
|
134,638 |
|
|
|
50,941 |
|
|
|
|
|
|
|
185,579 |
|
Depreciation |
|
|
|
|
|
|
16,198 |
|
|
|
4,063 |
|
|
|
|
|
|
|
20,261 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin |
|
|
|
|
|
|
90,638 |
|
|
|
14,486 |
|
|
|
|
|
|
|
105,124 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative |
|
|
2,643 |
|
|
|
30,651 |
|
|
|
2,242 |
|
|
|
|
|
|
|
35,536 |
|
Amortization |
|
|
46 |
|
|
|
1,801 |
|
|
|
11 |
|
|
|
|
|
|
|
1,858 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from
operations |
|
|
(2,689 |
) |
|
|
58,186 |
|
|
|
12,233 |
|
|
|
|
|
|
|
67,730 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in
affiliates, net of tax |
|
|
58,077 |
|
|
|
|
|
|
|
|
|
|
|
(58,077 |
) |
|
|
|
|
Interest, net |
|
|
(19,807 |
) |
|
|
67 |
|
|
|
(597 |
) |
|
|
|
|
|
|
(20,337 |
) |
Other |
|
|
45 |
|
|
|
97 |
|
|
|
(489 |
) |
|
|
|
|
|
|
(347 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income
(expense) |
|
|
38,315 |
|
|
|
164 |
|
|
|
(1,086 |
) |
|
|
(58,077 |
) |
|
|
(20,684 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income
taxes |
|
|
35,626 |
|
|
|
58,350 |
|
|
|
11,147 |
|
|
|
(58,077 |
) |
|
|
47,046 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes |
|
|
|
|
|
|
(7,045 |
) |
|
|
(4,375 |
) |
|
|
|
|
|
|
(11,420 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
35,626 |
|
|
$ |
51,305 |
|
|
$ |
6,772 |
|
|
$ |
(58,077 |
) |
|
$ |
35,626 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
62
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Year Ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis- |
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
Chalmers |
|
|
|
|
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
(Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors) |
|
|
Adjustments |
|
|
Total |
|
Cash Flows from Operating Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
35,626 |
|
|
$ |
51,305 |
|
|
$ |
6,772 |
|
|
$ |
(58,077 |
) |
|
$ |
35,626 |
|
Adjustments to reconcile net income
(loss) to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation & amortization |
|
|
46 |
|
|
|
17,999 |
|
|
|
4,074 |
|
|
|
|
|
|
|
22,119 |
|
Amortization & write-off of
deferred financing fees |
|
|
1,527 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,527 |
|
Stock based compensation |
|
|
3,394 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,394 |
|
Provision for bad debts |
|
|
|
|
|
|
781 |
|
|
|
|
|
|
|
|
|
|
|
781 |
|
Imputed interest |
|
|
|
|
|
|
355 |
|
|
|
|
|
|
|
|
|
|
|
355 |
|
Equity earnings in affiliates |
|
|
(58,077 |
) |
|
|
|
|
|
|
|
|
|
|
58,077 |
|
|
|
|
|
Deferred taxes |
|
|
(619 |
) |
|
|
247 |
|
|
|
2,587 |
|
|
|
|
|
|
|
2,215 |
|
Gain on sale of equipment |
|
|
|
|
|
|
(2,428 |
) |
|
|
(16 |
) |
|
|
|
|
|
|
(2,444 |
) |
Changes in operating assets and
liabilities, net of acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in accounts receivables |
|
|
|
|
|
|
(23,144 |
) |
|
|
(31 |
) |
|
|
|
|
|
|
(23,175 |
) |
(Increase) decrease in inventories |
|
|
|
|
|
|
(2,989 |
) |
|
|
352 |
|
|
|
|
|
|
|
(2,637 |
) |
(Increase) decrease in other
current assets |
|
|
(2,482 |
) |
|
|
4,120 |
|
|
|
867 |
|
|
|
|
|
|
|
2,505 |
|
(Increase) decrease in other assets |
|
|
296 |
|
|
|
101 |
|
|
|
(89 |
) |
|
|
|
|
|
|
308 |
|
(Decrease) increase in accounts
payable |
|
|
(82 |
) |
|
|
3,587 |
|
|
|
(5,842 |
) |
|
|
|
|
|
|
(2,337 |
) |
(Decrease) increase in accrued
interest |
|
|
11,508 |
|
|
|
(45 |
) |
|
|
(81 |
) |
|
|
|
|
|
|
11,382 |
|
(Decrease) increase in accrued
expenses |
|
|
(390 |
) |
|
|
1,633 |
|
|
|
(371 |
) |
|
|
|
|
|
|
872 |
|
(Decrease) in other liabilities |
|
|
(31 |
) |
|
|
(193 |
) |
|
|
|
|
|
|
|
|
|
|
(224 |
) |
(Decrease) increase in accrued
salaries, benefits and payroll
taxes |
|
|
(1,951 |
) |
|
|
2,780 |
|
|
|
2,563 |
|
|
|
|
|
|
|
3,392 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by
operating activities |
|
|
(11,235 |
) |
|
|
54,109 |
|
|
|
10,785 |
|
|
|
|
|
|
|
53,659 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions, net of cash acquired |
|
|
(528,167 |
) |
|
|
3,649 |
|
|
|
(2,054 |
) |
|
|
|
|
|
|
(526,572 |
) |
Notes receivable from affiliates |
|
|
(585 |
) |
|
|
|
|
|
|
|
|
|
|
585 |
|
|
|
|
|
Purchase of property and equipment |
|
|
|
|
|
|
(33,930 |
) |
|
|
(5,767 |
) |
|
|
|
|
|
|
(39,697 |
) |
Proceeds from sale of property and
equipment |
|
|
|
|
|
|
6,730 |
|
|
|
151 |
|
|
|
|
|
|
|
6,881 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) in
investing activities |
|
|
(528,752 |
) |
|
|
(23,551 |
) |
|
|
(7,670 |
) |
|
|
585 |
|
|
|
(559,388 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
63
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis- |
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
Chalmers |
|
|
|
|
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
(Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors) |
|
|
Adjustments |
|
|
Total |
|
Cash Flows from Financing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from long-term debt |
|
|
555,000 |
|
|
|
2,820 |
|
|
|
|
|
|
|
|
|
|
|
557,820 |
|
Payments on long-term debt |
|
|
(42,414 |
) |
|
|
(9,875 |
) |
|
|
(1,741 |
) |
|
|
|
|
|
|
(54,030 |
) |
Payments on related party debt |
|
|
|
|
|
|
(3,031 |
) |
|
|
|
|
|
|
|
|
|
|
(3,031 |
) |
Net (payments) borrowings on lines
of credit |
|
|
(6,400 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,400 |
) |
Accounts receivable from affiliates |
|
|
(16,444 |
) |
|
|
|
|
|
|
|
|
|
|
16,444 |
|
|
|
|
|
Accounts payable to affiliates |
|
|
|
|
|
|
16,427 |
|
|
|
17 |
|
|
|
(16,444 |
) |
|
|
|
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
585 |
|
|
|
(585 |
) |
|
|
|
|
Proceeds from issuance of common
stock, net of offering costs |
|
|
46,297 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
46,297 |
|
Proceeds from exercise of options
and warrants |
|
|
6,321 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,321 |
|
Tax benefit on stock plans |
|
|
6,440 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,440 |
|
Debt issuance costs |
|
|
(9,863 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,863 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used)
by financing activities |
|
|
538,937 |
|
|
|
6,341 |
|
|
|
(1,139 |
) |
|
|
(585 |
) |
|
|
543,554 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash
equivalents |
|
|
(1,050 |
) |
|
|
36,899 |
|
|
|
1,976 |
|
|
|
|
|
|
|
37,825 |
|
Cash and cash equivalents at
beginning of year |
|
|
1,050 |
|
|
|
870 |
|
|
|
|
|
|
|
|
|
|
|
1,920 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end
of period |
|
$ |
|
|
|
$ |
37,769 |
|
|
$ |
1,976 |
|
|
$ |
|
|
|
$ |
39,745 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 13 RELATED PARTY TRANSACTIONS
DLS was acquired from three British Virgin Island corporations. Two of our Directors;
Alejandro P. Bulgheroni and Carlos A. Bulgheroni, indirectly beneficially own substantially all of
the shares of the DLS sellers. DLS largest customer is Pan American Energy which is a joint
venture by British Petroleum and Bridas Corporation. Alejandro P. Bulgheroni and Carlos A.
Bulgheroni, indirectly beneficially own substantially all of the shares of the Bridas Corporation.
We purchased approximately $3.5 million of general oilfield supplies and materials from Ralow
Services, Inc., or Ralow in 2007 for our Rental Services segment. Ralow is owned by Brad A. Adams
and Bruce A. Adams who are brothers of Burt A. Adams, one of our directors and our former President
and Chief Operating Officer. In addition, Brad A. Adams and Bruce A. Adams were employed as
officers of Rental during 2007.
64
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
NOTE 14 SEGMENT INFORMATION
On January 31, 2008, we created the positions of Senior Vice President Oilfield Services
and Senior Vice President Rental Services. In conjunction with this organizational change, we
reviewed the presentation of our reporting segments during the first quarter of 2008. Based on
this review, we determined that our operational performance would be segmented and reviewed by the
Oilfield Services, Drilling and Completion and Rental Services segments. The Oilfield Services
segment includes our underbalanced drilling, directional drilling, tubular services and production
services operations. The Drilling and Completion segment includes our international drilling
operations. As a result, we realigned our financial reporting segments and will now report the
following operations as separate, distinct reporting segments: (1) Oilfield Services, (2) Drilling
and Completion and (3) Rental Services. Our historical segment data previously reported for the
years ended December 31, 2007, 2006 and 2005 have been restated to conform to the new presentation.
All of the segments provide services to the energy industry. The revenues, operating income
(loss), depreciation and amortization, capital expenditures and assets of each of the reporting
segments plus the corporate function are reported below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
233,986 |
|
|
$ |
189,953 |
|
|
$ |
102,963 |
|
Drilling & Completion |
|
|
215,795 |
|
|
|
69,490 |
|
|
|
|
|
Rental Services |
|
|
121,186 |
|
|
|
51,521 |
|
|
|
5,059 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
570,967 |
|
|
$ |
310,964 |
|
|
$ |
108,022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss): |
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
53,218 |
|
|
$ |
43,157 |
|
|
$ |
17,896 |
|
Drilling & Completion |
|
|
38,839 |
|
|
|
12,233 |
|
|
|
|
|
Rental Services |
|
|
49,139 |
|
|
|
26,293 |
|
|
|
1,300 |
|
General corporate |
|
|
(16,414 |
) |
|
|
(13,953 |
) |
|
|
(5,678 |
) |
|
|
|
|
|
|
|
|
|
|
Total income from operations |
|
$ |
124,782 |
|
|
$ |
67,730 |
|
|
$ |
13,518 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and Amortization Expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
16,838 |
|
|
$ |
10,434 |
|
|
$ |
5,751 |
|
Drilling & Completion |
|
|
11,288 |
|
|
|
4,074 |
|
|
|
|
|
Rental Services |
|
|
26,353 |
|
|
|
7,268 |
|
|
|
492 |
|
General corporate |
|
|
502 |
|
|
|
343 |
|
|
|
118 |
|
|
|
|
|
|
|
|
|
|
|
Total depreciation and amortization expense |
|
$ |
54,981 |
|
|
$ |
22,119 |
|
|
$ |
6,361 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures: |
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
48,610 |
|
|
$ |
29,077 |
|
|
$ |
16,651 |
|
Drilling & Completion |
|
|
28,911 |
|
|
|
5,770 |
|
|
|
|
|
Rental Services |
|
|
34,883 |
|
|
|
4,538 |
|
|
|
435 |
|
General corporate |
|
|
747 |
|
|
|
312 |
|
|
|
681 |
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures |
|
$ |
113,151 |
|
|
$ |
39,697 |
|
|
$ |
17,767 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Goodwill: |
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
30,493 |
|
|
$ |
18,199 |
|
|
$ |
12,417 |
|
Drilling & Completion |
|
|
1,523 |
|
|
|
1,504 |
|
|
|
|
|
Rental Services |
|
|
106,382 |
|
|
|
106,132 |
|
|
|
|
|
General corporate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total goodwill |
|
$ |
138,398 |
|
|
$ |
125,835 |
|
|
$ |
12,417 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
299,300 |
|
|
$ |
215,199 |
|
|
$ |
124,638 |
|
Drilling & Completion |
|
|
235,020 |
|
|
|
185,677 |
|
|
|
|
|
Rental Services |
|
|
454,216 |
|
|
|
453,802 |
|
|
|
8,034 |
|
General corporate |
|
|
65,049 |
|
|
|
53,648 |
|
|
|
4,683 |
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,053,585 |
|
|
$ |
908,326 |
|
|
$ |
137,355 |
|
|
|
|
|
|
|
|
|
|
|
65
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
339,476 |
|
|
$ |
231,852 |
|
|
$ |
101,261 |
|
International |
|
|
231,491 |
|
|
|
79,112 |
|
|
|
6,761 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
570,967 |
|
|
$ |
310,964 |
|
|
$ |
108,022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Long Lived Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
655,513 |
|
|
$ |
574,302 |
|
|
$ |
97,390 |
|
International |
|
|
180,178 |
|
|
|
153,262 |
|
|
|
4,313 |
|
|
|
|
|
|
|
|
|
|
|
Total long lived assets |
|
$ |
835,691 |
|
|
$ |
727,564 |
|
|
$ |
101,703 |
|
|
|
|
|
|
|
|
|
|
|
NOTE 15 SUPPLEMENTAL CASH FLOWS INFORMATION (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Interest paid |
|
$ |
40,363 |
|
|
$ |
8,571 |
|
|
$ |
3,924 |
|
|
|
|
|
|
|
|
|
|
|
Income taxes paid |
|
$ |
17,272 |
|
|
$ |
5,796 |
|
|
$ |
676 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other non-cash investing and financing transactions: |
|
|
|
|
|
|
|
|
|
|
|
|
Insurance premiums financed |
|
|
4,434 |
|
|
|
2,871 |
|
|
|
|
|
Purchase of equipment financed through assumption of debt or accounts payable |
|
|
|
|
|
|
|
|
|
|
592 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash investing and financing transactions in connection with acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of Property and equipment |
|
$ |
4,345 |
|
|
$ |
109,632 |
|
|
$ |
1,750 |
|
Fair value of goodwill and other intangibles |
|
|
350 |
|
|
|
4,010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
4,695 |
|
|
$ |
113,642 |
|
|
$ |
1,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Value of common stock, issued |
|
$ |
|
|
|
$ |
94,980 |
|
|
$ |
1,750 |
|
Seller financed note |
|
|
1,600 |
|
|
|
750 |
|
|
|
|
|
Deferred tax liability |
|
|
3,095 |
|
|
|
17,662 |
|
|
|
|
|
Accrued expenses |
|
|
|
|
|
|
250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
4,695 |
|
|
$ |
113,642 |
|
|
$ |
1,750 |
|
|
|
|
|
|
|
|
|
|
|
NOTE 16 LEGAL MATTERS
We are named from time to time in legal proceedings related to our activities prior to our
bankruptcy in 1988; however, we believe that we were discharged from liability for all such claims
in the bankruptcy and believe the likelihood of a material loss relating to any such legal
proceeding is remote.
We are involved in various other legal proceedings in the ordinary course of business. The
legal proceedings are at different stages; however, we believe that the likelihood of material loss
relating to any such legal proceeding is remote.
66
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
NOTE 17 SUBSEQUENT EVENTS
On January 23, 2008, we entered into an Agreement and Plan of Merger with Bronco Drilling
Company, Inc., or Bronco, whereby Bronco will become a wholly-owned subsidiary of Allis-Chalmers.
The merger agreement, which was approved by our Board of Directors and the Board of Directors of
Bronco, provides that the Bronco stockholders will receive aggregate merger consideration with a
value of approximately $437.8 million, consisting of (a) $280.0 million in cash and (b) shares of
our common stock, par value $0.01 per share, having an aggregate value of approximately $157.8
million. The number of shares of our common stock to be issued will be based on the average
closing price of our common stock for the ten-trading day period ending two days prior to the
closing. Completion of the merger is conditioned upon, among other things, adoption of the merger
agreement by Broncos stockholders and approval by our stockholders of the issuance of shares of
our common stock to be used as merger consideration.
In order to finance some or all of the cash component of the merger consideration, the
repayment of outstanding Bronco debt and transaction expenses, we expect to incur debt of up to
$350.0 million. We intend to obtain up to $350.0 million from either (1) a permanent debt
financing of up to $350.0 million or (2) if the permanent debt financing cannot be consummated
prior to the closing date of the merger, the draw down under a senior unsecured bridge loan
facility in an aggregate principal amount of up to $350.0 million to be arranged by RBC Capital
Markets Corporation and Goldman Sachs Credit Partners L.P., acting as joint lead arrangers and
joint bookrunners. We executed a commitment letter, dated January 28, 2008, with Royal Bank of
Canada and Goldman Sachs who have each, subject to certain conditions, severally committed to
provide 50% of the loans under the senior unsecured bridge facility to us. This commitment for the
bridge loan facility will terminate on July 31, 2008, if we have not drawn the bridge facility by
such date and the merger is not consummated by such date. The commitment may also terminate prior
to July 31, 2008, if the merger is abandoned or a material condition to the merger is not satisfied
or we breach our obligations under the commitment letter. We may use the proceeds of the bridge
facility to finance the cash component of the merger consideration, repay outstanding Bronco debt
and pay transaction expenses.
On January 29, 2008, Burt A. Adams resigned as our President and Chief Operating Officer,
effective February 28, 2008. Mr. Adams will remain as a member of our Board of Directors. On
January 29, 2008, Mark C. Patterson was elected our Senior Vice-President Rental Services. On
January 29, 2008, Terrence P. Keane was elected our Senior Vice-President Oilfield Services.
On January 31, 2008, we entered into an agreement with BCH Ltd., or BCH, to invest $40.0
million in cash in BCH in the form of a 15% Convertible Subordinated Secured debenture. The
debenture is convertible, at any time, at our option into 49% of the common equity of BCH. At the
end of two years, we have the option to acquire the remaining 51% of BCH from its parent, BrazAlta
Resources Corp., or BrazAlta, based on an independent valuation from a mutually acceptable
investment bank. BCH is a Canadian-based oilfield services company engaged in contract drilling
operations exclusively in Brazil.
On February 15, 2008, through our DLS subsidiary in Argentina, we entered into a $25.0 million
import finance facility with a bank. Borrowings under this facility will be used to fund a portion
of the purchase price of the new drilling and service rigs ordered for our Drilling and Completion
segment. The facility is available for borrowings until December 31, 2008. Each drawdown shall be
repaid over four years in equal semi-annual instalments beginning one year after each disbursement
with the final principal payment due not later than March 15, 2013. Interest is payable every six
months. The import finance facility is unsecured and contains customary events of default and
financial covenants and limits DLS ability to incur additional indebtedness, make capital
expenditures, create liens and sell assets.
NOTE 18 SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED) (in thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
135,900 |
|
|
$ |
143,362 |
|
|
$ |
147,881 |
|
|
$ |
143,824 |
|
Operating income |
|
|
31,470 |
|
|
|
41,474 |
|
|
|
31,148 |
|
|
|
20,690 |
|
Net income |
|
$ |
12,165 |
|
|
$ |
19,504 |
|
|
$ |
12,987 |
|
|
$ |
5,784 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.38 |
|
|
$ |
0.56 |
|
|
$ |
0.37 |
|
|
$ |
0.17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
0.37 |
|
|
$ |
0.55 |
|
|
$ |
0.37 |
|
|
$ |
0.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
67
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year 2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
47,911 |
|
|
$ |
61,383 |
|
|
$ |
86,772 |
|
|
$ |
114,898 |
|
Operating income |
|
|
8,856 |
|
|
|
16,108 |
|
|
|
19,336 |
|
|
|
23,430 |
|
Net income |
|
$ |
4,423 |
|
|
$ |
9,594 |
|
|
$ |
11,253 |
|
|
$ |
10,356 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.26 |
|
|
$ |
0.53 |
|
|
$ |
0.52 |
|
|
$ |
0.41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
0.23 |
|
|
$ |
0.50 |
|
|
$ |
0.50 |
|
|
$ |
0.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Item 9.01. Financial Statements and Exhibits.
(d) Exhibits
|
|
|
|
|
Exhibit
Number |
|
Description |
|
23.1 |
|
|
Consent of Independent Registered Public Accounting Firm |
68
SIGNATURES
Pursuant to the requirements 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 hereunto duly
authorized.
|
|
|
|
|
|
ALLIS-CHALMERS ENERGY INC.
|
|
|
By: |
/s/ Theodore
F. Pound III
|
|
|
|
Name: |
Theodore F. Pound III |
|
|
|
Title: |
General Counsel and Secretary |
|
|
Dated: July 25, 2008
69
EXHIBIT INDEX
|
|
|
Exhibit Number |
|
Description |
23.1
|
|
Consent of Independent Registered Public Accounting Firm |