ITEM 1.
BUSINESS
We provide services and equipment to oil and natural gas exploration and production companies throughout the U.S. including Texas, Oklahoma, Louisiana, Arkansas, Pennsylvania, New Mexico, Colorado, offshore in the Gulf of Mexico, and internationally primarily in Argentina, Mexico and Brazil. We operate in three sectors of the oil and natural gas service industry: Oilfield Services; Drilling and Completion and Rental Services. Our central operating strategy is to provide high-quality, technologically advanced services and equipment. As a result of our commitment to customer service, we have developed strong relationships with many of the leading oil and natural gas companies, including both independents and majors.
Our growth strategy is focused on identifying and pursuing opportunities in markets we believe are growing faster than the overall oilfield services industry and opportunities which we believe help us to
mitigate cyclical risk by diversifying our cash flow. Over the past several years, we have significantly expanded the geographic scope of our operations and the range of services we provide through strategic acquisitions and organic growth. Our organic growth has primarily been achieved by expanding our geographic scope, acquiring complementary property and equipment, hiring personnel to service new regions and cross-selling our products and services. Since 2001, we have completed 24 acquisitions, including six in 2005, six in 2006, four in 2007 and one in 2008.
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, or the Exchange Act, are made available free of charge on our website at www.alchenergy.com as soon as reasonably practicable after we electronically file or furnish them to the Securities and Exchange Commission, or SEC.
Our Board of Directors has documented its governance practices by adopting several corporate governance policies. These governance policies, including our corporate governance principles and our code of business ethics and conduct, as well as the charters for the committees of our Board (Audit Committee, Compensation Committee and Corporate Governance and Nominating Committee) may be viewed on the investor relations section of our website. Copies of such documents will be sent to stockholders free of charge upon written request of the corporate secretary at the address shown on the cover page of this Form 10-K.
Information contained on or connected to our website is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing we make with the SEC.
Divisional and geographic financial information appears in “Item 8. Financial Information - Notes to Consolidated Financial Statements - Note 14.”
Our History
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We were incorporated in 1913 under Delaware law.
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We reorganized in bankruptcy in 1988 and sold all of our major businesses. From 1988 to May 2001 we had only one operating company in the equipment repair business.
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In May 2001, under new management we consummated a merger in which we acquired Oil Quip Rentals, Inc., or Oil Quip, and its wholly-owned subsidiary, Mountain Compressed Air, Inc., or MCA.
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In December 2001, we sold Houston Dynamic Services, Inc., our last pre-bankruptcy business.
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In February 2002, we acquired approximately 81% of the capital stock of Allis-Chalmers Tubular Services Inc., or Tubular, formerly known as Jens’ Oilfield Service, Inc. and substantially all of the capital stock of Strata Directional Technology, Inc., or Strata.
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In July 2003, we entered into a limited liability company operating agreement with M-I L.L.C., or M-I, a joint venture between Smith International and Schlumberger N.V., to form a Delaware limited liability company named AirComp LLC, or AirComp. Pursuant to this agreement, we owned 55% and M-I owned 45% of AirComp.
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In September 2004, we acquired the remaining 19% of the capital stock of Tubular.
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In September 2004, we acquired all of the outstanding stock of Safco-Oil Field Products, Inc., or Safco.
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In November 2004, AirComp acquired substantially all of the assets of Diamond Air Drilling Services, Inc. and Marquis Bit Co., LLC, which we refer to collectively as Diamond Air.
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In December 2004, we acquired Downhole Injection Services, LLC, or Downhole.
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In April 2005, we acquired all of the outstanding stock of Delta Rental Service, Inc., or Delta.
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In May 2005, we acquired all of the outstanding stock of Capcoil Tubing Services, Inc., or Capcoil.
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In July 2005, we acquired M-I’s interest in AirComp, and acquired the compressed air drilling assets of W. T. Enterprises, Inc., or W.T.
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Effective August 2005, we acquired all of the outstanding stock of Target Energy Inc., or Target.
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In September 2005, we acquired the casing and tubing assets of IHS/Spindletop, a division of Patterson Services, Inc., a subsidiary of RPC, Inc.
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In January 2006, we acquired all of the outstanding stock of Specialty Rental Tools, Inc., or Specialty.
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In April 2006, we acquired all of the outstanding stock of Rogers Oil Tool Services, Inc., or Rogers.
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In August 2006, we acquired all of the outstanding stock of DLS Drilling, Logistics & Services Corporation, or DLS.
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In October 2006, we acquired all of the outstanding stock of Petro-Rentals, Incorporated, or Petro Rentals.
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In December 2006, we acquired all of the outstanding stock of Tanus Argentina S.A., or Tanus.
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In December 2006, we acquired substantially all of the assets of Oil & Gas Rental Services, Inc., or OGR.
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In June 2007, we acquired all of the outstanding stock of Coker Directional, Inc., or Coker and merged it with Strata.
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In June 2007, we sold our capillary assets that were acquired in the Downhole and Capcoil acquisitions
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In July 2007, we acquired all of the outstanding stock of Diggar Tools, LLC, or Diggar and merged it with Strata.
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In October 2007, we acquired all of the outstanding stock of Rebel Rentals, Inc., or Rebel.
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In November 2007, we acquired substantially all the assets Diamondback Oilfield Services, Inc. or Diamondback.
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In August 2008, we sold our drill pipe tong manufacturing assets that we acquired in the acquisition of Rogers.
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In December 2008, we acquired all of the outstanding stock of BCH Ltd., or BCH.
As a result of these transactions, our prior results may not be indicative of current or future operations of those sectors.
Our Industry
The oilfield industry is highly cyclical. The most critical factor in assessing the outlook for the industry is the worldwide supply and demand for oil and the domestic supply and demand for natural gas. The industry is driven by commodity demand and corresponding price increases. As demand increases, producers raise their prices. The price escalation enables producers to increase their capital expenditures. The increased capital expenditures ultimately result in greater revenues and profits for services and equipment companies. The increased capital expenditures also ultimately result in greater production which historically has resulted in increased supplies and reduced prices.
Demand for our services generally increased from 2004 through 2007. Activity in the U.S. Gulf of Mexico, however decreased in the second half of 2007 due to the hurricane season and relocation of rigs to more attractive international markets. Demand for our services for most of 2008 was generally stable due to high oil and natural gas prices and the capital expenditures of the exploration and production companies. As a result, the number of active rigs drilling, or rig count, in the U.S. peaked at 2,031 in August of 2008 compared to 1,782 at the end of 2007. In the last quarter of 2008, the rig count in the U.S. began to drop due to the weakening U.S. economy, the decrease in oil and natural gas prices and the turmoil in the financial markets which affected the availability of capital for our customers. As of February 27, 2009, the U.S. rig count stood at 1,243.
Business Segments
Oilfield Services. We utilize state-of-the-art equipment to provide well planning and engineering services, directional drilling packages, downhole motor technology, well site directional supervision, exploratory and development re-entry drilling, downhole guidance services and other drilling services to our customers, including measurement-while-drilling (MWD) services. We provide compressed air equipment, chemicals and other specialized products for underbalanced drilling and production applications. We also provide specialized equipment and trained operators to perform a variety of pipe handling services, including installing casing and tubing, changing out drill pipe and retrieving production tubing for both onshore and offshore drilling and workover operations, which we refer to as tubular services. In addition, we provide a variety of quality production-related rental tools and equipment and services, including wire line services, land and offshore pumping services and coiled tubing.
According to Baker Hughes, as of February 27, 2009, 56% of all wells in the U.S. are drilled directionally and/or horizontally. We believe directional drilling offers several advantages over conventional drilling including: 1) improvement of total cumulative recoverable reserves; 2) improved reservoir production performance beyond conventional vertical wells; and 3) reduction of the number of field development wells.
All wells drilled for oil and natural gas require casing to be installed for drilling, and if the well is producing, tubing will be required in the completion phase. We currently provide tubular services primarily in Texas, Louisiana, Oklahoma and both onshore and offshore in the Gulf of Mexico and Mexico.
Underbalanced drilling shortens the time required to drill a well and enhances production by minimizing formation damage. There is a trend in the industry to drill, complete and workover wells with underbalanced operations. We currently have a combined fleet of approximately 260 compressors, boosters and foam units and we believe we are one of the largest providers of underbalanced drilling services in the United States. We also provide premium air hammers and bits to oil and natural gas companies for use in underbalanced drilling. Our broad and diversified product line enables us to compete in the underbalanced market with equipment and services packages engineered and customized to specifically meet customer requirements.
In 2007, we expanded our directional drilling capability by completing three acquisitions for approximately $37.3 million in total. These were Coker (June 2007), Diggar (July 2007) and Diamondback (November 2007). These acquisitions provided additional directional drillers, downhole motors, and MWD tools and enabled us to expand our presence in the Northern Rockies and the Mid-Continent areas. We currently maintain an inventory of approximately 330 drilling motors. Our straight-hole motors offer an opportunity to capture additional market share. We currently provide our directional drilling services in Texas, Oklahoma, Pennsylvania, Louisiana, North Dakota and offshore in the Gulf of Mexico.
We expanded our tubular services in September 2005 by acquiring the casing and tubing assets of IHS/Spindletop, a division of Patterson Services, Inc., a subsidiary of RPC, Inc. We paid $15.7 million for RPC, Inc.’s casing and tubing assets, which consisted of casing and tubing installation equipment, including hammers, elevators, trucks, pickups, power units, laydown machines, casing tools and torque turn equipment. The acquisition of RPC, Inc.’s casing and tubing assets increased our capability in tubular services and expanded our geographic capability. We opened new field offices in Corpus Christi, Texas, Kilgore, Texas, Lafayette, Louisiana and Houma, Louisiana. The acquisition allowed us to enter the East Texas and Louisiana market for casing and tubing services as well as offshore in the Gulf of Mexico. Additionally, the acquisition greatly expanded our premium tubing services. In April 2006 we acquired Rogers for a purchase price of approximately $13.7 million. Historically, Rogers rented, sold and serviced power drill pipe tongs and accessories and rental tongs for snubbing and well control applications and provided specialized tong operators for rental jobs. In August 2008, we sold the drill pipe tong manufacturing assets we acquired in the Rogers acquisition for approximately $7.5 million. In October 2007 we acquired Rebel Rentals, Inc. for a purchase price of approximately $7.3 million. Rebel owns an inventory of equipment used primarily for tubing installation services in the South Louisiana and Gulf Coast regions.
In July 2005, we purchased the compressed air drilling assets of W. T., operating in West Texas for $6.0 million. The acquired assets included air compressors, boosters, mist pumps, rolling stock and other equipment. We also acquired the remaining 45% equity interest in AirComp from M-I in July 2005. We
currently provide underbalanced drilling services in Texas, Arkansas, Oklahoma, New Mexico, Colorado, Utah and Pennsylvania.
We started offering production related services with the acquisition of Downhole, in December 2004, and the acquisition of Capcoil, in May 2005. In October 2006, we expanded our production services with the acquisition of Petro Rentals for a purchase price of approximately $33.6 million. Petro Rentals served both the onshore and offshore markets, providing a variety of quality rental tools and equipment and services, with an emphasis on production-related equipment and services, including wire line services and equipment, land and offshore pumping services and coiled tubing. On June 29, 2007, we sold our capillary tubing units and related equipment for approximately $16.3 million. We reported a gain of approximately $8.9 million. The assets sold represented a small portion of our Oilfield Services segment. We currently provide production services in Texas, Louisiana and Arkansas.
Drilling and Completion. We provide drilling, completion, workover and related services for oil and natural gas wells. We operate out of the San Jorge, Cuyan, Neuquen, Austral and Noroeste basins of Argentina and the Espirito Santo, Potiguar, Reconcavo and Sergipe basins of Brazil and in Bolivia. We also offer a wide variety of other oilfield services such as drilling fluids and completion fluids and engineering and logistics to complement our customers’ field organization.
Our Drilling and Completion segment was established with the acquisition of DLS in August 2006 for a purchase price of approximately $114.5 million. We expanded our Drilling and Completion segment with the acquisition of BCH, which operates in Brazil. In 2008, we invested $40.0 million into BCH via a 15% convertible subordinated secured debenture and we acquired the common stock of BCH for a total purchase price of $56.1 million. We currently operate a fleet of 74 land rigs, including 18 drilling rigs and 46 service rigs (workover and pulling units) in Argentina, seven drilling rigs and one service rig in Brazil and two drilling rigs in Bolivia. Argentine rig operations are generally conducted in remote regions of the country and require substantial infrastructure and support. In 2007, we placed orders for four drilling rigs and 16 service rigs. All of the service rigs and one of the drilling rigs were placed into service at various dates in 2008. A second drilling rig will be activated in March 2009 and the remaining two drilling rigs are expected to be delivered in the second quarter of 2009 for use in the U.S. for a customer operating in the Haynesville Shale. As of February 28, 2009, all of our rig fleet was actively marketed, except for one drilling rig that is presently inactive and is being refurbished and upgraded.
Rental Services. We provide specialized oilfield rental equipment, including premium drill pipe, spiral heavy weight drill pipe, tubing work strings, blow out preventors, choke manifolds and various valves and handling tools, for both onshore and offshore well drilling, completion and workover operations. Most wells drilled for oil and natural gas require some form of rental equipment in both the drilling and completion of a well. We have an inventory of specialized equipment, which includes double studded adapters, test plugs, wear bushings, adaptor spools, baskets, spacer spools and other assorted handling tools in various sizes to meet our customers’ demands. We charge customers for rental equipment on a daily basis. Our customers are liable for the cost of inspection, repairs and lost or damaged equipment. We currently provide rental equipment in Texas, Louisiana, Oklahoma, offshore in the Gulf of Mexico and internationally in Mexico, Columbia, Libya and Malaysia.
Our Rental Services segment was established with the acquisition of Safco in September 2004 and Delta in April 2005. We significantly expanded our Rental Services segment in January 2006 with the acquisition of Specialty for a purchase price of approximately $95.3 million. Specialty had been in the rental business for over 25 years, providing oil and natural gas operators and oilfield services companies with rental equipment. We further expanded this segment with the acquisition of substantially all the assets of OGR in December 2006 for a purchase price of approximately $342.4 million. The assets we acquired included an extensive inventory of premium rental equipment, including drill pipe, spiral heavy weight drill pipe, tubing work strings, landing strings, blow out preventors, choke manifolds and various valves and handling tools for oil and natural gas drilling. Included in the acquisition were OGR’s facilities in Morgan City, Louisiana and Victoria, Texas.
Competitive Strengths
We believe the following competitive strengths will enable us to capitalize on future opportunities:
Strategic position in high growth markets. We focus on markets we believe are growing faster than the overall oilfield services industry and in which we can capitalize on our competitive strengths. Pursuant to this strategy, we have become a significant provider of products and services in directional drilling, casing and tubing, underbalanced drilling, drilling and completion and rental services.
Strong relationships with diversified customer base. We have strong relationships with many of the major and independent oil and natural gas producers and service companies in Texas, Oklahoma, Louisiana, Arkansas, Pennsylvania, New Mexico, Colorado, offshore in the Gulf of Mexico, Argentina, Brazil and Mexico. Our largest customers include Pan American Energy, Apache Corporation, Repsol-YPF, Chesapeake Energy, Oxy, BP, ConocoPhilips, Anadarko Petroleum, Devon Energy, Materiales y Equipo Petroleo, or Matyep, TXCO Resources, Pioneer Natural Resources, North American Petroleum, Jones Energy Ltd, Drilex SA DE CV, Mariner Energy, El Paso Corporation, and Petroleo Brasileiro S.A, or Petrobras. Since 2002, we have broadened our customer base as a result of our acquisitions, technical expertise and reputation for quality customer service and by providing customers with technologically advanced equipment and highly skilled operating personnel.
Successful execution of growth strategy. Over the past seven years, we have grown both organically and through successful acquisitions of competing businesses. Since 2001, we have completed 24 acquisitions. We strive to improve the operating performance of our acquired businesses by increasing their asset utilization and operating efficiency. These acquisitions and organic growth, through our capital expenditures program, have expanded our geographic presence and customer base and, in turn, have enabled us to cross-sell various products and services.
Diversified and increased cash flow sources. We operate as a diversified oilfield service company through our three business segments. We believe that our product and service offerings and geographical presence through our three business segments provide us with diverse sources of cash flow. Our acquisition of DLS in Argentina in August 2006 and our acquisition of BCH in Brazil at the end of 2008, increased our international presence and we believe, provides more stable long-term contracts when compared to the volatility in the U.S. domestic market. Our acquisition of Petro Rentals in October 2006 significantly enhanced our production-related services and equipment provided by our Oilfield Services segment, and our acquisition of substantially all the assets of OGR in December 2006 expanded our Rental Services segment and increased our offshore and international operations.
Experienced management team. Our executive management team has extensive experience in the energy sector, and consequently has developed strong and longstanding relationships with many of the major and independent exploration and production companies.
Business Strategy
The key elements of our long-term strategy include:
Mitigate cyclical risk through balanced operations. We strive to mitigate cyclical risk across our lines of business by balancing our operations between onshore versus offshore; drilling versus production; rental tools versus service; domestic versus international; and natural gas versus crude oil. We will continue to shape our organic and acquisition growth efforts to provide further balance across these five categories. A key part of our strategy has been to increase our international operations because they increase our exposure to crude oil and provide opportunities for long-term contracts.
Expand geographically to provide greater access and service to key customer segments. We have locations in Texas, New Mexico, Colorado, Wyoming, Arkansas, Oklahoma, Louisiana and Pennsylvania in order to enhance our proximity to customers and more efficiently serve their needs. Our acquisition of DLS expanded our geographic footprint into Argentina and our acquisition of BCH expanded our geographic footprint into Brazil. While we will continue to evaluate locations to conveniently serve our
customers, due to the decrease in the rig count in late 2008 and 2009 in the U.S., we have begun to consolidate overlapping domestic operating yard locations in order to reduce costs.
Prudently pursue strategic acquisitions. To complement our organic growth, we have historically pursued strategic acquisitions which we believe are accretive to earnings, complement our products and services, provide new equipment and technology, expand our geographic footprint and market presence, and further diversify our customer base. As part of our long-term growth strategy, we continue to review complementary acquisitions, as well as capital expenditures to enhance our ability to increase cash flows from our existing assets. Future acquisitions will be subject to an improved outlook for our products and services and improved availability of capital on reasonable terms.
Expand products and services provided in existing operating locations. Since the beginning of 2004, we have invested approximately $329.7 million in capital expenditures to grow our business organically by investing in new, technologically advanced equipment and by expanding our product and service offerings. This strategy is consistent with our belief that our customers favor modern equipment emphasizing efficiency and safety and integrated suppliers that can provide a broad range of products and services in many geographic locations. Current economic conditions have led us to reduce our capital spending and operating expenses consistent with the decline in demand for our services as producers curtail their drilling activity.
Increase utilization of assets. We seek to increase revenues and enhance margins by increasing the utilization of our assets with new and existing customers. We expect to accomplish this through leveraging longstanding relationships with our customers and cross-selling our suite of services and equipment. Currently, our focus has shifted to how to limit the reduction of utilization due to decreased drilling activity as a result of current economic conditions.
Customers
In 2008 and 2007, one of our customers, Pan American Energy LLC Sucursal Argentina, or Pan American Energy, represented approximately 28.5% and 20.7% of our consolidated revenues, respectively. Pan America Energy is a joint venture that is owned 60% by British Petroleum and 40% by Bridas Corporation. Alejandro P. Bulgheroni and Carlos A. Bulgheroni, two of our directors, may be deemed to indirectly beneficially own all of the outstanding capital stock of Bridas Corporation and are members of the Management Committee of Pan American Energy. The loss without replacement of our larger existing customers could have a material adverse effect on our results of operations.
Suppliers
The equipment utilized in our business is generally available new from manufacturers or at auction. However, the cost of acquiring new equipment to expand our business could increase as demand for equipment in the industry increases.
Competition
We experience significant competition in all areas of our business. In general, the markets in which we compete are highly fragmented, and a large number of companies offer services that overlap and are competitive with our services and products. We believe that the principal competitive factors are technical and mechanical capabilities, management experience, past performance and price. While we have considerable experience, there are many other companies that have comparable skills. Many of our competitors are larger and have greater financial resources than we do.
We believe that there are five major directional drilling companies, Schlumberger, Halliburton, Baker Hughes, Smith International (Pathfinder) and Weatherford, that market both worldwide and in the U.S. as well as numerous small regional players. Significant competitors in the tubular markets we serve include Frank’s Casing Crew and Rental Tools, Weatherford, BJ Services, Tesco and Premier. These markets remain highly competitive and fragmented with numerous casing and tubing crew companies working in the U.S. Our
primary competitors in Mexico are South American Enterprises and Weatherford, both of which provide similar products and services. Our largest competitor for underbalanced drilling services is Weatherford. Weatherford focuses on large projects, but also competes in the more common compressed air, mist, foam and aerated mud drilling applications. Other competition comes from smaller regional companies. In the production services market there are numerous competitors, most of which have larger coiled tubing services operations than us.
Our five largest competitors in the Drilling and Completion segment, which operate primarily in Argentina, are Pride International, Servicios WellTech, Ensign Energy Services, Nabors and Helmerich & Payne, and San Antonio Global Ltd in Brazil.
The Rental Services business is highly fragmented with hundreds of companies offering various rental tool services. Our largest competitors include Weatherford, Quail Rental Tools, Knight Rental Tools and Smith International (Thomas Tools).
Backlog
We do not view backlog of orders as a significant measure for our business because our jobs are short-term in nature, typically one to 30 days, without significant on-going commitments.
Employees
Our strategy includes acquiring companies with strong management and entering into long-term employment contracts with key employees in order to preserve customer relationships and assure continuity following acquisition. In general, we believe we have good relations with our employees. None of our employees, other than our Drilling and Completion employees, are represented by a union. We actively train employees across various functions, which we believe is crucial to motivate our workforce and maximize efficiency. Employees showing a higher level of skill are trained on more technologically complex equipment and given greater responsibility. All employees are responsible for on-going quality assurance. At February 20, 2009, we had approximately 3,580 employees. Almost all of our Drilling and Completion operations located in Argentina and Brazil are subject to collective bargaining agreements. We believe that we maintain a satisfactory relationship with the unions to which our Drilling and Completion employees belong.
Insurance
We carry a variety of insurance coverages for our operations, and we are partially self-insured for certain claims in amounts that we believe to be customary and reasonable. However, there is a risk that our insurance may not be sufficient to cover any particular loss or that insurance may not cover all losses. We are responsible for the first $250,000 of claims under our workers compensation policy and the first $100,000 of claims under our general liability and medical insurance policies. Insurance rates have in the past been subject to wide fluctuation and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions.
Seasonality
Oil and natural gas operations of our customers located offshore and onshore in the U.S. Gulf of Mexico and in Mexico may be adversely affected by hurricanes and tropical storms, resulting in reduced demand for our services. For example, from August to October of 2007 we witnessed a decline in offshore drilling rig operations in the Gulf of Mexico in anticipation of the hurricane season. Many of those rigs have not returned to the U.S. Gulf and have been relocated to the international markets. In 2008, Hurricanes Gustav and Ike disrupted our operations along the Texas and Louisiana Gulf Coast and the East Texas/West Louisiana corridor. In addition, our customers’ operations in the Mid-Continent and Rocky Mountain regions of the U.S. are also adversely affected by seasonal weather conditions. These weather conditions limit our access to these job sites and our ability to service wells in these areas. These constraints decrease drilling activity and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.
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.
ITEM 1A.
ITEM 1A.
RISK FACTORS
Our business, financial condition, results of operations and the trading price of our securities can be materially and adversely affected by many events and conditions, including the following:
Risks Associated With Our Industry
Global political, economic and market conditions could negatively impact our business.
Our operations are affected by global political, economic and market conditions and the condition of the oil and natural gas industry. During recent months, there has been a substantial downturn in business activity and in the worldwide credit and capital markets that has led to a worldwide economic recession. Our operating results and the forward-looking information we provide are based on our current assumptions about oil and natural gas supply and demand, oil and natural gas prices, rig count and other market trends. Our assumptions on these matters are in turn based on currently available information, which is subject to change. The oil and natural gas industry is extremely volatile and subject to change based on political and economic factors outside our control. This volatility causes oil and natural gas companies and drilling contractors to change their strategies and expenditure levels. We have experienced in the past, and expect to experience in 2009, significant fluctuations in operating results based on these changes.
The current sustained declines in oil and natural gas prices, particularly in combination with the constrained capital markets and overall economic downturn, has resulted in a decline in activity by customers in our Oilfield Services and Rental Services segments during the first quarter of 2009. We cannot predict the timing or the duration of this or any other economic downturn in the economy and if the current conditions continue, our operating results and financial conditions could be materially adversely affected.
Our industry is highly competitive, with intense price competition.
The markets in which we operate are highly competitive. Contracts are traditionally awarded on a competitive bid basis. Pricing is often the primary factor in determining which qualified contractor is awarded a job. The competitive environment has intensified as mergers among oil and natural gas companies have reduced the number of available customers. The competitive environment has also intensified, late in 2008 and 2009, due to the decrease in the U.S. rig count and the demand for our services. Many other oilfield services companies are larger than we are and have resources that are significantly greater than our resources. These competitors are better able to withstand industry downturns, compete on the basis of price and acquire new equipment and technologies, all of which could affect our revenues and profitability. These competitors compete with us both for customers and for acquisitions of other businesses. This competition may cause our
business to suffer. We believe that competition for contracts will continue to be intense in the foreseeable future.
Risks Associated With Our Company
Our business depends on spending by the oil and natural gas industry, and this spending and our business may be adversely affected by industry and financial market conditions that are beyond our control.
Demand for our products and services is dependent upon the level of oil and natural gas exploration and development activities of, and the corresponding capital spending by, oil and natural gas companies. The industry’s willingness to explore, develop and produce depends largely upon the availability of attractive drilling prospects, the price of oil and natural gas, and the prevailing view of future product prices. Oil and natural gas prices have been extremely volatile in recent months, and have declined significantly from their historic highs in mid-2008. Any prolonged reduction in oil and natural gas prices will depress levels of exploration, development, and production activity. Such price declines can be expected to reduce drilling activity and demand for our services, which could lead to lower pricing for our products and services. Accordingly, prolonged periods of lower drilling activity and the reduction in our customers’ expenditures could have a materially adverse effect on our financial condition, results of operations and cash flows.
Oil and natural gas prices depend on many factors beyond our control, including the following:
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economic conditions in the U.S. and elsewhere;
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changes in global supply and demand for oil and natural gas;
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the level of production of the Organization of Petroleum Exporting Countries, commonly called OPEC;
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the level of production of non-OPEC countries;
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the price and quantity of imports of foreign oil and natural gas;
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political conditions, including embargoes, in or affecting other oil and natural gas producing activities;
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the level of global oil and natural gas inventories;
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advances in exploration, development and production technologies; and
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the availability of capital for exploration and production companies.
Recent adverse changes in the capital markets have also caused a number of oil and natural gas producers to announce reductions in capital budgets for future periods. Limitations on the availability of capital, or higher costs of capital, for financing expenditures may cause these and other oil and natural gas producers to make additional reductions to capital budgets in the future even if commodity prices remain at historically high levels.
Historically, we have been dependent on a few customers operating in a single industry; the loss of one or more customers could adversely affect our financial condition and results of operations.
Our customers are engaged in the oil and natural gas exploration business in the U.S., Argentina, Mexico and elsewhere. Historically, we have been dependent upon a few customers for a significant portion of our revenues. In 2008, 2007 and 2006, one of our customers, Pan American Energy represented 28.5%, 20.7% and 11.7% of our consolidated revenues, respectively. Pan American Energy also contributes a majority of the revenue derived from our Drilling and Completion operations. In 2008, 2007 and 2006, Pan American Energy represented 66.0%, 51.0% and 45.6% of our Drilling and Completion revenues, respectively.
Additionally, in 2007, we placed orders for 16 new service rigs and four drilling rigs pursuant to our strategic agreement with Pan American Energy. The 16 service rigs and one of the drilling rigs were delivered and placed in service in 2008 and an additional drilling rig will be activated in March 2009. The agreement with Pan American Energy currently has an expiration date of June 30, 2011. However, Pan American Energy
may terminate the agreement (i) without cause at any time with 60 days’ notice, or (ii) in the event of a breach of the agreement by us if such breach is not cured within 20 days of notice of the breach. Because a majority of the revenues of our Drilling and Completion operations are currently generated under this agreement, the revenues and earnings of our Drilling and Completion operations will be materially adversely affected if this agreement is terminated unless we are able to enter into a satisfactory substitute arrangement. We cannot assure you that in the event of such a termination we would be able to enter into a substitute arrangement on terms similar to those contained in the current agreement with Pan American Energy.
This concentration of customers may increase our overall exposure to credit risk, and customers will likely be similarly affected by changes in economic and industry conditions. Our financial condition and results of operations will be materially adversely affected if one or more of our significant customers fails to pay us or ceases to contract with us for our services on terms that are favorable to us or at all.
Our customers may seek to cancel or renegotiate some of our Drilling and Completion contracts during periods of depressed market conditions or if we experience operational difficulties.
Substantially all of our Drilling and Completion business’ contracts with major customers are dayrate contracts, where we charge a fixed charge per day regardless of the number of days needed to drill the well. During depressed market conditions, a customer may no longer need a rig that is currently under contract or may be able to obtain a comparable rig at a lower daily rate. As a result, customers may seek to renegotiate the terms of their existing drilling contracts or avoid their obligations under those contracts. In addition, our customers may have the right to terminate existing contracts if we experience operational problems. The likelihood that a customer may seek to terminate a contract for operational difficulties is increased during periods of market weakness. The cancellation of a number of our drilling contracts could materially reduce our revenues and profitability.
An oversupply of comparable rigs in the geographic markets in which we compete could depress the utilization rates and dayrates for our rigs and materially reduce our revenues and profitability.
Utilization rates, which are the number of days a rig actually works divided by the number of days the rig is available for work, and dayrates, which are the contract prices customers pay for rigs per day, are also affected by the total supply of comparable rigs available for service in the geographic markets in which we compete. Improvements in demand in a geographic market may cause our competitors to respond by moving competing rigs into the market, thus intensifying price competition. Significant new rig construction could also intensify price competition. In the past, there have been prolonged periods of rig oversupply with correspondingly depressed utilization rates and dayrates largely due to earlier, speculative construction of new rigs. Improvements in dayrates and expectations of longer-term, sustained improvements in utilization rates and dayrates for drilling rigs may lead to construction of new rigs. These increases in the supply of rigs could depress the utilization rates and dayrates for our rigs and materially reduce our revenues and profitability.
We may experience increased labor costs or the unavailability of skilled workers and the failure to retain key personnel could hurt our operations.
Companies in our industry, including us, are dependent upon the available labor pool of skilled employees. We compete with other oilfield services businesses and other employers to attract and retain qualified personnel with the technical skills and experience required to provide our customers with the highest quality service. We are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require us to enhance our wage and benefits packages. There can be no assurance that labor costs will not increase. Any increase in our operating costs could cause our business to suffer.
The operations and financial condition of our Drilling and Completion business could be affected by union activity and general labor unrest. Additionally, the labor expenses of our Drilling and Completion business could increase as a result of governmental regulation of payments to employees.
In Argentina and Brazil, labor organizations have substantial support and have considerable political influence. The demands of labor organizations in Argentina have increased in recent years as a result of the general labor unrest and dissatisfaction resulting from the disparity between the cost of living and salaries in Argentina as a result of the devaluation of the Argentine Peso. There can be no assurance that our Drilling and Completion business will not face labor disruptions in the future or that any such disruptions will not have a material adverse effect on our financial condition or results of operations.
The Argentine government has in the past and may in the future promulgate laws, regulations and decrees requiring companies in the private sector to maintain minimum wage levels and provide specified benefits to employees, including significant mandatory severance payments. In the aftermath of the Argentine economic crisis of 2001 and 2002, both the government and private sector companies have experienced significant pressure from employees and labor organizations relating to wage levels and employee benefits. In early 2005, the Argentine government promised not to order salary increases by decree. However, there has been no abatement of pressure to mandate salary increases, and it is possible the government will adopt measures that will increase salaries or require our Drilling and Completion business to provide additional benefits, which would increase our costs and potentially reduce our profitability, cash flow and/or liquidity.
Rig upgrade, refurbishment and construction projects are subject to risks, including delays and cost overruns, which could have an adverse effect on our results of operations and cash flows.
Our Drilling and Completion business often has to make upgrade and refurbishment expenditures for its rig fleet to comply with our quality management and preventive maintenance system or contractual requirements or when repairs are required in response to an inspection by a governmental authority. We may also make significant expenditures when rigs are moved from one location to another. Additionally, we may make substantial expenditures for the construction of new rigs. Rig upgrade, refurbishment and construction projects are subject to the risks of delay or cost overruns inherent in any large construction project.
Significant cost overruns or delays could adversely affect our financial condition and results of operations. Additionally, capital expenditures for rig upgrade, refurbishment or construction projects could exceed our planned capital expenditures, impairing our ability to service our debt obligations.
Currently, we have two land drilling rigs under construction that are to be completed in the second quarter of 2009. If these rigs are not completed on time, our financing commitment will expire. The turmoil in the financial markets in 2008 and its impact on the financial condition of the banking sector and other lenders, has increased the uncertainty that capital will be available to us, or available at a reasonable cost. As such, we may be unable to complete the acquisition of these two rigs. In addition, we have halted construction on two other land drilling rigs because of the drop in the U.S. rig count and the feasibility of utilizing the rigs when completed.
Severe weather could have a material adverse impact on our business.
Our business could be materially and adversely affected by severe weather. Repercussions of severe weather conditions may include:
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curtailment of services;
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weather-related damage to facilities and equipment resulting in suspension of operations;
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inability to deliver materials to job sites in accordance with contract schedules; and
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loss of productivity.
For example, oil and natural gas operations of our customers located offshore and onshore in the Gulf of Mexico and in Mexico have from time to time been adversely affected by floods, hurricanes and tropical
storms, resulting in reduced demand for our services. In 2008, Hurricanes Gustav and Ike disrupted our operations along the Texas and Louisiana Gulf Coast and the East Texas/West Louisiana corridor. Further, our customers’ operations in the Mid-Continent and Rocky Mountain regions of the U.S. are also adversely affected by seasonal weather conditions. This limits our access to these job sites and our ability to service wells in these areas. These constraints decrease drilling activity and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.
We have recorded substantial goodwill as the result of our acquisitive nature and as such goodwill is subject to periodic reviews of impairment.
We perform purchase price allocations to intangible assets when we make a business combination. Business combinations and purchase price allocations have been consummated for acquisitions in all of our reportable segments. The excess of the purchase price after allocation of fair values to tangible assets is allocated to identifiable intangibles and thereafter to goodwill. In accordance with Financial Accounting Standards Board No. 142, Goodwill and Other Intangible Assets, or FASB No. 142, we conduct periodic reviews of goodwill for impairment in value. Any impairments would result in a non-cash charge against earnings in the period reviewed, which may or may not create a tax benefit, and would have a corresponding decrease in stockholders’ equity.
We reviewed goodwill at December 31, 2008 and recorded an impairment of $115.8 million, which was all of our goodwill for the Rental Services segment as well as the impairment of goodwill associated with our Tubular Services and Production Services businesses within our Oilfield Services segment. In the event that market conditions continue to deteriorate or we have a prolonged downturn, we may be required to record an additional impairment of goodwill and such impairment could be material.
We may fail to acquire additional businesses, which will restrict our growth and may have a material adverse effect on our ability to meet our obligations under the notes.
Part of our long term business strategy has been to acquire companies operating in the oilfield services industry. However, there can be no assurance that we will be successful in acquiring any additional companies. Successful acquisition of new companies will depend on various factors, including but not limited to:
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our ability to obtain financing;
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the competitive environment for acquisitions; and
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the integration and synergy issues described in the next risk factor.
There can be no assurance that we will be able to acquire and successfully operate any particular business or that we will be able to expand into areas that we have targeted. If we fail to acquire additional businesses or are unable to finance such acquisitions, our financial condition, our results of operations and our ability to meet our debt obligations may be materially adversely affected.
Difficulties in integrating acquired businesses may result in reduced revenues and income.
We may not be able to successfully integrate any business we acquire in the future. The integration of a business could be complex and time consuming and place a significant strain on management and our information systems, and this strain could disrupt our businesses. Furthermore, if our combined businesses continue to grow rapidly, we may be required to replace our current information and accounting systems with systems designed for companies that are larger than ours. We may encounter substantial difficulties, costs and delays involved in integrating common accounting, information and communication systems, operating procedures, internal controls and human resources practices, including incompatibility of business cultures and the loss of key employees and customers. These difficulties may reduce our ability to gain customers or retain existing customers, and may increase operating expenses, resulting in reduced revenues and income and a failure to realize the anticipated benefits of acquisitions.
We have made numerous acquisitions during the past five years. As a result of these transactions, our past performance is not indicative of future performance, and investors should not base their expectations as to our future performance on our historical results.
Failure to maintain effective disclosure controls and procedures and/or internal controls over financial reporting could have a material adverse effect on our operations.
As part of our growth strategy, we may make additional strategic acquisitions of privately held businesses. It is likely that our future acquired businesses will not have been required to maintain such disclosure controls and procedures or internal controls prior to their acquisition. Likewise, upon the completion of any future acquisition, we will be required to integrate the acquired business into our consolidated company’s system of disclosure controls and procedures and internal controls over financial reporting, but we cannot assure you as to how long the integration process may take for any business that we may acquire. Furthermore, during the integration process, we may not be able to fully implement our consolidated disclosure controls and internal controls over financial reporting.
Likewise, during the course of our integration of any acquired business, we may identify needed improvements to our or such acquired business’ internal controls and may be required to design enhanced processes and controls in order to make such improvements. This could result in significant delays and costs to us and could require us to divert substantial resources, including management time, from other activities.
If we fail to maintain the adequacy of our disclosure controls and procedures and our internal controls, we may not be able to conclude that we have effective disclosure controls and procedures and/or effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Also, our independent registered public accounting firm may be unable to express an opinion on our management’s evaluation of, or on the effectiveness of, our internal controls.
If it is determined that our disclosure controls and procedures and/or our internal controls over financial reporting are not effective and/or we fail to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act on a timely basis, we may not be able to provide reliable financial and other reports or prevent fraud, which, in turn:
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could harm our business and operating results,
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cause investors to lose confidence in the accuracy and completeness of our financial reports,
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have a material adverse effect on the trading price of our common stock or
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adversely affect our ability to timely file our periodic reports with the SEC.
Any failure to timely file our periodic reports with the SEC may give rise to a default under the indentures governing our outstanding 9.0% senior notes due 2014, which we refer to as our 9.0% senior notes, our outstanding 8.5% senior notes due 2017, which we refer to as our 8.5% senior notes and any other debt securities we may offer and, ultimately, an acceleration of amounts due thereunder. In addition, a default under the indentures generally will also give rise to a default under our credit agreement and could cause the acceleration of amounts due under the credit agreement. If an acceleration of our 9.0% senior notes, our 8.5% senior notes or our other debt were to occur, we cannot assure you that we would have sufficient funds to repay such obligations.
We do business in international jurisdictions whose political and regulatory environments and compliance regimes differ from those in the U.S:
A significant amount of our revenue is attributable to operations in foreign countries. These activities accounted for approximately 45.9% of our consolidated revenue in the year ended December 31, 2008. Risks associated with our operations in foreign areas include, but are not limited to:
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political instability, terrorist acts, war and civil disturbances;
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changes in laws or policies regarding the award of contracts;
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the inability to collect or repatriate currency, income, capital or assets;
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expropriation of assets;
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nationalization of components of the energy industry in the geographic areas where we operate;
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foreign currency fluctuations and devaluation; and
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new economic and tax policies.
Part of our strategy is to prudently and opportunistically acquire businesses and assets that complement our existing products and services, and to expand our geographic footprint. If we make acquisitions in other countries, we may increase our exposure to the risks discussed above.
We attempt to limit the risks of currency fluctuation and restrictions on currency repatriation where possible by obtaining contracts providing for payment of a percentage of the contract indexed to the U.S. dollar exchange rate. To the extent possible, we seek to limit our exposure to local currencies by matching the acceptance of local currencies to our local expense requirements in those currencies. Although we have done this in the past, we may not be able to take these actions in the future, thereby exposing us to foreign currency fluctuations that could cause our results of operations, financial condition and cash flows to deteriorate materially.
Additionally, in some jurisdictions we are subject to foreign governmental regulations favoring or requiring the awarding of contracts to local contractors or requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These regulations may adversely affect our ability to compete.
Our international business operations also include projects in countries where governmental corruption has been known to exist and where our competitors who are not subject to U.S. laws and regulations, such as the Foreign Corrupt Practices Act, can gain competitive advantages over us by securing business awards, licenses or other preferential treatment in those jurisdictions using methods that U.S. law and regulations prohibit us from using. For example, our non-U.S. competitors are not subject to the anti-bribery restrictions of the Foreign Corrupt Practices Act, which make it illegal to give anything of value to foreign officials or employees or agents of nationally owned oil companies in order to obtain or retain any business or other advantage. We may be subject to competitive disadvantages to the extent that our competitors are able to secure business, licenses or other preferential treatment by making payments to government officials and others in positions of influence.
Violations of these laws could result in monetary and criminal penalties against us or our subsidiaries and could damage our reputation and, therefore, our ability to do business.
Devaluation of the Argentine Peso, the Mexican Peso or the Brazilian Real could adversely affect our results of operations.
These currencies have been subject to significant devaluation in the past and may be subject to significant fluctuations in the future. Given the economic and political uncertainties which have historically existed in Argentina, it is impossible to predict whether, and to what extent, the value of the Argentine Peso may depreciate or appreciate against the U.S. dollar. We cannot predict how these uncertainties will affect our financial results, but there is a risk that our financial performance could be adversely affected. Moreover, we cannot predict whether the Argentine government will further modify its monetary policy and, if so, what effect any of these changes could have on the value of the Argentine Peso. Such changes could have an adverse effect on our financial condition and results of operations.
Argentina continues to face considerable political and economic uncertainty.
Although general economic conditions have shown improvement and political protests and social disturbances have diminished considerably since the economic crisis of 2001 and 2002, the rapid and radical nature of the changes in the Argentine social, political, economic and legal environment over the past several
years and the absence of a clear political consensus in favor of any particular set of economic policies have given rise to significant uncertainties about the country’s economic and political future. It is currently unclear whether the economic and political instability experienced over the past several years will continue and it is possible that, despite recent economic growth, Argentina may return to a deeper recession, higher inflation and unemployment and greater social unrest. If instability persists, there could be a material adverse effect on our results of operations and financial condition.
In the event of further social or political crisis, companies in Argentina may also face the risk of further civil and social unrest, strikes, expropriation, nationalization, forced renegotiation or modification of existing contracts and changes in taxation policies, including royalty and tax increases and retroactive tax claims.
In addition, investments in Argentine companies may be further affected by changes in laws and policies of the U.S. affecting foreign trade, taxation and investment.
An increase in inflation in Argentina could have a material adverse effect on our results of operations.
Historically, the devaluation of the Argentine Peso has created pressures on the domestic price system that generated high rates of inflation in 2002 before substantially stabilizing in 2003 and remaining stable in 2004. In 2005, however, inflation rates began to increase. In addition, in response to the economic crisis in 2002, the federal government granted the Central Bank greater control over monetary policy than was available to it under the previous monetary regime, known as the “Convertibility” regime, including the ability to print currency, to make advances to the federal government to cover its anticipated budget deficit and to provide financial assistance to financial institutions with liquidity problems. We cannot assure you that inflation rates will remain stable in the future. Significant inflation in Argentina could have a material adverse effect on our results of operations and financial condition.
The loss of key executives would adversely affect our ability to effectively finance and manage our business, acquire new businesses, and obtain and retain customers.
We are dependent upon the efforts and skills of our executives to finance and manage our business, identify and consummate additional acquisitions and obtain and retain customers. These executives include our Chief Executive Officer and Chairman of the Board, Munawar H. Hidayatallah.
In addition, our development and expansion will require additional experienced management and operations personnel. No assurance can be given that we will be able to identify and retain these employees. Also, the loss of the services of one or more of our key executives could increase our exposure to the other risks described in this “Risk Factors” section. We do not maintain key man insurance on any of our personnel.
We are subject to numerous governmental laws and regulations, including those that may impose significant liability on us for environmental and natural resource damages.
We are subject to various federal, state, local and foreign laws and regulations relating to the energy industry in general and the environment in particular. For example, many aspects of our Drilling and Completion operations are subject to laws and regulations that may relate directly or indirectly to the contract drilling and well servicing industries, including those requiring us to control the discharge of oil and other contaminants into the environment or otherwise relating to environmental protection. The countries where our Drilling and Completion business operates have environmental laws and regulations covering the discharge of oil and other contaminants and protection of the environment in connection with operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and even criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that may limit or prohibit our operations. Laws and regulations protecting the environment have become more stringent in recent years and may in certain circumstances impose strict liability, rendering us liable for environmental and natural resource damages without regard to negligence or fault on our part. These laws and regulations may expose us to liability for the conduct of, or conditions caused by, others or for acts that were in compliance with all applicable laws at the time the acts were performed. The application of these requirements, the modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or
development drilling for oil and gas could materially limit future contract drilling opportunities or materially increase our costs or both.
Environmental liabilities relating to discontinued operations could result in substantial losses.
Since our reorganization under the U.S. federal bankruptcy laws in 1988, a number of parties, including the Environmental Protection Agency, or EPA, have asserted that we are responsible for the cleanup of hazardous waste sites with respect to our pre-bankruptcy activities. We believe that such claims are barred by applicable bankruptcy law, and we have not experienced any material expense in relation to any such claims. However, if we do not prevail with respect to these claims in the future, or if additional environmental claims are asserted against us relating to our current or future activities in the oil and natural gas industry, we could become subject to material environmental liabilities that could have a material adverse effect on our financial condition and results of operations.
Products liability claims relating to discontinued operations could result in substantial losses.
Since our reorganization under the U.S. federal bankruptcy laws in 1988, we have been regularly named in products liability lawsuits primarily resulting from the manufacture of products containing asbestos. In connection with our bankruptcy, a special products liability trust was established and funded to address products liability claims. We believe that claims against us are barred by applicable bankruptcy law, and that the products liability trust will continue to be responsible for products liability claims. Since 1988, no court has ruled that we are responsible for products liability claims. However, if we are held responsible for product liability claims, we could suffer substantial losses that could have a material adverse effect on our financial condition and results of operations. We have not manufactured products containing asbestos since our reorganization in 1988.
We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition and results of operations.
Our products and services are used for the exploration and production of oil and natural gas. These operations are subject to inherent hazards that can cause personal injury or loss of life, damage to or destruction of property, equipment, the environment and marine life, and suspension of operations. Litigation arising from an accident at a location where our products or services are used or provided may cause us to be named as a defendant in lawsuits asserting potentially large claims. We maintain customary insurance to protect our business against these potential losses. Our insurance has deductibles or self-insured retentions and contains certain coverage exclusions. However, we could become subject to material uninsured liabilities that could have a material adverse effect on our financial condition and results of operations.
Substantially all of our Drilling and Completion operations are subject to hazards that are customary for oil and natural gas drilling operations, including blowouts, reservoir damage, loss of well control, cratering, oil and gas well fires and explosions, natural disasters, pollution and mechanical failure. Any of these risks could result in damage to or destruction of drilling equipment, personal injury and property damage, suspension of operations or environmental damage. Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer, and we generally obtain indemnification from customers by contract for some of these risks. However, there may be limitations on the enforceability of indemnification provisions that allow a contractor to be indemnified for damages resulting from the contractor’s fault. To the extent that we are unable to transfer such risks to customers by contract or indemnification agreements, we generally seek protection through insurance. However, we have a significant amount of self-insured retention or deductible for certain losses relating to workers’ compensation, employers’ liability, general liability and property damage. There is no assurance that such insurance or indemnification agreements will adequately protect us against liability from all of the consequences of the hazards and risks described above. The occurrence of an event not fully insured or for which we are not indemnified against, or the failure of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, there can be no assurance that insurance will continue to be available to cover any or all of these
risks, or, even if available, that insurance premiums or other costs will not rise significantly in the future, so as to make the cost of such insurance prohibitive.
Risks Associated With an Investment in Our Common Stock
Our common stock price has been volatile, which could adversely affect our business and cause our stockholders to suffer significant losses
The volatility of our stock price depends upon many factors including:
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decreases in prices for oil and natural gas resulting in decreased demand for our services;
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variations in our operating results and failure to meet expectations of investors and analysts;
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increases in interest rates;
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illiquidity of the market for our common stock;
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developments specifically affecting the economies in Latin America;
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sales of common stock by existing stockholders;
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our substantial indebtedness; and
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other developments affecting us or the financial markets.
A reduced stock price will result in a loss to investors and will adversely affect our ability to issue stock to fund our activities.
Substantial sales of our common stock could adversely affect our stock price.
Sales of a substantial number of shares of common stock, or the perception that such sales could occur, could adversely affect the market price of our common stock by introducing a large number of sellers to the market. Such sales could cause the market price of our common stock to decline.
We have 35,674,742 shares outstanding as of February 23, 2009. At December 31, 2008, we had reserved an additional 1,661,187 shares of common stock for issuance under our equity compensation plans, of which 901,732 shares were issuable upon the exercise of outstanding options with a weighted average exercise price of $10.95 per share and 481,666 shares were issuable under restricted stock award grants subject to performance based vesting. In addition, we have reserved 4,000 shares of common stock for issuance upon the exercise of outstanding options (with an exercise price of $13.75 per share) granted to board members in 1999 and 2000.
In connection with our acquisition of DLS, we entered into an investors rights agreement with the seller parties to the DLS stock purchase agreement, who collectively hold 4,867,000 shares of our common stock as of February 23, 2009. Under that agreement, the DLS sellers are entitled to certain rights with respect to the registration of the sale of such shares under the Securities Act. By exercising their registration rights and causing a large number of shares to be sold in the public market, these holders could cause the market price of our common stock to decline.
We cannot predict whether future sales of our common stock, or the availability of our common stock for sale, will adversely affect the market price for our common stock or our ability to raise capital by offering equity securities.
In connection with our acquisitions of DLS, the DLS sellers have the right to designate two nominees for election to our board of directors. The interests of the DLS sellers may be different from yours.
The DLS sellers collectively hold 4,867,000 shares of our common stock, representing approximately 13.6% of our issued and outstanding shares as of February 23, 2009. Under the investors rights agreement that we entered into in connection with the DLS acquisition, the DLS sellers have the right to designate two nominees for election to our board of directors. As a result, the DLS sellers have a greater ability to determine the composition of our
board of directors and to control our future operations and strategy as compared to the voting power and control that could be exercised by a stockholder owning the same number of shares and not benefiting from board designation rights.
Conflicts of interest between the DLS sellers, on the one hand, and other holders of our securities, on the other hand, may arise with respect to sales of shares of capital stock owned by the DLS sellers or other matters. In addition, the interests of the DLS sellers regarding any proposed merger or sale may differ from the interests of other holders of our securities.
The board designation rights described above could also have the effect of delaying or preventing a change in our control or otherwise discouraging a potential acquirer from attempting to obtain control of us, which in turn could have a material and adverse effect on the market price of our securities and/or our ability to meet our obligations thereunder.
Existing stockholders’ interest in us may be diluted by additional issuances of equity securities.
We expect to issue additional equity securities to fund the acquisition of additional businesses and pursuant to employee benefit plans. We may also issue additional equity securities for other purposes. These securities may have the same rights as our common stock or, alternatively, may have dividend, liquidation, or other preferences to our common stock. The issuance of additional equity securities will dilute the holdings of existing stockholders and may reduce the share price of our common stock.
We do not expect to pay dividends on our common stock, and investors will be able to receive cash in respect of the shares of common stock only upon the sale of the shares.
We have not paid any cash dividends on our common stock within the last ten years, and we have no intention in the foreseeable future to pay any cash dividends on our common stock. Furthermore, our credit agreement and the indentures governing our outstanding senior notes restrict our ability to pay dividends on our common stock. Therefore, an investor in our common stock will obtain an economic benefit from the common stock only after an increase in its trading price and only by selling the common stock.
Risks Associated With Our Indebtedness
We are a holding company, and as a result we are dependent on dividends from our subsidiaries to meet our obligations, including with respect to the notes.
We are a holding company and do not conduct any business operations of our own. Our principal assets are the equity interests we own in our operating subsidiaries, either directly or indirectly. As a result, we are dependent upon cash dividends, distributions or other transfers we receive from our subsidiaries to repay any debt we may incur, and to meet our other obligations. The ability of our subsidiaries to pay dividends and make payments to us will depend on their operating results and may be restricted by, among other things, applicable corporate, tax and other laws and regulations and agreements of those subsidiaries, as well as by the terms of our credit agreement and the indentures governing our 9.0% senior notes, our 8.5% senior notes and any other debt securities we may offer. For example, the corporate laws of some jurisdictions prohibit the payment of dividends by any subsidiary unless the subsidiary has a capital surplus or net profits in the current or immediately preceding fiscal year. Payments or distributions from our subsidiaries also could be subject to restrictions on dividends or repatriation of earnings under applicable local law, and monetary transfer restrictions in the jurisdictions in which our subsidiaries operate. Our subsidiaries are separate and distinct legal entities. Any right that we have to receive any assets of/or distributions from any subsidiary upon its bankruptcy, dissolution, liquidation or reorganization, or to realize proceeds from the sale of the assets of any subsidiary, will be junior to the claims of that subsidiary’s creditors, including trade creditors.
We have a substantial amount of debt, which could adversely affect our financial health and prevent us from making principal and interest payments on the notes and our other debt.
At December 31, 2008, we have approximately $593.7 million of consolidated total indebtedness outstanding and approximately $47.7 million of additional secured borrowing capacity available under our credit agreement.
Our substantial debt could have important consequences for you. For example, it could:
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make it more difficult for us to satisfy our obligations with respect to our 9.0% senior notes, our 8.5% senior notes and any other debt securities we may offer and our other debt;
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increase our vulnerability to general adverse economic and industry conditions, including declines in oil and natural gas prices and declines in drilling activities;
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limit our ability to obtain additional financing for future working capital, capital expenditures, mergers and other general corporate purposes;
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require us to dedicate a substantial portion of our cash flow from operations to payments on our debt, thereby reducing the availability of our cash flow for operations and other purposes;
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limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
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make us more vulnerable to increases in interest rates;
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place us at a competitive disadvantage compared to our competitors that have less debt; and
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have a material adverse effect on us if we fail to comply with the covenants in the indentures relating to our 9.0% senior notes, our 8.5% senior notes and any other debt securities we may offer or in the instruments governing our other debt.
In addition, we may incur substantial additional debt in the future. Each of the indentures governing our 9.0% senior notes and our 8.5% senior notes permits (and we anticipate that the indentures governing any other debt securities we may offer will also permit) us to incur additional debt, and our credit agreement permits additional borrowings. If new debt is added to our current debt levels, these related risks could increase.
We may not maintain sufficient revenues to sustain profitability or to meet our capital expenditure requirements and our financial obligations. Also, we may not be able to generate a sufficient amount of cash flow to meet our debt service obligations.
Our ability to make scheduled payments or to refinance our obligations with respect to our debt will depend on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and to certain financial, business and other factors beyond our control. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay scheduled expansion and capital expenditures, sell material assets or operations, obtain additional capital or restructure our debt. We cannot assure you that our operating performance, cash flow and capital resources will be sufficient for payment of our debt in the future. In the event that we are required to dispose of material assets or operations or restructure our debt to meet our debt service and other obligations, we cannot assure you that the terms of any such transaction would be satisfactory to us or if or how soon any such transaction could be completed.
If we fail to obtain additional financing, we may be unable to refinance our existing debt, expand our current operations or acquire new businesses, which could result in a failure to grow or result in defaults in our obligations under our credit agreement, our 9.0% senior notes, our 8.5% senior notes or our other debt securities.
In order to refinance indebtedness, expand existing operations and acquire additional businesses, we will require substantial amounts of capital. There can be no assurance that financing, whether from equity or debt
financings or other sources, will be available or, if available, will be on terms satisfactory to us. The turmoil in the financial markets in 2008 and its impact on the financial condition of the banking sector and other lenders, has increased the uncertainty that capital will be available to us, or available at a reasonable cost. If we are unable to obtain financing, we will be unable to acquire additional businesses and may be unable to meet our obligations under our credit agreement, our 9.0% senior notes, our 8.5% senior notes or any other debt securities we may offer.
The indenture governing our 9.0% senior notes, the indenture governing our 8.5% senior notes and our credit agreement impose restrictions on us that may limit the discretion of management in operating our business and that, in turn, could impair our ability to meet our obligations.
The indenture governing our 9.0% senior notes, the indenture governing our 8.5% senior notes and our credit agreement contain various restrictive covenants that limit management’s discretion in operating our business. In particular, these covenants limit our ability to, among other things:
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incur additional debt;
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make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock;
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sell assets, including capital stock of our restricted subsidiaries;
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restrict dividends or other payments by restricted subsidiaries;
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create liens;
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enter into transactions with affiliates; and
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merge or consolidate with another company.
Our revolving credit agreement requires us to maintain specified financial ratios. If we fail to comply with the financial ratio covenants, it could limit or eliminate the availability under our revolving credit agreement. Our ability to maintain such financial ratios may be affected by events beyond our control, including changes in general economic and business conditions, and we cannot assure you that we will maintain or meet such ratios and tests or that the lenders under the credit agreement will waive any failure to meet such ratios or tests. The decrease in the U.S. rig count experienced late in 2008 and early 2009, the expectation of additional decreases in the U.S. rig count, and the resulting decrease in demand for our services adversely impacts our ability to maintain or meet such financial ratios.
These covenants could materially and adversely affect our ability to finance our future operations or capital needs. Furthermore, they may restrict our ability to expand, to pursue our business strategies and otherwise to conduct our business. A breach of these covenants could result in a default under the indentures governing our 9.0% senior notes, our 8.5% senior notes and any other debt securities we may offer and/or the credit agreement. If there were an event of default under any of the indentures or the credit agreement, the affected creditors could cause all amounts borrowed under these instruments to be due and payable immediately. Additionally, if we fail to repay indebtedness under our credit agreement when it becomes due, the lenders under the credit agreement could proceed against the assets which we have pledged to them as security. Our assets and cash flow might not be sufficient to repay our outstanding debt in the event of a default.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2.
PROPERTIES
The following table describes the location and general character of the principal physical properties used in each of our company’s businesses as of March 2, 2009. Our principal executive office is rented and located in Houston, Texas and the table below presents all of our operating locations and whether the property is owned or leased.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
On June 29, 1987, we filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Our plan of reorganization was confirmed by the Bankruptcy Court after acceptance by our creditors and stockholders, and was consummated on December 2, 1988.
At confirmation of our plan of reorganization, the U.S. Bankruptcy Court approved the establishment of the A-C Reorganization Trust as the primary vehicle for distributions and the administration of claims under our plan of reorganization, two trust funds to service health care and life insurance programs for retired employees and a trust fund to process and liquidate future product liability claims. The trusts assumed responsibility for substantially all remaining cash distributions to be made to holders of claims and interests pursuant to our plan of reorganization. We were thereby discharged of all debts that arose before confirmation of our plan of reorganization.
We do not administer any of the aforementioned trusts and retain no responsibility for the assets transferred to or distributions to be made by such trusts pursuant to our plan of reorganization.
As part of our plan of reorganization, we settled with the EPA on claims for cleanup costs at all known sites where we were alleged to have disposed of hazardous waste. The EPA settlement included both past and future cleanup costs at these sites and released us of liability to other potentially responsible parties in connection with these specific sites. In addition, we negotiated settlements of various environmental claims asserted by certain state environmental protection agencies.
Subsequent to our bankruptcy reorganization, the EPA and state environmental protection agencies have in a few cases asserted that we are liable for cleanup costs or fines in connection with several hazardous waste disposal sites containing products manufactured by us prior to consummation of our plan of reorganization. In each instance, we have taken the position that the cleanup costs and all other liabilities related to these sites were discharged in the bankruptcy, and the cases have been disposed of without material cost. A number of Federal Courts of Appeal have issued rulings consistent with this position, and based on such rulings, we believe that we will continue to prevail in our position that our liability to the EPA and third parties for claims for environmental cleanup costs that had pre-petition triggers have been discharged. A number of claimants have asserted claims for environmental cleanup costs that had pre-petition triggers, and in each event, the A-C Reorganization Trust, under its mandate to provide plan of reorganization implementation services to us, has responded to such claims, generally, by informing claimants that our liabilities were discharged in the bankruptcy. Each of such claims has been disposed of without material cost. However, there can be no assurance that we will not be subject to environmental claims relating to pre-bankruptcy activities that would have a material adverse effect on us.
The EPA and certain state agencies continue from time to time to request information in connection with various waste disposal sites containing products manufactured by us before consummation of the plan of reorganization that were disposed of by other parties. Although we have been discharged of liabilities with respect to hazardous waste sites, we are under a continuing obligation to provide information with respect to our products to federal and state agencies. The A-C Reorganization Trust, under its mandate to provide plan of reorganization implementation services to us, has responded to these informational requests because pre-bankruptcy activities are involved.
The A-C Reorganization Trust has been dissolved, and as a result, we have assumed the responsibility of responding to claimants and to the EPA and state agencies previously undertaken by the A-C Reorganization Trust. However, we have been advised by the A-C Reorganization Trust that its cost of providing these services has not been material in the past, and therefore we do not expect to incur material expenses as a result of responding to such requests. However, there can be no assurance that we will not be subject to environmental claims relating to pre-bankruptcy activities that would have a material adverse effect on us.
We are named as a defendant from time to time in product liability lawsuits alleging personal injuries resulting from our activities prior to our reorganization involving asbestos. These claims are referred to and handled by a special products liability trust formed to be responsible for such claims in connection with our reorganization. As with environmental claims, we do not believe we are liable for product liability claims relating to our business prior to our bankruptcy; moreover, the products liability trust continues to defend all such claims. However, there can be no assurance that we will not be subject to material product liability claims in the future or that the products liability trust will continue to have funds to pay any such claims.
We have been named as a defendant in two lawsuits in connection with our proposed merger with Bronco Drilling, Inc., which was terminated August 2008. We do not believe that the suits have any merit.
We are involved in various other legal proceedings, including labor contract litigation, in the ordinary course of business. The legal proceedings are at different stages; however, we believe that the likelihood of material loss relating to any such legal proceedings is remote.
ITEM 4.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On December 4, 2008, we held our Annual Meeting of Stockholders. At the meeting, the stockholders voted on the following matters:
1. The election of eleven directors to serve a one-year term expiring at the 2009 annual meeting of stockholders.
2. The ratification of the appointment of UHY LLP as our independent auditor for the fiscal year ending December 31, 2008.
The eleven nominees to our Board of Directors were elected at the meeting, and the other proposals received the affirmative vote required for approval. The following sets forth the results of the voting with respect to each such matter:
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
MARKET PRICE INFORMATION
Our common stock is traded on the New York Stock Exchange under the symbol “ALY”. Prior to March 22, 2007, our common stock was traded on the American Stock Exchange. The following table sets forth, for periods prior to March 22, 2007, high and low sales prices of our common stock, as reported on the American Stock Exchange and for periods since March 22, 2007, high and low sale prices of our common stock reported on the New York Stock Exchange.
Holders
As of February 23, 2009, there were approximately 1,309 holders of record of our common stock. On February 23, 2009, the closing price for our common stock reported on the New York Stock Exchange was $1.83 per share.
Dividends
No dividends were declared or paid during the past three years, and no dividends are anticipated to be declared or paid in the foreseeable future. Our credit facilities and the indentures governing our senior notes restrict our ability to pay dividends on our common stock.
EQUITY COMPENSATION PLAN INFORMATION
The following table provides information as of December 31, 2008 with respect to the shares of our common stock that may be issued under our existing equity compensation plans.
Equity Compensation Plans Not Approved By Security Holders
These plans comprise the following:
In 1999 and 2000, the Board compensated Board members who had served from 1989 to March 31, 1999 without compensation by issuing promissory notes totaling $325,000 and by granting stock options to these same individuals. Options to purchase 4,800 shares of common stock were granted with an exercise price of $13.75. These options vested immediately and expire in March 2010. As of December 31, 2008, 4,000 of these options remain outstanding.
PERFORMANCE GRAPH
Set forth below is a line graph comparing the annual percentage change in the cumulative return to the stockholders of our common stock with the cumulative return of the Russell 2000 and the CoreData Services Oil and Gas Equipment and Services Index for the last five years. Our common stock was a component of the Russell 2000 during the year ended December 31, 2008. The CoreData Services Oil and Gas Equipment and Services Index is an index of approximately 75 oil and gas equipment and services providers. The information contained in the performance graph shall not be deemed to be “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or Exchange Act, except to the extent that we specifically incorporate it by reference into such filing.
The graph assumes that $100 was invested on December 31, 2003 in our common stock and in each index, and that all dividends were reinvested. No dividends have been declared or paid on our common stock. Stockholder returns over the indicated period should not be considered indicative of future shareholder returns.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA.
The following selected historical financial information for each of the five years ended December 31, 2008, has been derived from our audited consolidated financial statements and related notes. Certain reclassifications have been made to the prior year’s selected financial data to conform with the current period presentation. This information is only a summary and should be read in conjunction with material contained in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with our financial statements included elsewhere herein. As discussed in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” we have during the past five years effected a number of business combinations and other transactions that materially affect the comparability of the information set forth below (in thousands, except per share amounts):
ITEM 7.
ITEM 7.
MANAGEMENT’S 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 U.S., including Texas, Oklahoma, Louisiana, Arkansas, Pennsylvania, New Mexico, Colorado, offshore in the Gulf of Mexico, and internationally, primarily in Argentina, Mexico and Brazil. We operate in three sectors of the oil and natural gas service industry: Oilfield Services; Drilling and Completion and Rental Services.
We derive operating revenues from rates per job that we charge for the labor and equipment required to provide a service and rates per day for equipment and tools that we rent to our customers. The price we charge for our services depends upon several factors, including the level of oil and natural gas drilling activity and the competitive environment in the particular geographic regions in which we operate. Contracts are awarded based on the price, quality of service and equipment, and the general reputation and experience of our personnel. The demand for drilling services has historically been volatile and is affected by the capital expenditures of oil and natural gas exploration and development companies, which can fluctuate based upon the prices of oil and natural gas or the expectation for the prices of oil and natural gas.
The rig count is an important indicator of activity levels in the oil and natural gas industry. The rig count in the U.S. increased from 862 as of December 27, 2002 to 1,721 as of December 26, 2008, according to the Baker Hughes rig count. However the rig count in 2008 reached a peak of 2,031 in August 2008 and began to decline in the fourth quarter of 2008 and has continued to decline to 1,243 as of February 27, 2009. The rapid decline in the U.S. rig count is due to the economic slowdown in the U.S. and the decrease in natural gas and oil prices which has impacted the capital expenditures of our customers. The turmoil in the financial markets and its impact on the availability of capital for our customers has also affected drilling activity in the U.S. Directional and horizontal rig counts increased from 283 as of December 27, 2002 to 912 as of December 26, 2008, which accounted for 33% and 53% of the total U.S. rig count, respectively. The directional and horizontal rig count also decreased to 692 as of February 27, 2009. The offshore Gulf of Mexico rig count was 51 rigs at February 27, 2009 from 58 at February 28, 2008.
While our revenue can be correlated to the rig count, our operating costs do not fluctuate in direct proportion to changes in revenues. Our operating expenses consist principally of our labor costs and benefits, equipment rentals, maintenance and repairs of our equipment, depreciation, insurance and fuel. Because many of our costs are fixed, our operating income as a percentage of revenues is generally affected by our level of revenues.
Company Outlook
We believe that our revenue and operating income for our Oilfield Service and Rental Services segment will suffer significantly in 2009, due to the drop in U.S. rig count and the reduction of our customers’ spending. We have already taken steps in 2009 to reduce costs, including laying off employees and closing unprofitable operating locations. Even with these steps, our Oilfield Services segment may still generate negative operating income in 2009 due to its focus in the U.S. market. Although we expect our Rental Services segment to be negatively impacted in a material fashion by the industry wide reduction in drilling and completion activity, we believe that our Rental Services segment will still generate positive operating income, albeit on lower revenue and at reduced margins. We anticipate our Drilling and Completion segment will exceed 2008 results for both revenue and operating income as we benefit from a full year of operations on rigs acquired during 2008 and from the acquisition of BCH at the end of 2008. Our Drilling and Completion segment primarily operates in Argentina and Brazil, but we have two rigs coming into service in 2009 in the U.S. market. Currently, we have no firm commitments of work for our U.S. rigs, so the impact of revenue and operating income from these rigs may be insignificant. BCH is a relatively new company and has not yet attained the levels of profitability we have forecasted.
We expect to incur less general and administrative expenses in 2009 as we reduce our administrative staffs to reflect the decline in activity. Our net interest expense is dependent upon our level of debt and cash on hand, which are principally dependent on acquisitions we complete, our capital expenditures and our cash flows from operations. Due to the shortage of liquidity and credit in the U.S. financial markets, we may see an increase in our effective interest rate in 2009. In addition, the interest rate on our credit facilities may increase if we violate any of our financial covenants in 2009. We anticipate that our effective tax rate will increase in 2009 due to a lower taxable income to spread the negative effects of non-deductible items and state income taxes. This rate could exceed 50.0% for U.S. tax purposes in 2009. In addition, the favorable tax rates we realized in 2008 from our international operations due to foreign currency fluctuations, may not be realized in 2009.
The sustainability and future growth in our operating income is principally dependent on our level of revenues and the pricing environment of our services. In addition, our sustainability and the demand for our services is dependent upon our customers’ capital spending plans, which are largely driven by current commodity prices and their expectations of future commodity prices. Recent declines in both natural gas and oil prices have caused our customers to delay or curtail capital spending plans. In addition to the impact of the decline in natural gas prices on our customers’ capital expenditures and overall liquidity, the recent credit crisis has limited the availability of funds, which lead to decreased capital expenditures for our customers. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets could lead to an extended global recession. The slowdown in economic activity caused by the recession has reduced demand for energy and resulted in lower oil and natural gas prices. Such a continued slowdown in economic activity could have a material adverse effect on our revenue and profitability. We are monitoring the credit worthiness of our customers, as well as outstanding receivables, in light of the current credit crisis and as such increased our reserve for doubtful accounts significantly at December 31, 2008, but further reserves may be necessary in 2009.
We continue to monitor the effect of the global financial crisis on our industry, and the resulting impact on the capital spending budgets of our customers in order to estimate the effect on our company. We have already reduced our planned capital spending significantly in 2009 compared to 2008. We currently expect that 2009 capital expenditures will total approximately $75.0 million compared to 2008 capital expenditures of $154.5 million. We believe that 2009 will be an extremely challenging year for our operations but we are optimistic that our cost saving cuts, coupled with our strategy of striving to mitigate cyclical risk through our international growth, by offering new equipment and technology to our customers and our focus on the U.S. land shale plays, will carry us through the current recession.
Results of Operations
In April 2006, we acquired all of the outstanding stock of Rogers and in October 2006, we acquired all of the outstanding stock of Petro Rentals, and the results for the operations of both acquired companies are included in our Oilfield Services segment. In August 2006, we acquired all of the outstanding stock of DLS and in December 2006, we acquired all of the outstanding stock of Tanus. We report the operations of DLS and Tanus in our Drilling and Completion segment. In January 2006, we acquired all of the outstanding stock of Specialty and in December 2006, we acquired substantially all of the assets of OGR. We report the operations of Specialty and OGR in our Rental Services segment.
In June 2007, we acquired all of the outstanding stock of Coker, in July 2007, we acquired all of the outstanding stock of Diggar and in November 2007, we acquired substantially all of the assets of Diamondback. In October 2007, we acquired all of the outstanding stock of Rebel. In June 2007, we sold our capillary assets. We report the operations of these four acquisitions and one disposition in our Oilfield Services segment.
In December 2008, we acquired all of the outstanding stock of BCH, which will be reported as part of our Drilling and Completion segment. In August 2008, we sold our drill pipe tong manufacturing assets, which were reported in our Oilfield Services segment.
We consolidated the results of all of these acquisitions from the day they were acquired.
The foregoing acquisitions and dispositions affect the comparability from period to period of our historical results, and our historical results may not be indicative of our future results.
Comparison of Years Ended December 31, 2008 and December 31,
Our revenues for the year ended December 31, 2008 were $675.9 million, an increase of 18.4% compared to $571.0 million for the year ended December 31, 2007. The increase in revenues is due to the increase in revenues in our Drilling and Completion and our Oilfield Services segments, offset in part by a decrease in revenues in our Rental Services segment. The most significant increase in revenues was in our Drilling and Completion segment due to additional drilling and service rigs placed in service in 2008 and price increases. The Drilling and Completion segment generated $291.3 million in revenues for the year ended December 31, 2008 compared to $215.8 million for the year ended December 31, 2007. Our Oilfield Services segment revenues increased to $280.8 million in 2008 compared to $234.0 million in 2007 due to acquisitions completed in the third and fourth quarters of 2007 which added downhole motors, measurement-while-drilling, or MWD, tools, and directional drilling personnel resulting in increased capacity and increased market penetration. Revenues also increased at our Oilfield Services segment due to the purchase of additional equipment, principally new compressor packages for our underbalanced operations, coiled tubing equipment and expansion of operations into new geographic regions. The impact of the additional MWD tools, downhole motors and the acquisitions of Diggar and Coker completed in the last half of 2007 are not easily identifiable as they were quickly integrated with our pre-existing operations. The acquisition of the Diamondback assets provided $30.3 million in revenues for the year ended December 31, 2008 compared to $3.1 million in revenues from the date of acquisition to December 31, 2007. The additional coiled tubing equipment provided an additional $11.8 million in revenues for the year ended December 31, 2008 compared to 2007. These increases in revenue were partially offset by a significant decrease in revenues at our Rental Services segment due to the reduction of drilling activity in the U.S. Gulf of Mexico beginning in the last half of 2007, as rigs departed the U.S. Gulf in favor of the international markets and the impact of hurricanes in 2008. These factors also caused the pricing for our Rental Services segment to become more competitive. Also impacting revenues was a $5.5 million decrease in revenues from our capillary tubing assets compared to 2007 as those assets were sold on June 29, 2007.
Our direct costs for the year ended December 31, 2008 increased 30.7% to $446.2 million, or 66.0% of revenues, compared to $341.5 million, or 59.8%, of revenues for the year ended December 31, 2007. On a percentage basis, direct costs in our Oilfield Services segment outpaced the growth in revenue for that segment. Oilfield Services revenue for the year ended December 31, 2008 increased 20.0% from revenue in the Oilfield Services segment for the year ended December 31, 2007, while the direct costs increased 24.4% over that same period. This unfavorable variance was primarily associated with costs incurred in the deployment of our new coiled tubing rigs. On a percentage basis, direct costs in our Drilling and Completion segment outpaced the growth in our revenue for that segment. Drilling and Completion revenue for the year ended December 31, 2008 increased 35.0% from revenue in the Drilling and Completion segment for the year ended December 31, 2007, while the direct costs increased 45.1% over that same period. This unfavorable variance is primarily attributed to higher labor costs in our Drilling and Completion segment relating to labor concessions in Argentina granted by the oil industry in the last half of 2007 and a significant increase in our labor force and labor-related expenses in connection with the delivery of new rigs prior to their activation. Our direct costs in our Rental Services segment did not decrease on the same percentage as the drop in our revenue for that segment. Rental Services revenue for the year ended December 31, 2008 decreased 14.4% from revenue in the Rental Services segment for the year ended December 31, 2007, while the direct costs decreased 5.9% over that same period. Our direct costs for the Rental Services segment are largely fixed because they primarily relate to yard expenses to maintain the rental inventory. In addition, the change in the service mix from the longer-term Gulf of Mexico rentals that we benefited from in 2007 to the shorter term land-drilling rental work in 2008, requires more handling on our part which increases costs.
Depreciation expense increased 24.6% to $63.5 million for the year ended December 31, 2008 from $50.9 million for the year ended December 31, 2007. The primary increase in depreciation expense is due to
the acquisitions completed in the second half of 2007 and our capital expenditures, principally the addition of new service rigs and one drilling rig in Argentina.
General and administrative expense was $60.0 million for the year ended December 31, 2008 compared to $58.6 million for the year ended December 31, 2007. General and administrative expense increased primarily due to the amortization of share-based compensation arrangements. General and administrative expense includes share-based compensation expense of $7.9 million in 2008 and $4.7 million in 2007. As a percentage of revenues, general and administrative expenses were 8.9% in 2008 compared to 10.3% in 2007.
Effective August 1, 2008, we sold our drill pipe tong manufacturing assets that were part of our Oilfield Services segment. The total consideration was approximately $7.5 million. We recognized a gain of $166,000 related to the transaction. On June 29, 2007, we sold our capillary tubing assets that were part of our Oilfield Services segment. The total consideration was approximately $16.3 million in cash. We recognized a gain of $8.9 million related to the sale of these assets.
In accordance with FASB No. 142, we recorded an impairment of goodwill of $115.8 million as of December 31, 2008. In light of adverse market conditions affecting our stock price and market conditions, we determined that impairment was necessary on all of our goodwill associated with our Rental Services segment as well as on our Tubular Services and Production Services reporting units included in our Oilfield Services segment. We performed the same annual impairment test as of December 31, 2007 and recorded no impairment.
Amortization expense was $4.2 million for the year ended December 31, 2008 compared to $4.1 million for the year ended December 31, 2007.
Our loss from operations for the year ended December 31, 2008 totaled $13.5 million, compared to $124.8 million in income from operations for the year ended December 31, 2007, for a total decrease of $138.3 million. The decrease is primarily related to the $115.8 million goodwill impairment, increased depreciation and amortization expense of $12.7 million from the year ended December 31, 2008 compared to year ended December 31, 2007 and the $8.9 million gain related to the sale of our capillary tubing assets in 2007.
Our interest expense was $48.4 million for the year ended December 31, 2008, compared to $49.5 million for the year ended December 31, 2007. During 2008, we borrowed against our revolving credit facility and as of December 31, 2008, we had an outstanding balance of $36.5 million. In 2008, through our DLS subsidiary in Argentina, we also entered into a new $25.0 million import finance facility with a bank to fund a portion of the purchase price of new drilling and service rigs. In January 2007 we issued $250.0 million of senior notes bearing interest at 8.5% to pay off, in part, the $300.0 million bridge loan utilized to complete the acquisition of substantially all of the assets of OGR and for working capital. This bridge loan was repaid on January 29, 2007. The average interest rate on the bridge loan was approximately 10.6%. Interest expense for 2007 includes the write-off of deferred financing fees of $1.2 million related to the repayment of the bridge loan. Interest expense also includes amortization expense of deferred financing costs of $2.1 million and $1.9 million for 2008 and 2007, respectively.
Our interest income was $5.6 million for the year ended December 31, 2008, compared to $3.3 million for the year ended December 31, 2007. In January 2008, we invested $40.0 million into a 15% convertible subordinated secured debenture with BCH. We earned interest on this note up until December 28, 2008, when we acquired all of the outstanding stock of BCH. In 2007, we had excess cash as the result of a senior note financing and an equity offering and we were able to generate interest income during this period.
Our benefit for income taxes for the year ended December 31, 2008 was $17.4 million, or 30.6% of our net loss before income taxes, compared to a income tax expense of $28.8 million, or 36.4% of our net income before income taxes for 2007. The income tax benefit recorded in 2008 was the result of net loss before income taxes compared to net income before income taxes in the previous year and a lower effective tax rate. The lower effective tax rate in 2008 is attributable to the impact of foreign currency losses on the
foreign income tax as well a lower benefit from the loss generated on our U.S. operations due to nondeductible expenses and state income taxes.
We had a net loss of $39.5 million for the year ended December 31, 2008, compared to net income of $50.4 million for the year ended December 31, 2007.
The following table compares revenues and income (loss) from operations for each of our business segments for the years ended December 31, 2008 and December 31, 2007. Income (loss) from operations consists of our revenues and the gain on asset dispositions less direct costs, general and administrative expenses, goodwill impairment, depreciation and amortization:
Oilfield Services. Revenues for the year ended December 31, 2008 for our Oilfield Services segment were $280.8 million, an increase of 20.0% from the $234.0 million in revenues for the year ended December 31, 2007. The increase in revenues is due to the purchase of additional MWD tools, new compressors and new “foam” units for our underbalanced drilling operations, new coiled tubing units and the benefit of acquisitions completed in the last half of 2007 which added downhole motors, MWDs, and directional drillers. The additional equipment and personnel enabled us to strengthen our presence in new geographic markets and increase our market penetration. The impact of the acquisitions of Diggar and Coker completed in the last half of 2007 and of the additional MWD tools are not easily identifiable as they were quickly integrated with our pre-existing operations. The acquisition of Diamondback provided $30.3 million in 2008 compared to $3.1 million of revenues from the date of acquisition to December 31, 2007. Income from operations decreased 27.4% to $38.6 million for 2008 from $53.2 million for 2007 because income from operations for the year ended December 31, 2008 includes a goodwill impairment charge of $9.4 million while the year ended December 31, 2007 included an $8.9 million gain on sale of our capillary tubing assets. Depreciation and amortization expense increased 46.8% to $24.7 million for the year ended December 31, 2008 compared to $16.8 million in 2007. The increase is depreciation expense was due to our capital expenditures, principally the new coiled tubing units which were delivered in the second half of 2008.
Drilling and Completion. Our Drilling and Completion revenues were $291.3 million for the year ended December 31, 2008, an increase of 35.0% from the $215.8 million in revenues for the year ended December 31, 2007. Our Drilling and Completion revenues increased in 2008 primarily due to 16 new service rigs and one drilling rig which were placed in service at various dates in 2008 and increased prices for our services. Income from operations increased to $40.2 million in 2008 compared to $38.8 million for the year ended December 31, 2007. Income from operations as percentage of revenue decreased to 13.8% for 2008 compared to 18.0% for 2007. This was due primarily to higher wages, which included other payroll expenses, and the increase in administrative costs all relating to labor concessions in Argentina granted by the oil industry in the last half of 2007 and a significant increase in our labor force and labor-related expenses in connection with the delivery of new rigs prior to their activation. Depreciation expense increased $3.0 million for the year ended December 31, 2008 compared to the prior year due to capital expenditures for the Drilling and Completion segment in 2008 and 2007.
Rental Services. Our Rental Services revenues were $103.8 million for the year ended December 31, 2008, a decrease of 14.4% from the $121.2 million in revenues for the year ended December 31, 2007. The decrease in revenue is primarily attributable to a more competitive market environment due to the decreased U.S. Gulf of Mexico drilling activity beginning in the last half of 2007 stemming from the departure of drilling rigs in favor of the international markets and the impact of hurricanes in the U.S. Gulf of Mexico in
2008. Income from operations decreased $123.5 million to a loss of $74.4 million in 2008 compared to income of $49.1 million in 2007. The decrease in operating income is primarily attributable to a $106.4 million non-cash charge for impairment of goodwill recorded in the year ending December 31, 2008 and due to the decrease in revenue.
Comparison of Years Ended December 31, 2007 and December 31,
Our revenues for the year ended December 31, 2007 were $571.0 million, an increase of 83.6% compared to $311.0 million for the year ended December 31, 2006. Revenues increased in all of our business segments due principally to the acquisitions completed during the two year period ended December 31, 2007, the investment in new equipment and the opening of new operating locations. The most significant increase in revenues was due to the acquisition of DLS on August 14, 2006 which established our Drilling and Completion segment. The Drilling and Completion segment generated $215.8 million in revenues for the twelve months ended December 31, 2007 compared to $69.5 million for the period from the date of the DLS acquisition to December 31, 2006. Revenues also increased significantly at our Rental Services segment due to the acquisition of the OGR assets on December 18, 2006. The OGR assets, including its two rental yards, expanded our assets available for rent. The OGR assets generated revenues of $82.2 million for the twelve months ended December 31, 2007 compared to $2.1 million for the period from the date of acquisition of the OGR assets to December 31, 2006. We experienced a decline in demand at our Rental Services segment in the last half of 2007 due to a reduction of drilling activity in the U.S. Gulf of Mexico as rigs departed the U.S. Gulf in favor of the international markets. Our Oilfield Services segment revenues increased in the 2007 period compared to the 2006 period due to acquisitions completed in the third and fourth quarters of 2007 which added downhole motors, MWD tools, and directional drilling personnel resulting in increased capacity and increased market penetration. Revenues also increased at our Oilfield Services segment due to the acquisition of Petro-Rentals in October 2006 and the purchase of additional equipment, principally new compressor packages for our underbalanced operations, and expansion of operations into new geographic regions. The impact of the additional MWD tools, downhole motors and the acquisitions of Diggar and Coker completed in the last half of 2007 are not easily identifiable as they were quickly integrated with our pre-existing operations. The acquisition of the Diamondback assets provided $3.1 million in revenues from the date of acquisition to December 31, 2007. The Petro-Rentals acquisition and additional coil tubing equipment provided an additional $20.6 million in revenues for the year ended December 31, 2007 compared to 2006. These gains in revenues were partly offset by a reduction of $6.7 million in revenues from our capillary assets compared to 2006 as the assets were sold on June 29, 2007.
Our direct costs for the year ended December 31, 2007 increased 84.0% to $341.5 million, or 59.8% of revenues, compared to $185.6 million, or 59.7%, of revenues for the year ended December 31, 2006. The increase in direct costs is due to the increase in revenues in all of our business segments.
Depreciation expense increased 151.3% to $50.9 million for the year ended December 31, 2007 from $20.3 million for the year ended December 31, 2006. The primary increase in depreciation expense is due to the acquisitions of the OGR assets, DLS and Petro-Rentals and our capital expenditures. The increase in our depreciation expense related to the OGR assets was $15.9 million to $16.6 million for the year ended December 31, 2007 compared to $650,000 for the period from the date of the acquisition of the OGR assets to December 31, 2006. Depreciation expense for DLS increased $7.2 million to $11.3 million for the year ended December 31, 2007 from $4.1 million for the period from the date of acquisition of DLS to December 31, 2006. Depreciation expense for Petro-Rentals for the year ended December 31, 2007 was $3.6 million compared to $688,000 for the period from the date of acquisition of Petro-Rentals to December 31, 2006.
General and administrative expense was $58.6 million for the year ended December 31, 2007 compared to $35.5 million for the year ended December 31, 2006. General and administrative expense increased due to the acquisitions, and the hiring of additional sales, operations, accounting and administrative personnel. As a percentage of revenues, general and administrative expenses were 10.3% in 2007 compared to 11.4% in 2006. General and administrative expense includes share-based compensation expense of $4.7 million in 2007 and $3.0 million in 2006.
On June 29, 2007, we sold our capillary tubing assets that were part of our Oilfield Services segment. The total consideration was approximately $16.3 million in cash. We recognized a gain of $8.9 million related to the sale of these assets.
Amortization expense was $4.1 million for the year ended December 31, 2007 compared to $1.9 million for the year ended December 31, 2006. The increase in amortization expense is primarily due to the amortization of intangible assets in connection with our acquisition of the OGR assets, which increased $2.2 million to $2.3 million for the year ended December 31, 2007 compared to $96,000 for the period from the date of the acquisition of the OGR assets to December 31, 2006.
Income from operations for the year ended December 31, 2007 totaled $124.8 million, an 84.2% increase over the $67.7 million in income from operations for the year ended December 31, 2006, reflecting the increase in our revenues of $260.0 million, offset in part by increased direct costs of $155.9 million, increased general and administrative expense of $23.1 million and increased amortization expense of $2.2 million. Our income from operations as a percentage of revenues increased slightly to 21.9% in 2007 from 21.8% in 2006. Income from operations in the 2007 period includes an $8.9 million gain from the sale of our capillary tubing assets in the second quarter of 2007.
Our net interest expense was $46.3 million for the year ended December 31, 2007, compared to $20.3 million for the year ended December 31, 2006. Interest expense increased in 2007 due to our increased debt. In August 2006 we issued $95.0 million of senior notes bearing interest at 9.0% to fund a portion of the acquisition of DLS. In January 2007 we issued $250.0 million of senior notes bearing interest at 8.5% to pay off, in part, the $300.0 million bridge loan utilized to complete the OGR acquisition and for working capital. This bridge loan was repaid on January 29, 2007. The average interest rate on the bridge loan was approximately 10.6%. Interest expense for 2007 includes the write-off of deferred financing fees of $1.2 million related to the repayment of the bridge loan. Interest expense includes amortization expense of deferred financing costs of $1.9 million and $1.5 million for 2007 and 2006, respectively.
Our income tax expense for the year ended December 31, 2007 was $28.8 million, or 36.4% of our net income before income taxes, compared to $11.4 million, or 24.3% of our net income before income taxes for 2006. The increase in our income tax expense is attributable to the increase in our operating income and a higher effective tax rate. The effective tax rate in 2006 was favorably impacted by the reversal of our valuation allowance on our deferred tax assets. The valuation allowance was reversed due to operating results that allowed for the realization of our deferred tax assets.
We had net income of $50.4 million for the year ended December 31, 2007, an increase of 41.6%, compared to net income of $35.6 million for the year ended December 31, 2006.
The following table compares revenues and income from operations for each of our business segments for the years ended December 31, 2007 and December 31, 2006. Income from operations consists of our revenues and gain on asset disposition less direct costs, general and administrative expenses, depreciation and amortization:
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 in the 2007 period includes an $8.9 million gain on sale of our capillary tubing assets.
Drilling and Completion. On August 14, 2006, we acquired DLS which established our Drilling and Completion segment. Our Drilling and Completion revenues were $215.8 million for the year ended December 31, 2007, an increase from the $69.5 million in revenues for the period from the date of the DLS acquisition until December 31, 2006. Income from operations increased to $38.8 million in 2007 compared to $12.2 million from the date of the DLS acquisition until December 31, 2006. Income from operations as percentage of revenue increased to 18.0% for 2007 compared to 17.6% for 2006. We believe the increase in the percentage was primarily due to the price increases implemented in 2007. During 2007 we placed orders for 16 service rigs (workover rigs and pulling rigs) and four drilling rigs. Four of the service rigs were delivered in the fourth quarter of 2007.
Rental Services. Our Rental Services revenues were $121.2 million for the year ended December 31, 2007, an increase of 135.2% from the $51.5 million in revenues for the year ended December 31, 2006. Income from operations increased 86.9% to $49.1 million in 2007 compared to $26.3 million in 2006. The increase in revenue and operating income is primarily attributable to the acquisition of the OGR assets in December 2006. The OGR assets, including its two rental yards, expanded our assets available for rent. We generated $82.2 million for the twelve months ended December 31, 2007 compared to $2.1 million for the period from the date of acquisition of the OGR assets to December 31, 2006. Income from operations as a percentage of revenues decreased to 40.5% for 2007 compared to 51.0% for the prior year as a result of higher depreciation expense associated with the OGR acquisition and capital expenditures. Our depreciation expense for the OGR assets increased $15.9 million to $16.6 million for the year ended December 31, 2007 compared to $650,000 for the period from the date of acquisition of the OGR assets to December 31, 2006. Rental Services revenues and operating income was impacted by a more competitive market environment due to the decreased U.S. Gulf of Mexico drilling activity in the last half of 2007 attributed to the hurricane season and the departure of drilling rigs in favor of the international markets.
Liquidity and Capital Resources
Our on-going capital requirements arise primarily from our need to service our debt, to acquire and maintain equipment, to fund our working capital requirements and to complete acquisitions. Our primary sources of liquidity are proceeds from the issuance of debt and equity securities and cash flows from operations. Our amended and restated revolving credit facility permits borrowings of up to $90.0 million in principal amount. As of December 31, 2008, we had $47.7 million available for borrowing under our amended and restated revolving credit facility. We also have up to $29.0 million available under a new credit agreement which we executed in February 2009 to fund a portion of the purchase price of two drilling rigs. Cash flows from operations are expected to be our primary source of liquidity in fiscal 2009. We had cash and cash equivalents of $6.9 million at December 31, 2008 compared to $43.7 million at December 31, 2007.
Our revolving credit agreement requires us to maintain specified financial ratios. If we fail to comply with the financial ratio covenants, it could limit or eliminate the availability under our revolving credit agreement. Our ability to maintain such financial ratios may be affected by events beyond our control, including changes in general economic and business conditions, and we cannot assure you that we will maintain or meet such ratios and tests or that the lenders under the credit agreement will waive any failure to meet such ratios or tests. The decrease in the U.S. rig count experienced late in 2008 and early 2009, the expectation of additional decreases in the U.S. rig count, and the resulting decrease in demand for our services adversely impacts our ability to maintain or meet such financial ratios.
We have reduced our planned capital spending for 2009 compared to 2008. Exclusive of any opportunistic acquisitions, we currently expect to spend a total of approximately $66.0 million in 2009, which is net of equipment deposits paid in 2008. As of December 31, 2008, we had commitments covering $41.4 million of the $66.0 million. We believe that our cash generated from operations, cash on hand and cash available under our credit facilities will provide sufficient funds for our identified projects. Our ability to obtain capital for opportunistic acquisitions or additional projects to implement our growth strategy over the longer term will depend upon our future operating performance and financial condition, which will be dependent upon the prevailing conditions in our industry and the global market, including the availability of equity and debt financing, many of which are beyond our control.
Operating Activities
In the year ended December 31, 2008, we generated $113.7 million in cash from operating activities. Our net loss for the year ended December 31, 2008 was $39.5 million. Non-cash additions to net loss totaled $164.8 million in the 2008 period consisting primarily of $115.8 million of impairment of goodwill, $67.7 million of depreciation and amortization, $7.9 million related to the expensing of stock options as required under SFAS No. 123R, $3.3 million for bad debts and $2.1 million of amortization and write-off of deferred financing fees, partially offset by $29.9 million in deferred tax and $1.9 million of gains from the dispositions of equipment.
During the year ended December 31, 2008, changes in working capital used $11.7 million in cash, principally due to an increase of $27.5 million in accounts receivable, an increase of $9.7 million in inventories and an increase in other current assets of $1.6 million, offset by an increase of $21.9 million in accounts payable, an increase of $3.5 million in accrued employee benefits and payroll taxes, an increase of $1.2 million in accrued expenses and an increase in accrued interest of $567,000. Our accounts receivables increased at December 31, 2008 primarily due to the increase in our revenues in 2008. Inventories increased at December 31, 2008 primarily due to our larger rig fleet in our Drilling and Completion segment. Other current assets increased primarily due to estimated tax payments exceeding the estimated tax liability as of December 31, 2008. Our accounts payable, accrued employee benefits and payroll taxes and other accrued expenses increased primarily due to the increase in costs due to our growth in revenues.
In the year ended December 31, 2007, we generated $103.5 million in cash from operating activities. Our net income for the year ended December 31, 2007 was $50.4 million. Non-cash additions to net income totaled $61.2 million in the 2007 period consisting primarily of $55.0 million of depreciation and amortization, $4.9 million related to the expensing of stock options as required under SFAS No. 123R, $8.0 million of deferred income tax, $1.3 million for bad debts and $3.2 million of amortization and write-off of deferred financing fees, partially offset by $2.3 million of gain from the disposition of equipment and a $8.9 million gain from the sale of capillary assets.
During the year ended December 31, 2007, changes in working capital used $8.1 million in cash, principally due to an increase of $31.4 million in accounts receivable, an increase of $4.5 million in other assets and an increase in inventories of $5.4 million, offset by a decrease of $8.2 million in other current assets, an increase of $10.7 million in accounts payable, an increase of $6.0 million in accrued interest, an increase of $4.0 million in accrued employee benefits and payroll taxes, an increase of $1.5 million in accrued expenses and an increase in other long-term liabilities of $2.7 million. Our accounts receivables increased at December 31, 2007 primarily due to the increase in our revenues in 2007. Other assets increase primarily due to the contract costs related to the deployment of new rigs for our Drilling and Completion segment. The decrease in other current assets is principally due to the collection of the working capital adjustment from the OGR acquisition for approximately $7.1 million in the first quarter of 2007. Accrued interest increased at December 31, 2007 due principally to interest accrued on our 8.5% senior notes issued in January 2007 and our 9.0% senior notes issued in August 2006 which are both payable semi-annually. Our accounts payable, accrued employee benefits and payroll taxes and other accrued expenses increased primarily due to the increase in costs due to our growth in revenues and acquisition completed in 2007. Other long-term liabilities increased primarily due to the deferral of contract revenue related to our new rigs being constructed in the Drilling and Completion segment.
In the year ended December 31, 2006, we generated $53.7 million in cash from operating activities. Our net income for the year ended December 31, 2006 was $35.6 million. Non-cash additions to net income totaled $27.6 million in the 2006 period consisting primarily of $22.1 million of depreciation and amortization, $3.4 million related to the expensing of stock options as required under SFAS No. 123R, $2.2 million of deferred income tax, $781,000 for bad debts and $1.5 million for amortization of finance fees, including the bridge loan fees, partially offset by $2.4 million of gain from the disposition of equipment.
During the year ended December 31, 2006, changes in working capital used $9.9 million in cash, principally due to an increase of $23.2 million in accounts receivable, an increase of $2.6 million in inventories, a decrease of $2.3 million in accounts payable, offset in part by a decrease in other current assets of $2.5 million, an increase of $11.4 million in accrued interest, an increase of $3.4 million in accrued employee benefits and payroll taxes and an increase of $872,000 in accrued expenses. Our accounts receivables increased at December 31, 2006 primarily due to the increase in our revenues in 2006. Accrued interest increased at December 31, 2006 due principally to interest accrued on our 9.0% senior notes, which are payable semi-annually. Our accrued employee benefits and payroll taxes and other accrued expenses increased primarily due to the increase in costs due to our growth in revenues and acquisition completed in 2006.
Investing Activities
During the year ended December 31, 2008, we used $202.2 million in investing activities. During the year ended December 31, 2008, we acquired BCH for a total net cash outlay of $53.7 million, consisting of the purchase price and acquisition costs less cash acquired. In addition we made capital expenditures of approximately $154.5 million during the year ended December 31, 2008, including $73.4 million to expand our drilling fleet and to purchase, improve and replace other equipment in our Drilling and Completion segment, $58.4 million to purchase and upgrade our equipment for our Oilfield Services segment and $22.6 million to increase our inventory of equipment and replace “lost-in-hole” equipment in the Rental Services segment. We received proceeds of $3.0 million from the sale of our drill pipe tong manufacturing assets. We also received $11.5 million from the sale of assets during the year ended December 31, 2008, comprised mostly from equipment “lost-in-hole” from our Rental Services segment ($8.3 million) and our Oilfield Services segment ($2.3 million). We also made net advance payments of $8.8 million on the purchase of new drilling and service rigs to be delivered in 2009 for our Drilling and Completion segment and advance payments of $1.1 million on the purchase of new directional drilling tools for our Oilfield Services segment.
During the year ended December 31, 2007, we used $137.1 million in investing activities consisting of four acquisitions and our capital expenditures. During the year ended December 31, 2007, we completed the following acquisitions for a total net cash outlay of $41.0 million, consisting of the purchase price and acquisition costs less cash acquired:
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In June 2007, we acquired Coker for a purchase price of approximately $3.6 million in cash and a promissory note for $350,000.
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In July 2007, we acquired Diggar for a purchase price of approximately $6.7 million in cash, the payment of approximately $2.8 million of debt and a promissory note for $750,000.
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In October 2007, we acquired Rebel for a purchase price of approximately $5.0 million in cash, the payment of approximately $1.8 million of debt and escrow, and promissory notes for an aggregate of $500,000.
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In November 2007, we acquired substantially all of the assets of Diamondback for a purchase price of approximately $23.1 million in cash.
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:
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Effective January 1, 2006, we acquired Specialty for a purchase price of approximately $95.3 million in cash.
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Effective April 1, 2006, we acquired Rogers for a purchase price of approximately $11.3 million in cash, 125,285 shares of our common stock and a promissory note for $750,000.
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On August 14, 2006, we acquired DLS for a purchase price of approximately $93.7 million in cash, 2.5 million shares of our common stock and the assumption of $9.1 million of indebtedness.
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On October 16, 2006, we acquired Petro Rentals for a purchase price of approximately $20.2 million in cash, 246,761 shares of our common stock and the payment of approximately $9.6 million of debt.
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Effective December 1, 2006, we acquired Tanus for a purchase price of $2.5 million in cash.
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On December 18, 2006, we acquired substantially all of the assets of OGR for a purchase price of approximately $291.0 million in cash and 3.2 million shares of our common stock.
In addition we made capital expenditures of approximately $39.7 million during the year ended December 31, 2006, including $29.1 million to purchase and upgrade equipment for our Oilfield Services segment, $5.8 million to purchase, improve and replace equipment in our Drilling and Completion segment and $4.5 million to replace “lost-in-hole” equipment and to increase our inventory of equipment in the Rental Services segment. We also received $6.9 million from the sale of assets during the year ended December 31, 2006, comprised mostly from equipment “lost-in-hole” from our Rental Services segment ($3.8 million) and our Oilfield Services segment ($1.8 million).
Financing Activities
During the year ended December 31, 2008, financing activities provided a net of $51.7 million in cash. We received $25.0 million of proceeds of long-term debt which was used to finance the expansion of our Drilling and Completion segment’s rig fleet. During the year ended December 31, 2008, we had a net draw on our revolving credit facility of $36.5 million which was necessary due to our investment in BCH and our capital expenditures. We also received $633,000 from the proceeds of option exercises with 558,707 shares of our common stock being issued under our equity compensation plans. Financing uses during the year ended December 31, 2008 were the repayment of $9.9 million of long-term debt and $525,000 in debt issuance costs.
During the year ended December 31, 2007, financing activities provided a net of $37.6 million in cash. We received $250.0 million in borrowings from the issuance of our 8.5% senior notes due 2017. We also received $100.1 million in net proceeds from the issuance of 6,000,000 shares of our common stock, $1.7 million on the tax benefit of stock compensation plans and $3.3 million from the proceeds of warrant and option exercises with 882,624 shares of our common stock being issued under our equity compensation plans. The proceeds were used to repay long-term debt totaling $309.7 million and to pay $7.8 million in debt issuance costs. The repayment of long-term debt consisted primarily of the repayment of our $300.0 million bridge loan which was used to fund the acquisition of substantially all the assets of OGR.
During the year ended December 31, 2006, financing activities provided a net of $543.6 million in cash. We received $557.8 million in borrowings under long-term debt facilities, consisting primarily of the issuance of $255.0 million of our 9.0% senior notes due 2014 and a $300.0 million senior unsecured bridge loan. The bridge loan, which was repaid on January 29, 2007, was used to fund the acquisition of substantially all the
assets of OGR. We also received $46.3 million in net proceeds from the issuance of 3,450,000 shares of our common stock, $6.4 million on the tax benefit of options and $6.3 million from the proceeds of warrant and option exercises with 1,851,377 shares of our common stock being issued under our equity compensation plans. The proceeds were used to repay long-term debt totaling $54.0 million, repay $6.4 million in net borrowings under our revolving credit facility, repay related party debt of $3.0 million and to pay $9.9 million in debt issuance costs.
On January 18, 2006 and August 14, 2006, we closed on private offerings, to qualified institutional buyers pursuant to Rule 144A under the Securities Act, of $160.0 million and $95.0 million aggregate principal amount of our senior notes, respectively. The senior notes are due January 15, 2014 and bear interest at 9.0%. The proceeds were used to fund the acquisitions of Specialty and DLS, to repay existing debt and for general corporate purposes. Debt repaid included all outstanding balances under our credit agreement, including a $42.1 million term loan and $6.4 million in working capital advances, a $4.0 million subordinated note issued in connection with acquisition of AirComp, approximately $3.0 million subordinated note issued in connection with the acquisition of Tubular, approximately $548,000 on a real estate loan and approximately $350,000 on outstanding equipment financing.
On December 18, 2006, we closed on a $300.0 million senior unsecured bridge loan. The bridge loan was due 18 months after closing and had a weighted average interest rate of 10.6%. The bridge loan, which was repaid on January 29, 2007, was used to fund the acquisition of substantially all the assets of OGR.
In January 2007, we closed on a private offering, to qualified institutional buyers pursuant to Rule 144A under the Securities Act, of $250.0 million principal amount of 8.5% senior notes due 2017. The proceeds of the senior notes offering, together with a portion of the proceeds of our concurrent common stock offering, were used to repay the debt outstanding under our $300.0 million bridge loan facility which we incurred to finance our acquisition of substantially all the assets of OGR.
On January 18, 2006, we also executed an amended and restated credit agreement which provides for a $25.0 million revolving line of credit with a maturity of January 2010. On April 26, 2007, we entered into a Second Amended and Restated Credit Agreement, which increased our revolving line of credit to $62.0 million, and has a final maturity date of April 26, 2012. On December 3, 2007, we entered into a First Amendment to Second Amended and Restated Credit Agreement, which increased our revolving line of credit to $90.0 million. The amended and restated credit agreement contains customary events of default and financial covenants and limits our ability to incur additional indebtedness, make capital expenditures, pay dividends or make other distributions, create liens and sell assets. Our obligations under the amended and restated credit agreement are secured by substantially all of our assets located in the U.S. The credit agreement loan rates are based on prime or LIBOR plus a margin. We were in compliance with all debt covenants as of December 31, 2008 and 2007. The weighted average interest rate was 4.6% at December 31, 2008. As of December 31, 2008 and 2007, amounts borrowed under the facility were $36.5 million and $0 and availability was reduced by outstanding letters of credit of $5.8 million and $8.4 million, respectively.
As part of our acquisition of DLS, we assumed various bank loans with floating interest rates based on LIBOR plus a margin and terms ranging from two to five years. The weighted average interest rates on these loans was 5.1% and 6.7% at December 31, 2008 and 2007, respectively. The bank loans are denominated in U.S. dollars and the outstanding amount due as of December 31, 2008 and 2007 was $2.5 million and $4.9 million, respectively.
On February 15, 2008, through our DLS subsidiary in Argentina, we entered into a $25.0 million import finance facility with a bank. Borrowings under this facility were used to fund a portion of the purchase price of the new drilling and service rigs ordered for our Drilling and Completion segment. The facility was available for borrowings until December 31, 2008. Each drawdown shall be repaid over four years in equal semi-annual installments beginning one year after each disbursement with the final principal payment due not later than March 15, 2013. The import finance facility is unsecured and contains customary events of default and financial covenants and limits DLS’ ability to incur additional indebtedness, make capital expenditures, create liens and sell assets. We were in compliance with all debt covenants as of December 31, 2008. The bank loan rates are based on LIBOR plus a margin. The weighted average interest rate was 6.9% at
December 31, 2008. The bank loans are denominated in U.S. dollars and the outstanding amount as of December 31, 2008 was $25.0 million.
As part of our acquisition of BCH, we assumed a $23.6 million term loan credit facility with a bank. The credit agreement is dated June 2007 and contains customary events of default and financial covenants. Obligations under the facility are secured by substantially all of the BCH assets. The facility is repayable in quarterly principal installments plus interest with the final payment due not later than August 2012. We were in compliance with all debt covenants as of December 31, 2008. The credit facility loan is denominated in U.S. dollars and interest rates are based on LIBOR plus a margin. At December 31, 2008, the outstanding balance was $22.1 million and the interest rate was 6.0%.
In connection with the acquisition of Rogers, we issued to the seller a note in the amount of $750,000. The note bears interest at 5.0% and is due April 3, 2009. In connection with the purchase of Coker, we issued to the seller a note in the amount of $350,000. The note bore interest at 8.25% and was repaid in June 2008. In connection with the purchase of Diggar, we issued to the seller a note in the amount of $750,000. The note bore interest at 6.0% and was repaid in July 2008. In connection with the purchase of Rebel, we issued to the sellers notes in the amount of $500,000. The notes bore interest at 5.0% and were repaid in October 2008.
In connection with the purchase of Capcoil, we agreed to pay a total of $500,000 to two management employees in exchange for non-compete agreements. We were required to make annual payments of $110,000 through May 2008. Total amounts due under these non-compete agreements at December 31, 2008 and 2007 were $0 and $110,000, respectively.
In 2000 we compensated directors, including current directors Nederlander and Toboroff, who served on the board of directors from 1989 to March 31, 1999 without compensation, by issuing promissory notes totaling $325,000. The notes bear interest at the rate of 5.0%. At December 31, 2008 and 2007, the principal and accrued interest on these notes totaled approximately $32,000.
We have various rig and equipment financing loans with interest rates ranging from 8.3% to 8.7% and terms of 2 to 5 years. As of December 31, 2008 and 2007, the outstanding balances for rig and equipment financing loans were $0 and $595,000, respectively.
In April 2007 and August 2007, we obtained insurance premium financings in the aggregate amount of $4.4 million with a fixed weighted average interest rate of 5.9%. Under terms of the agreements, amounts outstanding are paid over 10 and 11 month repayment schedules. The outstanding balance of these notes was approximately $0 and $1.7 million as of December 31, 2008 and 2007, respectively. In April 2008 and August 2008, we obtained insurance premium financings in the aggregate amount of $3.0 million with a fixed average weighted interest rate of 4.9%. Under terms of the agreements, amounts outstanding are paid over 10 and 11 month repayment schedules. The outstanding balance of these notes was approximately $991,000 at December 31, 2008.
As part of our acquisition of BCH, we assumed various capital leases with terms of two to three years. The outstanding balance under these capital leases was $779,000 at December 31, 2008. We also had other capital leases with terms that expired in 2008. As of December 31, 2007, amounts outstanding under capital leases were $14,000.
The following table summarizes our obligations and commitments to make future payments under our notes payable, operating leases, employment contracts and consulting agreements for the periods specified as of December 31, 2008.
(a)
These amounts represent our minimum capital lease obligations, net of interest payments totaling $86,000.
Recent Developments
In February 2009, we entered into a new credit agreement in an amount up to $29.0 million. The credit agreement is subject to customary closing conditions, with the proceeds being used to fund 80% of the purchase price of two land drilling rigs and related equipment that are scheduled for delivery in the second quarter of 2009. The loan will be secured by the equipment and will be repaid in quarterly installments over six years from the funding date.
We expect to utilize the two land drilling rigs for an existing client operating in the Haynesville Shale under a long-term alliance which would include other services that we would provide. We have suspended the construction of two other land drilling rigs which were ordered in the summer of 2008.
In February 2009, we executed a joint venture agreement with Rawabi Holding Company Ltd., or Rawabi, under the laws of the Kingdom of Saudi Arabia. The purpose of the joint venture is to provide oilfield services and rental equipment in the Kingdom of Saudi Arabia. We will own 50% of the joint venture.
As a result of the economic environment and the decrease in the U.S. rig count in 2009, in February of 2009 we announced cost reduction steps which include a reduction in the U.S. workforce of approximately 235 people, reduction of certain day rates paid to personnel, reduction or consolidation of certain operating yards and reduction of employee benefits. Additional workforce reductions and other cost saving measures are anticipated. Capital expenditures for 2009 will be limited to required maintenance levels and those related to firm commitments made in 2008.
Critical Accounting Policies
We have identified the policies below as critical to our business operations and the understanding of our results of operations. The impact and any associated risks related to these policies on our business operations is discussed throughout Management’s 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.
Impairment Of Long-Lived Assets. Long-lived assets, principally property, plant and equipment, comprise a significant amount of our total assets. We make judgments and estimates in conjunction with the carrying value of these assets, including amounts to be capitalized, depreciation and amortization methods and useful lives. Additionally, the carrying values of these assets are reviewed for impairment or whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. This requires us to make long-term forecasts of our future revenues and costs related to the assets subject to review. These forecasts require assumptions about demand for our products and services, future market conditions and technological developments. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period.
Goodwill And Other Intangibles. As of December 31, 2008, we have recorded approximately $43.3 million of goodwill and $37.4 million of other identifiable intangible assets. We perform purchase price allocations to intangible assets when we make a business combination. Business combinations and purchase price allocations have been consummated for acquisitions in all of our reportable segments. The excess of the purchase price after allocation of fair values to tangible assets is allocated to identifiable intangibles and thereafter to goodwill. We make judgments and estimates in conjunction with the carrying value of these assets, including amounts to be capitalized and whether the asset has finite live for amortization purposes.
We perform our annual impairment test in accordance with FASB No. 142. Our tests included two approaches to determine the carrying amount of the individual reporting units. The first approach is the Discounted Cash Flow Method, which focuses on our expected cash flow. In applying this approach, the cash flow available for distribution is projected for a finite period of years. Cash flow available for distribution is defined as the amount of cash that could be distributed as a dividend without impairing our future profitability or operations. The cash flow available for distribution and the terminal value (our value at the end of the estimation period) are then discounted to present value to derive an indication of value of the business enterprise. This valuation method is dependent upon the assumptions made regarding future cash flow and cash requirements. The second approach is the Guideline Company Method which focuses on comparing us to selected reasonably similar publicly traded companies. Under this method, valuation multiples are: (i) derived from operating data of selected similar companies; (ii) evaluated and adjusted based on our strengths and weaknesses relative to the selected guideline companies; and (iii) applied to our operating data to arrive at an indication of value. This valuation method is dependent upon the assumption that our value can be evaluated by analysis of our earnings and our strengths and weaknesses relative to the selected similar companies. We recorded an impairment charge of $115.8 million in 2008 as a result of our test. Significant and unanticipated changes to these assumptions could require an additional provision for impairment in a future period.
Purchase Price Allocation of Acquired Businesses. We allocate the purchase price of acquired businesses to the identifiable assets and liabilities of the businesses, post acquisition, based on estimated fair values. The
excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. We engage third-party appraisal firms and valuation experts to assist in the determination of identifiable assets and liabilities. Our judgments and estimates for the allocation of purchase price are based on information available during the measurement period, these judgments and estimates can materially impact our financial position as well as our results of operations.
Income Taxes. The determination and evaluation of our annual income tax provision involves the interpretation of tax laws in various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations and our level of operations or profitability in each jurisdiction may impact our tax liability in any given year. While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined. Current income tax expense (benefit) reflects an estimate of our income tax liability for the current year, withholding taxes, changes in tax rates and changes in prior year tax estimates as returns are filed. Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the enacted tax rates in effect at year end. A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. We provide for uncertain tax positions pursuant to FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109.
It is our intention to permanently reinvest all of the undistributed earnings of our non-U.S. subsidiaries in such subsidiaries. Accordingly, we have not provided for U.S. deferred taxes on the undistributed earnings of our non-U.S. subsidiaries. If a distribution is made to us from the undistributed earnings of these subsidiaries, we could be required to record additional taxes. Because we cannot predict when, if at all, we will make a distribution of these undistributed earnings, we are unable to make a determination of the amount of unrecognized deferred tax liability.
Recently Issued Accounting Standards
In September 2006, the Financial Accounting Standards Board, or FASB, issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements, or SFAS No. 157. SFAS No. 157 clarifies the principle that fair value should be based on the assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, with early adoption permitted. Subsequently, the FASB provided for a one-year deferral of the provisions of SFAS No. 157 for non-financial assets and liabilities that are recognized or disclosed at fair value in the consolidated financial statements on a non-recurring basis. As allowed under SFAS No. 157, we adopted all requirements of SFAS No. 157 on January 1, 2008, except as they relate to nonfinancial assets and liabilities, which were adopted on January 1, 2009 and neither adoption had any impact on our financial statements.
In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, or SFAS No. 159, which permits entities to elect to measure many financial instruments and certain other items at fair value. Upon adoption of SFAS No. 159, an entity may elect the fair value option for eligible items that exist at the adoption date. Subsequent to the initial adoption, the election of the fair value option should only be made at the initial recognition of the asset or liability or upon a re-measurement event that gives rise to the new-basis of accounting. All subsequent changes in fair value for that instrument are reported in earnings. SFAS No. 159 does not affect any existing accounting literature that requires certain assets and liabilities to be recorded at fair value nor does it eliminate disclosure requirements included in other accounting standards. SFAS No. 159 is effective as of the beginning of each reporting entity’s first fiscal year that begins after November 15, 2007. We adopted SFAS No. 159 on January 1, 2008 and there was no impact on our financial statements.
In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141 (revised 2007), Business Combinations, or SFAS No. 141(R). SFAS No. 141(R) changes the requirements for an acquirer’s recognition and measurement of the assets acquired and the liabilities assumed in a business combination. Additionally, SFAS No. 141(R) requires that acquisition-related costs, including restructuring costs, be recognized as expense separately from the acquisition. We adopted SFAS No. 141(R) on January 1, 2009 and there was no impact on our financial statements.
In December 2007, the FASB issued Statement of Financial Accounting Standards No. 160, Non-controlling Interests in Consolidated Financial Statements - an amendment of ARB No. 51, or SFAS No. 160. SFAS No. 160 requires (i) that non-controlling (minority) interests be reported as a component of shareholders’ equity, (ii) that net income attributable to the parent and to the non-controlling interest be separately identified in the consolidated statement of operations, (iii) that changes in a parent’s ownership interest while the parent retains its controlling interest be accounted for as equity transactions, (iv) that any retained non-controlling equity investment upon the deconsolidation of a subsidiary be initially measured at fair value, and (v) that sufficient disclosures are provided that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. SFAS No. 160 is effective for annual periods beginning after December 15, 2008 and should be applied prospectively. The presentation and disclosure requirements of the statement shall be applied retrospectively for all periods presented. We adopted SFAS No. 160 on January 1, 2009 and there was no impact on our financial statements.
In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133, or SFAS No. 161. SFAS No. 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in hedged positions. The statement also requires enhanced disclosures regarding how and why entities use derivative instruments, how derivative instruments and related hedged items are accounted and how derivative instruments and related hedged items affect entities’ financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008. We adopted SFAS No. 161 on January 1, 2009 and there was no impact on our financial statements.
In April 2008, the FASB issued FASB Staff Position SFAS 142-3, Determination of the Useful Life of Intangible Assets, or FSP SFAS 142-3. FSP SFAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142. The objective of FSP SFAS 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141R, and other U.S. GAAP principles. FSP SFAS 142-3 is effective for fiscal years beginning after December 15, 2008. We adopted FSP SFAS 142-3 on January 1, 2009 and there was no impact on our financial statements.
Off-Balance Sheet Arrangements
We have no off balance sheet arrangements, other than normal operating leases and employee contracts, that have or are likely to have a current or future material effect on our financial condition, changes in financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources. We have a $90.0 million revolving credit facility with a maturity of April 2012. At December 31, 2008, $36.5 million was borrowed on the facility and availability is further reduced by outstanding letters of credit of $5.8 million. We do not guarantee obligations of any unconsolidated entities.
ITEM 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.
We are exposed to market risk primarily from changes in interest rates and foreign currency exchange risks.
Interest Rate Risk
Fluctuations in the general level of interest rates on our current and future fixed and variable rate debt obligations expose us to market risk. We are vulnerable to significant fluctuations in interest rates on our variable rate debt and on any future refinancing of our fixed rate debt and on future debt.
At December 31, 2008, we were exposed to interest rate fluctuations on approximately $86.1 million of bank loans carrying variable interest rates. A hypothetical one hundred basis point increase in interest rates for these notes payable would increase our annual interest expense by approximately $861,000. Due to the uncertainty of fluctuations in interest rates and the specific actions that might be taken by us to mitigate the impact of such fluctuations and their possible effects, the foregoing sensitivity analysis assumes no changes in our financial structure.
We have also been subject to interest rate market risk for short-term invested cash and cash equivalents. The principal of such invested funds would not be subject to fluctuating value because of their highly liquid short-term nature. As of December 31, 2008, we had no short-term maturing investments.
Foreign Currency Exchange Rate Risk
We have designated the U.S. dollar as the functional currency for our operations in international locations as we contract with customers, purchase equipment and finance capital using the U.S. dollar. Local currency transaction gains and losses, arising from remeasurement of certain assets and liabilities denominated in local currency, are included in our consolidated statements of income. For the years ended December 31, 2008, 2007 and 2006, we had a net foreign exchange loss of $1.2 million, $128,000 and $515,000, respectively relating to our Drilling and Completion operations. We also conduct international business through our Rental Services and Oilfield Services segments and to control the foreign exchange risk, we provide for payment in U.S. dollars.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
ALLIS-CHALMERS ENERGY INC. AND SUBSIDIARIES
MANAGEMENT’S REPORT TO THE STOCKHOLDERS OF ALLIS-CHALMERS ENERGY INC.
Management’s Report on Internal Control Over Financial Reporting
As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for Allis-Chalmers Energy Inc. and its subsidiaries, or Allis-Chalmers. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing, using the criteria in Internal Control-Integral Framework issued by the Committee of Sponsoring Organization of the Treadway Commission (COSO). Allis-Chalmers’ system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitation, internal control over financial reporting may not prevent or detect misstatements.
Based on our assessment, we have concluded that Allis-Chalmers maintained effective internal control over financial reporting as of December 31, 2008, based on criteria in Internal Control-Integrated Framework issued by the COSO. The effectiveness of Allis-Chalmers internal control over financial reporting as of December 31, 2008 has been audited by UHY LLP, an independent registered public accounting firm, as stated in their report, which is included herein.
Management’s Certifications
The certifications of Allis-Chalmers’ Chief Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Allis-Chalmers’ Form 10-K.
ALLIS-CHALMERS ENERGY INC.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Allis-Chalmers Energy Inc.:
We have audited the accompanying consolidated balance sheets of Allis-Chalmers Energy Inc. and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2008. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Allis-Chalmers Energy Inc. and subsidiaries as of December 31, 2008 and 2007, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Allis-Chalmers Energy Inc.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 9, 2009 expressed an unqualified opinion thereon.
/s/ UHY LLP
Houston, Texas
March 9, 2009
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of
Allis-Chalmers Energy Inc.:
We have audited Allis-Chalmers Energy Inc.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Allis-Chalmers Energy Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s 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 company’s 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 company’s 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 company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Allis-Chalmers Energy Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Allis-Chalmers Energy Inc. and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008, and our report dated March 9, 2009 expressed an unqualified opinion thereon.
/s/ UHY LLP
Houston, Texas
March 9, 2009
ALLIS-CHALMERS ENERGY INC.
CONSOLIDATED BALANCE SHEETS
The accompanying Notes are an integral part of the Consolidated Financial Statements.
ALLIS-CHALMERS ENERGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying Notes are an integral part of the Consolidated Financial Statements.
ALLIS-CHALMERS ENERGY INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
The accompanying Notes are an integral part of the Consolidated Financial Statements.
ALLIS-CHALMERS ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying Notes are an integral part of the Consolidated Financial Statements.
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements
NOTE 1 -
NATURE OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization of Business
Allis-Chalmers Energy Inc. (“Allis-Chalmers”, “we”, “our” or “us”) was incorporated in Delaware in 1913. We provide services and equipment to oil and natural gas exploration and production companies throughout the U.S. including Texas, Louisiana, Oklahoma, New Mexico, Colorado, Pennsylvania, Arkansas, offshore in the Gulf of Mexico, and internationally, primarily in Argentina, Brazil and Mexico. We operate in three sectors of the oil and natural gas service industry: Oilfield Services; Drilling and Completion and Rental Services.
The nature of our operations and the many regions in which we operate subject us to changing economic, regulatory and political conditions. We are vulnerable to near-term and long-term changes in the demand for and prices of oil and natural gas and the related demand for oilfield service operations.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Future events and their effects cannot be perceived with certainty. Accordingly, our accounting estimates require the exercise of judgment. While management believes that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. Estimates are used for, but are not limited to, determining the following: allowance for doubtful accounts, recoverability of long-lived assets and intangibles, useful lives used in depreciation and amortization, income taxes and valuation allowances. The accounting estimates used in the preparation of the consolidated financial statements may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.
Principles of Consolidation
The consolidated financial statements include the accounts of Allis-Chalmers and its subsidiaries. Our subsidiaries at December 31, 2008 are AirComp LLC (“AirComp”), Allis-Chalmers Tubular Services LLC (“Tubular”), Strata Directional Technology LLC (“Strata”), Allis-Chalmers Rental Services LLC (“Rental”), Allis-Chalmers Production Services LLC (“Production”), Allis-Chalmers Management LLC, Allis-Chalmers Holdings Inc., DLS Drilling, Logistics & Services Company (“DLS”), DLS Argentina Limited, Tanus Argentina S.A. (“Tanus”), Petro-Rentals LLC (“Petro-Rental”), Rebel Rentals LLC (“Rebel”), Allis-Chalmers Drilling LLC, BCH Ltd. (“BCH”) and BCH Energy do Brasil Servicos de Petroleo Ltda. All significant inter-company transactions have been eliminated.
Revenue Recognition
We provide rental equipment and drilling services to our customers at per day, or daywork, and per job contractual rates and recognize the drilling related revenue as the work progresses and when collectibility is reasonably assured. Revenue from daywork contracts is recognized when it is realized or realizable and earned. On daywork contracts, revenue is recognized based on the number of days completed at fixed rates stipulated by the contract. For certain contracts, we receive lump-sum and other fees for equipment and other mobilization costs. Mobilization fees and the related costs are deferred and amortized over the contract terms when material. We recognize reimbursements received for out-of-pocket expenses incurred as revenues and account for out-of-pocket expenses as direct costs. Payments from customers for the cost of oilfield rental equipment that is damaged or lost-in-hole are reflected as revenues. We recognized revenue from damaged or
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
lost-in-hole equipment of $10.6 million, $12.6 million and $2.4 million for the years ended December 31, 2008, 2007 and 2006, respectively.
Allowance for Doubtful Accounts
Accounts receivable are customer obligations due under normal trade terms. We sell our services to oil and natural gas exploration and production companies. We perform continuing credit evaluations of its customers’ financial condition and although we generally do not require collateral, letters of credit may be required from customers in certain circumstances.
The allowance for doubtful accounts represents our estimate of the amount of probable credit losses existing in our accounts receivable. Significant individual accounts receivable balances which have been outstanding greater than 90 days are reviewed individually for collectibility. We have a limited number of customers with individually large amounts due at any given date. Any unanticipated change in any one of these customer’s credit worthiness or other matters affecting the collectibility of amounts due from such customers could have a material effect on the results of operations in the period in which such changes or events occur. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. As of December 31, 2008 and 2007, we had recorded an allowance for doubtful accounts of $4.2 million and $1.9 million respectively. Bad debt expense was $3.3 million, $1.3 million and $781,000 for the years ended December 31, 2008, 2007 and 2006, respectively.
Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents.
Inventories
Inventories are stated at the lower of cost or market. Cost is determined using the first - in, first - out (“FIFO”) method or the average cost method, which approximates FIFO, and includes the cost of materials, labor and manufacturing overhead.
Property and Equipment
Property and equipment is recorded at cost less accumulated depreciation. Certain equipment held under capital leases are classified as equipment and the related obligations are recorded as liabilities.
Maintenance and repairs, which do not improve or extend the life of the related assets, are charged to operations when incurred. Refurbishments and renewals are capitalized when the value of the equipment is enhanced for an extended period. When property and equipment are sold or otherwise disposed of, the asset account and related accumulated depreciation account are relieved, and any gain or loss is included in operations. Interest is capitalized on construction in progress at the weighted average cost of debt outstanding during the construction period or at the interest rate on debt incurred for construction.
The cost of property and equipment currently in service is depreciated over the estimated useful lives of the related assets, which range from three to twenty years. Depreciation is computed on the straight-line method for financial reporting purposes. Capital leases are amortized using the straight-line method over the estimated useful lives of the assets and lease amortization is included in depreciation expense. Depreciation expense charged to operations was $63.5 million, $50.9 million and $20.3 million for the years ended December 31, 2008, 2007 and 2006, respectively.
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
Goodwill, Intangible Assets and Amortization
Goodwill and other intangible assets with infinite lives are not amortized, but tested for impairment annually or more frequently if circumstances indicate that impairment may exist. Intangible assets with finite useful lives are amortized either on a straight-line basis over the asset’s estimated useful life or on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized.
The impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. Reporting units are at a business unit level and is one level below our operating segments. If the fair value of the reporting unit is less than the book value (including goodwill) then goodwill is reduced to its implied fair value and the amount of the write-down is charged against earnings. We perform impairment tests on the carrying value of our goodwill on an annual basis as of December 31st for each of our reportable segments. Historically, we have used the Discounted Cash Flow method, which focuses on our expected cash flow. In applying this approach, the cash flow available for distribution is projected for a finite period of years, we use five years. The cash flow available for distribution and the terminal value, which is an estimate of the value at the end of the five years, are then discounted to present value to derive an indication of value of the business unit. For our annual assessment of impairment for 2008, due to the economic conditions affecting our industry, we also utilized the Guideline Company Method. Under this method we make a comparison of our projections to reasonably similar publicly traded companies. As a result we recorded an impairment of $115.8 million at December 31, 2008. At December 31, 2007, no impairment was deemed necessary. Increases in estimated future costs or decreases in projected revenues could lead to an impairment of all or a portion of our goodwill in future period.
Impairment of Long-Lived Assets
Long-lived assets, which include property, plant and equipment, and other intangible assets, and certain other assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. The determination of recoverability is made based upon the estimated undiscounted future net cash flows, excluding interest expense. The impairment loss is determined by comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value of the related assets.
Financial Instruments
Financial instruments consist of cash and cash equivalents, accounts receivable and payable, and debt. The carrying value of cash and cash equivalents and accounts receivable and payable approximate fair value due to their short-term nature. We believe the fair values and the carrying value of our debt, excluding the senior notes, would not be materially different due to the instruments’ interest rates approximating market rates for similar borrowings at December 31, 2008 and 2007. Our senior notes, in the aggregate amount of $505 million, trade “over the counter” in limited amounts and on an infrequent basis. Based on those trades we estimate the fair value of our senior notes to be approximately $284 million and $490 million at December 31, 2008 and 2007, respectively. The price at which our senior notes trade is based on many factors such as the level of interest rates, the economic environment, the outlook for the oilfield services industry and the perceived credit risk. Additionally, due to the turmoil in the financial markets of 2008 and 2009, and its impact on investors of our senior notes, the price at which our senior notes trade may be affected by the investors’ financial distress and need for liquidity.
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
Concentration of Credit and Customer Risk
Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents and trade accounts receivable. As of December 31, 2008, we have approximately $782,000 and $3.2 million of cash and cash equivalents residing in Argentina and Brazil, respectively. Cash and cash equivalents of $1.8 million are restricted in conjunction with financial institution obligations in Brazil. We transact our business with several financial institutions. However, the amount on deposit in two financial institutions exceeded the $250,000 federally insured limit at December 31, 2008 by a total of $7.0 million. Management believes that the financial institutions are financially sound and the risk of loss is minimal.
We sell our services to major and independent domestic and international oil and natural gas companies. We perform ongoing credit valuations of our customers and provide allowances for probable credit losses where appropriate. In 2008, 2007 and 2006, one of our customers, Pan American Energy LLC Sucursal Argentina, or Pan American Energy, represented 28.5%, 20.7% and 11.7% of our consolidated revenues, respectively. Revenues from Pan American Energy represented 62.0%, 51.0% and 45.6% of our international revenues in 2008, 2007 and 2006, respectively (see Note 13).
Debt Issuance Costs
The costs related to the issuance of debt are capitalized and amortized to interest expense using the straight-line method, which approximates the interest method, over the maturity periods of the related debt. Interest expense related to debt issuance costs were $2.1 million, $1.9 million and $1.5 million for the years ended December 31, 2008, 2007 and 2006, respectively.
Income Taxes
Our income tax expense is based on our income, statutory tax rates and tax planning opportunities available to us in the various jurisdictions in which we operate. We provide for income taxes based on the tax laws and rates in effect in the countries in which operations are conducted and income is earned. Our income tax expense is expected to fluctuate from year to year as our operations are conducted in different taxing jurisdictions and the amount of pre-tax income fluctuates.
The determination and evaluation of our annual income tax provision involves the interpretation of tax laws in various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations and our level of operations or profitability in each jurisdiction may impact our tax liability in any given year. While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined.
Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in tax rates and changes in prior year tax estimates as returns are filed. Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the enacted tax rates in effect at year end. A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. We provide for uncertain tax positions pursuant to Financial Accounting Standards Board, or FASB, Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109 (“FIN 48”). Our policy is that we recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense. As of the date of adoption of FIN 48, we did not have any accrued interest or penalties associated with any unrecognized tax benefits. For U.S. federal tax purposes, our tax returns for the tax years 2001 through 2007 remain open for
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
examination by the tax authorities. Our foreign tax returns remain open for examination for the tax years 2001 through 2007. Generally, for state tax purposes, our 2003 through 2007 tax years remain open for examination by the tax authorities under a four year statute of limitations, however, certain states may keep their statute open for six to ten years.
It is our intention to permanently reinvest all of the undistributed earnings of our non-U.S. subsidiaries in such subsidiaries. Accordingly, we have not provided for U.S. deferred taxes on the $57.8 million of undistributed earnings of our non-U.S. subsidiaries as of December 31, 2008. If a distribution is made to us from the undistributed earnings of these subsidiaries, we could be required to record additional taxes. Because we cannot predict when, if at all, we will make a distribution of these undistributed earnings, we are unable to make a determination of the amount of unrecognized deferred tax liability.
Stock-Based Compensation
We adopted Statement of Financial Accounting Standards No. 123R, Share-Based Payment (“SFAS No. 123R”), effective January 1, 2006. This statement requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their grant-date fair values. We adopted SFAS No. 123R using the modified prospective transition method, utilizing the Black-Scholes option pricing model for the calculation of the fair value of our employee stock options. Under the modified prospective method, we record compensation cost related to unvested stock awards as of December 31, 2005 by recognizing the unamortized grant date fair value of these awards over the remaining vesting periods of those awards with no change in historical reported earnings. We estimated forfeiture rates for 2008, 2007 and 2006 based on our historical experience.
The Black-Scholes model incorporates assumptions to value stock-based awards. The risk-free rate of interest is the related U.S. Treasury yield curve for periods within the expected term of the option at the time of grant. The dividend yield on our common stock is assumed to be zero as we have historically not paid dividends and have no current plans to do so in the future. The expected volatility is based on historical volatility of our common stock.
Our net income (loss) for the years ended December 31, 2008, 2007 and 2006 includes approximately $7.9 million, $4.9 million and $3.4 million of compensation costs related to share-based payments, respectively. The tax benefit recorded in association with the share-based payments was $9,000, $1.7 million and $6.4 million for the years-ended December 31, 2008, 2007 and 2006, respectively. As of December 31, 2008 there is $10.8 million of unrecognized compensation expense related to non-vested stock based compensation grants.
No options were granted in 2008. See Note 10 for further disclosures regarding stock options. The following assumptions were applied in determining the compensation costs for options granted in 2007 and 2006:
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
Income (Loss) Per Common Share
We compute income (loss) per common share in accordance with the provisions of Statement of Financial Accounting Standards No. 128, Earnings Per Share (“SFAS No. 128”). SFAS No. 128 requires companies with complex capital structures to present basic and diluted earnings per share. Basic earnings per share are computed on the basis of the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share is similar to basic earnings per share, but presents the dilutive effect on a per share basis of potential common shares (e.g., convertible preferred stock, stock options, etc.) as if they had been converted. Restricted stock grants are legally considered issued and outstanding, but are included in basic and diluted earnings per share only to the extent that they are vested. Unvested restricted stock is included in the computation of diluted earnings per share using the treasury stock method. Potential dilutive common shares that have an anti-dilutive effect (e.g., those that increase income per share) are excluded from diluted earnings per share.
The components of basic and diluted earnings (deficit) per share are as follows (in thousands, except per share amounts):
Warrants and share based compensation shares of approximately 332,000 were excluded in the computation of diluted earnings per share for 2008 as the effect would have been anti-dilutive due to the net loss for the year.
Segments of an Enterprise and Related Information
We disclose the results of our segments in accordance with Statement of Financial Accounting Standards No. 131, Disclosures About Segments Of An Enterprise And Related Information (“SFAS No. 131”). We designate the internal organization that is used by management for allocating resources and assessing performance as the source of our reportable segments. SFAS No. 131 also requires disclosures about products and services, geographic areas and major customers. Please see Note 14 for further disclosure of segment information in accordance with SFAS No. 131.
Reclassification
Certain prior period balances have been reclassified to conform to current year presentation.
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
New Accounting Pronouncements
In September 2006, the FASB, issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements, or SFAS No. 157. SFAS No. 157 clarifies the principle that fair value should be based on the assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, with early adoption permitted. Subsequently, the FASB provided for a one-year deferral of the provisions of SFAS No. 157 for non-financial assets and liabilities that are recognized or disclosed at fair value in the consolidated financial statements on a non-recurring basis. As allowed under SFAS No. 157, we adopted all requirements of SFAS No. 157 on January 1, 2008, except as they relate to nonfinancial assets and liabilities, which were adopted on January 1, 2009 and neither adoption had any impact on our financial statements.
In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, or SFAS No. 159, which permits entities to elect to measure many financial instruments and certain other items at fair value. Upon adoption of SFAS No. 159, an entity may elect the fair value option for eligible items that exist at the adoption date. Subsequent to the initial adoption, the election of the fair value option should only be made at the initial recognition of the asset or liability or upon a re-measurement event that gives rise to the new-basis of accounting. All subsequent changes in fair value for that instrument are reported in earnings. SFAS No. 159 does not affect any existing accounting literature that requires certain assets and liabilities to be recorded at fair value nor does it eliminate disclosure requirements included in other accounting standards. SFAS No. 159 is effective as of the beginning of each reporting entity’s first fiscal year that begins after November 15, 2007. We adopted SFAS No. 159 on January 1, 2008 and there was no impact on our financial statements.
In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141 (revised 2007), Business Combinations, or SFAS No. 141(R). SFAS No. 141(R) changes the requirements for an acquirer’s recognition and measurement of the assets acquired and the liabilities assumed in a business combination. Additionally, SFAS No. 141(R) requires that acquisition-related costs, including restructuring costs, be recognized as expense separately from the acquisition. We adopted SFAS No. 141(R) on January 1, 2009 and there was no impact on our financial statements.
In December 2007, the FASB issued Statement of Financial Accounting Standards No. 160, Non-controlling Interests in Consolidated Financial Statements - an amendment of ARB No. 51, or SFAS No. 160. SFAS No. 160 requires (i) that non-controlling (minority) interests be reported as a component of shareholders’ equity, (ii) that net income attributable to the parent and to the non-controlling interest be separately identified in the consolidated statement of operations, (iii) that changes in a parent’s ownership interest while the parent retains its controlling interest be accounted for as equity transactions, (iv) that any retained non-controlling equity investment upon the deconsolidation of a subsidiary be initially measured at fair value, and (v) that sufficient disclosures are provided that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. SFAS No. 160 is effective for annual periods beginning after December 15, 2008 and should be applied prospectively. The presentation and disclosure requirements of the statement shall be applied retrospectively for all periods presented. We adopted SFAS No. 160 on January 1, 2009 and there was no impact on our financial statements.
In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133, or SFAS No. 161. SFAS No. 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in hedged positions. The statement also requires enhanced disclosures
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
regarding how and why entities use derivative instruments, how derivative instruments and related hedged items are accounted and how derivative instruments and related hedged items affect entities’ financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008. We adopted SFAS No. 161 on January 1, 2009 and there was no material impact on our financial statements.
In April 2008, the FASB issued FASB Staff Position SFAS 142-3, Determination of the Useful Life of Intangible Assets, or FSP SFAS 142-3. FSP SFAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, or SFAS No. 142. The objective of FSP SFAS 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141R, Business Combinations, and other U.S. GAAP principles. FSP SFAS 142-3 is effective for fiscal years beginning after December 15, 2008. We adopted FSP SFAS 142-3 on January 1, 2009 and there was no impact on our financial statements.
See also Note 6 - Income Taxes for a discussion of the FASB’s Interpretation No. 48 - Accounting for Uncertainty in Income Taxes.
NOTE 2 -
POST RETIREMENT BENEFIT OBLIGATIONS
Medical and Life
Pursuant to the Plan of Reorganization that was confirmed by the Bankruptcy Court after acceptances by our creditors and stockholders and was consummated on December 2, 1988, we assumed the contractual obligation to Simplicity Manufacturing, Inc. (SMI) to reimburse SMI for 50% of the actual cost of medical and life insurance claims for a select group of retirees (SMI Retirees) of the prior Simplicity Manufacturing Division of Allis-Chalmers. The actuarial present value of the expected retiree benefit obligation is determined by an actuary and is the amount that results from applying actuarial assumptions to (1) historical claims-cost data, (2) estimates for the time value of money (through discounts for interest) and (3) the probability of payment (including decrements for death, disability, withdrawal, or retirement) between today and expected date of benefit payments. As of December 31, 2008 and 2007, we have post-retirement benefit obligations of $0 and $31,000, respectively.
401(k) Savings Plan
On June 30, 2003, we adopted the 401(k) Profit Sharing Plan (the “Plan”). The Plan is a defined contribution savings plan designed to provide retirement income to our eligible employees. The Plan is intended to be qualified under Section 401(k) of the Internal Revenue Code of 1986, as amended. It is funded by voluntary pre-tax contributions from eligible employees who may contribute a percentage of their eligible compensation, limited and subject to statutory limits. The Plan is also funded by discretionary matching employer contributions. Eligible employees cannot participate in the Plan until they have attained the age of 21 and completed three-months of service with us. Each participant is 100% vested with respect to the participants’ contributions while our matching contributions are vested over a three-year period in accordance with the Plan document. Contributions are invested, as directed by the participant, in investment funds available under the Plan. Matching contributions of approximately $1.5 million, $1.8 million and $735,000 were paid in 2008, 2007 and 2006, respectively.
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
NOTE 3 -
ACQUISITIONS AND ASSET DISPOSITIONS
Effective January 1, 2006, we acquired 100% of the outstanding stock of Specialty Rental Tools, Inc., or Specialty, for approximately $95.3 million in cash. In addition, approximately $588,000 of costs were incurred in relation to the Specialty acquisition. Specialty, located in Lafayette, Louisiana, was engaged in the rental of high quality drill pipe, heavy weight spiral drill pipe, tubing work strings, blow-out preventors, choke manifolds and various valves and handling tools for oil and natural gas drilling. The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):
Specialty’s historical property and equipment values were increased by approximately $71.6 million based on third-party valuations. The results of Specialty since the acquisition are included in our Rental Services segment.
Effective April 1, 2006, we acquired 100% of the outstanding stock of Rogers Oil Tools, Inc., or Rogers, based in Lafayette, Louisiana, for a total consideration of approximately $13.7 million, which includes approximately $11.3 million in cash, $1.6 million in our common stock and a $750,000 three-year promissory note. In addition, approximately $380,000 of costs were incurred in relation to the Rogers acquisition. Rogers sells, services and rents power drill pipe tongs and accessories and rental tongs for snubbing and well control applications. Rogers also provides specialized tong operators for rental jobs. The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):
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.
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
Effective August 14, 2006, we acquired 100% of the outstanding stock of DLS, based in Argentina, for a total consideration of approximately $114.5 million, which includes approximately $93.7 million in cash, $38.1 million in our common stock, less approximately $17.3 million of debt assigned to us. In addition, approximately $3.4 million of costs were incurred in relation to the DLS acquisition. DLS operated a fleet of 51 rigs, including 20 drilling rigs, 18 workover rigs and 12 pulling rigs in Argentina and one drilling rig in Bolivia. The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):
DLS’ historical property and equipment values were increased by approximately $22.7 million based on third-party valuations. The results of DLS since the acquisition are included in our Drilling and Completion segment.
On October 16, 2006, we acquired 100% of the outstanding stock of Petro Rental, based in Lafayette, Louisiana, for a total consideration of approximately $33.6 million, which includes approximately $20.2 million in cash, $3.8 million in our common stock and repaid $9.6 million of existing Petro Rental debt. In addition, approximately $82,000 of costs were incurred in relation to the Petro-Rental acquisition. Petro-Rental provides a variety of production-related rental tools and equipment and services, including wire line services and equipment, land and offshore pumping services and coiled tubing. The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):
Petro Rental’s 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
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
have a weighted-average useful life of 10 years. The results of Petro-Rental since the acquisition are included in our Oilfield Services segment.
Effective December 1, 2006, we acquired 100% of the outstanding stock of Tanus, based in Argentina, for a total consideration of $2.5 million. In addition, approximately $17,000 of costs were incurred in relation to the Tanus acquisition. Tanus is engaged in the research and manufacturing of additives for the oil, natural gas and water well drilling and completion fluids in Argentina. The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed at the date of the acquisition (in thousands).
The results of Tanus since the acquisition are included in our Drilling and Completion segment.
On December 18, 2006, we acquired substantially all of the assets of Oil & Gas Rental Services, Inc, or OGR, based in Morgan City, Louisiana, for a total consideration of approximately $342.4 million, which includes approximately $291.0 million in cash, and $51.4 million in our common stock. In addition, approximately $3.0 million of costs were incurred in relation to the acquisition of the assets of OGR The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired at the date of acquisition (in thousands):
OGR’s historical property and equipment values were increased by approximately $168.9 million based on third-party valuations. Intangible assets include approximately $106.1 million assigned to goodwill, $22.0 million to customer relations, $831,000 to patents and $35,000 assigned to employment agreements based on third-party valuations. The amortizable intangibles have a weighted-average useful life of 10.1 years. The results of the OGR assets since their acquisition are included in our Rental Services segment.
On June 29 2007, we acquired Coker Directional, Inc., or Coker, for a total consideration of approximately $3.9 million, which includes approximately $3.6 million in cash and a promissory note for $350,000. In addition, approximately $5,000 of costs were incurred in relation to the Coker acquisition. Coker was a directional drilling company operating in the Gulf coast and Central Texas regions. The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed at the date of the acquisition (in thousands):
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
Intangible assets include approximately $1.8 million assigned to goodwill and $2.1 million assigned to customer relationships and non-compete. The amortizable intangibles have a weighted-average useful life of 9.4 years. The results of Coker since the acquisition are included in our Oilfield Services segment.
On July 26, 2007, we acquired Diggar Tools, LLC, or Diggar, for a total consideration of approximately $10.3 million, which includes approximately $6.7 million in cash, a promissory note for $750,000 and payment of approximately $2.8 million of existing Diggar debt. In addition, approximately $29,000 of costs were incurred in relation to the Diggar acquisition. Diggar was a directional drilling company operating in the Rocky Mountains with an inventory of 115 downhole motors. The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired at the date of acquisition (in thousands):
Diggar’s historical property and equipment values were increased by approximately $3.4 million based on third-party valuations. Intangible assets include approximately $2.7 million assigned to goodwill. The results of Diggar since the acquisition are included in our Oilfield Services segment.
On October 23, 2007, we acquired Rebel for a total consideration of approximately $7.3 million, which includes approximately $5.0 million in cash, promissory notes for an aggregate of $500,000, payment of approximately $1.5 million of existing Rebel debt and the deposit of $305,000 in escrow to cover distributions owed under the Rebel Defined Benefit Pension Plan & Trust. In addition, approximately $214,000 of costs were incurred in relation to the Rebel acquisition. Rebel is based in Lafayette, Louisiana and had an extensive inventory of tubular services equipment and primarily provided tubing installation services. The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired at the date of acquisition (in thousands):
Rebel’s historical property and equipment values were increased by approximately $8.5 million based on third-party valuations. Intangible assets include approximately $461,000 assigned to goodwill and $683,000 assigned to customer relations. The amortizable intangibles have a useful life of 15 years. The results of Rebel since the acquisition are included in our Oilfield Services segment.
On November 1, 2007, we acquired substantially all the assets Diamondback Oilfield Services, Inc. or Diamondback, for a total consideration of approximately $23.1 million in cash. Approximately $89,000 of costs were incurred in relation to the Diamondback acquisition. Diamondback was a directional drilling
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
company based in Conroe, Texas with operations focused in the Texas Panhandle and Oklahoma. Diamondback assets included 30 downhole motors, five measurement while drilling kits and eight wireline steering vehicles. The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired at the date of acquisition (in thousands):
Diamondback’s historical property and equipment values were increased by approximately $2.0 million based on third-party valuations. Intangible assets include approximately $7.6 million assigned to goodwill, $650,000 assigned to non-compete, $620,000 assigned to trade name and $3.4 million assigned to customer relations based on third-party valuations. The amortizable intangibles have a weighted-average useful life of 13.3 years. Subsequent to the date of acquisition, the sellers earned an additional $3.0 million cash earn-out payment as the business achieved certain earning objectives. The earn-out increased goodwill and was accrued at December 31, 2008 and will be paid in 2009. The results of the Diamondback assets since their acquisition are included in our Oilfield Services segment.
On December 31 2008, we completed the acquisition of all of the outstanding stock of BCH for a total consideration of approximately $56.1 million. Approximately $251,000 of costs were incurred in relation to the BCH acquisition. BCH is a land drilling contractor operating in Brazil. The following table summarizes the preliminary allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired at the date of acquisition (in thousands):
BCH’s historical property and equipment values were decreased by approximately $2.8 million based on third-party valuations. Intangible assets include approximately $18.5 million assigned to goodwill, $4.9 million to customer contracts, $2.2 million assigned to trade name and $600,000 to non-competes based on third-party valuations. The amortizable intangibles have a weighted-average useful life of 12.6 years. We do not expect any material differences from the preliminary allocation of the purchase price and the final purchase price allocations.
The acquisitions were accounted for using the purchase method of accounting.
On June 29, 2007, we sold our capillary tubing units and related equipment for approximately $16.3 million. We reported a gain of approximately $8.9 million. The assets sold represented a small portion of our Oilfield Services segment.
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
Effective August 1, 2008, we sold our drill pipe tong manufacturing assets for approximately $7.5 million. We received cash of approximately $2.0 million at the time of sale, a 90-day note for $1.0 million and a 10-year non-interest bearing note for $4.5 million. Repayment on the 10-year note is tied to various performance targets and we have assigned a fair value of approximately $3.1 million to this note. We reported a gain of approximately $166,000 on this transaction. The assets sold represented a small portion of our Oilfield Services segment.
The following unaudited pro forma consolidated summary financial information for the year ended December 31, 2006 illustrates the effects of the acquisitions and the related public offerings of debt and equity for Rogers, DLS, Petro-Rental and OGR as if the acquisitions occurred as of January 1, 2006, based on the historical results of the acquisitions. The historical results for OGR are based on their historical year end of October 31 (in thousands, except per share amounts):
NOTE 4 -
INVENTORIES
Inventories are comprised of the following as of December 31 (in thousands):
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
NOTE 5 -
PROPERTY AND OTHER INTANGIBLE ASSETS
Property and equipment is comprised of the following as of December 31 (in thousands):
The net book value of equipment recorded under capital leases was $1.7 million and $285,000 as of December 31, 2008 and 2007, respectively. Interest expense capitalized to property and equipment was $1.9 million and $0 for the years ended December 31, 2008 and 2007, respectively.
Other intangible assets are as follows as of December 31 (in thousands):
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
Amortization expense related to other intangibles was $4.2 million, $4.1 million and $1.9 million for the years ended December 31, 2008, 2007 and 2006, respectively. Future amortization of intangible assets at December 31, 2008 is as follows (in thousands):
NOTE 6 -
INCOME TAXES
We had a loss before income taxes of $95.3 million for U.S. tax purposes for the year ended December 31, 2008. We had income before income taxes of $41.7 million and $35.9 million for U.S. tax purposes for the years ended December 31, 2007 and 2006, respectively. We also had income before income taxes of $38.4 million, $37.6 million and $11.1 million reported in non-U.S. countries for the years ended December 31, 2008, 2007 and 2006, respectively. We treat the withholding taxes incurred by our U.S. subsidiaries in foreign countries as foreign tax, and we anticipate using those tax payments to offset U.S. tax.
The income tax provision consists of the following (in thousands):
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.
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
The following table reconciles the statutory tax rates to our actual tax rate:
Significant components of deferred income tax assets as of December 31, were as follows (in thousands):
Net future tax-deductible items relate primarily to timing differences. Timing differences are differences between the tax basis of assets and liabilities and their reported amounts in the financial statements that will result in differences between income for tax purposes and income for financial statement purposes in future years. For example, the goodwill impairment that we recorded in 2008 for financial statement purposes related to our Rental Services segment has created a deferred tax asset that will be realized over the next 13 years.
The Tax Reform Act of 1986 contains provisions that limit the utilization of net operating loss and tax credit carry forwards if there has been a “change of ownership” as described in Section 382 of the Internal Revenue Code. Such a change of ownership may limit our utilization of our net operating loss and tax credit carryforwards, and could be triggered by a public offering or by subsequent sales of securities by us or our stockholders. This provision has limited the amount of net operating losses available to us currently. Net operating loss carryforwards for tax purposes at December 31, 2008 and 2007 were $6.7 million and $7.7 million, respectively, expiring through 2024.
Our 1988 Plan of Reorganization established the A-C Reorganization Trust to settle claims and to make distributions to creditors and certain stockholders. We transferred cash and certain other property to the A-C Reorganization Trust on December 2, 1988. Payments made by us to the A-C Reorganization Trust did not
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
generate tax deductions for us upon the transfer but generate deductions for us as the A-C Reorganization Trust makes payments to holders of claims and for administrative expenses. The Plan of Reorganization also created a trust to process and liquidate product liability claims. Payments made by the A-C Reorganization Trust to the Product Liability Trust did not generate current tax deductions for us upon the payment but generates deductions for us as the Product Liability Trust makes payments to liquidate claims or incurs administrative expenses. We believe the aforementioned trusts are grantor trusts and therefore we include the income or loss of these trusts in our income or loss for tax purposes. The income or loss of these trusts is not included in our results of operations for financial reporting purposes.
A valuation allowance is established for deferred tax assets when management, based upon available information, considers it more likely than not that a benefit from such assets will not be realized. As of December 31, 2008 and 2007, the valuation allowance was zero.
Approximately $4.7 million and $9.7 million of ad valorem, franchise, income, sales and other tax accruals are included in our accrued expense balances of $26.6 million and $20.5 million as of December 31, 2008 and 2007, respectively.
We adopted the provisions of FIN 48 on January 1, 2007. This interpretation clarifies the accounting for uncertain tax positions and requires companies to recognize the impact of a tax position in their financial statements, if that position is more likely than not of being sustained on audit, based on the technical merits of the position. The adoption of FIN 48 did not have any impact on the total liabilities or stockholders’ equity.
NOTE 7 -
DEBT
Our long-term debt consists of the following as of December 31 (in thousands):
Our weighted average interest rate for current and total debt was approximately 6.4% and 8.3% as of December 31, 2008 and 6.3% and 8.7% as of December 31, 2007, respectively.
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
Maturities of debt obligations as of December 31, 2008 are as follows (in thousands):
Senior notes, bank loans and line of credit agreements
On January 18, 2006 and August 14, 2006, we closed on private offerings, to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, of $160.0 and $95.0 million aggregate principal amount of our senior notes, respectively. The senior notes are due January 15, 2014 and bear interest at 9.0%. The proceeds were used to fund the acquisitions of Specialty and DLS, to repay existing debt and for general corporate purposes.
On December 18, 2006, we closed on a $300.0 million senior unsecured bridge loan. The bridge loan was due 18 months after closing and had a weighted average interest rate of 10.6%. The bridge loan, which was repaid on January 29, 2007, was used to fund the acquisition of substantially all the assets of OGR.
In January 2007, we closed on a private offering, to qualified institutional buyers pursuant to Rule 144A under the Securities Act, of $250.0 million principal amount of 8.5% senior notes due 2017. The proceeds of the senior notes offering, together with a portion of the proceeds of our concurrent common stock offering, were used to repay the debt outstanding under our $300.0 million bridge loan facility which we incurred to finance our acquisition of substantially all the assets of OGR.
On January 18, 2006, we also executed an amended and restated credit agreement which provided for a $25.0 million revolving line of credit with a maturity of January 2010. On April 26, 2007, we entered into a Second Amended and Restated Credit Agreement, which increased our revolving line of credit to $62.0 million, and had a final maturity date of April 26, 2012. On December 3, 2007, we entered into a First Amendment to Second Amended and Restated Credit Agreement, which increased our revolving line of credit to $90.0 million. The amended and restated credit agreement contains customary events of default and financial covenants and limits our ability to incur additional indebtedness, make capital expenditures, pay dividends or make other distributions, create liens and sell assets. Our obligations under the amended and restated credit agreement are secured by substantially all of our assets located in the U.S. We were in compliance with all debt covenants as of December 31, 2008 and 2007. The credit agreement loan rates are based on prime or LIBOR plus a margin. The weighted average interest rate was 4.6% at December 31, 2008. As of December 31, 2008 and 2007, amounts borrowed under the facility were $36.5 million and $0 and availability was reduced by outstanding letters of credit of $5.8 million and $8.4 million, respectively.
As part of our acquisition of DLS, we assumed various bank loans with floating interest rates based on LIBOR plus a margin and terms ranging from 2 to 5 years. The weighted average interest rates on these loans was 5.1% and 6.7% as of December 31, 2008 and 2007, respectively. The bank loans are denominated in U.S. dollars and the outstanding amount due as of December 31, 2008 and 2007 was $2.5 million and $4.9 million, respectively.
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
On February 15, 2008, through our DLS subsidiary in Argentina, we entered into a $25.0 million import finance facility with a bank. Borrowings under this facility were used to fund a portion of the purchase price of the new drilling and service rigs ordered for our Drilling and Completion segment. The facility was available for borrowings until December 31, 2008. Each drawdown shall be repaid over four years in equal semi-annual installments beginning one year after each disbursement with the final principal payment due not later than March 15, 2013. The import finance facility is unsecured and contains customary events of default and financial covenants and limits DLS’ ability to incur additional indebtedness, make capital expenditures, create liens and sell assets. We were in compliance with all debt covenants as of December 31, 2008. The bank loan rates are based on LIBOR plus a margin. The weighted average interest rate was 6.9% at December 31, 2008. The bank loans are denominated in U.S. dollars and the outstanding amount as of December 31, 2008 was $25.0 million.
As part of our acquisition of BCH, we assumed a $23.6 million term loan credit facility with a bank. The credit agreement is dated June 2007 and contains customary events of default and financial covenants. Obligations under the facility are secured by substantially all of the BCH assets. The facility is repayable in quarterly principal installments plus interest with the final payment due not later than August 2012. We were in compliance with all debt covenants as of December 31, 2008. The credit facility loan is denominated in U.S. dollars and interest rates are based on LIBOR plus a margin. At December 31, 2008, the outstanding amount of the loan was $22.1 million and the interest rate was 6.0%.
Notes payable
In connection with the acquisition of Rogers, we issued to the seller a note in the amount of $750,000. The note bears interest at 5.0% and is due April 2009. In connection with the purchase of Coker, we issued to the seller a note in the amount of $350,000. The note bore interest at 8.25% and was repaid in June 2008. In connection with the purchase of Diggar, we issued to the seller a note in the amount of $750,000. The note bore interest at 6.0% and was repaid in July 2008. In connection with the purchase of Rebel, we issued to the sellers notes in the amount of $500,000. The notes bore interest at 5.0% and were repaid in October 2008.
In 2000 we compensated directors, including current directors Nederlander and Toboroff, who served on the board of directors from 1989 to March 31, 1999 without compensation, by issuing promissory notes totaling $325,000. The notes bear interest at the rate of 5.0%. As of December 31, 2008 and 2007, the principal and accrued interest on these notes totaled approximately $32,000.
We have various rig and equipment financing loans with interest rates ranging from 8.3% to 8.7% and terms of 2 to 5 years. As of December 31, 2008 and 2007, the outstanding balances for rig and equipment financing loans were $0 and $595,000, respectively.
In April 2007 and August 2007, we obtained insurance premium financings in the aggregate amount of $4.4 million with a fixed weighted average interest rate of 5.9%. Under terms of the agreements, amounts outstanding are paid over 10 and 11 month repayment schedules. The outstanding balance of these notes was approximately $0 and $1.7 million as of December 31, 2008 and 2007, respectively. In April 2008 and August 2008, we obtained insurance premium financings in the aggregate amount of $3.0 million with a fixed average weighted interest rate of 4.9%. Under terms of the agreements, amounts outstanding are paid over 10 and 11 month repayment schedules. The outstanding balance of these notes was approximately $991,000 at December 31, 2008.
Other debt
In connection with the purchase of Capcoil Tubing Services, Inc., we agreed to pay a total of $500,000 to two management employees in exchange for non-compete agreements. We were required to make annual
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
payments of $110,000 through May 2008. Total amounts due under these non-compete agreements as of December 31, 2008 and 2007 were $0 and $110,000, respectively.
As part of our acquisition of BCH, we assumed various capital leases with terms of two to three years. The outstanding balance under these capital leases was $779,000 at December 31, 2008. We also had other capital leases with terms that expired in 2008. As of December 31, 2007, amounts outstanding under capital leases were $14,000.
NOTE 8 -
COMMITMENTS AND CONTINGENCIES
We have placed orders for capital equipment totaling $41.4 million to be received and paid for through 2009. Approximately $22.6 million is for drilling and service rigs for our Drilling and Completion segment, $10.0 million is for other drilling equipment for our Drilling and Completion segment, $5.5 million is for rental equipment, principally drill pipe, for our Rental Services segment and $3.3 million is for various equipment to be utilized by our Oilfield Services segment.
We rent office space and certain other facilities and shop yards for equipment storage and maintenance. Facility rent expense for the years ended December 31, 2008, 2007 and 2006 was $2.8 million, $2.7 million and $1.6 million, respectively.
At December 31, 2008, future minimum rental commitments for all operating leases are as follows (in thousands):
NOTE 9 -
STOCKHOLDERS’ EQUITY
During 2006, we issued 125,285 shares, 2.5 million shares, 246,761 shares and 3.2 million shares of our common stock in relation to the Rogers, DLS, Petro Rental and OGR asset acquisitions, respectively (see Note 3).
On August 14, 2006 we closed on a public offering of 3,450,000 shares of our common stock at a public offering price of $14.50 per share. Net proceeds from the public offering of approximately $46.3 million were used to fund a portion of our acquisition of DLS.
During 2006, we had options and warrants exercised, which resulted in 1,851,377 shares of our common stock being issued for approximately $6.3 million. We recognized approximately $3.4 million of compensation expense related to stock options in 2006 that was recorded as capital in excess of par value (see Note 1). We also recorded approximately $6.4 million of tax benefit related to our stock compensation plans.
In January 2007 we closed on a public offering of 6.0 million shares of our common stock at a public offering price of $17.65 per share. Net proceeds from the public offering, together with the proceeds of our concurrent senior notes offering, were used to repay the debt outstanding under our $300.0 million bridge loan facility, which we incurred to finance the OGR acquisition and for general corporate purposes.
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
During 2007, we also had restricted stock award grants, and options and warrants exercised, which resulted in 882,624 shares of our common stock being issued for approximately $3.3 million. We recognized approximately $4.9 million of compensation expense related to share based payments that was recorded as capital in excess of par value (see Note 1). We also recorded approximately $1.7 million of tax benefit related to our stock compensation plans.
During 2008, we had restricted stock award grants, and options exercised, which resulted in 558,707 shares of our common stock being issued for approximately $633,000. We recognized approximately $7.9 million of compensation expense related to share based payments that was recorded as capital in excess of par value (see Note 1). We also recorded approximately $9,000 of tax benefit related to our stock compensation plans.
NOTE 10 -
STOCK OPTIONS
In 2000, we issued stock options and promissory notes to certain directors as compensation for services as directors (See Note 7), and our Board of Directors granted stock options to these same individuals. Options to purchase 4,800 shares of our common stock were granted with an exercise price of $13.75 per share. These options vested immediately and may be exercised any time prior to March 28, 2010. As of December 31, 2008, 4,000 of the stock options remain outstanding. No compensation expense has been recorded for these options as they were issued with an exercise price equal to the fair value of the common stock at the date of grant.
On May 31, 2001, the Board granted to Leonard Toboroff, one of our directors, an option to purchase 100,000 shares of our common stock at $2.50 per share, exercisable for 10 years from October 15, 2001. The option was granted for services provided by Mr. Toboroff to Oil Quip Rentals, Inc., or Oil Quip, prior to the merger, including providing financial advisory services, assisting in Oil Quip’s capital structure and assisting Oil Quip in finding strategic acquisition opportunities. We recorded compensation expense of $500,000 for the issuance of the option for the year ended December 31, 2001. All of the stock options were exercised in May 2006.
The 2003 Incentive Stock Plan (“2003 Plan”), as amended, permits us to grant to our key employees and outside directors various forms of stock incentives, including, among others, incentive and non-qualified stock options and restricted stock. The 2003 Plan is administered by the Compensation Committee of the Board, which consists of two or more directors appointed by the Board. The following benefits may be granted under the 2003 Plan: (a) stock appreciation rights; (b) restricted stock; (c) performance awards; (d) incentive stock options; (e) nonqualified stock options; and (f) other stock-based awards. Stock incentive terms are not to be in excess of ten years. The maximum number of shares of our common stock that may be issued under the 2003 Plan shall be the lesser of 3,000,000 shares and 15% of the total number of shares of common stock outstanding.
The 2006 Incentive Plan (“2006 Plan”), was approved by our stockholders in November 2006. The 2006 Plan is administered by the Compensation Committee of the Board. The maximum number of shares of our common stock that may be issued under the 2006 Plan is equal to 1,500,000 shares, subject to adjustment in the event of stock splits and certain other corporate events. The 2006 Plan provides for the grant of any or all of the following types of awards: (i) stock options, including incentive stock options and non-qualified stock options; (ii) bonus stock; (iii) restricted stock awards; (iv) performance awards; and (v) other stock-based awards. Except with respect to awards of incentive stock options, all of our employees, consultants and non-employee directors are eligible to participate in the 2006 Plan. The term of each Award shall be for such period as may be determined by the Committee; provided, that in no event shall the term of any Award exceed a period of ten years from the date of its grant.
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
A summary of our stock option activity and related information is as follows:
The total intrinsic value of stock options (the amount by which the market price of the underlying stock on the date of exercise exceeds the exercise price of the option) exercised was approximately $542,000, $6.6 million and $18.8 million during the years ended December 31, 2008, 2007 and 2006, respectively. As of December 31, 2008, there was approximately $1.5 million of total unrecognized compensation cost related to stock options, with $918,000 and $532,000 to be recognized during the years ended December 31, 2009 and 2010, respectively.
The following table summarizes additional information about our stock options outstanding as of December 31, 2008:
The aggregate pretax intrinsic value of stock options outstanding and exercisable was approximately $490,000 at December 31, 2008. The amount represents the value that would have been received by the option holders had the respective options been exercised on December 31, 2008.
Restricted Stock Awards
In addition to stock options, our 2003 and 2006 Plans allow for the grant of restricted stock awards (“RSA”). A time-lapse RSA is an award of common stock, where each unit represents the right to receive at the end of a stipulated period one unrestricted share of stock with no exercise price. The time-lapse RSA restrictions lapse periodically over an extended period of time not exceeding 10 years. We determine the fair value of RSAs based on the market price of our common stock on the date of grant. Compensation cost for RSAs is primarily recognized on a straight-line basis over the vesting or service period and is net of forfeitures. A performance-based RSA is an award of common stock, where each unit represents the right to receive one unrestricted share of stock with no exercise price at the attainment of established performance criteria. During 2007, we granted 710,000 performance based RSAs with market conditions. The performance-based RSAs are granted, but not earned and issued until certain annual total shareholder return criteria are attained over the next 3 years. The fair value of the performance-based RSAs were based on third-party valuations.
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
The following table summarizes activity in our nonvested restricted stock awards:
The total fair value of RSA shares that vested during 2008 was approximately $4.7 million. As of December 31, 2008, there was approximately $9.4 million of total unrecognized compensation cost related to nonvested RSAs, with $6.0 million, $2.5 million, $709,000 and $208,000 to be recognized during the years ended December 31, 2009, 2010, 2011 and 2012, respectively.
NOTE 11 -
STOCK PURCHASE WARRANTS
In conjunction with Oil Quip’s purchase of Mountain Compressed Air, Inc., or MCA, in February of 2001, MCA issued a common stock warrant for 620,000 shares to a third-party investment firm that assisted us in its initial identification and purchase of the MCA assets. The warrant entitles the holder to acquire up to 620,000 shares of common stock of MCA at an exercise price of $.01 per share over a nine-year period commencing on February 7, 2001.
We issued two warrants (“Warrants A and B”) for the purchase of 233,000 total shares of our common stock at an exercise price of $0.75 per share and one warrant for the purchase of 67,000 shares of our common stock at an exercise price of $5.00 per share (“Warrant C”) in connection with our subordinated debt financing for MCA in 2001. Warrants A and B were paid off on December 7, 2004. Warrant C was exercised during November 2006.
In May 2004, we issued a warrant to purchase 3,000 shares of our common stock at an exercise price of $4.75 per share to a consultant in consideration of financial advisory services to be provided pursuant to a consulting agreement. The warrants were exercised in May 2004. This consultant was also granted 16,000 warrants in May of 2004 exercisable at $4.65 per share. These warrants were exercised in November of 2005. Warrants for 4,000 shares of our common stock at an exercise price of $4.65 were also issued to this consultant in May 2004 and were exercised in January 2007.
In conjunction with BCH debt financing in January of 2007, BCH issued a common stock warrant for 250,000 shares to a financial institution. The warrant entitles the holder to acquire up to 250,000 shares of common stock of BCH at an exercise price of $10.00 per share over a five-year period.
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
NOTE 12 -
CONDENSED CONSOLIDATED FINANCIAL INFORMATION
Set forth on the following pages are the condensed consolidating financial statements of (i) Allis-Chalmers Energy Inc., (ii) its subsidiaries that are guarantors of the senior notes and revolving credit facility and (iii) the subsidiaries that are not guarantors of the senior notes and revolving credit facility (in thousands):
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2008
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Year Ended December 31, 2008
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Year Ended December 31, 2008
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2007
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Year Ended December 31, 2007
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Year Ended December 31, 2007
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Year Ended December 31, 2006
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Year Ended December 31, 2006
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
NOTE 13 -
RELATED PARTY TRANSACTIONS
DLS’ largest customer is Pan American Energy which is a joint venture by British Petroleum and Bridas Corporation. Two of our Directors, Alejandro P. Bulgheroni and Carlos A. Bulgheroni, indirectly beneficially own substantially all of the shares of the Bridas Corporation. In 2008, 2007 and 2006, Pan American Energy represented 28.5%, 20.7%, and 11.7% of our consolidated revenues, respectively. At December 31, 2008 and 2007, we had trade receivables with Pan American Energy of $40.0 million and $23.1 million, respectively.
In 2008 and 2007, we derived revenue of approximately $1.0 million and $1.7 million from BEUSA Energy, Inc., or BEUSA, a company controlled by Alejandro P. Bulgheroni. At December 31, 2008 and 2007, we had trade receivables from BEUSA of approximately $558,000 and $1.6 million, respectively.
We purchase general oilfield supplies and materials from Ralow Services, Inc., or Ralow. Ralow is owned by Brad A. Adams and Bruce A. Adams who are brothers of Burt A. Adams, a former member of our board of directors and our former President and Chief Operating Officer. We purchased supplies and materials from Ralow in an aggregate amount of approximately $747,000 and $3.5 million for the years ended December 31, 2008 and 2007, respectively.
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
NOTE 14 -
SEGMENT INFORMATION
On January 31, 2008, we created the positions of Senior Vice President - Oilfield Services and Senior Vice President - Rental Services. In conjunction with this organizational change, we reviewed the presentation of our reporting segments during the first quarter of 2008. Based on this review, we determined that our operational performance would be segmented and reviewed by the Oilfield Services, Drilling and Completion and Rental Services segments. The Oilfield Services segment includes our underbalanced drilling, directional drilling, tubular services and production services operations. The Drilling and Completion segment includes our international drilling operations. As a result, we realigned our financial reporting segments and now report the following operations as separate, distinct reporting segments: (1) Oilfield Services, (2) Drilling and Completion and (3) Rental Services. Our historical segment data previously reported for the years ended December 31, 2007 and 2006 have been restated to conform to the new presentation.
All of our segments provide services to the energy industry. The revenues, operating income (loss), depreciation and amortization, capital expenditures and assets of each of the reporting segments plus the corporate function are reported below (in thousands):
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
NOTE 15 -
SUPPLEMENTAL CASH FLOWS INFORMATION (in thousands)
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 have been named as a defendant in two lawsuits in connection with our proposed merger with Bronco Drilling, Inc., which was terminated August 2008. We do not believe that the suits have any merit.
We are involved in various other legal proceedings in the ordinary course of business. The legal proceedings are at different stages; however, we believe that the likelihood of material loss relating to any such legal proceeding is remote.
NOTE 17 -
SUBSEQUENT EVENTS
In February 2009, we entered into a new credit agreement in an amount up to $29.0 million. The credit agreement is subject to customary closing conditions, with the proceeds being used to fund 80% of the purchase price of two land drilling rigs and related equipment that scheduled for delivery in the second quarter of 2009. The loan will be secured by the equipment and will be repaid in quarterly installments over six years from the funding date.
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements - (Continued)
In February 2009, we executed a joint venture agreement with Rawabi Holding Company Ltd., or Rawabi, under the laws of the Kingdom of Saudi Arabia. The purpose of the joint venture is to provide oilfield services and rental equipment in the Kingdom of Saudi Arabia. We will own 50% of the joint venture.
NOTE 18 -
SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED) (in thousands, except per share amounts)
ITEM 9.
ITEM 9.
CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
(a)
Evaluation Of Disclosure Controls And Procedures
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our “disclosure controls and procedures” (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)), as of December 31, 2008. Based on their evaluation, they have concluded that our disclosure controls and procedures as of the end of the period covered by this report were adequate to ensure that (1) information required to be disclosed by us in the reports filed or furnished by us under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and (2) such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures as of December 31, 2008 were effective at reaching a reasonable level of assurance of achieving the desired objective.
(b)
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as that term is defined in Exchange Act Rule 13a-15(f). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Our control environment is the foundation for our system of internal control over financial reporting and is an integral part of our Code of Business Ethics and Conduct for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, which sets the tone of our company. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements. Our evaluation did not include companies which were acquired during fiscal year 2008, since, under SEC guidelines, acquisitions do not have to be evaluated until twelve months after the acquisition date.
In order to evaluate the effectiveness of our internal control over financial reporting as of December 31, 2008, as required by Section 404 of the Sarbanes-Oxley Act of 2002, our management conducted an assessment, including testing, based on the criteria set forth in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting and, based on that assessment, concluded that, as of December 31, 2008, our internal controls over financial reporting are effective based on these criteria.
Management Report on Internal Control Over Financial Reporting.
Our Management Report on Internal Controls Over Financial Reporting can be found in Item 8 of this report. UHY LLP, an independent registered public accounting firm, has issued a report on our internal control over financial reporting as of December 31, 2008, which can be found in Item 8 of this report.
(c)
Change in Internal Control Over Financial Reporting.
During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Pursuant to General Instructions G(3), information on directors and executive officers of Allis-Chalmers will be filed in an amendment to this Annual Report on Form 10-K or incorporated by reference from our Definitive Proxy Statement for the 2009 annual meeting of stockholders filed within 120 days of the end of our fiscal year ending December 31, 2008.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
Pursuant to General Instructions G(3), information on executive compensation will be filed in an amendment to this Annual Report on Form 10-K or incorporated by reference from our Definitive Proxy Statement for the 2009 annual meeting of stockholders filed within 120 days of the end of our fiscal year ending December 31, 2008.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Pursuant to General Instruction G(3), information on security ownership of certain beneficial owners and management will be filed in an amendment to this Annual Report on Form 10-K or incorporated by reference from our Definitive Proxy Statement for the 2009 annual meeting of stockholders filed within 120 days of the end of our fiscal year ending December 31, 2008.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Pursuant to General Instruction G(3), information on security ownership of certain beneficial owners and management will be filed in an amendment to this Annual Report on Form 10-K or incorporated by reference from our Definitive Proxy Statement for the 2009 annual meeting of stockholders filed within 120 days of the end of our fiscal year ending December 31, 2008.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
Pursuant to General Instruction G(3), information on principal accountant fees and services will be filed in an amendment to this Annual Report on Form 10-K or incorporated by reference from our Definitive Proxy Statement for the 2009 annual meeting of stockholders filed within 120 days of the end of our fiscal year ending December 31, 2008.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) Financial Statements: The following financial statements for Allis-Chalmers Energy Inc. and Subsidiaries are included in Item 8. “Financial Statements and Supplementary Data”
Consolidated Balance Sheets as of December 31, 2008 and 2007.
Consolidated Statements of Operations for the years ended December 31, 2008, 2007 and 2006.
Consolidated Statement of Stockholders’ Equity for the years ended December 31, 2008, 2007 and 2006.
Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006.
Notes to Consolidated Financial Statements.
(2) Financial Statement Schedules
Schedule II - Valuation and Qualifying Accounts
All other schedules are omitted because they are not applicable, not required, or the information is included in the financial statements or the notes thereto.
(3) Exhibits
The exhibits listed on the accompanying Exhibit Index are incorporated by reference into this annual report on Form 10-K.
(2)
Financial Statement Schedule:
Schedule II - Valuation and Qualifying Accounts
Allis-Chalmers Energy Inc.
Valuation and Qualifying Accounts
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on March 9, 2009.
ALLIS-CHALMERS ENERGY INC.
/s/ MUNAWAR H. HIDAYATALLAH
Munawar H. Hidayatallah
Chief Executive Officer and Chairman
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, this report has been signed on the date indicated by the following persons on behalf of the registrant and in the capacities indicated.
EXHIBIT INDEX
*
Compensation Plan or Agreement

Filed herewith.