UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549

Form 10-K

 

 

Commission file number 1-2199

 

ALLIS-CHALMERS ENERGY INC.

(Exact name of registrant as specified in its charter)

 

 

(713) 369-0550

Registrant’s telephone number, including area code

 

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

 

 

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

NONE

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o     No þ

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.  Yes o     No þ

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o

 

Indicate by check mark whether the registrant has submitted electronically and posted on it corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o     No o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

(Do not check if a smaller reporting company)

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o     No þ

 

The aggregate market value of the common equity held by non-affiliates of the registrant, computed using the closing price of the common stock of $2.31 per share on June 30, 2009, as reported on the New York Stock Exchange, was approximately $94,383,251.

 

As of February 26, 2010 there were 71,459,876 shares of common stock issued and outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE:

 

Certain information called for by Items 10, 11, 12, 13 and 14 of Part III will be included in an amendment to this annual report on Form 10-K or incorporated by reference from the registrant’s definitive proxy statement for its 2010 annual meeting of stockholders.

 

 

TABLE OF CONTENTS

 

 

DEFINITIONS

 

 

SPECIAL NOTE
REGARDING FORWARD-LOOKING STATEMENTS

 

This annual report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, regarding our business, financial condition, results of operations and prospects. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements. However, these are not the exclusive means of identifying forward-looking statements. Although such forward-looking statements reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Consequently, forward-looking statements are inherently subject to risks and uncertainties, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. These factors include, but are not limited to, the following:

 

 

Further information about the risks and uncertainties that may impact us are described in “Risk Factors” beginning on page — 12 — of this annual report. You should read those sections carefully. You should not place undue reliance on forward-looking statements, which speak only as of the date of this annual report. We undertake no obligation to update publicly any forward-looking statements in order to reflect any event or circumstance occurring after the date of this annual report or currently unknown facts or conditions or the occurrence of unanticipated events.

 

 

We provide services and equipment to oil and natural gas exploration and production companies throughout the U.S. including Texas, Louisiana, Arkansas, Pennsylvania, Oklahoma, New Mexico, offshore in the Gulf of Mexico, and internationally primarily in Argentina, Brazil, Bolivia and Mexico. Our central operating strategy is to provide high-quality, technologically advanced services and equipment. As a result of our commitment to customer service, we have developed strong relationships with many of the leading oil and natural gas companies, including both independents and majors.

Our growth strategy is focused on identifying and pursuing opportunities in markets, products and services we believe will grow faster than the overall oilfield services industry and opportunities which we believe help us to mitigate cyclical risk by diversifying our cash flow, both domestically and internationally. Over the past several years, we have significantly expanded the geographic scope of our operations and the range of services we provide through strategic acquisitions and organic growth. Our organic growth has primarily been achieved by expanding our geographic scope, acquiring complementary property and equipment, hiring personnel to service new regions and cross-selling our products and services. Currently, as part of our strategic plan, we are focusing on international growth opportunities. We also continually assess the strategic fit of our existing businesses and may divest businesses that are deemed not to fit with our strategic plan or are not achieving the desired return on investment.

 

Our History

 

We were incorporated in 1913 under Delaware law. We reorganized in bankruptcy in 1988 and sold all of our major businesses. From 1988 to May 2001 we had only one operating company in the equipment repair business, which was sold in December 2001.

 

In May 2001, under new management, we embarked on a new course of direction into the oilfield service industry. Since 2001, we have completed 24 acquisitions, including six in 2005, six in 2006, four in 2007 and one in 2008. Our first series of acquisitions became the backbone of our Oilfield Services segment. In May 2001 we entered the underbalanced drilling market and then in February of 2002 we entered the directional drilling business and the tubular services business. In December 2004, we entered the production services business. We have improved our product line offerings by completing additional acquisitions for all product lines. We also disposed of some nonstrategic assets in our production services business in June 2007 and in our tubular services business in August 2008.

 

In September 2004, we entered the Rental Services market which we subsequently expanded with acquisitions in April 2005 and January and December 2006. As a result of these acquisitions, we are now a major provider of oilfield rental tools primarily in the Gulf Coast region of the U.S.

 

In August 2006, we entered the Drilling and Completion business with the acquisition of DLS Drilling, Logistics & Services Corporation, or DLS, in Argentina. Subsequently, in December 2008 we increased our business in this segment with the acquisition of BCH Ltd, or BCH, in Brazil. In addition, we are building a drilling presence in the U.S. by building new drilling rigs.

 

As a result of these transactions, our prior results may not be indicative of current or future operations. Segment and geographic financial information appears in “Item 8. Financial Information — Notes to Consolidated Financial Statements — Note 15.”

 

Our Industry

 

The oilfield industry is highly cyclical. The most critical factor in assessing the outlook for the industry is the worldwide supply and demand for oil and the domestic supply and demand for natural gas. The industry is driven by commodity demand and corresponding price increases. As demand increases, producers raise their prices. The price escalation enables producers to increase their capital expenditures. The increased capital expenditures ultimately result in greater revenues and profits for services and equipment companies. The increased capital expenditures also ultimately result in greater production which historically has resulted in increased supplies and reduced prices.

 

Demand for our services generally increased from 2004 through 2007. Activity in the U.S. Gulf of Mexico, however decreased in the second half of 2007 due to the hurricane season and relocation of offshore rigs to more attractive international markets. Demand for our services for most of 2008 was generally stable due to high oil and natural gas prices and the capital expenditures of the exploration and production companies. As a result, the number of active rigs drilling, or rig count, in the U.S., according to Baker Hughes, peaked at 2,031 in August of 2008 compared to 1,782 at the end of 2007. In the last quarter of 2008, the rig count in the U.S. began to drop due to the weakening U.S. economy, the decrease in oil and natural gas

prices and the turmoil in the financial markets which affected the availability of capital for our customers. The Baker Hughes U.S. rig count decreased to 876 in June 2009 and then gradually began to improve in response to increased prices and more stable natural gas prices. As of February 26, 2010, the Baker Hughes U.S. rig count stood at 1,373.

 

Business Segments

 

We conduct our operations through three principal segments:

 

 

Oilfield Services.  We utilize state-of-the-art equipment to provide well planning and engineering services, directional drilling packages, downhole motor technology, well site directional supervision, exploratory and development re-entry drilling, downhole guidance services and other drilling services to our customers, including measurement-while-drilling (MWD) services. We provide compressed air equipment, chemicals and other specialized products for underbalanced drilling and production applications. We also provide specialized equipment and trained operators to perform a variety of pipe handling services, including installing casing and tubing, changing out drill pipe and retrieving production tubing for both onshore and offshore drilling and workover operations, which we refer to as tubular services. In addition, we provide a variety of quality production-related rental tools and equipment and services, including wire line support services and coiled tubing.

 

According to Baker Hughes, as of February 26, 2010, 67% of the active drilling rigs in the U.S. were drilling directionally and/or horizontally. We believe directional drilling offers several advantages over conventional drilling including: 1) improvement of total cumulative recoverable reserves; 2) improved reservoir production performance beyond conventional vertical wells; and 3) reduction of the number of field development wells.

 

In 2007, we expanded our directional drilling capability by completing three acquisitions for a total of approximately $37.3 million. These were Coker Directional, Inc. (June 2007), Diggar Tools, LLC (July 2007) and substantially all of the assets of Diamondback Oilfield Services, Inc. (November 2007). These acquisitions provided additional directional drillers, downhole motors, and MWD tools and enabled us to expand our presence in the Northern Rockies and the Mid-Continent areas. We currently maintain an inventory of approximately 315 drilling motors. Our straight-hole motors offer an opportunity to capture additional market share. We currently provide directional drilling services primarily in Texas, Pennsylvania, Louisiana, Oklahoma and offshore in the Gulf of Mexico.

 

All wells drilled for oil and natural gas require casing to be installed for drilling, and if the well is producing, tubing will be required in the completion phase. We currently provide tubular services primarily in Texas, Louisiana and both onshore and offshore in the Gulf of Mexico and Mexico.

 

We expanded our tubular services in October 2007 by acquiring Rebel Rentals, Inc., or Rebel, for a purchase price of approximately $7.3 million. Rebel owns an inventory of equipment used primarily for tubing installation services in the South Louisiana and Gulf Coast regions. In August 2008, we sold our drill pipe tong manufacturing assets for approximately $7.5 million.

 

Underbalanced drilling shortens the time required to drill a well and enhances production by minimizing formation damage. There is a trend in the industry to drill, complete and workover wells with underbalanced operations. We currently have a combined fleet of approximately 185 compressors, boosters and foam units and we believe we are one of the largest providers of underbalanced drilling services in the United States. We also provide premium air hammers and bits to oil and natural gas companies for use in underbalanced drilling. Our broad and diversified product line enables us to compete in the underbalanced market with equipment and services packages engineered and customized to specifically meet customer requirements. We currently

provide underbalanced drilling services primarily in Arkansas, Pennsylvania, New Mexico, Texas, Oklahoma and California.

 

Our production services product line is focused on coiled tubing services and rental of various tools used in the production process. We sold our capillary tubing units and related equipment for approximately $16.3 million and reported a gain of approximately $8.9 million in June 2007. The assets sold represented a small portion of our Oilfield Services segment. We currently provide production services primarily in Texas, Arkansas, Louisiana and West Virginia.

 

Drilling and Completion.  We provide drilling, completion, workover and related services for oil and natural gas wells. We operate out of the San Jorge, Cuyan, Neuquen, Austral and Noroeste basins of Argentina and the Espirito Santo, Potiguar, Reconcavo and Sergipe basins of Brazil and in Bolivia. We also offer a wide variety of other oilfield services such as drilling fluids and completion fluids and engineering and logistics to complement our customers’ field organization. We provide the rigs and drilling crews and we also provide rig management services on a variety of rigs, consisting of technical drilling assistance, personnel, repair and maintenance services and drilling operation management services.

 

Our Drilling and Completion segment was established with the acquisition of DLS in August 2006 for a purchase price of approximately $114.5 million. We expanded our Drilling and Completion segment with the acquisition of BCH, which operates in Brazil. In 2008, we invested $40.0 million into BCH via a 15% convertible subordinated secured debenture and we acquired the common stock of BCH for a total purchase price of $56.1 million. We currently operate a fleet of 76 land rigs, including 17 drilling rigs and 47 service rigs (workover and pulling units) in Argentina, eight drilling rigs and one service rig in Brazil and three drilling rigs in Bolivia. In 2007, we placed orders for four drilling rigs and 16 service rigs. All of the service rigs and one of the drilling rigs were placed into service in Argentina at various dates in 2008. A second drilling rig was activated in Argentina in March 2009. The remaining two drilling rigs were substantially completed during 2009. However, currently both of the drilling rigs are at the original manufacturer’s facility for modification or improvements and we are uncertain as to when these rigs will be available for service. Additionally in 2008 we placed orders for two 1600 horsepower drilling rigs for the U.S. market from a different manufacturer. As a result of industry market conditions in late 2008 and 2009, completion and delivery of these rigs was suspended. It is currently expected that these rigs will be delivered in the second and fourth quarters of 2010.

 

Rental Services.  We provide specialized oilfield rental equipment, including premium drill pipe, spiral heavy weight drill pipe, tubing work strings, blow out preventors, choke manifolds and various valves and handling tools, for both onshore and offshore well drilling, completion and workover operations. Most wells drilled for oil and natural gas require some form of rental equipment in both the drilling and completion of a well. We have an inventory of specialized equipment, which includes double studded adapters, test plugs, wear bushings, adaptor spools, baskets, spacer spools and other assorted handling tools in various sizes to meet our customers’ demands. We charge customers for rental equipment on a daily basis. Our customers are liable for the cost of inspection, repairs and lost or damaged equipment. We currently provide rental equipment primarily in Texas, Louisiana, Oklahoma, offshore in the Gulf of Mexico and internationally in Mexico, Columbia and Egypt.

 

Competitive Strengths

 

We believe the following competitive strengths will enable us to capitalize on future opportunities:

 

Strategic position in high growth markets.  We focus on markets, products and services we believe are growing faster than the overall oilfield services industry and in which we can capitalize on our competitive strengths. Pursuant to this strategy, we have become a significant provider of products and services in directional drilling, casing and tubing, underbalanced drilling, drilling and completion and rental services. We also have an established presence in certain international markets which provide additional opportunities for growth and diversification of cash flow.

Strong relationships with diversified customer base.  We have strong relationships with many of the major and independent oil and natural gas producers and service companies in Texas, Louisiana, Arkansas, Pennsylvania, Oklahoma, New Mexico, offshore in the Gulf of Mexico, Argentina, Brazil, Bolivia and Mexico. Our largest customers include Pan American Energy LLC Sucursal Argentina, or Pan American Energy, Petroleo Brasileiro S.A, or Petrobras, Repsol-YPF, Chesapeake Energy, Apache Corporation, Anadarko Petroleum, Occidental Petroleum, BP, Devon Energy, and Materiales y Equipo Petroleo. Since 2002, we have broadened our customer base as a result of our acquisitions, technical expertise and reputation for quality customer service and by providing customers with technologically advanced equipment and highly skilled operating personnel.

 

Successful execution of growth strategy.  Over the past seven years, we have grown both organically and through successful acquisitions of competing businesses. Since 2001, we have completed 24 acquisitions. We strive to improve the operating performance of our acquired businesses by increasing their asset utilization and operating efficiency. These acquisitions and organic growth, through our capital expenditures program, have expanded our geographic presence and customer base and, in turn, have enabled us to cross-sell various products and services.

 

Diversified and increased cash flow sources.  We operate as a diversified oilfield service company through our three business segments. We believe that our product and service offerings and geographical presence through our three business segments provide us with diverse sources of cash flow. Our acquisition of DLS in Argentina in August 2006 and our acquisition of BCH in Brazil at the end of 2008, increased our international presence and we believe, provides more stable long-term contracts and revenue streams when compared to the volatility in the U.S. domestic market. Additionally, the international markets are primarily driven by oil prices compared to the natural gas focus of the U.S. domestic market.

 

Experienced management team.  Our executive management team has extensive experience in the energy sector, and consequently has developed strong and longstanding relationships with many of the major and independent exploration and production companies.

 

Business Strategy

 

The key elements of our long-term strategy include:

 

Mitigate cyclical risk through balanced operations.  We strive to mitigate cyclical risk across our lines of business by balancing our operations between onshore versus offshore; drilling versus production; rental tools versus service; domestic versus international; and natural gas versus crude oil. We will continue to shape our organic and acquisition growth efforts to provide further balance across these five categories. A key part of our strategy has been to increase our international operations because they increase our exposure to crude oil and provide opportunities for long-term contracts.

 

Expand geographically to provide greater access and service to key customer segments.  We have locations in Texas, New Mexico, Arkansas, Louisiana and Pennsylvania in order to enhance our proximity to customers and more efficiently serve their needs. We have redeployed our assets to the growing land shale plays such as the Marcellus (principally in Pennsylvania), the Haynesville (Louisiana), the Bakken (North Dakota) and the Eagleford in South Texas. Internationally, our acquisition of DLS expanded our geographic footprint into Argentina and Bolivia and our acquisition of BCH expanded our geographic footprint into Brazil. We expect to increase our international presence principally in South America, Mexico, the Middle East and North Africa. We will continue to evaluate locations to conveniently serve our customers and exploit emerging markets.

 

Prudently pursue strategic acquisitions.  To complement our organic growth, we have historically pursued strategic acquisitions which we believe are accretive to earnings, complement our products and services, provide new equipment and technology, expand our geographic footprint and market presence, and further diversify our customer base. As part of our long-term growth strategy, we continue to review complementary acquisitions, as well as capital expenditures to enhance our ability to increase cash flows

from our existing assets. Future acquisitions will be subject to an improved outlook for our products and services and improved availability of capital on reasonable terms.

 

Expand products and services provided in existing operating locations.  Since the beginning of 2005, we have invested approximately $403.2 million in capital expenditures to grow our business organically by investing in new, technologically advanced equipment and by expanding our product and service offerings. This strategy is consistent with our belief that our customers favor modern equipment emphasizing efficiency and safety and integrated suppliers that can provide a broad range of products and services in many geographic locations. Recent economic conditions have led us to reduce our capital spending and operating expenses consistent with the decline in demand for our services as producers curtailed their drilling activity in 2009.

 

Increase utilization of assets.  We seek to increase revenues and enhance margins by increasing the utilization of our assets with new and existing customers. We expect to accomplish this through leveraging longstanding relationships with our customers and cross-selling our suite of services and equipment.

 

Customers

 

In 2009, 2008 and 2007, one of our customers, Pan American Energy, represented approximately 35.5%, 28.5% and 20.7% of our consolidated revenues, respectively. Pan America Energy is a joint venture that is owned 60% by British Petroleum and 40% by Bridas Corporation. Alejandro P. Bulgheroni, one of our directors, may be deemed to indirectly beneficially own 50% of the outstanding capital stock of Bridas Corporation and is a member of the Management Committee of Pan American Energy. The loss without replacement of our larger existing customers could have a material adverse effect on our results of operations.

 

Suppliers

 

The equipment utilized in our business is generally available new from manufacturers or at auction. However, the cost of acquiring new equipment to expand our business could increase as demand for equipment in the industry increases.

 

Competition

 

We experience significant competition in all areas of our business. In general, the markets in which we compete are highly fragmented, and a large number of companies offer services that overlap and are competitive with our services and products. We believe that the principal competitive factors are technical and mechanical capabilities, management experience, past performance and price. While we have considerable experience, there are many other companies that have comparable skills. Many of our competitors are larger and have greater financial resources than we do.

 

We believe that there are five major directional drilling companies, Schlumberger, Halliburton, Baker Hughes, Smith International (Pathfinder) and Weatherford, that market both worldwide and in the U.S. as well as numerous small regional players. Significant competitors in the tubular markets we serve include 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 Servicios WellTech, Ensign Energy Services, Nabors and Helmerich & Payne, and San Antonia Global Ltd in Brazil.

The Rental Services business is highly fragmented with hundreds of companies offering various rental tool services. Our largest competitors include Weatherford, Quail Rental Tools, Knight Rental Tools, Superior Energy Services (Workstrings) and Smith International (Thomas Tools).

 

Backlog

 

We do not view backlog of orders as a significant measure for our business because our jobs are short-term in nature, typically one to 30 days, without significant on-going commitments.

 

Employees

 

Our strategy includes acquiring companies with strong management and entering into long-term employment contracts with key employees in order to preserve customer relationships and assure continuity following acquisition. In general, we believe we have good relations with our employees. None of our employees, other than our Drilling and Completion employees, are represented by a union. We actively train employees across various functions, which we believe is crucial to motivate our workforce and maximize efficiency. Employees showing a higher level of skill are trained on more technologically complex equipment and given greater responsibility. All employees are responsible for on-going quality assurance. At February 26, 2010, we had approximately 3,174 employees. Almost all of our Drilling and Completion operations located in Argentina and Brazil are subject to collective bargaining agreements. We believe that we maintain a satisfactory relationship with the unions to which our Drilling and Completion employees belong.

 

Insurance

 

We carry a variety of insurance coverages for our operations, and we are partially self-insured for certain claims in amounts that we believe to be customary and reasonable. However, there is a risk that our insurance may not be sufficient to cover any particular loss or that insurance may not cover all losses. We are responsible for the first $250,000 of claims under our workers compensation policy and the first $100,000 of claims under our general liability and medical insurance policies. Insurance rates have in the past been subject to wide fluctuation and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions.

 

Seasonality

 

Oil and natural gas operations of our customers located offshore and onshore in the U.S. Gulf of Mexico and in Mexico may be adversely affected by hurricanes and tropical storms, resulting in reduced demand for our services. For example, from August to October of 2007 we witnessed a decline in offshore drilling rig operations in the Gulf of Mexico in anticipation of the hurricane season. Many of those rigs have not returned to the U.S. Gulf and have been relocated to the international markets. In 2008, Hurricanes Gustav and Ike disrupted our operations along the Texas and Louisiana Gulf Coast and the East Texas/West Louisiana corridor. In addition, our customers’ operations in the Mid-Continent and Rocky Mountain regions of the U.S. are also adversely affected by seasonal weather conditions. These weather conditions limit our access to these job sites and our ability to service wells in these areas. These constraints decrease drilling activity and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

 

Federal Regulations and Environmental Matters

 

Our operations are subject to federal, state and local laws and regulations relating to the energy industry in general and the environment in particular. Environmental laws have in recent years become more stringent and have generally sought to impose greater liability on a larger number of potentially responsible parties. Because we provide services to companies producing oil and natural gas, which are toxic substances, we may become subject to claims relating to the release of such substances into the environment. While we are not currently aware of any situation involving an environmental claim that would likely have a material adverse

effect on us, it is possible that an environmental claim could arise that could cause our business to suffer. We do not anticipate any material expenditures to comply with environmental regulations affecting our operations.

 

In addition to claims based on our current operations, we are from time to time named in environmental claims relating to our activities prior to our reorganization in 1988 (See “Item 3. Legal Proceedings”).

 

Intellectual Property Rights

 

Except for our relationships with our customers and suppliers described above, we do not own any patents, trademarks, licenses, franchises or concessions which we believe are material to the success of our business.

 

Available Information

 

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, or the Exchange Act, are made available free of charge on our web site at www.alchenergy.com as soon as reasonably practicable after we electronically file or furnish them to the Securities and Exchange Commission, or SEC.

 

Our Board of Directors has documented its governance practices by adopting several corporate governance policies. These governance policies, including our corporate governance principles and our code of business ethics and conduct, as well as the charters for the committees of our Board (Audit Committee, Compensation Committee, Corporate Governance and Nominating and Finance Committee) may be viewed on the investor relations section of our website. Copies of such documents will be sent to stockholders free of charge upon written request of the corporate secretary at the address shown on the cover page of this Form 10-K.

 

Information contained on or connected to our website is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing we make with the SEC.

 

 

Our business, financial condition, results of operations and the trading price of our securities can be materially and adversely affected by many events and conditions, including the following:

 

Risks Associated With Our Industry

 

Global political, economic and market conditions could negatively impact our business.

 

Our operations are affected by global political, economic and market conditions and the condition of the oil and natural gas industry. Our operating results and the forward-looking information we provide are based on our current assumptions about oil and natural gas supply and demand, oil and natural gas prices, rig count and other market trends. Our assumptions on these matters are in turn based on currently available information, which is subject to change. The oil and natural gas industry is extremely volatile and subject to change based on political and economic factors outside our control. This volatility caused oil and natural gas companies and drilling contractors to change their strategies and expenditure levels late in 2008 and in 2009. We have experienced in the past, and expect to experience in 2010, significant fluctuations in operating results based on these changes.

 

Our industry is highly competitive, with intense price competition.

 

The markets in which we operate are highly competitive. Contracts are traditionally awarded on a competitive bid basis. Pricing is often the primary factor in determining which qualified contractor is awarded a job. The competitive environment has intensified as mergers among oil and natural gas companies have reduced the number of available customers. The competitive environment has also intensified, late in 2008 and

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 and have declined significantly from their historic highs in mid-2008. Any prolonged reduction in oil and natural gas prices will depress levels of exploration, development, and production activity. Such price declines reduce drilling activity and demand for our services, which could lead to lower pricing for our products and services. Accordingly, prolonged periods of lower drilling activity and the reduction in our customers’ expenditures could have a materially adverse effect on our financial condition, results of operations and cash flows.

 

Oil and natural gas prices depend on many factors beyond our control, including the following:

 

 

Limitations on the availability of capital, or higher costs of capital, for financing expenditures may cause these and other oil and natural gas producers to make additional reductions to capital budgets in the future even if commodity prices remain at historically high levels.

 

Historically, we have been dependent on a few customers operating in a single industry; the loss of one or more customers could adversely affect our financial condition and results of operations.

 

Our customers are engaged in the oil and natural gas exploration business in the U.S., Argentina, Brazil, Mexico and elsewhere. Historically, we have been dependent upon a few customers for a significant portion of our revenues. In 2009, 2008 and 2007, one of our customers, Pan American Energy represented 35.5%, 28.5% and 20.7% of our consolidated revenues, respectively. Pan American Energy also contributes a majority of the revenue derived from our Drilling and Completion operations. In 2009, 2008 and 2007, Pan American Energy represented 59.2%, 66.0% and 51.0% of our Drilling and Completion revenues, respectively.

The strategic agreement with Pan American Energy currently has an expiration date of June 30, 2011. However, Pan American Energy may terminate the agreement (i) without cause at any time with 60 days’ notice, or (ii) in the event of a breach of the agreement by us if such breach is not cured within 20 days of notice of the breach. Because a majority of the revenues of our Drilling and Completion operations are currently generated under this agreement, the revenues and earnings of our Drilling and Completion operations will be materially adversely affected if this agreement is terminated unless we are able to enter into a satisfactory substitute arrangement. We cannot assure you that in the event of such a termination we would be able to enter into a substitute arrangement on terms similar to those contained in the current agreement with Pan American Energy. In addition, our results of operations could be materially adversely affected if any of our major customers terminates its contracts with us, fails to renew its existing contracts or refuses to award new contracts to us and we are unable to enter into contracts with new customers at comparable rates.

 

This concentration of customers may increase our overall exposure to credit risk. Our customers will likely be similarly affected by changes in economic and industry conditions. Our financial condition and results of operations will be materially adversely affected if one or more of our significant customers fails to pay us or ceases to contract with us for our services on terms that are favorable to us or at all.

 

Our customers may seek to cancel or renegotiate some of our Drilling and Completion contracts during periods of depressed market conditions or if we experience operational difficulties.

 

Substantially all of our Drilling and Completion business’ contracts with major customers are dayrate contracts, where we charge a fixed charge per day regardless of the number of days needed to drill the well. During depressed market conditions, a customer may no longer need a rig that is currently under contract or may be able to obtain a comparable rig at a lower daily rate. As a result, customers may seek to renegotiate the terms of their existing drilling contracts or avoid their obligations under those contracts. In addition, our customers may have the right to terminate existing contracts if we experience operational problems. The likelihood that a customer may seek to terminate a contract for operational difficulties is increased during periods of market weakness. The cancellation of a number of our drilling contracts could materially reduce our revenues and profitability.

 

If we are unable to renew or obtain new and favorable contracts for rigs whose contracts are expiring or are terminated, our revenues and profitability could be materially reduced.

 

We have a number of contracts that will expire in 2010 and 2011. Our ability to renew these contracts or obtain new contracts and the terms of any such contracts will depend on market conditions. We may be unable to renew our expiring contracts or obtain new contracts for the rigs under contracts that have expired or been terminated, and the dayrates under any new contracts may be substantially below the existing dayrates, which could materially reduce our revenues and profitability.

 

Failure to secure a drilling contract prior to deployment of a rig under construction or any other rigs we may construct in the future prior to their deployment could adversely affect our future results of operations.

 

We have two rigs being constructed that are scheduled for delivery in second and fourth quarters of 2010. We have not yet obtained a drilling contract for these rigs. Our failure to secure a drilling contract for any rig under construction prior to its deployment could adversely affect our results of operations and financial condition.

 

An oversupply of comparable rigs in the geographic markets in which we compete could depress the utilization rates and dayrates for our rigs and materially reduce our revenues and profitability.

 

Utilization rates, which are the number of days a rig actually works divided by the number of days the rig is available for work, and dayrates, which are the contract prices customers pay for rigs per day, are also affected by the total supply of comparable rigs available for service in the geographic markets in which we compete. Improvements in demand in a geographic market may cause our competitors to respond by moving

competing rigs into the market, thus intensifying price competition. Significant new rig construction could also intensify price competition. In the past, there have been prolonged periods of rig oversupply with correspondingly depressed utilization rates and dayrates largely due to earlier, speculative construction of new rigs. Improvements in dayrates and expectations of longer-term, sustained improvements in utilization rates and dayrates for drilling rigs may lead to construction of new rigs. These increases in the supply of rigs could depress the utilization rates and dayrates for our rigs and materially reduce our revenues and profitability.

 

The loss of the services of key executives or our failure to attract and retain skilled workers and key personnel could hurt our operations.

 

We are dependent upon the efforts and skills of our executives to finance and manage our business, identify and consummate additional acquisitions and obtain and retain customers. These executives include our Chief Executive Officer and Chairman of the Board, Munawar H. Hidayatallah. We do not maintain key man insurance on any of our personnel.

 

In addition, companies in our industry, including us, are dependent upon the available labor pool of skilled employees. Our development and expansion will require additional experienced management and operations personnel. No assurance can be given that we will be able to identify and retain these employees. We compete with other oilfield services businesses and other employers to attract and retain qualified personnel with the technical skills and experience required to provide our customers with the highest quality service. We are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. A shortage in the labor pool of skilled workers, increases in wage rates or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require us to enhance our wage and benefits packages. There can be no assurance that labor costs will not increase. Any increase in our operating costs could cause our business to suffer.

 

The operations and financial condition of our Drilling and Completion business could be affected by union activity and general labor unrest. Additionally, the labor expenses of our Drilling and Completion business could increase as a result of governmental regulation of payments to employees.

 

In Argentina and Brazil, labor organizations have substantial support and have considerable political influence. The demands of labor organizations in Argentina have increased in recent years as a result of the general labor unrest and dissatisfaction resulting from the disparity between the cost of living and salaries in Argentina as a result of the devaluation of the Argentine Peso. There can be no assurance that our Drilling and Completion business will not face labor disruptions in the future or that any such disruptions will not have a material adverse effect on our financial condition or results of operations.

 

The Argentine government has in the past and may in the future promulgate laws, regulations and decrees requiring companies in the private sector to maintain minimum wage levels and provide specified benefits to employees, including significant mandatory severance payments. It is possible the government will adopt measures that will increase salaries or require our Drilling and Completion business to provide additional benefits, which would increase our costs and potentially reduce our profitability, cash flow and/or liquidity. In addition, in many of the countries in which we operate, our workforce has certain compensation and other rights arising from our various collective bargaining agreements and from statutory requirements of those countries relating to involuntary terminations. If we choose to cease operations in one of those countries or if market conditions reduce the demand for our drilling services in such a country, we could incur costs, which may be material, associated with workforce reductions.

 

Rig upgrade, refurbishment and construction projects are subject to risks, including delays and cost overruns, which could have an adverse effect on our results of operations and cash flows.

 

Our Drilling and Completion business often has to make upgrade and refurbishment expenditures for its rig fleet to comply with our quality management and preventive maintenance system or contractual requirements or when repairs are required in response to an inspection by a governmental authority. We may also make significant expenditures when rigs are moved from one location to another. Additionally, we may

make substantial expenditures for the construction of new rigs. Rig upgrade, refurbishment and construction projects are subject to the risks of delay or cost overruns inherent in any large construction project.

 

We have two land drilling rigs that were substantially completed in 2009. One of these rigs worked for a limited period before encountering certain operational malfunctions. Currently both rigs are at the original manufacturer’s facility undergoing modifications or improvements. At this time we cannot be assured that these rigs will not require significant expenditures to bring them to satisfactory operational standards and we are uncertain as to when these rigs will be available for service. We have two additional drilling rigs scheduled to be delivered in 2010 by a different manufacturer.

 

Significant cost overruns or delays could adversely affect our financial condition and results of operations. Additionally, capital expenditures for rig upgrade, refurbishment or construction projects could exceed our planned capital expenditures, impairing our ability to service our debt obligations.

 

Severe weather could have a material adverse impact on our business.

 

Our business could be materially and adversely affected by severe weather. Repercussions of severe weather conditions may include:

 

 

For example, oil and natural gas operations of our customers located offshore and onshore in the Gulf of Mexico and in Mexico have from time to time been adversely affected by floods, hurricanes and tropical storms, resulting in reduced demand for our services. In 2008, Hurricanes Gustav and Ike disrupted our operations along the Texas and Louisiana Gulf Coast and the East Texas/West Louisiana corridor. Further, our customers’ operations in the Mid-Continent and Rocky Mountain regions of the U.S. are also adversely affected by seasonal weather conditions. This limits our access to these job sites and our ability to service wells in these areas. These constraints decrease drilling activity and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

 

We have recorded substantial goodwill as the result of our acquisitive nature and as such goodwill is subject to periodic reviews of impairment.

 

We perform purchase price allocations to intangible assets when we make a business combination. Business combinations and purchase price allocations have been consummated for acquisitions in all of our reportable segments. The excess of the purchase price after allocation of fair values to tangible assets is allocated to identifiable intangibles and thereafter to goodwill. We conduct periodic reviews of goodwill for impairment in value. Any impairments would result in a non-cash charge against earnings in the period reviewed, which may or may not create a tax benefit, and would have a corresponding decrease in stockholders’ equity.

 

We reviewed goodwill at December 31, 2009 and recorded no impairment but based on our review of goodwill at December 31, 2008 we recorded an impairment of $115.8 million, which was all of our goodwill for the Rental Services segment as well as the impairment of goodwill associated with our Tubular Services and Production Services businesses within our Oilfield Services segment. In the event that market conditions deteriorate or we have a prolonged downturn, we may be required to record an additional impairment of goodwill and such impairment could be material.

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. This could result in significant delays and costs to us and could require us to divert substantial resources, including management time, from other activities.

 

If it is determined that our disclosure controls and procedures and/or our internal controls over financial reporting are not effective and/or we fail to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act on a timely basis, we may not be able to provide reliable financial and other reports or prevent fraud, which, in turn:

 

 

Any failure to timely file our periodic reports with the SEC may give rise to a default under the indentures governing our outstanding 9.0% senior notes due 2014, which we refer to as our 9.0% senior notes, our outstanding 8.5% senior notes due 2017, which we refer to as our 8.5% senior notes and any other debt securities we may offer and, ultimately, an acceleration of amounts due thereunder. In addition, a default under the indentures generally will also give rise to a default under our credit agreement and could cause the acceleration of amounts due under the credit agreement. If an acceleration of our 9.0% senior notes, our 8.5% senior notes or our other debt were to occur, we cannot assure you that we would have sufficient funds to repay such obligations.

 

Our strategic plan may not achieve the intended results.

 

In 2009, we filed a five-year plan outlining our strategic decision to focus our geographical expansion in the international markets, particularly Columbia, Mexico, Saudi Arabia, Libya, Egypt and the MENA region. As part of this plan, we have begun to transfer idle assets overseas. We may not be successful in executing our strategy. We may not be able to find suitable international acquisitions. In addition, engaging in any international acquisition will incur a variety of costs, and we may never realize the anticipated benefits of any such acquisition. We may need additional financing in order to fund additional acquisitions. Acquisition efforts can consume significant management attention and require substantial expenditures, which could detract from our other businesses. In addition, we may devote resources to potential acquisitions that are never completed. If not successful in achieving our strategic plan may have a material adverse effect on our financial condition, liquidity and results of operations.

 

We do business in international jurisdictions whose political and regulatory environments and compliance regimes differ from those in the U.S:

 

A significant amount of our revenue is attributable to operations in foreign countries. These activities accounted for approximately 62.8% of our consolidated revenue in the year ended December 31, 2009. Risks associated with our operations in foreign areas include, but are not limited to:

 

 

 

Part of our strategy is to prudently and opportunistically acquire businesses and assets that complement our existing products and services, and to expand our geographic footprint. If we make acquisitions in other countries, we may increase our exposure to the risks discussed above.

 

We attempt to limit the risks of currency fluctuation and restrictions on currency repatriation where possible by obtaining contracts providing for payment of a percentage of the contract indexed to the U.S. dollar exchange rate. To the extent possible, we seek to limit our exposure to local currencies by matching the acceptance of local currencies to our local expense requirements in those currencies. Although we have done this in the past, we may not be able to take these actions in the future, thereby exposing us to foreign currency fluctuations that could cause our results of operations, financial condition and cash flows to deteriorate materially.

 

Additionally, in some jurisdictions we are subject to foreign governmental regulations favoring or requiring the awarding of contracts to local contractors or requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These regulations may adversely affect our ability to compete.

 

Our international business operations also include projects in countries where governmental corruption has been known to exist. We are subject to the anti-bribery restrictions of the Foreign Corrupt Practices Act, which make it illegal to give anything of value to foreign officials or employees or agents of nationally owned oil companies in order to obtain or retain any business or other advantage.

 

Violations of these laws could result in monetary and criminal penalties against us or our subsidiaries and could damage our reputation and, therefore, our ability to do business.

 

Devaluation of the Argentine Peso, the Mexican Peso or the Brazilian Real could adversely affect our results of operations.

 

These currencies have been subject to significant devaluation in the past and may be subject to significant fluctuations in the future. Given the economic and political uncertainties which have historically existed in Argentina, it is impossible to predict whether, and to what extent, the value of the Argentine Peso may depreciate or appreciate against the U.S. dollar. We cannot predict how these uncertainties will affect our financial results, but there is a risk that our financial performance could be adversely affected. Moreover, we cannot predict whether the Argentine government will further modify its monetary policy and, if so, what effect any of these changes could have on the value of the Argentine Peso. Such changes could have an adverse effect on our financial condition and results of operations. Similar economic and political turmoil in Mexico and Brazil could also expose us to unpredictable currency exchange rates in these countries that may result in an adverse effect on our financial condition and results of operations.

 

Argentina continues to face considerable political and economic uncertainty.

 

Although general economic conditions have shown improvement and political protests and social disturbances have diminished considerably since the economic crisis of 2001 and 2002, the rapid and radical nature of the changes in the Argentine social, political, economic and legal environment over the past several years and the absence of a clear political consensus in favor of any particular set of economic policies have given rise to significant uncertainties about the 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.

 

An increase in inflation in Argentina could have a material adverse effect on our results of operations.

 

Historically, the devaluation of the Argentine Peso has created pressures on the domestic price system that generated high rates of inflation. We cannot assure you that inflation rates will remain stable in the future. Significant inflation in Argentina could have a material adverse effect on our results of operations and financial condition.

 

We are subject to numerous governmental laws and regulations, including those that may impose significant liability on us for environmental and natural resource damages.

 

We are subject to various federal, state, local and foreign laws and regulations relating to the energy industry in general and the environment in particular. For example, many aspects of our Drilling and Completion operations are subject to laws and regulations that may relate directly or indirectly to the contract drilling and well servicing industries, including those requiring us to control the discharge of oil and other contaminants into the environment or otherwise relating to environmental protection. The countries where our Drilling and Completion business operates have environmental laws and regulations covering the discharge of oil and other contaminants and protection of the environment in connection with operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and even criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that may limit or prohibit our operations. Laws and regulations protecting the environment have become more stringent in recent years and may in certain circumstances impose strict liability, rendering us liable for environmental and natural resource damages without regard to negligence or fault on our part. These laws and regulations may expose us to liability for the conduct of, or conditions caused by, others or for acts that were in compliance with all applicable laws at the time the acts were performed. The application of these requirements, the modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or development drilling for oil and gas could materially limit future contract drilling opportunities or materially increase our costs or both.

 

Environmental liabilities relating to discontinued operations could result in substantial losses.

 

Since our reorganization under the U.S. federal bankruptcy laws in 1988, a number of parties, including the Environmental Protection Agency, or EPA, have asserted that we are responsible for the cleanup of hazardous waste sites with respect to our pre-bankruptcy activities. We believe that such claims are barred by applicable bankruptcy law, and we have not experienced any material expense in relation to any such claims. However, if we do not prevail with respect to these claims in the future, or if additional environmental claims are asserted against us relating to our current or future activities in the oil and natural gas industry, we could become subject to material environmental liabilities that could have a material adverse effect on our financial condition and results of operations.

 

Products liability claims relating to discontinued operations could result in substantial losses.

 

Since our reorganization under the U.S. federal bankruptcy laws in 1988, we have been regularly named in products liability lawsuits primarily resulting from the manufacture of products containing asbestos. In connection with our bankruptcy, a special products liability trust was established and funded to address products liability claims. This product liability trust is in the process of being dissolved. We believe that product liability claims relating to our business prior to bankruptcy are barred by applicable bankruptcy law. Since 1988, no court has ruled that we are responsible for products liability claims. However, if we are held responsible for product liability claims, we could suffer substantial losses that could have a material adverse

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 trading price of our common stock has historically fluctuated significantly. For example, during the twelve months ended December 31, 2009, the high sales price per share of our common stock as reported on the New York Stock Exchange was $6.07 and the low sales price per share was $0.71. The volatility of our stock price depends upon many factors including:

 

 

A reduced stock price will result in a loss to investors and will adversely affect our ability to issue stock to fund our activities.

 

Substantial sales of our common stock could adversely affect our stock price.

 

Sales of a substantial number of shares of our common stock, or the perception that such sales could occur, could adversely affect the market price of our common stock.

 

We had 71,459,876 shares of common stock outstanding as of February 26, 2010 and 14,202,146 shares reserved for issuance upon conversion of our convertible preferred stock. At February 26, 2010, we had reserved an additional 8,552,387 shares of common stock for issuance under our equity compensation plans, of which 701,732 shares were issuable upon the exercise of outstanding options with a weighted average exercise price of $6.31 per share. As of the same date, there were a total of 433,960 shares of non-performance-based restricted stock and 481,666 shares of performance-based restricted stock outstanding under our equity compensation plans.

 

In connection with our acquisition of DLS we entered into an investors rights agreement with the seller parties to the DLS stock purchase agreement, who collectively hold over 15% of our common stock as of February 26, 2010 In addition, in connection with our backstopped rights offering, we entered into a registration rights agreement with Lime Rock who hold 19,889,044 shares of our common stock and 36,393 shares of our preferred stock as of February 26, 2010, which are convertible into 14,202,146 shares of our common stock. Pursuant to those agreements, the DLS sellers and Lime Rock are entitled to certain rights with respect to the registration of the sale of such common shares under the Securities Act. By exercising their registration rights and causing a large number of shares to be sold in the public market, these holders could cause the market price of our common stock to decline.

 

We cannot predict whether future sales of our common stock, or the availability of our common stock for sale, will adversely affect the market price for our common stock or our ability to raise capital by offering equity securities.

 

The DLS sellers and Lime Rock control substantial ownership stakes in us and have board nomination rights, and they are therefore able to exert significant influence on our affairs and actions, including matters submitted for a stockholder vote.

 

The DLS sellers collectively hold over 15% of our issued and outstanding common stock as of February 26, 2010. Under the investors rights agreement that we entered into in connection with the DLS acquisition, the DLS sellers have the right to designate two nominees for election to our board of directors. Lime Rock currently holds 19,889,044 shares of our common stock, representing approximately 27.8% of our issued and outstanding shares as of February 26, 2010. In addition, Lime Rock owns 36,393 shares of preferred stock which are convertible into 14,202,146 shares of our common stock. Through its ownership of common and preferred stock, Lime Rock controls, in the aggregate, 35% of our stockholders’ voting power. Pursuant to the investment agreement we entered into with Lime Rock, Lime Rock has the right to designate up to four people to serve on our board of directors based upon the amount of our common stock Lime Rock and its affiliates beneficially own (counting the preferred stock on an as converted basis). Lime Rock has the right to designate four nominees for election to our board of directors and have designated two directors at this time. As a result, the DLS sellers and Lime Rock each have considerable influence over the composition of our board of directors, our future operations and strategy and our future corporate actions, including matters submitted for a stockholder vote.

 

Following the earlier of June 26, 2012 and the date on which the transfer restrictions set forth in the Investment Agreement expire, Lime Rock will not be prohibited from acquiring additional shares of our common stock or converting its shares of preferred stock, even if such conversion will result in its control of more than 35% of our stockholders’ voting power. As a result, Lime Rock’s influence over us may increase in the future.

Conflicts of interest between the DLS sellers and Lime Rock, on the one hand, and other holders of our securities, on the other hand, may arise with respect to sales of shares of capital stock owned by the DLS sellers or Lime Rock or other matters. In addition, the interests of the DLS sellers or Lime Rock regarding any proposed merger or sale may differ from the interests of other holders of our securities.

 

The board designation rights described above could have the effect of delaying or preventing a change in our control or otherwise discouraging a potential acquirer from attempting to obtain control of us, which in turn could have a material and adverse effect on the market price of our securities and/or our ability to meet our obligations thereunder.

 

Existing stockholders’ interest in us may be diluted by additional issuances of equity securities.

 

We expect to issue additional equity securities to fund the acquisition of additional businesses and pursuant to employee benefit plans. We may also issue additional equity securities for other purposes. These securities may have the same rights as our common stock or, alternatively, may have dividend, liquidation, or other preferences to our common stock. The issuance of additional equity securities will dilute the holdings of existing stockholders and may reduce the share price of our common stock.

 

Risks Associated With Our Indebtedness

 

We are a holding company, and as a result we are dependent on dividends from our subsidiaries to meet our obligations, including with respect to the notes.

 

We are a holding company and do not conduct any business operations of our own. Our principal assets are the equity interests we own in our operating subsidiaries, either directly or indirectly. As a result, we are dependent upon cash dividends, distributions or other transfers we receive from our subsidiaries to repay any debt we may incur, and to meet our other obligations. The ability of our subsidiaries to pay dividends and make payments to us will depend on their operating results and may be restricted by, among other things, applicable corporate, tax and other laws and regulations and agreements of those subsidiaries. For example, the corporate laws of some jurisdictions prohibit the payment of dividends by any subsidiary unless the subsidiary has a capital surplus or net profits in the current or immediately preceding fiscal year. Payments or distributions from our subsidiaries also could be subject to restrictions on dividends or repatriation of earnings under applicable local law, and monetary transfer restrictions in the jurisdictions in which our subsidiaries operate. Our subsidiaries are separate and distinct legal entities. Any right that we have to receive any assets of/or distributions from any subsidiary upon its bankruptcy, dissolution, liquidation or reorganization, or to realize proceeds from the sale of the assets of any subsidiary, will be junior to the claims of that 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, 2009, we have approximately $492.2 million of consolidated total indebtedness outstanding and approximately $85.8 million of additional secured borrowing capacity available under our credit agreement.

 

In addition, we may incur substantial additional debt in the future. Each of the indentures governing our 9.0% senior notes and our 8.5% senior notes permits us to incur additional debt, and our credit agreement permits additional borrowings. If new debt is added to our current debt levels, these related risks could increase.

 

We may not maintain sufficient revenues to meet our capital expenditure requirements and our financial obligations. Also, we may not be able to generate a sufficient amount of cash flow to meet our debt service obligations.

 

Our ability to make scheduled payments or to refinance our obligations with respect to our debt will depend on our financial and operating performance, which, in turn, is subject to prevailing economic

conditions and to certain financial, business and other factors beyond our control. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay scheduled expansion and capital expenditures, sell material assets or operations, obtain additional capital or restructure our debt. We cannot assure you that our operating performance, cash flow and capital resources will be sufficient for payment of our debt in the future. In the event that we are required to dispose of material assets or operations or restructure our debt to meet our debt service and other obligations, we cannot assure you that the terms of any such transaction would be satisfactory to us or if or how soon any such transaction could be completed.

 

If we fail to obtain additional financing, we may be unable to refinance our existing debt, expand our current operations or acquire new businesses, which could result in a failure to grow or result in defaults in our obligations under our credit agreement, our 9.0% senior notes, our 8.5% senior notes or our other debt securities.

 

In order to refinance indebtedness, expand existing operations and acquire additional businesses, we will require substantial amounts of capital. There can be no assurance that financing, whether from equity or debt financings or other sources, will be available or, if available, will be on terms satisfactory to us. The turmoil in the financial markets since mid-2008 and its impact on the financial condition of the banking sector and other lenders, has significantly reduced access to the capital markets. It is uncertain to what extent capital will be available to us in the future and at what cost. If we are unable to obtain financing, we will be unable to acquire additional businesses and may be unable to meet our obligations under our credit agreement, our 9.0% senior notes, our 8.5% senior notes or any other debt securities we may offer.

 

The indenture governing our 9.0% senior notes, the indenture governing our 8.5% senior notes and our credit agreement impose restrictions on us that may limit the discretion of management in operating our business and that, in turn, could impair our ability to meet our obligations.

 

The indenture governing our 9.0% senior notes, the indenture governing our 8.5% senior notes and our credit agreement contain various restrictive covenants that limit management’s discretion in operating our business. In particular, these covenants limit our ability to, among other things:

 

 

Our revolving credit agreement requires us to maintain specified financial ratios. If we fail to comply with the financial ratio covenants, it could limit or eliminate the availability under our revolving credit agreement. Our ability to maintain such financial ratios may be affected by events beyond our control, including changes in general economic and business conditions, and we cannot assure you that we will maintain or meet such ratios and tests or that the lenders under the credit agreement will waive any failure to meet such ratios or tests. The decrease in demand for our services experienced in 2009 adversely impacts our ability to maintain or meet such financial ratios.

 

These covenants could materially and adversely affect our ability to finance our future operations or capital needs. Furthermore, they may restrict our ability to expand, to pursue our business strategies and otherwise to conduct our business. A breach of these covenants could result in a default under the indentures governing our 9.0% senior notes, our 8.5% senior notes and any other debt securities we may offer and/or the

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.

 

 

None.

 

 

The following table describes the location and general character of the principal physical properties used in each of our company’s businesses as of February 26, 2010. Our principal executive office is rented and located in Houston, Texas and the table below presents all of our material operating locations and whether the property is owned or leased.

 

 

On June 29, 1987, we filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Our plan of reorganization was confirmed by the Bankruptcy Court after acceptance by our creditors and stockholders, and was consummated on December 2, 1988.

 

At confirmation of our plan of reorganization, the U.S. Bankruptcy Court approved the establishment of the A-C Reorganization Trust as the primary vehicle for distributions and the administration of claims under our plan of reorganization, two trust funds to service health care and life insurance programs for retired employees and a trust fund to process and liquidate future product liability claims. The trusts assumed responsibility for substantially all remaining cash distributions to be made to holders of claims and interests pursuant to our plan of reorganization. We were thereby discharged of all debts that arose before confirmation of our plan of reorganization.

 

We do not administer any of the aforementioned trusts, some of which have been dissolved, and retain no responsibility for the assets transferred to or distributions made or to be made by such trusts pursuant to our plan of reorganization.

 

As part of our plan of reorganization, we settled with the EPA on claims for cleanup costs at all known sites where we were alleged to have disposed of hazardous waste. The EPA settlement included both past and future cleanup costs at these sites and released us of liability to other potentially responsible parties in connection with these specific sites. In addition, we negotiated settlements of various environmental claims asserted by certain state environmental protection agencies.

 

Subsequent to our bankruptcy reorganization, the EPA and state environmental protection agencies have in a few cases asserted that we are liable for cleanup costs or fines in connection with several hazardous waste disposal sites containing products manufactured by us prior to consummation of our plan of reorganization. In each instance, we have taken the position that the cleanup costs and all other liabilities related to these sites were discharged in the bankruptcy, and the cases have been disposed of without material cost. A number of Federal Courts of Appeal have issued rulings consistent with this position, and based on such rulings, we believe that we will continue to prevail in our position that our liability to the EPA and third parties for claims for environmental cleanup costs that had pre-petition triggers have been discharged. A number of claimants have asserted claims for environmental cleanup costs that had pre-petition triggers, and in each event, the A-C Reorganization Trust, under its mandate to provide plan of reorganization implementation services to us, had responded to such claims, generally, by informing claimants that our liabilities were discharged in the bankruptcy. Each of such claims have been disposed of without material cost. However, there can be no assurance that we will not be subject to environmental claims relating to pre-bankruptcy activities that would have a material adverse effect on us.

 

We have assumed the responsibility of responding to claimants and to the EPA and state agencies previously undertaken by the A-C Reorganization Trust. However, we have been advised by the A-C Reorganization Trust that its cost of providing these services has not been material in the past, and therefore we do not expect to incur material expenses as a result of responding to such requests. However, there can be no assurance that we will not be subject to environmental claims relating to pre-bankruptcy activities that would have a material adverse effect on us.

 

We are named as a defendant from time to time in product liability lawsuits alleging personal injuries resulting from our activities prior to our reorganization involving asbestos. These claims had previously been referred to and handled by a special products liability trust formed to be responsible for such claims in connection with our reorganization. Such products liability trust is in the process of being dissolved. As with environmental claims, we do not believe we are liable for product liability claims relating to our business prior to our bankruptcy. However, there can be no assurance that we will not be subject to material product liability claims in the future.

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.

 

 

 

MARKET PRICE INFORMATION

 

Our common stock is traded on the New York Stock Exchange under the symbol “ALY”. The following table sets forth high and low sale prices of our common stock reported on the New York Stock Exchange.

 

 

Holders

 

As of February 26, 2010, there were approximately 878 holders of record of our common stock. On February 26, 2010, the closing price for our common stock reported on the New York Stock Exchange was $3.78 per share.

 

Dividends

 

No dividends were declared or paid on our common stock during the past two years, and no dividends are anticipated to be declared or paid in the foreseeable future on such common stock. Our credit facilities and the indentures governing our senior notes restrict our ability to pay dividends on our common stock.

EQUITY COMPENSATION PLAN INFORMATION

 

The following table provides information as of December 31, 2009 with respect to the shares of our common stock that may be issued under our existing equity compensation plans.

 

 

Equity Compensation Plans Not Approved By Security Holders

 

These plans comprise the following:

 

In 1999 and 2000, the Board compensated Board members who had served from 1989 to March 31, 1999 without compensation by issuing promissory notes totaling $325,000 and by granting stock options to these same individuals. Options to purchase 4,800 shares of common stock were granted with an exercise price of $13.75. These options vested immediately and expire in March 2010. As of December 31, 2009, 4,000 of these options remain outstanding.

PERFORMANCE GRAPH

 

Set forth below is a line graph comparing the annual percentage change in the cumulative return to the stockholders of our common stock with the cumulative return of the Russell 2000 and the CoreData Services Oil and Gas Equipment and Services Index for the last five years. Our common stock was a component of the Russell 2000 during the year ended December 31, 2009. The CoreData Services Oil and Gas Equipment and Services Index is an index of approximately 75 oil and gas equipment and services providers. The information contained in the performance graph shall not be deemed to be “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or Exchange Act, except to the extent that we specifically incorporate it by reference into such filing.

 

The graph assumes that $100 was invested on December 31, 2004 in our common stock and in each index, and that all dividends were reinvested. No dividends have been declared or paid on our common stock. Stockholder returns over the indicated period should not be considered indicative of future shareholder returns.

 

 

*$100 invested on 12/31/04 in stock or index, including reinvestment of dividends.
Fiscal year ending December 31.

 

COMPARISON OF CUMULATIVE TOTAL RETURN OF ONE OR MORE
COMPANIES, PEER GROUPS, INDUSTRY INDEXES AND/OR BROAD MARKETS

 

 

 

The following selected historical financial information for each of the five years ended December 31, 2009, has been derived from our audited consolidated financial statements and related notes. Certain reclassifications have been made to the prior 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):

 

 

 

 

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, Louisiana, Arkansas, Pennsylvania, Oklahoma, New Mexico, offshore in the Gulf of Mexico, and internationally, primarily in Argentina, Brazil, Bolivia and Mexico. We operate in three sectors of the oil and natural gas service industry: Oilfield Services; Drilling and Completion and Rental Services.

 

We derive operating revenues from rates per job that we charge for the labor and equipment required to provide a service and rates per day for equipment and tools that we rent to our customers. The price we charge for our services depends upon several factors, including the level of oil and natural gas drilling activity and the competitive environment in the particular geographic regions in which we operate. Contracts are awarded based on the price, quality of service and equipment, and the general reputation and experience of our personnel. The demand for drilling services has historically been volatile and is affected by the capital expenditures of oil and natural gas exploration and development companies, which can fluctuate based upon the prices of oil and natural gas or the expectation for the prices of oil and natural gas.

 

The rig count is an important indicator of activity levels in the oil and natural gas industry. According to the Baker Hughes rig count, the rig count in the U.S. increased from 862 as of December 27, 2002 to a peak of 2,031 in August 2008. However the rig count began to decline in the fourth quarter of 2008 and continued to decline in 2009 reaching a low of 876 rigs in June 2009. The rapid decline in the U.S. rig count experienced in 2009 was due to the economic slowdown in the U.S. and the decrease in natural gas and oil prices which impacted the capital expenditures of our customers. The turmoil in the financial markets and its impact on the availability of capital for our customers also affected drilling activity in the U.S. The rig count has since increased to 1,373 as of February 26, 2010 due to the recovery of oil prices and the stabilization of natural gas prices. The directional and horizontal rig count in the U.S., according to Baker Hughes, was 914 as of February 26, 2010 compared to 692 one year earlier. According to Baker Hughes, the offshore Gulf of Mexico rig count was 44 rigs at February 26, 2010 from 51 at February 27, 2009.

 

While our revenue can be correlated to the rig count, our operating costs do not fluctuate in direct proportion to changes in revenues. Our operating expenses consist principally of our labor costs and benefits, equipment rentals, maintenance and repairs of our equipment, depreciation, insurance and fuel. Because many of our costs are fixed, our operating income as a percentage of revenues is generally affected by our level of revenues.

 

Company Outlook

 

We believe that our revenue and operating income for all of our operating segments will improve in 2010. Our Oilfield Service segment is heavily based on oil and natural gas activity in the U.S. and a good indicator of that activity is the U.S. rig count. The Baker Hughes rig count in the U.S. for the first eight weeks of 2010 decreased to an average of 1,308 compared to an average of 1,428 for the first eight weeks of 2009, but has increased when compared to the average rig count for the fourth quarter of 2009 of 1,115 or the average rig count of 1,079 for all of 2009. That favorable trend in rig count should result in improved demand and pricing for our Oilfield Services segment. Our Rental Services segment has historically been very dependent on drilling activity in the Gulf of Mexico. The Baker Hughes average rig count in the Gulf of Mexico for the first eight weeks of 2010 decreased to 42 rigs compared to an average of 60 rigs for the first eight weeks of 2009, but increased when compared to 34 rigs for the last quarter of 2009. We believe this favorable trend since the fourth quarter, and our strategy of moving rental assets to new markets, will result in increased utilization and pricing for our Rental Services segment. We anticipate our Drilling and Completion segment will exceed 2009 results for both revenue and operating income as drilling activity in Argentina is improving and we have relocated underutilized rigs to Brazil. We have also signed two new contracts in Bolivia to commence drilling

operations in February and April of 2010. Our Drilling and Completion segment currently operates in Argentina, Brazil and Bolivia, but we have two rigs scheduled to be delivered in the U.S. in 2010. Currently, we have no firm commitments of work for the two U.S. rigs, so the impact of revenue and operating income from these rigs may have a negative impact on our Drilling and Completion segment’s operating results.

 

We expect our general and administrative expenses in 2010 to be relatively flat as we realize a full year benefit from reductions of our administrative staffs made in 2009 to reflect the decline in activity, offset by additional administrative positions created to handled our growing international activities and costs related to investigation of new operational and financial reporting tools to improve our operating performance. We also anticipate an increase in compensation for existing administrative positions in response to market conditions. Our net interest expense is dependent upon our level of debt and cash on hand, which are principally dependent on acquisitions we complete, our capital expenditures and our cash flows from operations. Due to the shortage of liquidity and credit in the U.S. financial markets, we may see an increase in our effective interest rate in 2010. We do not anticipate the ability to record a gain on debt extinguishment in 2010 as our senior notes are trading close to face value. We anticipate that our effective tax rate will increase in 2010 due to a projected domestic tax loss at lower tax rate than the tax rate applied to our international operations which are expected to generate taxable income.

 

Our operating income is principally dependent on our level of revenues and the pricing environment of our services. In addition, demand for our services is dependent upon our customers’ capital spending plans, which are largely driven by current commodity prices and their expectations of future commodity prices.

 

We believe that 2010 will be a challenging year for our operations although increased oil and natural gas prices and the resulting increased rig count should increase the utilization and pricing for our equipment and services. We believe our cost cuts and our strategy of international growth, by offering new equipment and technology to our customers and our focus on the U.S. land shale plays, will improve our operating results in 2010.

 

Results of Operations

 

In June 2007, we acquired all of the outstanding stock of Coker, in July 2007, we acquired all of the outstanding stock of Diggar and in November 2007, we acquired substantially all of the assets of Diamondback. In October 2007, we acquired all of the outstanding stock of Rebel. In June 2007, we sold our capillary assets. We report the operations of these four acquisitions and one disposition in our Oilfield Services segment.

 

In December 2008, we acquired all of the outstanding stock of BCH, which is reported as part of our Drilling and Completion segment. In August 2008, we sold our drill pipe tong manufacturing assets, which were reported in our Oilfield Services segment.

 

We consolidated the results of all of these acquisitions from the day they were acquired.

 

The foregoing acquisitions and dispositions affect the comparability from period to period of our historical results, and our historical results may not be indicative of our future results.

 

Comparison of Years Ended December 31, 2009 and December 31, 2008

 

Our revenues for the year ended December 31, 2009 were $506.3 million, a decrease of 25.1% compared to $675.9 million for the year ended December 31, 2008. The decrease in revenues is due to the decrease in revenues in our Oilfield Services and Rental Services segments, offset in part by a slight increase in revenues in our Drilling and Completion segment. Both our Oilfield Services and Rental Services segments have a strong concentration in the U.S. domestic oil and natural gas market. Due to the decline in oil and natural gas prices and drilling activity in the U.S. compared to 2008, we experienced significant deterioration in both equipment utilization and pricing. This resulted in a decline in revenues of our Oilfield Services segment to $143.6 million for the year ended December 31, 2009 compared to revenues of $280.8 million for the year ended December 31, 2008. Our Rental Services segment had a decline in revenues to $58.7 million for the year ended December 31, 2009 compared to revenues of $103.8 million for the year ended December 31,

2008. The increase in revenues in our Drilling and Completion segment was due to the acquisition of BCH in Brazil offset by lower rig utilization and pricing in our Argentina operations. The Drilling and Completion segment generated $304.0 million in revenues for the year ended December 31, 2009 compared to revenues of $291.3 million for the year ended December 31, 2008. BCH, which was acquired on December 31, 2008, generated $43.6 million in revenues for the year ended December 31, 2009.

 

Our direct costs for the year ended December 31, 2009 decreased 14.4% to $379.4 million, or 75.0% of revenues, compared to $443.4 million, or 65.6%, of revenues for the year ended December 31, 2008. The increase in the percentage of direct costs to revenue between periods is primarily due to the change in our revenue mix and the fact that not all of our direct costs are variable and therefore do not fluctuate with revenues. For the year ended December 31, 2009, our higher margin Rental Services segment only comprised 11.6% of our total revenues compared to 15.4% of our total revenues for the year ended December 31, 2008. Our direct costs in our Oilfield Services and Rental Services segments decreased in absolute dollars for the year ended December 31, 2009 compared to the year ended December 31, 2008, but our revenues in our Oilfield Services and Rental Services segments decreased more during that same period than the reduction in direct costs. Our Oilfield Services segment direct costs for the year ended December 31, 2009 decreased 39.4% from direct costs for the year ended December 31, 2008, while the revenues decreased 48.9% over that same period. In addition, our Oilfield Services segment had $1.2 million of expenses recorded during the year ended December 31, 2009 related to severance payments, the closing of unprofitable locations and downsizing other locations. Our Oilfield Services segment has also been impacted by pricing pressure that decreases revenues but has no impact on direct costs. Our Rental Services segment direct costs for the year ended December 31, 2009 decreased 36.4% from direct costs for the year ended December 31, 2008, while the revenues decreased 43.4% over that same period. Our direct costs for the Rental Services segment are largely fixed because they primarily relate to yard expenses to maintain the rental inventory. In addition, pricing pressure has reduced our Rental Services revenues but had no impact on our direct costs. Direct costs in our Drilling and Completion segment increased $20.6 million for the year ended December 31, 2009 compared to the year ended December 31, 2008. Direct costs related to our December 2008 acquisition of BCH were $29.6 million during the year ended December 31, 2009. Our Drilling and Completion segment direct costs for the year ended December 31, 2009 increased 9.1% from direct costs for the year ended December 31, 2008, while the revenues increased 4.3% over that same period. This unfavorable variance is primarily attributed to lower utilization of our drilling and service rigs during the year ended December 31, 2009 compared to the same period of the prior year and labor and other cost increases due to the inflationary environment in Argentina. Additionally, workforce reductions in response to market conditions are difficult and costly to implement in the labor environment in Argentina. We incurred $1.7 million in severance costs in Argentina during the year ended December 31, 2009.

 

Depreciation expense increased 23.3% to $78.3 million for the year ended December 31, 2009 from $63.5 million for the year ended December 31, 2008. The primary increase in depreciation expense is due to the acquisitions completed in the second half of 2008 and the acquisition of BCH in December 2008. Depreciation expense for BCH was $3.3 million for the year ended December 31, 2009.

 

General and administrative expense was $50.8 million for the year ended December 31, 2009 compared to $62.8 million for the year ended December 31, 2008. General and administrative expense decreased primarily due to the amortization of share-based compensation arrangements, reduced management, accounting and administrative staffs and reductions in provided benefits. General and administrative expense includes share-based compensation expense of $4.8 million in 2009 and $7.9 million in 2008. As a percentage of revenues, general and administrative expenses were 10.0% in 2009 compared to 9.3% in 2008.

 

During the year ended December 31, 2009, we recorded a $1.6 million loss on an asset disposition from the total loss of a rig from a blow-out in our Drilling and Completion segment. The insurance proceeds for the loss were not sufficient to cover the book value of the rig and related assets. Effective August 1, 2008, we sold our drill pipe tong manufacturing assets that were part of our Oilfield Services segment. The total consideration was approximately $7.5 million. We recognized a gain of $166,000 related to the transaction.

We recorded an impairment of goodwill of $115.8 million as of December 31, 2008. In light of adverse market conditions affecting our stock price and market conditions at that time, we determined that impairment was necessary on all of our goodwill associated with our Rental Services segment as well as on our Tubular Services and Production Services reporting units included in our Oilfield Services segment. We performed the same annual impairment test as of December 31, 2009 and recorded no impairment.

 

Amortization expense was $4.7 million for the year ended December 31, 2009 compared to $4.2 million for the year ended December 31, 2008. The increase was primarily attributable to intangible assets associated with our acquisition of BCH in December 2008.

 

Our loss from operations for the year ended December 31, 2009 totaled $8.5 million, compared to $13.5 million loss for the year ended December 31, 2008, for an improvement of $5.0 million. The improvement is primarily related to the $115.8 million goodwill impairment in the year ended December 31, 2008 compared to no impairment for the year ended December 31, 2009, offset by decreased revenues and increased depreciation and amortization expense of $15.3 million from the year ended December 31, 2009 compared to year ended December 31, 2008.

 

Our interest expense was $48.1 million for the year ended December 31, 2009, compared to $48.4 million for the year ended December 31, 2008. On June 29, 2009 we purchased $74.8 million of our senior notes with proceeds from our $125.6 million in equity issuances on that same date. We also prepaid the then $35.0 million outstanding loan balance under our revolving credit facility on June 29, 2009 from those same equity proceeds. This compared to an outstanding balance of $36.5 million at December 31, 2008 under our revolving credit facility. In 2008, through DLS, we entered into a new $25.0 million import finance facility with a bank to fund a portion of the purchase price of new drilling and service rigs. Interest expense increased due to the acquisition of BCH at the end of 2008. BCH had a $22.1 million term loan facility at December 31, 2008 which was reduced to $16.2 million at December 31, 2009. Interest expense includes amortization expense of debt issuance costs of $2.2 million and $2.1 million for the years ended December 31, 2009 and 2008, respectively.

 

Our interest income was $72,000 for the year ended December 31, 2009, compared to $5.6 million for the year ended December 31, 2008. In January 2008, we invested $40.0 million into a 15% convertible subordinated secured debenture with BCH. We earned interest on this note up until December 28, 2008, when we acquired all of the outstanding stock of BCH.

 

During the year ended December 31, 2009, we recorded a gain of $26.4 million as a result of a tender offer that we completed on June 29, 2009. We purchased $30.6 million aggregate principal of our 9.0% senior notes and $44.2 million aggregate principal of 8.5% senior notes for approximately $46.4 million. Included in the computation of the gain is the write-off of $1.5 million of debt issuance costs related to the retired notes and we incurred approximately $466,000 in expenses related to the transactions.

 

Our benefit for income taxes for the year ended December 31, 2009 was $9.9 million, or 31.8% of our net loss before income taxes, compared to an income tax benefit of $17.4 million, or 30.6% of our net income before income taxes for 2008. Our effective tax rate in the U.S. was 35.5% in 2009 compared to 31.1% in 2008, while our effective tax rate for international activities increased to 44.4% in 2009 compared to 31.7% in 2008. The increase in the U.S. tax rate was primarily attributable to higher nondeductible items during the 2008 year including intangible disposals and meals and entertainment. The increase in the international tax rate is primarily due to our BCH operations which generate a loss in Brazil which has a valuation allowance of $2.1 million against its benefit. For the year ended December 31, 2009, the U.S. operations generated a $43.9 million book loss before income taxes, while the international activities generated $12.9 million of income before income taxes, resulting in the U.S. operations having a higher influence on our consolidated effective tax rate in 2009.

 

We had a net loss of $21.2 million for the year ended December 31, 2009, compared to a net loss of $39.5 million for the year ended December 31, 2008.

 

The net loss attributed to common stockholders was $22.5 million after $1.3 million in preferred stock dividends. The preferred stock dividend relates to 36,393 shares of $1,000 par value preferred shares at 7.0%.

The following table compares revenues and income (loss) from operations for each of our business segments for the years ended December 31, 2009 and December 31, 2008. Income (loss) from operations consists of our revenues and the gain (loss) on asset dispositions less direct costs, general and administrative expenses, goodwill impairment, depreciation and amortization:

 

 

Oilfield Services.  Revenues for the year ended December 31, 2009 for our Oilfield Services segment were $143.6 million, a decrease of 48.9% from the $280.8 million in revenues for the year ended December 31, 2008. Income from operations for our Oilfield Services segment decreased $53.3 million and resulted in a loss from operations of $14.7 million for the year ended December 31, 2009 compared to income from operations of $38.6 million for the year ended December 31, 2008. The operating income for the year ended December 31, 2008 included a $9.4 million non-cash charge for the impairment of goodwill. Our Oilfield Services segment revenues and operating income for the year ended December 31, 2009 decreased compared to the year ended December 31, 2008 due to weak market conditions that resulted in reduced demand and pricing for our services. During the year ended December 31, 2009, we incurred $1.2 million of costs related to severance payments, the closing of unprofitable locations and downsizing other locations in our Oilfield Services segment. Depreciation and amortization expense for the Oilfield Services segment increased by $5.9 million or 23.7% for the year ended December 31, 2009 compared to the prior year, due to capital expenditures completed during 2008, including six coiled tubing units delivered in the last half of 2008. We have not realized the benefits of these capital expenditures due to decreased utilization and pricing of our equipment as a result of the decline in U.S. drilling activity.

 

Drilling and Completion.  Our Drilling and Completion revenues were $304.0 million for the year ended December 31, 2009, an increase of 4.3% from the $291.3 million in revenues for the year ended December 31, 2008. Our Drilling and Completion revenues increased in 2009 primarily due to $43.6 million in revenues generated by BCH, which we acquired in December 2008, offset by a decrease in revenues in Argentina. Income from operations decreased to $19.2 million in 2009 compared to $40.2 million for the year ended December 31, 2008. Income from operations as percentage of revenue decreased to 6.3% for 2009 compared to 13.8% for 2008. This reduction was due to: (1) reduced rig utilization and rig rates in Argentina during the year ended December 31, 2009; (2) increased labor and other costs in Argentina during the year ended December 31, 2009 (3) an increase of $8.0 million, or 55.9%, in depreciation and amortization in the year ended December 31, 2009; (4) a $1.6 million non-cash loss recorded in the year ended December 31, 2009 on a rig destroyed in a blow-out; (5) $1.7 million of severance costs during the year ended December 31, 2009 related to workforce reductions in Argentina as a result of lower activity and (6) $329,000 of costs incurred to consolidate operating locations in Brazil during the year ended December 31, 2009. The increase in depreciation and amortization expense was the result of the addition of new rigs in Argentina and the acquisition of BCH.

 

Rental Services.  Our Rental Services revenues were $58.7 million for the year ended December 31, 2009, a decrease of 43.4% from the $103.8 million in revenues for the year ended December 31, 2008. Income from operations for our Rental Services segment increased to $140,000 for the year ended December 31, 2009 compared to a loss of $74.4 million for the year ended December 31, 2008. The operating income for the year ended December 31, 2008 included a $106.4 million non-cash charge for impairment of goodwill, without this charge our operating income for the year ended December 31, 2008 would have been $32.0 million. Our Rental Services segment revenues and operating income as adjusted for goodwill impairment for the year ended December 31, 2009 decreased compared to the prior year due primarily to the decrease in utilization of

our rental equipment and a more competitive pricing environment due to the decrease in drilling activity in the United States. The decrease in income from operations for the year ended December 31, 2009 is also due to a $306,000 increase to the bad debt expense for Rental Services segment customers who are facing financial difficulties, and $237,000 of costs related to closing a rental yard and reducing our workforce. Our bad debt expense recorded in our Rental Services segment for the year ended December 31, 2009 was $1.5 million compared to $1.2 million for the year ended December 31, 2008. In addition, depreciation and amortization expense for our Rental Services segment increased $1.7 million or 5.9%, for the year ending December 31, 2009 compared to the prior year due to capital expenditures made during 2008.

 

General Corporate.  General corporate expenses decreased $4.8 million to $13.2 million for the year ended December 31, 2009 compared to $18.0 million for the year ended December 31, 2008. The decrease was primarily due to the decrease in share-based compensation expense and the decrease in payroll costs and benefits due to reduced management and accounting and administrative staff. Share-based compensation expense included in general corporate was $3.7 million for the year ended December 31, 2009 compared to $6.7 million for the year ended December 31, 2008.

 

Comparison of Years Ended December 31, 2008 and December 31, 2007

 

Our revenues for the year ended December 31, 2008 were $675.9 million, an increase of 18.4% compared to $571.0 million for the year ended December 31, 2007. The increase in revenues is due to the increase in revenues in our Drilling and Completion and our Oilfield Services segments, offset in part by a decrease in revenues in our Rental Services segment. The most significant increase in revenues was in our Drilling and Completion segment due to additional drilling and service rigs placed in service in 2008 and price increases. The Drilling and Completion segment generated $291.3 million in revenues for the year ended December 31, 2008 compared to $215.8 million for the year ended December 31, 2007. Our Oilfield Services segment revenues increased to $280.8 million in 2008 compared to $234.0 million in 2007 due to acquisitions completed in the third and fourth quarters of 2007 which added downhole motors, measurement-while-drilling, or MWD, tools, and directional drilling personnel resulting in increased capacity and increased market penetration. Revenues also increased at our Oilfield Services segment due to the purchase of additional equipment, principally new compressor packages for our underbalanced operations, coiled tubing equipment and expansion of operations into new geographic regions. The impact of the additional MWD tools, downhole motors and the acquisitions of Diggar and Coker completed in the last half of 2007 are not easily identifiable as they were quickly integrated with our pre-existing operations. The acquisition of the Diamondback assets provided $30.3 million in revenues for the year ended December 31, 2008 compared to $3.1 million in revenues from the date of acquisition to December 31, 2007. The additional coiled tubing equipment provided an additional $11.8 million in revenues for the year ended December 31, 2008 compared to 2007. These increases in revenue were partially offset by a significant decrease in revenues at our Rental Services segment due to the reduction of drilling activity in the U.S. Gulf of Mexico beginning in the last half of 2007, as rigs departed the U.S. Gulf in favor of the international markets and the impact of hurricanes in 2008. These factors also caused the pricing for our Rental Services segment to become more competitive. Also impacting revenues was a $5.5 million decrease in revenues from our capillary tubing assets compared to 2007 as those assets were sold on June 29, 2007.

 

Our direct costs for the year ended December 31, 2008 increased 30.9% to $443.4 million, or 65.6% of revenues, compared to $338.8 million, or 59.3%, of revenues for the year ended December 31, 2007. On a percentage basis, direct costs in our Oilfield Services segment outpaced the growth in revenue for that segment. Oilfield Services revenue for the year ended December 31, 2008 increased 20.0% from revenue in the Oilfield Services segment for the year ended December 31, 2007, while the direct costs increased 24.7% over that same period. This unfavorable variance was primarily associated with costs incurred in the deployment of our new coiled tubing rigs. On a percentage basis, direct costs in our Drilling and Completion segment outpaced the growth in our revenue for that segment. Drilling and Completion revenue for the year ended December 31, 2008 increased 35.0% from revenue in the Drilling and Completion segment for the year ended December 31, 2007, while the direct costs increased 45.1% over that same period. This unfavorable variance is primarily attributed to higher labor costs in our Drilling and Completion segment relating to labor

concessions in Argentina granted by the oil industry in the last half of 2007 and a significant increase in our labor force and labor-related expenses in connection with the delivery of new rigs prior to their activation. Our direct costs in our Rental Services segment did not decrease on the same percentage as the drop in our revenue for that segment. Rental Services revenue for the year ended December 31, 2008 decreased 14.4% from revenue in the Rental Services segment for the year ended December 31, 2007, while the direct costs decreased 5.9% over that same period. Our direct costs for the Rental Services segment are largely fixed because they primarily relate to yard expenses to maintain the rental inventory. In addition, the change in the service mix from the longer-term Gulf of Mexico rentals, which we benefited from in 2007, to the shorter term land-drilling rental work in 2008, requires more handling on our part which increases costs.

 

Depreciation expense increased 24.6% to $63.5 million for the year ended December 31, 2008 from $50.9 million for the year ended December 31, 2007. The primary increase in depreciation expense is due to the acquisitions completed in the second half of 2007 and our capital expenditures, principally the addition of new service rigs and one drilling rig in Argentina.

 

General and administrative expense was $62.8 million for the year ended December 31, 2008 compared to $61.2 million for the year ended December 31, 2007. General and administrative expense increased primarily due to the amortization of share-based compensation arrangements. General and administrative expense includes share-based compensation expense of $7.9 million in 2008 and $4.7 million in 2007. As a percentage of revenues, general and administrative expenses were 9.3% in 2008 compared to 10.7% in 2007.

 

Effective August 1, 2008, we sold our drill pipe tong manufacturing assets that were part of our Oilfield Services segment. The total consideration was approximately $7.5 million. We recognized a gain of $166,000 related to the transaction. On June 29, 2007, we sold our capillary tubing assets that were part of our Oilfield Services segment. The total consideration was approximately $16.3 million in cash. We recognized a gain of $8.9 million related to the sale of these assets.

 

We recorded an impairment of goodwill of $115.8 million as of December 31, 2008. In light of adverse market conditions affecting our stock price and market conditions, we determined that impairment was necessary on all of our goodwill associated with our Rental Services segment as well as on our Tubular Services and Production Services reporting units included in our Oilfield Services segment. We performed the same annual impairment test as of December 31, 2007 and recorded no impairment.

 

Amortization expense was $4.2 million for the year ended December 31, 2008 compared to $4.1 million for the year ended December 31, 2007.

 

Our loss from operations for the year ended December 31, 2008 totaled $13.5 million, compared to $124.8 million in income from operations for the year ended December 31, 2007, for a total decrease of $138.3 million. The decrease is primarily related to the $115.8 million goodwill impairment, increased depreciation and amortization expense of $12.7 million from the year ended December 31, 2008 compared to year ended December 31, 2007 and the $8.9 million gain related to the sale of our capillary tubing assets in 2007.

 

Our interest expense was $48.4 million for the year ended December 31, 2008, compared to $49.5 million for the year ended December 31, 2007. During 2008, we borrowed against our revolving credit facility and as of December 31, 2008, we had an outstanding balance of $36.5 million. In 2008, through our DLS subsidiary in Argentina, we also entered into a new $25.0 million import finance facility with a bank to fund a portion of the purchase price of new drilling and service rigs. In January 2007 we issued $250.0 million of senior notes bearing interest at 8.5% to pay off, in part, the $300.0 million bridge loan utilized to complete the acquisition of substantially all of the assets of Oil & Gas Rental Services, Inc., or OGR, and for working capital. This bridge loan was repaid on January 29, 2007. The average interest rate on the bridge loan was approximately 10.6%. Interest expense for 2007 includes the write-off of deferred financing fees of $1.2 million related to the repayment of the bridge loan. Interest expense also includes amortization expense of deferred financing costs of $2.1 million and $1.9 million for 2008 and 2007, respectively.

 

Our interest income was $5.6 million for the year ended December 31, 2008, compared to $3.3 million for the year ended December 31, 2007. In January 2008, we invested $40.0 million into a 15% convertible

subordinated secured debenture with BCH. We earned interest on this note up until December 28, 2008, when we acquired all of the outstanding stock of BCH. In 2007, we had excess cash as the result of a senior note financing and an equity offering and we were able to generate interest income during this period.

 

Our benefit for income taxes for the year ended December 31, 2008 was $17.4 million, or 30.6% of our net loss before income taxes, compared to an income tax expense of $28.8 million, or 36.4% of our net income before income taxes for 2007. The income tax benefit recorded in 2008 was the result of net loss before income taxes compared to net income before income taxes in the previous year and a lower effective tax rate. The lower effective tax rate in 2008 is attributable to the impact of foreign currency losses on the foreign income tax as well a lower benefit from the loss generated on our U.S. operations due to nondeductible expenses and state income taxes.

 

We had a net loss of $39.5 million for the year ended December 31, 2008, compared to net income of $50.4 million for the year ended December 31, 2007.

 

The following table compares revenues and income (loss) from operations for each of our business segments for the years ended December 31, 2008 and December 31, 2007. Income (loss) from operations consists of our revenues and the gain on asset dispositions less direct costs, general and administrative expenses, goodwill impairment, depreciation and amortization:

 

 

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.

 

General Corporate.  General corporate expenses increased $1.6 million to $18.0 million for the year ended December 31, 2008 compared to $16.4 million for the year ended December 31, 2007. The increase was primarily due to the increase in share-based compensation expense.

 

Liquidity and Capital Resources

 

In June 2009, we strengthened our balance sheet by raising approximately $125.6 million in gross proceeds from the sale of common stock and a newly issued series of preferred stock. The transactions were effected through a common stock rights offering to our existing stockholders, the sale of common stock to Lime Rock through its backstop commitment of the rights offering, and the sale of convertible perpetual preferred stock to Lime Rock. Approximately $46.4 million of the proceeds were used to purchase an aggregate of $74.8 million principal amount of our existing senior notes, approximately $35.0 million was used to repay all the borrowings under our revolving bank credit facility due 2012, except for outstanding letters of credit, and the remainder for general corporate purposes.

 

Our on-going capital requirements arise primarily from our need to service our debt, to acquire and maintain equipment, to fund our working capital requirements and to complete acquisitions. Our primary sources of liquidity are proceeds from the issuance of debt and equity securities and cash flows from operations. Our amended and restated revolving credit facility permits borrowings of up to $90.0 million in principal amount. As of December 31, 2009, we had $85.8 million available for borrowing under our amended and restated revolving credit facility. Cash flows from operations are expected to be our primary source of liquidity in fiscal 2010. We had cash and cash equivalents of $41.1 million at December 31, 2009 compared to $6.9 million at December 31, 2008.

 

Our revolving credit agreement requires us to maintain specified financial ratios. If we fail to comply with the financial ratio covenants, it could limit or eliminate the availability under our revolving credit agreement. Our ability to maintain such financial ratios may be affected by events beyond our control, including changes in general economic and business conditions, and we cannot assure you that we will maintain or meet such ratios and tests or that the lenders under the credit agreement will waive any failure to meet such ratios or tests. The decrease in the U.S. rig count experienced late in 2008 and 2009 and the resulting decrease in demand for our services adversely impacts our ability to maintain or meet such financial ratios. We believe that the $125.6 million in gross equity proceeds received in June 2009 has significantly improved our liquidity and decreased our reliance on our revolving credit facility. We utilized a portion of the equity proceeds to prepay all borrowings under our revolving credit agreement.

 

Exclusive of any acquisitions, we currently expect our capital spending to be between $60.0 million and $85.0 million in 2010 depending upon the market demand we experience, our operating performance during the year and expenditures which may be associated with potential new contracts. These amounts are net of equipment deposits paid in 2009. As of December 31, 2009, we had capital expenditure commitments of $19.2 million, net of equipment deposits. The majority of these commitments are due to $12.1 million remaining to be paid on two new 1600 horsepower drilling rigs expected to be completed in the second and fourth quarters of 2010. We believe that our cash generated from operations, cash on hand and cash available

under our credit facilities will provide sufficient funds for our identified projects. Our ability to obtain capital for opportunistic acquisitions or additional projects to implement our growth strategy over the longer term will depend upon our future operating performance and financial condition, which will be dependent upon the prevailing conditions in our industry and the global market, including the availability of equity and debt financing.

 

Operating Activities

 

In the year ended December 31, 2009, we generated $55.5 million in cash from operating activities. Our net loss for the year ended December 31, 2009 was $21.2 million. Non-cash additions to net loss totaled $49.3 million in the 2009 period consisting primarily of $83.0 million of depreciation and amortization, $4.8 million related to the expensing of stock options, $2.8 million for bad debts, $2.2 million of amortization and write-off of deferred financing fees and $1.6 million related to loss on rig destroyed by fire, partially offset by $26.4 million from gain on debt extinguishment, $17.9 million in deferred income taxes and $0.9 million of gains from the dispositions of equipment.

 

During the year ended December 31, 2009, changes in working capital provided $27.4 million in cash, principally due to a decrease of $50.0 million in accounts receivable, a decrease of $4.6 million in inventories, a decrease in other current assets of $4.6 million and an increase of $2.7 million in accrued employee benefits and payroll taxes, offset by an decrease of $27.6 million in accounts payable, a decrease of $4.6 million in accrued expenses and a decrease in accrued interest of $2.8 million. Our accounts receivables decreased at December 31, 2009 primarily due to the decrease in our revenues in 2009. Inventories decreased at December 31, 2009 primarily due to a slow down in our activity. Other current assets decreased primarily due to tax refunds received in 2009. Our accounts payable, and other accrued expenses decreased primarily due to the decrease in costs due to our decrease in activity.

 

In the year ended December 31, 2008, we generated $113.7 million in cash from operating activities. Our net loss for the year ended December 31, 2008 was $39.5 million. Non-cash additions to net loss totaled $164.8 million in the 2008 period consisting primarily of $115.8 million of impairment of goodwill, $67.7 million of depreciation and amortization, $7.9 million related to the expensing of stock options, $3.3 million for bad debts and $2.1 million of amortization and write-off of deferred financing fees, partially offset by $29.9 million in deferred income taxes and $1.9 million of gains from the dispositions of equipment.

 

During the year ended December 31, 2008, changes in working capital used $11.7 million in cash, principally due to an increase of $27.5 million in accounts receivable, an increase of $9.7 million in inventories and an increase in other current assets of $1.6 million, offset by an increase of $21.9 million in accounts payable, an increase of $3.5 million in accrued employee benefits and payroll taxes, an increase of $1.2 million in accrued expenses and an increase in accrued interest of $567,000. Our accounts receivables increased at December 31, 2008 primarily due to the increase in our revenues in 2008. Inventories increased at December 31, 2008 primarily due to our larger rig fleet in our Drilling and Completion segment. Other current assets increased primarily due to estimated tax payments exceeding the estimated tax liability as of December 31, 2008. Our accounts payable, accrued employee benefits and payroll taxes and other accrued expenses increased primarily due to the increase in costs due to our growth in revenues.

 

In the year ended December 31, 2007, we generated $103.5 million in cash from operating activities. Our net income for the year ended December 31, 2007 was $50.4 million. Non-cash additions to net income totaled $61.2 million in the 2007 period consisting primarily of $55.0 million of depreciation and amortization, $4.9 million related to the expensing of stock options, $8.0 million of deferred income tax, $1.3 million for bad debts and $3.2 million of amortization and write-off of deferred financing fees, partially offset by $2.3 million of gain from the disposition of equipment and a $8.9 million gain from the sale of capillary assets.

 

During the year ended December 31, 2007, changes in working capital used $8.1 million in cash, principally due to an increase of $31.4 million in accounts receivable, an increase of $4.5 million in other assets and an increase in inventories of $5.4 million, offset by a decrease of $8.2 million in other current assets, an increase of $10.7 million in accounts payable, an increase of $6.0 million in accrued interest, an

increase of $4.0 million in accrued employee benefits and payroll taxes, an increase of $1.5 million in accrued expenses and an increase in other long-term liabilities of $2.7 million. Our accounts receivables increased at December 31, 2007 primarily due to the increase in our revenues in 2007. Other assets increase primarily due to the contract costs related to the deployment of new rigs for our Drilling and Completion segment. The decrease in other current assets is principally due to the collection of the working capital adjustment from the OGR acquisition for approximately $7.1 million in the first quarter of 2007. Accrued interest increased at December 31, 2007 due principally to interest accrued on our 8.5% senior notes issued in January 2007 and our 9.0% senior notes issued in August 2006 which are both payable semi-annually. Our accounts payable, accrued employee benefits and payroll taxes and other accrued expenses increased primarily due to the increase in costs due to our growth in revenues and acquisition completed in 2007. Other long-term liabilities increased primarily due to the deferral of contract revenue related to our new rigs being constructed in the Drilling and Completion segment.

 

Investing Activities

 

During the year ended December 31, 2009, we used $64.0 million in investing activities, consisting of $78.1 million for capital expenditures, $1.1 million of additional investments, offset by a decrease of $2.7 million in deposits on asset commitments, $8.6 million of proceeds from equipment sales and $3.9 million in insurance proceeds for a drilling rig destroyed by a blow-out. Included in the $78.1 million for capital expenditures was $11.4 million for our Oilfield Services segment, $38.5 million for two domestic drilling rigs and $19.9 million for additional equipment in our Drilling and Completion segment and $8.2 million for drill pipe and other equipment used in our Rental Services segment. We invested $2.4 million of cash and cash expenditures for equipment into our investment into our Saudi Arabia joint venture and we received $1.3 million from insurance proceeds related to a pre-acquisition contingency on BCH. The decrease in other assets was due to the conversion of deposits on equipment purchases into capital expenditures for the drilling rigs and assets used in our directional drilling services. We also received $8.6 million from the sale of assets during the year ended December 31, 2009, comprised mostly from equipment “lost-in-hole” from our Rental Services segment ($3.5 million) and our Oilfield Services segment ($0.8 million) along with $3.9 million from the sale a plane in our Rental Services segment. We also transferred $1.6 million of rental assets as part of our investment into our Saudi Arabia joint venture in a non-cash transaction. In 2009, we reduced the carrying value of goodwill on the BCH acquisition by $1.3 million due to the utilization of a pre-acquisition tax asset.

 

During the year ended December 31, 2008, we used $202.2 million in investing activities. During the year ended December 31, 2008, we acquired BCH for a total net cash outlay of $53.7 million, consisting of the purchase price and acquisition costs less cash acquired. In addition we made capital expenditures of approximately $154.5 million during the year ended December 31, 2008, including $73.4 million to expand our drilling fleet and to purchase, improve and replace other equipment in our Drilling and Completion segment, $58.4 million to purchase and upgrade our equipment for our Oilfield Services segment and $22.6 million to increase our inventory of equipment and replace “lost-in-hole” equipment in the Rental Services segment. We received proceeds of $3.0 million from the sale of our drill pipe tong manufacturing assets. We also received $11.5 million from the sale of assets during the year ended December 31, 2008, comprised mostly from equipment “lost-in-hole” from our Rental Services segment ($8.3 million) and our Oilfield Services segment ($2.3 million). We also made net advance payments of $8.8 million on the purchase of new drilling and service rigs to be delivered in 2009 for our Drilling and Completion segment and advance payments of $1.1 million on the purchase of new directional drilling tools for our Oilfield Services segment.

 

During the year ended December 31, 2007, we used $137.1 million in investing activities consisting of four acquisitions and our capital expenditures. During the year ended December 31, 2007, we completed the following acquisitions for a total net cash outlay of $41.0 million, consisting of the purchase price and acquisition costs less cash acquired:

 

 

 

In addition we made capital expenditures of approximately $113.2 million during the year ended December 31, 2007, including $48.6 million to purchase and upgrade our equipment for our Oilfield Services segment, $34.9 million to increase our inventory of equipment and replace “lost-in-hole” equipment in the Rental Services segment and $28.9 million to purchase, improve and replace equipment in our Drilling and Completion segment. We received proceeds of $16.3 million from the sale of our capillary assets. We also received $12.8 million from the sale of assets during the year ended December 31, 2007, comprised mostly from equipment “lost-in-hole” from our Rental Services segment ($11.0 million) and our Oilfield Services segment ($1.4 million). We also made advance payments of $11.5 million on the purchase of new drilling and service rigs to be delivered in 2008 for our Drilling and Completion segment.

 

Financing Activities

 

During the year ended December 31, 2009, financing activities provided $42.7 million in cash. We raised $120.2 million net of expenses from the issuance of common and preferred stock, and borrowed $25.0 million under a loan facility to acquire two drilling rigs, offset in part by repayments of $64.8 million of long-term debt, a net repayment on our revolving credit facility of $36.5 million and $665,000 for preferred dividend payments. The repayments of long-term debt consisted of $46.4 million on the senior notes as a result of a tender offer and $18.4 million of scheduled debt repayment including a prepayment on our BCH loan facility. We also incurred $658,000 in debt issuance costs consisting of $528,000 on the revolving credit facility, primarily to modify our loan covenants, and $131,000 on the rig financing agreement. In addition, we financed our renewal of $3.2 million in insurance policy premiums in non-cash transactions.

 

During the year ended December 31, 2008, financing activities provided a net of $51.7 million in cash. We received $25.0 million of proceeds of long-term debt which was used to finance the expansion of our Drilling and Completion 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.

 

On January 18, 2006 and August 14, 2006, we closed on private offerings, to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, of $160.0 and $95.0 million aggregate principal amount of our senior notes, respectively. The senior notes are due January 15, 2014 and bear interest at 9.0%. The proceeds were used to fund the acquisitions of Specialty Rental Tools, Inc. and DLS, to repay existing debt and for general corporate purposes. On June 29, 2009, we closed on a tender offer in which we purchased $30.6 million aggregate principal of our 9.0% senior notes for a total consideration of $650 per $1,000 principal amount.

In January 2007, we closed on a private offering, to qualified institutional buyers pursuant to Rule 144A under the Securities Act, of $250.0 million principal amount of 8.5% senior notes due 2017. The proceeds of the senior notes offering, together with a portion of the proceeds of our concurrent common stock offering, were used to repay the debt outstanding under our $300.0 million bridge loan facility which we incurred to finance our acquisition of substantially all the assets of Oil & Gas Rental Services, Inc. On June 29, 2009, we closed on a tender offer in which we purchased $44.2 million aggregate principal of our 8.5% senior notes for a total consideration of $600 per $1,000 principal amount.

 

On January 18, 2006, we also executed an amended and restated credit agreement which provided for a $25.0 million revolving line of credit with a maturity of January 2010. On April 26, 2007, we entered into a Second Amended and Restated Credit Agreement, which increased our revolving line of credit to $62.0 million, and had a final maturity date of April 26, 2012. On December 3, 2007, we entered into a First Amendment to Second Amended and Restated Credit Agreement, which increased our revolving line of credit to $90.0 million. The amended and restated credit agreement contains customary events of default and financial covenants and limits our ability to incur additional indebtedness, make capital expenditures, pay dividends or make other distributions, create liens and sell assets. On April 9, 2009, we entered into a Third Amendment to our existing Second Amended and Restated Credit Agreement dated as of April 26, 2007 which modified the leverage and interest coverage ratio covenants of the Credit Agreement. In addition, permitted maximum capital expenditures were reduced to $85.0 million for 2009 compared to the previous limit of $120.0 million. Effective December 31, 2009, we amended the leverage and interest coverage ratio covenants of the Credit Agreement. This amendment relaxed the required financial ratios for the quarter ended December 31, 2009 and for each of the quarters in 2010. Our obligations under the amended and restated credit agreement are secured by substantially all of our assets located in the U.S. We were in compliance with all debt covenants as of December 31, 2009 and 2008. As of December 31, 2009, we had no borrowings under the facility except $4.2 million in outstanding letters of credit. At December 31, 2008 we had $36.5 million of borrowings outstanding and $5.8 million in outstanding letters of credit. The credit agreement loan rates are based on prime or LIBOR plus a margin. The weighted average interest rate was 4.6% at December 31, 2008.

 

As part of our acquisition of DLS, we assumed various bank loans with floating interest rates based on LIBOR plus a margin and terms ranging from 2 to 5 years. The weighted average interest rates on these loans was 2.1% and 5.1% as of December 31, 2009 and 2008, respectively. The bank loans are denominated in U.S. dollars and the outstanding amount due as of December 31, 2009 and 2008 was $1.1 million and $2.5 million, respectively.

 

On February 15, 2008, through our DLS subsidiary in Argentina, we entered into a $25.0 million import finance facility with a bank. Borrowings under this facility were used to fund a portion of the purchase price of the new drilling and service rigs ordered for our Drilling and Completion segment. The loan is repayable over four years in equal semi-annual installments beginning one year after each disbursement with the final principal payment due not later than March 15, 2013. The import finance facility is unsecured and contains customary events of default and financial covenants and limits DLS’ ability to incur additional indebtedness, make capital expenditures, create liens and sell assets. We were in compliance with all debt covenants as of December 31, 2009 and 2008. The bank loan rates are based on LIBOR plus a margin. The weighted average interest rate was 4.4% and 6.9% at December 31, 2009 and 2008, respectively. The bank loans are denominated in U.S. dollars and the outstanding amount as of December 31, 2009 and 2008 was $20.1 million and $25.0 million, respectively.

 

As part of our acquisition of BCH, we assumed a $23.6 million term loan credit facility with a bank. The credit agreement is dated June 2007 and contains customary events of default and financial covenants. Obligations under the facility are secured by substantially all of the BCH assets. The facility is repayable in quarterly principal installments plus interest with the final payment due not later than August 2012. We were in compliance with all debt covenants as of December 31, 2009 and 2008. The credit facility loan is denominated in U.S. dollars and interest rates are based on LIBOR plus a margin. At December 31, 2009 and 2008, the outstanding amount of the loan was $16.2 million and $22.1 million and the interest rate was 3.5% and 6.0%, respectively.

On May 22, 2009, we drew down $25.0 million on a new term loan credit facility with a lending institution. The facility was utilized to fund a portion of the purchase price of two new drilling rigs. The loan is secured by the equipment. The facility is repayable in quarterly installments of approximately $1.4 million of principal and interest and matures in May 2015. The loan bears interest at a fixed rate of 9.0%. At December 31, 2009, the outstanding amount of the loan was $23.4 million.

 

In connection with the acquisition of Rogers Oil Tools, Inc., we issued to the seller a note in the amount of $750,000. The note bore interest at 5.0% and was paid in full in April 2009 in accordance with its terms.

 

In 2000 we compensated directors who served on the board of directors from 1989 to March 31, 1999 without compensation, by issuing promissory notes totaling $325,000. The notes bear interest at the rate of 5.0%. As of December 31, 2009 and 2008, the principal and accrued interest on these notes totaled approximately $0 and $32,000, respectively.

 

In April 2008 and August 2008, we obtained insurance premium financings in the aggregate amount of $3.0 million with a fixed average weighted interest rate of 4.9%. Under terms of the agreements, amounts outstanding are paid over 10 and 11 month repayment schedules. The outstanding balance of these notes was approximately $0 and $991,000 at December 31, 2009 and 2008, respectively. In 2009, we obtained insurance premium financings in the aggregate amount of $3.2 million with a fixed average weighted interest rate of 4.8%. Under terms of the agreements, the amount outstanding is paid over 10 and 11 month repayment schedules. The outstanding balance of these notes was approximately $997,000 as of December 31, 2009.

 

As part of our acquisition of BCH, we assumed various capital leases with terms of two to three years. The outstanding balance under these capital leases was $254,000 and $779,000 at December 31, 2009 and 2008, respectively.

 

The following table summarizes our obligations and commitments to make future payments under our notes payable, operating leases, employment contracts and consulting agreements for the periods specified as of December 31, 2008.

 

 

 

 

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, oilfield services and drilling services to our customers at per day, or daywork, and per job contractual rates and recognize the drilling related revenue as the work progresses and when collectibility is reasonably assured. Revenue from daywork contracts is recognized when it is realized or realizable and earned. On daywork contracts, revenue is recognized based on the number of days completed at fixed rates stipulated by the contract. For certain contracts, we receive lump-sum and other fees for equipment and other mobilization costs. Mobilization fees and the related costs are deferred and amortized over the contract terms when material.

 

Impairment Of Long-Lived Assets.  Long-lived assets, principally property, plant and equipment, comprise a significant amount of our total assets. We make judgments and estimates in conjunction with the carrying value of these assets, including amounts to be capitalized, depreciation and amortization methods and useful lives. Additionally, the carrying values of these assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. This requires us to make long-term forecasts of our future revenues and costs related to the assets subject to review. These forecasts require assumptions about demand for our products and services, future market conditions and technological developments. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period.

 

Goodwill and Other Intangibles.  As of December 31, 2009 we have recorded approximately $40.6 million of goodwill and $32.6 million of other identifiable intangible assets. We perform purchase price allocations to intangible assets when we make a business combination. Business combinations and purchase price allocations have been consummated for acquisitions in all of our reportable segments. The excess of the purchase price after allocation of fair values to tangible assets is allocated to identifiable intangibles and thereafter to goodwill. We make judgments and estimates in conjunction with the carrying value of these assets, including amounts to be capitalized and whether the asset has a finite life for amortization purposes.

 

Our annual impairment tests involve the use of different valuation techniques, including the income approach and/or market approach, to determine the fair value of our reporting units. Determining the fair value of a reporting unit is a matter of judgment and often involves the use of significant estimates and assumptions. If the fair value of the reporting unit is less than its carrying value, an impairment loss is recorded to the extent that the implied fair value of the reporting unit’s goodwill is less than its carrying value. We recorded an impairment charge of $115.8 million in 2008 as a result of our test. At December 31, 2009 and 2007, no impairment was deeded necessary. Significant and unanticipated changes to these assumptions could require an additional provision for impairment in a future period.

 

Purchase Price Allocation of Acquired Businesses.  We allocate the purchase price of acquired businesses to the identifiable assets and liabilities of the businesses, post acquisition, based on estimated fair values. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. We engage third-party appraisal firms and valuation experts to assist in the determination of identifiable assets and liabilities. Our judgments and estimates for the allocation of purchase price are based on information available during the measurement period, these judgments and estimates can materially impact our financial position as well as our results of operations.

Income Taxes.  The determination and evaluation of our annual income tax provision involves the interpretation of tax laws in various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations and our level of operations or profitability in each jurisdiction may impact our tax liability in any given year. While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined. Current income tax expense (benefit) reflects an estimate of our income tax liability for the current year, withholding taxes, changes in tax rates and changes in prior year tax estimates as returns are filed. Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the enacted tax rates in effect at year end. A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized.

 

It is our intention to permanently reinvest all of the undistributed earnings of our non-U.S. subsidiaries in such subsidiaries. Accordingly, we have not provided for U.S. deferred taxes on the undistributed earnings of our non-U.S. subsidiaries. If a distribution is made to us from the undistributed earnings of these subsidiaries, we could be required to record additional taxes. Because we cannot predict when, if at all, we will make a distribution of these undistributed earnings, we are unable to make a determination of the amount of unrecognized deferred tax liability.

 

Recently Issued Accounting Standards

 

For a discussion of new accounting standards, see the applicable section in Note 1 to our Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

 

Off-Balance Sheet Arrangements

 

We have no off balance sheet arrangements, other than normal operating leases and employee contracts, that have or are likely to have a current or future material effect on our financial condition, changes in financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources. We have a $90.0 million revolving credit facility with a maturity of April 2012. At December 31, 2009, we had no borrowings on the facility, but availability is reduced by outstanding letters of credit of $4.2 million. We do not guarantee obligations of any unconsolidated entities.

 

 

We are exposed to market risk primarily from changes in interest rates and foreign currency exchange risks.

 

Interest Rate Risk

 

Fluctuations in the general level of interest rates on our current and future fixed and variable rate debt obligations expose us to market risk. We are vulnerable to significant fluctuations in interest rates on our variable rate debt and on any future refinancing of our fixed rate debt and on future debt.

 

At December 31, 2009 we were exposed to interest rate fluctuations on approximately $37.4 million of bank loans carrying variable interest rates. A hypothetical one hundred basis point increase in interest rates for these notes payable would increase our annual interest expense by approximately $374,000. Due to the uncertainty of fluctuations in interest rates and the specific actions that might be taken by us to mitigate the impact of such fluctuations and their possible effects, the foregoing sensitivity analysis assumes no changes in our financial structure.

 

We have also been subject to interest rate market risk for short-term invested cash and cash equivalents. The principal of such invested funds would not be subject to fluctuating value because of their highly liquid

short-term nature. As of December 31, 2009, we had approximately $24.0 million of short-term maturing investments.

 

Foreign Currency Exchange Rate Risk

 

We have designated the U.S. dollar as the functional currency for our operations in international locations as we contract with customers, purchase equipment and finance capital using the U.S. dollar. Local currency transaction gains and losses, arising from remeasurement of certain assets and liabilities denominated in local currency, are included in our consolidated statements of income. For the years ended December 31, 2009, 2008 and 2007, we had a net foreign exchange loss of $0.7 million, $1.2 million and $128,000, respectively relating to our Drilling and Completion operations. We also conduct international business through our Rental Services and Oilfield Services segments and to control the foreign exchange risk, we provide for payment in U.S. dollars.

 

INDEX TO FINANCIAL STATEMENTS

 

ALLIS-CHALMERS ENERGY INC. AND SUBSIDIARIES

 

 

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, 2009, based on criteria in Internal Control-Integrated Framework issued by the COSO. The effectiveness of Allis-Chalmers internal control over financial reporting as of December 31, 2009 has been audited by UHY LLP, an independent registered public accounting firm, as stated in their report, which is included herein.

 

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.

 

 

To the Board of Directors and Stockholders of

Allis-Chalmers Energy Inc.:

 

We have audited the accompanying consolidated balance sheets of Allis-Chalmers Energy Inc. and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the 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, 2009 and 2008, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Allis-Chalmers Energy Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 9, 2010 expressed an unqualified opinion thereon.

 

/s/ UHY LLP

 

Houston, Texas

March 9, 2010

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

The Board of Directors and Stockholders of

Allis-Chalmers Energy Inc.:

 

We have audited Allis-Chalmers Energy Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Allis-Chalmers Energy Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying 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 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, 2009, based on the COSO criteria.

 

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Allis-Chalmers Energy Inc. and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2009, and our report dated March 9, 2010 expressed an unqualified opinion thereon.

 

/s/ UHY LLP

 

Houston, Texas

March 9, 2010

 

 

The accompanying Notes are an integral part of the Consolidated Financial Statements.

 

 

The accompanying Notes are an integral part of the Consolidated Financial Statements.

 

 

The accompanying Notes are an integral part of the Consolidated Financial Statements.