Index to Financial Statements


Delaware		27-3321250
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

11125 EQUITY DRIVE, SUITE 200, HOUSTON, TEXAS		77041
(Address of principal executive offices)		(Zip code)

(713) 856-4222

Registrant’s telephone number, including area code

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: None

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ 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 ¨ 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 ¨

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 ¨ No ¨

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. ¨

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

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

The aggregate market value of the common equity held by non-affiliates of the registrant, computed using the closing price of the common stock of $2.06 per share on June 30, 2010, as reported on the New York Stock Exchange, was approximately $73,905,369.

As of March 1, 2011 there were 1,000 shares of common stock issued and outstanding.

Allis-Chalmers Energy Inc. meets the conditions set forth in general instruction I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.

TABLE OF CONTENTS


		Page
	PART I

Item 1.	Business	- 5 -
Item 1A.	Risk Factors	- 10 -
Item 1B.	Unresolved Staff Comments	- 19 -
Item 2.	Properties	- 20 -
Item 3.	Legal Proceedings	- 20 -
Item 4.	[Reserved]	- 22 -

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	- 22 -
Item 6.	Selected Financial Data	- 24 -
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	- 24 -
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	- 33 -
Item 8.	Financial Statements and Supplementary Data	- 34 -
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	- 72 -
Item 9A.	Controls and Procedures	- 72 -
Item 9B.	Other Information	- 73 -

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	- 73 -
Item 11.	Executive Compensation	- 73 -
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	- 73 -
Item 13.	Certain Relationships and Related Transactions, and Director Independence	- 73 -
Item 14.	Principal Accounting Fees and Services	- 73 -

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	- 74 -
	Signatures and Certifications	- 75 -

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DEFINITIONS



“blow out preventors”		A large safety device placed on the surface of an oil or natural gas well to maintain high pressure well bores.

“booster”		A machine that increases the pressure and/or volume of air when used in conjunction with a compressor or a group of compressors.

“capillary tubing”		A small diameter tubing installed in producing wells and through which chemicals are injected to enhance production and reduce corrosion and other problems.

“casing”		A pipe placed in a drilled well to secure the well bore and formation.

“choke manifolds”		An arrangement of pipes, valves and special valves on the rig floor that controls pressure during drilling by diverting pressure away from the blow-out preventors and the annulus of the well.

“coiled tubing”		A small diameter tubing used to service producing and problematic wells and to work in high pressure applications during drilling, production and workover operations.

“directional drilling”		The technique of drilling a well while varying the angle of direction of a well and changing the direction of a well to hit a specific target.

“double studded adapter”		A device that joins two dissimilar connections on certain equipment, including valves, piping and blow-out preventers.

“drill pipe”		A pipe that attaches to the drill bit to drill a well.

“foam unit”		A compressor, a booster, a mist pump and a fuel tank all mounted together on one flat bed trailer to be used for completion, workover and/or shallow drilling operations. Foam units are designed to provide a small footprint and easy transport.

“horizontal drilling”		The technique of drilling wells at a 90-degree angle.

“land drilling rig”		Composed of a drawworks or hoist, a derrick, a power plant, rotating equipment and pumps to circulate the drilling fluid and the drill string.

“measurement-while-drilling”		The technique used to measure direction and angle while drilling a well.

“mist pump”		A drilling pump that uses mist as the circulation medium for injecting small amounts of foaming agent, corrosion agent and other chemical solutions into the well.

“pulling rig”		A type of well-servicing rig used to pull downhole equipment, such as tubing, rods or the pumps from a well, and replace them when necessary. A pulling rig is also used to set downhole tools and perform lighter jobs.

“service rig”		A type of well-servicing rig which can function as either a workover or as a pulling rig.

“spacer spools”		High pressure connections or links which are stacked to elevate the blow out preventors to the drilling rig floor.

“spiral heavy weight drill pipe”		A heavy drill pipe used for special applications primarily in directional drilling. The “spiral” design increases flexibility and penetration of the pipe.

“straight-hole drilling”		The technique of drilling that allows very little or no vertical deviation.

“test plugs”		A device used to test the connections of well heads and the blow out preventors.

“tubing”		A pipe placed inside the casing to allow the well to produce.

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“tubing work strings”		The tubing used on workover rigs through which high pressure liquids, gases or mixtures are pumped into a well to perform production operations.

“underbalanced drilling”		A technique in which oil, natural gas, or geothermal wells are drilled by creating a pressure within the well that is lower than the reservoir pressure. The result is increased rate of penetration, reduced formation damage and reduced drilling costs.

“wear bushings”		A device placed inside a wellhead to protect the wellhead from wear.

“workover rigs”		Similar to a land drilling rig, however, they are smaller than the drilling rig for the same depth of well. These rigs are used to complete the drilled wells or to repair them whenever necessary.

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SPECIAL NOTE

REGARDING FORWARD-LOOKING STATEMENTS

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

•

the impact of the weak economic conditions and the future impact of such conditions on the oil and natural gas industry and demand for our services;

•

unexpected future capital expenditures (including the amount and nature thereof);

•

unexpected difficulties in integrating our operations as a result of any significant acquisitions;

•

adverse weather conditions in certain regions;

•

the impact of political disturbances, war, or terrorist attacks and changes in global trade policies;

•

the availability (or lack thereof) of capital to fund our business strategy and/or operations;

•

the potential impact of the loss of one or more key employees;

•

the effect of environmental liabilities that are not covered by an effective indemnity or insurance;

•

the impact of current and future laws;

•

the impact of customer defaults and related bad debt expense;

•

the potential impairment in the carrying value of goodwill and other acquired intangible assets;

•

the risks associated with doing business outside the United States, including currency exchange rates;

•

the effects of competition; and

•

the effects of our indebtedness, which could adversely restrict our ability to operate, could make us vulnerable to general adverse economic and industry conditions, could place us at a competitive disadvantage compared to competitors that have less debt, and could have other adverse consequences

Further information about the risks and uncertainties that may impact us are described in “Risk Factors” beginning on page - 10 - of this annual report. You should read those sections carefully. You should not place undue reliance on forward-looking statements, which speak only as of the date of this annual report. We undertake no obligation to update publicly any forward-looking statements in order to reflect any event or circumstance occurring after the date of this annual report or currently unknown facts or conditions or the occurrence of unanticipated events.

PART I

ITEM 1. BUSINESS

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

Our growth strategy is focused on identifying and pursuing opportunities in markets, products and services we believe will grow faster than the overall oilfield services industry and opportunities which we believe help us to mitigate cyclical risk by diversifying our cash flow, both domestically and internationally. Over the past several years, we have significantly expanded the geographic scope of our operations and the range of services we provide through strategic acquisitions and organic growth. Our organic growth has primarily been achieved by expanding our geographic scope, acquiring complementary property and equipment, hiring personnel to service new regions and cross-selling our products and services.

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Our History

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

In May 2001, under new management, we embarked on a new course of direction into the oilfield service industry. Since 2001, we have completed 25 acquisitions, including six in 2005, six in 2006, four in 2007, one in 2008 and one in 2010. Our first series of acquisitions became the backbone of our Oilfield Services segment. In May 2001, we entered the underbalanced drilling market and then in February of 2002 we entered the directional drilling business and the tubular services business. In December 2004, we entered the production services business. We have improved our product line offerings by completing additional acquisitions for all product lines. We also disposed of some nonstrategic assets in our production services business in June 2007 and in our tubular services business in August 2008.

In September 2004, we entered the Rental Services market which we subsequently expanded with acquisitions in April 2005 and January and December 2006. In July 2010, we acquired American Well Control, Inc., or AWC, as an expansion of our portfolio of services in our Rental Services segment. AWC is a leading manufacturer of premium high-pressure valves used in hydraulic fracturing in the unconventional gas shale plays. As a result of these acquisitions, we are now a major provider of oilfield rental tools primarily in the Gulf Coast region of the United States.

In August 2006, we entered the Drilling and Completion business with the acquisition of DLS Drilling, Logistics & Services Corporation, or DLS, in Argentina. Subsequently, in December 2008, we increased our business in this segment with the acquisition of BCH Ltd, or BCH, in Brazil.

On August 12, 2010, we entered into a merger agreement with Seawell Limited, or Seawell, and Wellco Sub Company, a wholly owned subsidiary of Seawell. On February 23, 2011, the merger transactions closed and we merged with and into Wellco Sub Company, becoming a wholly owned subsidiary of Seawell under the name “Allis-Chalmers Energy Inc.” Following the merger, Seawell and its subsidiaries, including us, have begun operating under the name Archer; however, our legal name will remain “Allis-Chalmers Energy Inc.” until further notice.

As a result of these transactions, our prior results may not be indicative of current or future operations. Segment and geographic financial information appears in “Item 8. Financial Information – Notes to Consolidated Financial Statements – Note 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 for most of 2008 was generally stable due to high oil and natural gas prices and the capital expenditures of the exploration and production companies. As a result, the number of active rigs drilling, or rig count in the United States, according to Baker Hughes, peaked at 2,031 in August of 2008. In the last quarter of 2008, the rig count in the United States began to drop due to the weakening United States economy, the decrease in oil and natural gas prices and the turmoil in the financial markets which affected the availability of capital for our customers. The Baker Hughes United States rig count decreased to 876 in June 2009 and then gradually began to improve in response to increased prices and more stable natural gas prices. As of March 4, 2011, the Baker Hughes United States rig count stood at 1,707.

Business Segments

We conduct our operations through three principal segments:

•

Oilfield Services. This segment includes the following oilfield service divisions: directional drilling services, casing and tubular services, underbalanced drilling services and production services.

•

Drilling and Completion. This segment includes drilling, completion, workover and related services.

•

Rental Services. This segment includes the rental of specialized oilfield equipment.

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

According to Baker Hughes, as of March 4, 2011, 71% of the active drilling rigs in the United States were drilling directionally and/or horizontally. We believe directional drilling offers several advantages over conventional drilling including: 1) improvement of total cumulative recoverable reserves; 2) improved reservoir production performance beyond conventional vertical wells; and 3) reduction of the number of field development wells.

We currently maintain an inventory of approximately 338 drilling motors which are utilized in our directional drilling services. Our straight-hole motors offer an opportunity to capture additional market share. We currently provide directional drilling services primarily in Texas, Wyoming, Pennsylvania, Louisiana and Oklahoma.

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

Underbalanced drilling shortens the time required to drill a well and enhances production by minimizing formation damage. We currently have a combined fleet of approximately 233 compressors, boosters and foam units which are utilized in our underbalanced services. We believe we are one of the largest providers of underbalanced drilling services in the United States. We also provide premium air hammers and bits to oil and natural gas companies for use in underbalanced drilling. Our broad and diversified product line enables us to compete in the underbalanced market with equipment and services packages engineered and customized to specifically meet customer requirements. We currently provide underbalanced drilling services primarily in Pennsylvania, Arkansas, West Virginia, New Mexico and Texas.

Our production services product line is focused on coiled tubing services and rental of various tools used in the production process. We currently provide production services primarily in Texas, Louisiana, West Virginia and Pennsylvania.

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

Our Drilling and Completion segment was established with the acquisition of DLS in August 2006 for a purchase price of approximately $114.5 million. We expanded our Drilling and Completion segment with the acquisition of BCH, which operates in Brazil. In 2008, we invested $40.0 million into BCH via a 15% convertible subordinated secured debenture and we acquired the common stock of BCH for a total purchase price of $56.1 million. We currently operate a fleet of 77 land rigs, including 18 drilling rigs and 48 service rigs (workover and pulling units) in Argentina, seven drilling rigs and one service rig in Brazil and three drilling rigs in Bolivia. In 2007, we placed orders for four drilling rigs and 16 service rigs. All of the service rigs and one of the drilling rigs were placed into service in Argentina at various dates in 2008. A second drilling rig was activated in Argentina in March 2009. The remaining two drilling rigs were sold to the manufacturer due to an operational problem and we realized a $10.6 million loss on the transaction in 2010. Additionally in 2008, we placed orders for two 1600 horsepower drilling rigs from a different manufacturer and both of those rigs were completed in the fourth quarter of 2010. One of those rigs was placed in service in Texas in January 2011, while the remaining rig has been awarded a two year contract in Argentina and it will be mobilized there.

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Rental Services. We provide specialized oilfield rental equipment, including premium drill pipe, spiral heavy weight drill pipe, tubing work strings, blow out 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, Pennsylvania, offshore in the Gulf of Mexico and internationally in Mexico, Columbia and Egypt.

Customers

In 2010, 2009 and 2008, one of our customers, Pan American Energy, or PAE, represented approximately 31.1%, 35.5% and 28.5% of our consolidated revenues, respectively. PAE is now wholly owned by Bridas Corporation, and Bridas Corporation is owned 50% by Bridas Energy Holdings Ltd and 50% by CNOOC International Limited. Alejandro P. Bulgheroni, one of the directors of our parent company, may be deemed to indirectly beneficially own 50% of the outstanding capital stock of Bridas Energy Holdings Ltd and is a member of the Management Committee of PAE. The loss without replacement of any of our larger existing customers could have a material adverse effect on our results of operations.

Suppliers

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

Competition

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

We believe that there are four major directional drilling companies, Schlumberger, Halliburton, Baker Hughes and Weatherford, that market worldwide, as well as numerous smaller regional players. Significant competitors in the tubular markets we serve include Frank’s Casing Crew and Rental Tools, Weatherford, Baker Hughes, Tesco and Premier. These markets remain highly competitive and fragmented with numerous casing and tubing crew companies working in the United States. Our primary competitors in Mexico are South American Enterprises and Weatherford, both of which provide similar products and services. Our largest competitor for underbalanced drilling services is Weatherford. Weatherford focuses on large projects, but also competes in the more common compressed air, mist, foam and aerated mud drilling applications. Other competition comes from smaller regional companies. In the production services market there are numerous competitors, most of which have larger coiled tubing services operations than us including Schlumberger, Halliburton, Baker Hughes, Weatherford and Premier.

Our five largest competitors in the Drilling and Completion segment, which operate primarily in Argentina, are Servicios WellTech, Ensign Energy Services, Nabors and Helmerich & Payne, and San Antonia Global Ltd in Brazil.

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

Backlog

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

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Employees

In general, we believe we have good relations with our employees. None of our employees, other than our Drilling and Completion employees, are represented by a union. We actively train employees across various functions, which we believe is crucial to motivate our workforce and maximize efficiency. Employees showing a higher level of skill are trained on more technologically complex equipment and given greater responsibility. All employees are responsible for on-going quality assurance. At March 1, 2011, we had approximately 3,750 employees. Almost all of our Drilling and Completion operations located in Argentina and Brazil are subject to collective bargaining agreements. We believe that we maintain a satisfactory relationship with the unions to which our Drilling and Completion employees belong.

Insurance

We carry a variety of insurance coverages for our operations, and we are partially self-insured for certain claims in amounts that we believe to be customary and reasonable. However, there is a risk that our insurance may not be sufficient to cover any particular loss or that insurance may not cover all losses. We are responsible for the first $250,000 of claims under our workers compensation policy and the first $100,000 of claims under our general liability and medical insurance policies. Insurance rates have in the past been subject to wide fluctuation and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions (See “Item 1A. Risk Factors – Risks Associated with Our Company”).

Seasonality

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

Federal Regulations and Environmental Matters

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

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

Intellectual Property Rights

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

Available Information

We have publicly traded, registered debt securities, which require us to file reports with the Securities and Exchange Commission, or SEC. All of our SEC filings, which include our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, or the Exchange Act, are made available free of charge on our web site at www.alchenergy.com as soon as reasonably practicable after we electronically file or furnish them to the SEC.

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

ITEM 1A. RISK FACTORS

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

Risks Associated With Our Industry

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

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

The Deepwater Horizon incident in the United States Gulf of Mexico and its consequences, including the potential enactment of further restrictions or regulations on offshore drilling, could have a material adverse effect on our business.

On October 12, 2010, the moratorium was lifted, and deepwater oil and natural gas drilling in the United States Gulf of Mexico has been allowed to resume, provided that operators certify compliance with all existing rules and requirements, including those that recently went into effect, and demonstrate the availability of adequate blowout containment resources. The first drilling permit was not issued until March 2011.

Our business has historically been very dependent on drilling activity in the United States Gulf of Mexico. Although the moratorium on oil and natural gas drilling in the United States Gulf of Mexico has been lifted, new guidelines, regulations and restrictions could increase the costs of exploration and production, reduce the area of operations and result in further permitting delays. These may include new or additional bonding and safety requirements and other requirements regarding certification of equipment. There is no assurance that operations related to drilling offshore in the United States will reach the same levels that existed prior to the moratorium. The delay in resuming these activities or the failure of these activities to reach levels that existed prior to the moratorium has and could continue to adversely impact our operating results. The enactment of stricter restrictions on offshore drilling or further regulation of offshore drilling or contracting services operations could materially affect our business, financial condition and results of operations.

Our industry is highly competitive, with intense price competition.

The markets in which we operate are highly competitive. Contracts are traditionally awarded on a competitive bid basis. Pricing is often the primary factor in determining which qualified contractor is awarded a job. The competitive environment has intensified as mergers among oil and natural gas companies have reduced the number of available customers. Many other oilfield services companies are larger than we are and have resources that are significantly greater than our resources. These competitors are better able to withstand industry downturns, compete on the basis of price and acquire new equipment and technologies, all of which could affect our revenues and profitability. These competitors compete with us both for customers and for acquisitions of other businesses. This competition may cause our business to suffer. We believe that competition for contracts will continue to be intense in the foreseeable future.

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Risks Associated With Our Company

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. 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:

•

economic conditions in the United States and elsewhere;

•

changes in global supply and demand for oil and natural gas;

•

the level of production of the Organization of Petroleum Exporting Countries, commonly called OPEC;

•

the level of production of non-OPEC countries;

•

the price and quantity of imports of foreign oil and natural gas;

•

political conditions, including embargoes, in or affecting other oil and natural gas producing activities;

•

the level of global oil and natural gas inventories;

•

advances in exploration, development and production technologies; and

•

the availability of capital for exploration and production companies.

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

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

Our customers are engaged in the oil and natural gas exploration business in the United States, Argentina, Brazil, Mexico and elsewhere. Historically, we have been dependent upon a few customers for a significant portion of our revenues. In 2010, 2009 and 2008, one of our customers, PAE represented 31.1%, 35.5% and 28.5% of our consolidated revenues, respectively. PAE also contributes a majority of the revenue derived from our Drilling and Completion operations. In 2010, 2009 and 2008, PAE represented 54.2%, 59.2% and 66.0% of our Drilling and Completion revenues, respectively.

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

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

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

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

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

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

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 manage our business, identify and consummate additional acquisitions and obtain and retain customers. We do not maintain key man insurance on any of our personnel.

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

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

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

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

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

Our Drilling and Completion business often has to make upgrade and refurbishment expenditures for its rig fleet to comply with our quality management and preventive maintenance system or contractual requirements or when repairs are required in response to an inspection by a governmental authority. We may also make significant expenditures when rigs are moved from one location to another. Additionally, we may make substantial expenditures for the construction of new rigs. Rig upgrade, refurbishment and construction projects are subject to the risks of delay or cost overruns inherent in any large construction project.

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

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:

•

curtailment of services;

•

weather-related damage to facilities and equipment resulting in suspension of operations;

•

inability to deliver materials to job sites in accordance with contract schedules; and

•

loss of productivity.

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

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

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

We reviewed goodwill at December 31, 2010 and 2009 and recorded no impairment but based on our review of goodwill at December 31, 2008 we recorded an impairment of $115.8 million, which was all of our goodwill for the Rental Services segment as well as the impairment of goodwill associated with our Tubular Services and Production Services businesses within our Oilfield Services segment. In the event that market conditions deteriorate or we have a prolonged downturn, we may be required to record an additional impairment of goodwill and such impairment could be material.

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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:

•

could harm our business and operating results,

•

cause investors to lose confidence in the accuracy and completeness of our financial reports,

•

have a material adverse effect on the trading price of our common stock or

•

adversely affect our ability to timely file our periodic reports with the SEC.

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

We do business in international jurisdictions whose political and regulatory environments and compliance regimes differ from those in the United States.

A significant amount of our revenue is attributable to operations in foreign countries. These activities accounted for approximately 59.2% of our consolidated revenue in the year ended December 31, 2010. Risks associated with our operations in foreign areas include, but are not limited to:

•

political instability, terrorist acts, war and civil disturbances;

•

changes in laws or policies regarding the award of contracts;

•

the inability to collect or repatriate currency, income, capital or assets;

•

expropriation of assets;

•

nationalization of components of the energy industry in the geographic areas where we operate;

•

foreign currency fluctuations and devaluation; and

•

new economic and tax policies.

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

We attempt to limit the risks of currency fluctuation and restrictions on currency repatriation where possible by obtaining contracts providing for payment of a percentage of the contract indexed to the United States dollar exchange rate. To the extent 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.

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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 United States dollar. We cannot predict how these uncertainties will affect our financial results, but there is a risk that our financial performance could be adversely affected. Moreover, we cannot predict whether the Argentine government will further modify its monetary policy and, if so, what effect any of these changes could have on the value of the Argentine Peso. Such changes could have an adverse effect on our financial condition and results of operations. Similar economic and political turmoil in Mexico and Brazil could also expose us to unpredictable currency exchange rates in these countries that may result in an adverse effect on our financial condition and results of operations.

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.

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Existing or future laws, regulations, treaties or international agreements related to greenhouse gases and climate change could have a negative impact on our business and may result in additional compliance obligations with respect to the release, capture, and use of carbon dioxide that could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

International, national, and state governments and agencies are currently evaluating and promulgating climate-related legislation and regulations that are focused on restricting greenhouse gas (“GHG”) emissions. In the United States, the Environmental Protection Agency (“EPA”) is taking steps to require monitoring and reporting of GHG emissions and to regulate GHGs as pollutants under the Clean Air Act (“CAA”). The EPA’s “Mandatory Reporting of Greenhouse Gases” rule established a comprehensive scheme of regulations that require monitoring and reporting of GHG emissions that began in 2010. Furthermore, the EPA recently proposed additional GHG reporting rules specifically for the oil and gas industry. The EPA has also published a final rule, the “Endangerment Finding,” finding that GHGs in the atmosphere endanger public health and welfare, and that emissions of GHGs from mobile sources cause or contribute to the GHG pollution. Following issuance of the Endangerment Finding, the EPA promulgated final motor vehicle GHG emission standards on April 1, 2010. The EPA has asserted that the final motor vehicle GHG emission standards will trigger construction and operating permit requirements for stationary sources. In addition, climate change legislation is pending in the United States Congress. These developments may curtail production and demand for fossil fuels such as oil and gas in areas of the world where our customers operate and thus adversely affect future demand for our services, which may in turn adversely affect future results of operations. Additionally, legislation to reduce greenhouse gases may have an adverse effect on our operations, including payment of additional costs due to carbon emissions. Higher carbon emission activities include transportation, including marine vessels, cement production (by third party suppliers), and electricity generation (by third party suppliers) as well as other activities. Finally, our business could be negatively affected by climate change related physical changes or changes in weather patterns, which could result in damages to or loss of our physical assets, impacts to our ability to conduct operations and/or disruption of our customers’ operations.

Legislation may be introduced in the United States Congress that would authorize the EPA to regulate hydraulic fracturing. In addition, a number of states are evaluating the adoption of legislation or regulations governing hydraulic fracturing. Such legislation or regulations could reduce demand for pressure pumping services. If federal and/or state legislation or regulations were enacted, it could adversely affect our financial condition, results of operations and cash flows. We are unable to predict whether the proposed legislation, regulations, or any other proposals will ultimately be enacted.

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

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

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

Since our reorganization under the United States federal bankruptcy laws in 1988, we have been regularly named in products liability lawsuits primarily resulting from the manufacture of products containing asbestos. In connection with our bankruptcy, a special products liability trust was established and funded to address products liability claims. This product liability trust is in the process of being dissolved. We believe that product liability claims relating to our business prior to bankruptcy are barred by applicable bankruptcy law. Since 1988, no court has ruled that we are responsible for products liability claims. However, if we are held responsible for product liability claims, we could suffer substantial losses that could have a material adverse effect on our financial condition and results of operations. We have not manufactured products containing asbestos since our reorganization in 1988.

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We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition and results of operations.

We provide services and equipment to oil and natural gas exploration and production companies. These operations are subject to inherent hazards that can cause personal injury or loss of life, damage to or destruction of property, equipment, the environment and marine life, and suspension of operations. Substantially all of our Drilling and Completion operations are subject to hazards that are customary for oil and natural gas drilling operations, including blowouts, reservoir damage, loss of well control, cratering, oil and gas well fires and explosions, natural disasters, pollution and mechanical failure. Any of these risks could result in damage to or destruction of drilling equipment, personal injury and property damage, suspension of operations or environmental damage.

We operate with our customers through Master Service Agreements, or MSAs. We endeavor to allocate potential liabilities and risks between the parties in the MSAs. Generally, our MSAs contain indemnification to us for liability for pollution or environmental claims arising from subsurface conditions or resulting from the drilling activities of our customers or their operators. We may have liability in such cases if we are grossly negligent or commit willful acts. In addition, any liability may be capped for either party to an MSA. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death, unless resulting from our gross negligence or willful misconduct. Similarly, we agree to indemnify our customers for liabilities arising from personal injury or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, our customers agree to indemnify us for loss or destruction of customer-owned property or equipment, and in turn, we agree to indemnify our customers for loss or destruction of property or equipment we own. However, for equipment we rent to our customers, our contracts generally provide that the customer is responsible for the replacement of any damaged or lost equipment in their care. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation or we might incur an unforeseen liability falling outside the scope of such allocation.

Litigation arising from an accident at a location where our products or services are used or provided may cause us to be named as a defendant in lawsuits asserting potentially large claims. We maintain customary insurance to protect our business against these potential losses. Our general liability policy would cover claims where we agreed to indemnify the customer, subject to any typical exclusions that may exist under the policy. However, we could become subject to material uninsured liabilities that could have a material adverse effect on our financial condition and results of operations. The limits and deductibles for our general liability policy are as follows:

•

General Aggregate $2,000,000;

•

Products/Completed Operations Aggregate $2,000,000;

•

Occurrence Limit $1,000,000;

•

Personal/Advertising Injury Limit $1,000,000;

•

Deductible (Bodily Injury & Property Damage Combined) Per Claim $100,000.

In addition, our general liability policy is scheduled under a $30.0 million umbrella/excess liability policy (subject to the policy’s terms, conditions and exclusions). We also have workers compensation insurance coverage up to $1,000,000.

We have a contractor’s pollution liability policy of $10.0 million which has a $200,000 deductible, and all environmental claims would be subject to the terms, conditions and exclusions of that policy. Our umbrella policy does not apply to the contractor’s pollution liability policy.

There is no assurance that such insurance or indemnification agreements will adequately protect us against liability from all of the consequences of the hazards and risks described above. The occurrence of an event not fully insured or for which we are not indemnified against, or the failure of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, there can be no assurance that insurance will continue to be available to cover any or all of these risks, or, even if available, that insurance premiums or other costs will not rise significantly in the future so as to make the cost of such insurance prohibitive.

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Risks Related to the Merger

We have and will continue to incur transaction costs in connection with the merger.

We have incurred, and expect to continue to incur, significant costs in connection with the merger, including the fees of our respective professional advisors. We will also incur integration and restructuring costs following the completion of the merger as our operations are integrated with Seawell’s operations. The efficiencies anticipated to arise from the merger may not be achieved in the near term or at all, and, if achieved, may not be sufficient to offset the costs associated with the merger. Unanticipated costs, or the failure to achieve expected efficiencies, may have an adverse impact on the results of operations of the combined company following the completion of the merger.

Following the merger, the combined company may be unable to successfully integrate our business into Archer’s business and realize the anticipated benefits of the merger.

The merger involves the combination of two companies that operated as independent public companies. The combined company will be required to devote management attention and resources to integrating its business practices and operations. Potential difficulties that the combined company may encounter in the integration process include the following:

•

the inability to successfully integrate our business into Seawell’s business in a manner that permits the combined company to achieve the cost savings and operating synergies anticipated to result from the merger, which would result in the anticipated benefits of the merger not being realized partly or wholly in the time frame currently anticipated or at all;

•

integrating personnel from the two companies while maintaining focus on providing consistent, high quality products and customer service;

•

potential unknown liabilities and unforeseen increased expenses, delays or regulatory conditions associated with the merger; and

•

performance shortfalls at one or both of the two companies as a result of the diversion of management’s attention caused by completing the merger and integrating the companies’ operations.

It is possible that the integration process could result in the diversion of management’s attention, the disruption or interruption of, or the loss of momentum in, our ongoing businesses or inconsistencies in standards, controls, procedures and policies, any of which could adversely affect our ability to maintain relationships with customers, suppliers and employees or our ability to achieve the anticipated benefits of the merger, or could reduce the earnings or otherwise adversely affect the business and financial results of the combined company.

Following the merger, the carrying value of our assets may differ significantly from the historical cost.

As part of the acquisition process, we are currently undergoing a purchase price valuation exercise to review the fair values of our assets. As part of this review, the book values of assets may differ materially once the exercise is concluded and the new values pushed down into our balance sheet. The accounting rules related to the valuation of assets acquired in a business combination are different from the reporting of historical results. We expect this exercise to be completed by June 30, 2011.

The failure of the lenders under Seawell’s undrawn credit facilities to perform could have a material adverse effect on our liquidity and results of operations. We are exposed to systemic risk of the financial markets and institutions and the risk of non-performance of the individual lenders under Seawell’s undrawn credit facilities.

Maintaining sufficient liquidity in our business for maintenance and operating expenditures, capital expenditures and collateral is crucial in order to mitigate the risk of future financial distress to us. Accordingly, Seawell maintains a revolving credit facility to manage its expected liquidity needs and contingencies. The failure of the lenders to perform under the Seawell revolving credit facility could have a material adverse effect on our results of operations. In the event that financial institutions are unwilling or unable to renew Seawell’s existing revolving credit facility or enter into new revolving credit facilities, our ability to hedge economically our assets could be impaired.

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Risks Associated With Our Indebtedness

We are an indirect wholly owned subsidiary of Seawell. Seawell can exercise substantial control over our business and operations and could do so in a manner that is adverse to our interests.

We are managed by officers and employees of Seawell. Our management will make determinations with respect to the following:

•

decisions on our financings and our capital raising activities;

•

mergers or other business combinations; and

•

our acquisition or disposition of assets.

We are a wholly owned subsidiary. As a result, we are dependent upon cash dividends, distributions or other transfers we receive from our parent to repay any debt we may incur, and to meet our other obligations. The ability of our parent to make payments to us will depend on their operating results and may be restricted by, among other things, applicable corporate, tax and other laws and regulations and agreements.

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

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

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

•

incur additional debt;

•

make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock;

•

sell assets, including capital stock of our restricted subsidiaries;

•

restrict dividends or other payments by restricted subsidiaries;

•

create liens;

•

enter into transactions with affiliates; and

•

merge or consolidate with another company.

If there were an event of default under any of the indentures, the affected creditors could cause all amounts borrowed under these instruments to be due and payable immediately.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 2. PROPERTIES

The following table describes the location and general character of the principal physical properties used in each of our company’s businesses as of March 1, 2011. Our principal executive office is rented and located in Houston, Texas and the table below presents all of our material operating locations and whether the property is owned or leased.


Business Segment	Location	Owned/Leased
Oilfield Services	Kensett, Arkansas	Leased
	Youngsville, Louisiana	Owned
	Carlsbad, New Mexico	Leased
	Farmington, New Mexico	Leased
	Elk City, Oklahoma	Leased
	McAlester, Oklahoma	Leased
	Mt Morris, Pennsylvania	Leased
	Muncy, Pennsylvania	Leased
	Conroe, Texas	Leased
	Corpus Christi, Texas	Leased – 2 locations
	Houston, Texas	Leased
	Kilgore, Texas	Leased
	Longview, Texas	Leased
Drilling and Completion	Buenos Aires, Argentina	Leased
	Comodoro Rivadavia, Argentina	Owned
	Neuquen, Argentina	Owned
	Pio Truncado, Santa Cruz, Argentina	Leased
	Rincon de los Sauces, Argentina	Owned
	Rio Grande, Tierra del Fuego, Argentina	Leased
	Tartagal, Argentina	Owned
	Santa Cruz, Bolivia	Leased
	Catu, Bahia, Brazil	Owned
	Aracuja, Sergipe, Brazil	Leased
	Macae, Rio de Janeiro, Brazil	Leased
	Parnamirim, Rio Grande de Norte, Brazil	Leased
	Rio de Janeiro, Rio de Janeiro, Brazil	Leased
Rental Services	Broussard, Louisiana	Leased
	Morgan City, Louisiana	Owned
	Muncy, Pennsylvania	Leased
	Conroe, Texas	Owned
	Victoria, Texas	Owned

ITEM 3. LEGAL PROCEEDINGS

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

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

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

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

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

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

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

Shortly following the announcement of the merger agreement, ten putative stockholder class-action petitions and compliants were filed against various combinations of us, members of our board of directors, Seawell, and Wellco. Seven of the lawsuits were filed in the District Court of Harris County, Texas, which we refer to as the Texas Actions, and three lawsuits were filed in the Court of Chancery of the State of Delaware, which we refer to as the Delaware Actions. These lawsuits challenge the proposed merger and generally allege, among other things, that our directors have breached their fiduciary duties owed to our public stockholders by approving the proposed merger and failing to take steps to maximize our value to our public stockholders, that we, Seawell, and Wellco aided and abetted such breaches of fiduciary duties, and that the merger agreement unreasonably dissuades potential suitors from making competing offers and restricts us from considering competing offers. The lawsuits generally seek, among other things, compensatory damages, attorneys’ and experts’ fees, declaratory and injunctive relief concerning the alleged breaches of fiduciary duties, and injunctive relief prohibiting the defendants from consummating the merger.

Various plaintiffs in the Texas Actions filed competing motions to consolidate the suits, to appoint their counsel as interim class counsel and to compel expedited discovery. On September 16, 2010, the defendants filed joint motions to stay the Texas Actions in favor of a first-filed Delaware lawsuit, and opposing the motions for expedited discovery. There is no hearing date set for these motions. The parties to the Texas State Court actions have agreed that the various defendants need not respond to the petitions until after lead counsel is appointed, a consolidated amended petition is filed and served or, alternatively, an active petition is designated by lead counsel.

On September 21, 2010, the plaintiffs in the Delaware Actions wrote the court seeking consolidation of the Delaware cases. Defendants did not oppose consolidation and took no position regarding lead plaintiff. On September 29, 2010, the Delaware court granted the motion to consolidate. Previously, on September 16, 2010, Seawell and Wellco answered the first-filed Girard Complaint, which is the operative complaint post-consolidation. We answered the consolidated complaint on October 4, 2010. On January 26, 2011, the plaintiffs in the Delaware Actions filed an amended complaint that included, among other claims, allegations that the disclosures made by Defendants concerning the merger are incomplete and misleading. Also on January 26, 2011, the plaintiffs in the Delaware Actions filed a motion to expedite proceedings for discovery and briefing and to set a date and time to hear their application for a preliminary injunction to enjoin the merger. Following a hearing, on February 3, 2011, the Delaware court denied plaintiffs’ motion.

We believe all of these lawsuits are without merit and intend to defend them vigorously.

We are involved in various other legal proceedings, including labor contract litigation, in the ordinary course of business. The legal proceedings are at different stages; however, we believe that the likelihood of material loss relating to any such legal proceedings is remote.

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ITEM 4. [RESERVED]

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

MARKET PRICE INFORMATION

On February 23, 2011, we merged with and into Wellco Sub Company, a wholly owned subsidiary of Seawell. Accordingly, there is no established public trading market for our common stock. Prior to the merger, our common stock was traded on the New York Stock Exchange under the symbol “ALY”. The following table sets forth high and low sale prices of our common stock reported on the New York Stock Exchange for 2010 and 2009.


Calendar Quarter	High		Low
2010
First Quarter	$	4.57	$	3.36
Second Quarter		4.28		2.00
Third Quarter		4.18		1.79
Fourth Quarter		7.17		4.16
2009
First Quarter	$	6.07	$	0.71
Second Quarter		4.53		1.80
Third Quarter		4.94		2.01
Fourth Quarter		4.87		3.06

Holder

There was one record holder of our common stock at March 1, 2011.

Dividends

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

EQUITY COMPENSATION PLAN INFORMATION

The following table provides information as of December 31, 2010 with respect to the shares of our common stock that may be issued under our equity compensation plans.


Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants And Rights		Weighted Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (excluding securities reflected in first column)

Equity compensation plans approved by security holders		2,683,101	$	4.74		4,342,286
Equity compensation plans not approved by security holders		—		—		—

Total		2,683,101	$	4.74		4,342,286

Equity Compensation Plans Not Approved By Security Holders

None

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PERFORMANCE GRAPH

Set forth below is a line graph comparing the annual percentage change in the cumulative return to the stockholders of our common stock with the cumulative return of the Russell 2000 and the CoreData Services Oil and Gas Equipment and Services Index for the last five years. Our common stock was a component of the Russell 2000 during the year ended December 31, 2010. The CoreData Services Oil and Gas Equipment and Services Index is an index of approximately 75 oil and gas equipment and services providers. The information contained in the performance graph shall not be deemed to be “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or Exchange Act, except to the extent that we specifically incorporate it by reference into such filing.

The graph assumes that $100 was invested on December 31, 2005 in our common stock and in each index, and that all dividends were reinvested. No dividends have been declared or paid on our common stock. Stockholder returns over the indicated period should not be considered indicative of future shareholder returns.

LOGO

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COMPARISON OF CUMULATIVE TOTAL RETURN OF ONE OR MORE

COMPANIES, PEER GROUPS, INDUSTRY INDEXES AND/OR BROAD MARKETS

FISCAL YEAR ENDING

COMPANY/INDEX/MARKET

12/31/2005

12/31/2006

12/30/2007

12/29/2008

12/31/2009

12/31/2010

Allis-Chalmers Energy Inc.

100.00

184.76

118.28

44.11

31.51

59.25

Russell 2000 Index

100.00

118.37

116.51

77.15

98.11

124.46

Oil & Gas Equipment/Svcs

100.00

120.81

174.92

70.98

116.10

158.33

ITEM 6. SELECTED FINANCIAL DATA.

Omitted pursuant to Instruction I of Form 10-K. (Omission of Information by Certain Wholly Owned Subsidiaries).

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Pursuant to General Instruction I of Form 10-K “Omission of Information by Certain Wholly-Owned Subsidiaries,” this section includes only management’s narrative analysis of the results of operations for the year ended December 31, 2010, the most recent fiscal year, compared with the year ended December 31, 2009, the fiscal year immediately preceding it.

The following discussion and analysis should be read in conjunction with our accompanying financial statements and the notes to those financial statements included elsewhere in this document. The following discussion contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that reflect our plans, estimates and beliefs. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of risks and uncertainties, including, but not limited to, those discussed under “Item 1A. Risk Factors.”

Overview of Our Business

We are a multi-faceted oilfield service company that provides services and equipment to oil and natural gas exploration and production companies, throughout the United States including Texas, Louisiana, Pennsylvania, Arkansas, West Virginia, Oklahoma, Colorado, offshore in the Gulf of Mexico and internationally primarily in Argentina, Brazil, Bolivia and Mexico. We operate in three sectors of the oil and natural gas service industry: Oilfield Services; Drilling and Completion and Rental Services.

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

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

Merger with Seawell

On February 23, 2011, we merged with and into Wellco Sub Company, a wholly owned subsidiary of Seawell, and each share of our common stock was converted into the right to receive either 1.15 Seawell common shares or $4.25 in cash. In connection with the merger, Wellco Sub Company changed its name to Allis-Chalmers Energy Inc.

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We recorded approximately $2.1 million of costs related to the merger during the year ended December 31, 2010, which are included in selling, general and administrative expense on our Consolidated Statements of Operations. Approval of the merger resulted in certain of our contractual obligations being triggered or accelerated under the “change of control” provisions of such contractual arrangements. Examples of such arrangements include stock-based compensation awards, severance and retirement plan agreements applicable to executive officers, directors and certain employees and certain other debt obligations, including our senior notes.

Company Outlook

Throughout the first half of 2009, we saw a significant decline in the global economy which led to reduced activity in the energy sector. This reduced activity in the energy sector resulted in lower demand for our services and we incurred significant losses. Since the second quarter of 2009, we have experienced quarter over quarter improvement in our total revenues which has resulted in reduced net losses.

On April 20, 2010, a fire and explosion occurred onboard the semisubmersible drilling rig Deepwater Horizon, which was owned by Transocean Ltd. and under contract to a subsidiary of BP plc. The accident resulted in the loss of life and a significant oil spill. In response to this incident, the Minerals Management Service of the United States Department of Interior, or the MMS, issued a notice on May 30, 2010 implementing a six-month moratorium on certain drilling activities in the United States Gulf of Mexico. The notice also stated that the MMS would not consider drilling permits for new wells and related activities for specified water depths during the six-month moratorium period. In addition, entities in the process of drilling wells covered by the moratorium were required to halt drilling and take steps to secure such wells. On October 12, 2010, the moratorium was lifted, and deepwater oil and natural gas drilling in the United States Gulf of Mexico has been allowed to resume, provided that operators certify compliance with all existing rules and requirements, including those that recently went into effect, and demonstrate the availability of adequate blowout containment resources. The first new permit was not issued until March 2011.

Although the moratorium on oil and natural gas drilling in the United States Gulf of Mexico has been lifted, new guidelines, regulations and restrictions could increase the costs of exploration and production, reduce the area of operations and result in permitting delays. These may include new or additional bonding and safety requirements, and other requirements regarding certification of equipment. The enactment of stricter restrictions on offshore drilling or further regulation of offshore drilling or contracting services operations could materially affect our business, financial condition and results of operations.

Results of Operations

In July 2010, we acquired all of the outstanding stock of AWC, which is reported as part of our Rental Services segment. We consolidated the results of this acquisition from the day it was acquired. The foregoing acquisition affects the comparability from period to period of our historical results, and our historical results may not be indicative of our future results.

Comparison of Years Ended December 31, 2010 and December 31, 2009

Our revenues for the year ended December 31, 2010 were $659.7 million, an increase of 30.3% compared to $506.3 million for the year ended December 31, 2009. Revenues increased in all three of our segments. Both our Oilfield Services and Rental Services segments have a strong concentration in the United States domestic oil and natural gas market. Due to the increased drilling activity in the United States, particularly in the natural gas shale plays, compared to 2009, we experienced significant improvement in both equipment utilization and pricing. This resulted in an increase in revenues of our Oilfield Services segment to $210.6 million for the year ended December 31, 2010 compared to revenues of $143.6 million for the year ended December 31, 2009. Our Rental Services segment had an increase in revenues to $70.9 million for the year ended December 31, 2010 compared to revenues of $58.7 million for the year ended December 31, 2009. The acquisition of AWC in July 2010 contributed $15.7 million of the increase in revenues for the Rental Services segment. The contribution in revenues by AWC and the increase in activity from the United States land shale plays were partially offset by the drilling moratorium in the Gulf of Mexico. The increase in revenues in our Drilling and Completion segment was due to higher rig utilization and pricing in our Argentina operations. The Drilling and Completion segment generated $378.2 million in revenues for the year ended December 31, 2010 compared to revenues of $304.0 million for the year ended December 31, 2009.

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Our direct costs for the year ended December 31, 2010 increased 31.3% to $498.1 million, or 75.5% of revenues, compared to $379.4 million, or 75.0%, of revenues for the year ended December 31, 2009. The increase in direct costs is consistent with the increase in revenues. Our Oilfield Services segment direct costs for the year ended December 31, 2010 increased $35.0 million, or 31.4%, from direct costs for the year ended December 31, 2009, while the revenues increased 46.7% over that same period, resulting in an improved gross margin of 30.4% for 2010 compared to 22.3% for 2009. In addition, our Oilfield Services segment had $1.2 million of expenses recorded during the year ended December 31, 2009 related to severance payments, the closing of unprofitable locations and downsizing other locations. Direct costs in our Drilling and Completion segment increased $74.4 million, or 30.2%, for the year ended December 31, 2010 compared to the year ended December 31, 2009, while the revenues increased 24.4% over that same period, resulting in a reduction of gross margin to 15.1% for 2010 compared to 18.8% in 2009. This unfavorable variance is primarily attributed to labor and other cost increases due to the inflationary environment in Argentina and decreased utilization and pricing for our rigs in Brazil. Our Rental Services segment direct costs for the year ended December 31, 2010 increased $9.3 million, or 43.9%, from direct costs for the year ended December 31, 2009, while the revenues increased 20.7% over that same period, resulting in a reduction of gross margin to 57.0% in 2010 compared to 63.9% in 2009. The AWC acquisition in July 2010 contributed $15.7 million in revenues and $9.5 million in direct costs to the Rental Services segment for the year ended December 31, 2010 for an effective gross margin as a percentage of revenues of 39.5%. The lower margin manufacturing operation of AWC is the primary reason that the gross margin percentage in the Rental Services segment declined for the year ended December 31, 2010 compared to the year ended December 31, 2009.

Depreciation expense increased 7.5% to $84.1 million for the year ended December 31, 2010 from $78.3 million for the year ended December 31, 2009. The primary increase in depreciation expense is due to our on-going investment in equipment to serve our customer base.

Selling, general and administrative expense was $60.4 million for the year ended December 31, 2010 compared to $50.8 million for the year ended December 31, 2009. Selling, general and administrative expense increased primarily due to bonuses, the amortization of share-based compensation arrangements and merger related transaction costs, partially offset by reduced bad debt provision. Bonus expense for the year ended December 31, 2010 was $6.9 million compared to $1.3 million for the prior year due to the improved operating results for 2010 compared to 2009. Selling, general and administrative expense includes share-based compensation expense of $8.0 million in 2010 and $4.8 million in 2009. Transaction costs related to the merger with Seawell were $2.1 million and included our fairness opinion and other professional fees. Our bad debt expense for the year ended December 31, 2010 was $368,000 compared to $2.8 million for the year ended December 31, 2009 and is a reflection of the improved market conditions in the United States oilfield industry. As a percentage of revenues, selling, general and administrative expenses were 9.2% in 2010 compared to 10.0% in 2009.

During the year ended December 31, 2010, we recorded a $10.6 million loss on the sale of two drilling rigs that we had constructed in 2008 which we were never able to operate on a reliable basis. We received $25.0 million for the rigs, but our costs related to the rig were $35.2 million. In addition, we incurred a $311,000 early repayment fee and wrote off deferred financing costs of $115,000 related to the underlying debt to those two rigs. During the year ended December 31, 2009, we recorded a $1.6 million loss on an asset disposition from the total loss of a rig from a blow-out in our Drilling and Completion segment. The insurance proceeds for the loss were not sufficient to cover the book value of the rig and related assets.

Amortization expense was $4.8 million for the year ended December 31, 2010 compared to $4.7 million for the year ended December 31, 2009. The increase was primarily attributable to intangible assets associated with our acquisition of AWC in July 2010.

Our income from operations for the year ended December 31, 2010 totaled $1.6 million, compared to an $8.5 million loss for the year ended December 31, 2009, for an improvement of $10.1 million. The improvement is primarily related to increased revenues in all our segments, partially offset by higher selling, general and administrative costs, the increased loss on asset dispositions and increased depreciation and amortization expense for the year ended December 31, 2010 compared to year ended December 31, 2009.

Our interest expense was $45.8 million for the year ended December 31, 2010, compared to $48.1 million for the year ended December 31, 2009. On June 29, 2009 we purchased $74.8 million of our senior notes with proceeds from our $125.6 million in equity issuances on that same date. We also prepaid the then $35.0 million outstanding loan balance under our revolving credit facility on June 29, 2009 from those same equity proceeds. Our outstanding balance under our revolving credit facility was $36.5 million at December 31, 2010 compared to no borrowings at December 31, 2009. In November 2010, we repaid the outstanding balance of $20.8 million term loan on the two rigs that were sold in 2010. Interest expense includes amortization expense of debt issuance costs of $2.2 million for both of the years ended December 31, 2010 and 2009.

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Our interest income was $537,000 for the year ended December 31, 2010, compared to $72,000 for the year ended December 31, 2009. We received $405,000 of interest income related to a receivable that was collected through bankruptcy proceedings in 2010.

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

Our benefit for income taxes for the year ended December 31, 2010 was $7.4 million, or 15.8% of our net loss before income taxes, compared to an income tax benefit of $9.9 million, or 31.8% of our net loss before income taxes for 2009. Our effective tax rate in the United States was 29.4% in 2010 compared to 35.5% in 2009, while our effective tax rate for international activities increased to 85.6% in 2010 compared to 44.4% in 2009. The decrease in the United States tax rate was primarily attributable to higher nondeductible items during the 2010 year including transaction costs and meals and entertainment. The increase in the international tax rate is primarily due to our BCH operations which generate a loss in Brazil but incurs a withholding tax on its revenues which is reported as an income tax.

We had a net loss of $39.5 million for the year ended December 31, 2010, compared to a net loss of $21.2 million for the year ended December 31, 2009. The net loss for the year ended December 31, 2010 included the $10.6 million loss on the sale of two rigs, while the net loss in 2009 includes the $26.4 million gain as a result of the senior notes tender offer.

The net loss attributed to common stockholders for the years ended December 31, 2010 and 2009 was $42.1 million and $22.5 million, respectively, after $2.5 million and $1.3 million in preferred stock dividends, respectively. The preferred stock dividend relates to 36,393 shares of $1,000 par value preferred shares at 7.0%.

The following table compares revenues and income (loss) from operations for each of our business segments for the years ended December 31, 2010 and December 31, 2009. Income (loss) from operations consists of our revenues and the gain (loss) on asset dispositions less direct costs, general and administrative expenses, depreciation and amortization:


	Revenues						Income (Loss) from Operations
	2010		2009		Change		2010			2009			Change
	(In thousands)
Oilfield Services	$	210,617	$	143,564	$	67,053	$	15,393		$	(14,691	)	$	30,084
Drilling & Completion		378,154		303,975		74,179		4,369			19,222			(14,853	)
Rental Services		70,894		58,714		12,180		4,115			140			3,975
General Corporate		—		—		—		(22,314	)		(13,218	)		(9,096	)

Total	$	659,665	$	506,253	$	153,412	$	1,563		$	(8,547	)	$	10,110

Oilfield Services. Revenues for the year ended December 31, 2010 for our Oilfield Services segment were $210.6 million, an increase of 46.7% from the $143.6 million in revenues for the year ended December 31, 2009. Income from operations for our Oilfield Services segment increased $30.1 million and resulted in an income from operations of $15.4 million for the year ended December 31, 2010 compared to loss from operations of $14.7 million for the year ended December 31, 2009. Our Oilfield Services segment revenues and operating income for the year ended December 31, 2010 increased compared to the year ended December 31, 2009 due to improved market conditions that resulted in increased demand and pricing for our services. During the year ended December 31, 2009, we incurred $1.2 million of costs related to severance payments, the closing of unprofitable locations and downsizing other locations in our Oilfield Services segment.

Drilling and Completion. Our Drilling and Completion revenues were $378.2 million for the year ended December 31, 2010, an increase of 24.4% from the $304.0 million in revenues for the year ended December 31, 2009. Our Drilling and Completion revenues increased in 2010 primarily due to increased activity in Argentina. Income from operations decreased to $4.4 million in 2010 compared to $19.2 million for the year ended December 31, 2009. Income from operations as percentage of revenue decreased to 1.2% for 2010 compared to 6.3% for 2009. This reduction was due to: (1) a $10.6 million loss on the disposition of two drilling rigs manufactured in 2008 that never achieved acceptable performance; (2) increased labor and other costs in Argentina during the year ended December 31, 2010; (3) an increase of $4.1 million, or 18.4%, in depreciation and amortization in the year ended December 31, 2010; and (4) reduced rig utilization and rig rates in Brazil during the year ended December 31, 2010 compared to the prior year. Results for the Drilling and Completion segment in 2010 were also impacted by a high incidence of labor strikes in Argentina during the year. Operating income in 2009 was impacted by (1) a $1.6 million non-cash loss recorded in the year ended December 31, 2009 on a rig destroyed in a blow-out; (2) $1.7 million of severance costs during the year ended December 31, 2009 related to workforce reductions in Argentina as a result of lower activity and (3) $329,000 of costs incurred to consolidate operating locations in Brazil during the year ended December 31, 2009. The increase in depreciation and amortization expense was the result of our continual upgrade to our equipment.

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Rental Services. Our Rental Services revenues were $70.9 million for the year ended December 31, 2010, an increase of 20.7% from the $58.7 million in revenues for the year ended December 31, 2009. Income from operations for our Rental Services segment increased to $4.1 million for the year ended December 31, 2010 compared to $140,000 for the year ended December 31, 2009. Our Rental Services segment revenues and operating income for the year ended December 31, 2010 increased compared to the prior year due primarily to the acquisition of AWC. AWC generated $15.7 million of revenues and $5.3 million of operating income from its acquisition in July 2010 through December 31, 2010. Our Rental Services segment was negatively impacted by the moratorium in the Gulf of Mexico resulting from the Deepwater Horizon incident, partially offset by increased pricing and utilization of certain equipment as a result of our focus on the land shale drilling activity. We had no bad debt expense recorded in our Rental Services segment for the year ended December 31, 2010 compared to $1.5 million for the year ended December 31, 2009.

General Corporate. General corporate expenses increased $9.1 million to $22.3 million for the year ended December 31, 2010 compared to $13.2 million for the year ended December 31, 2009. The increase was primarily due to the increase in share-based compensation expense, bonus expense and transaction costs related to the merger with Seawell. Share-based compensation expense included in general corporate was $6.7 million for the year ended December 31, 2010 compared to $3.7 million for the year ended December 31, 2009, with the increase primarily attributed to accelerated vesting on restricted stock in connection with the then pending merger with Seawell. Bonus expense for the year ended December 31, 2010 was $6.4 million higher than the previous year due to a new bonus plan adopted in 2010 and the achievement of certain performance goals for 2010. We incurred $2.1 million of costs related to the Seawell merger during the year ended December 31, 2010.

Liquidity and Capital Resources

Our on-going capital requirements arise primarily from our need to service our debt, to acquire and maintain equipment, to fund our working capital requirements and to complete acquisitions. In the past, our primary source of liquidity were the proceeds from the issuance of debt and equity securities and cash flows from operations. At the completion of the merger our revolving credit facility was repaid and cancelled and future funds will be provided by operating cash flow or advances from our parent company.

Operating Activities

In the year ended December 31, 2010, we generated $54.9 million in cash from operating activities. Our net loss for the year ended December 31, 2010 was $39.5 million. Non-cash additions to the net loss totaled $96.0 million in the 2010 period consisting primarily of $88.9 million of depreciation and amortization, $10.6 million related to loss on disposition of two drilling rigs, $8.0 million related to the expensing of stock options, $2.2 million of amortization and write-off of deferred financing fees, $1.5 million from the loss on the sale of an investment in an exploration and production company, $0.8 million from losses incurred by a joint venture operating in Saudi Arabia and $0.7 million of losses from the disposition of equipment, partially offset by $17.1 million in deferred income taxes.

During the year ended December 31, 2010, changes in working capital used $1.6 million in cash. Cash was provided by decreases in prepaid expenses and other of $11.1 million and $1.7 million in other assets, increases in trade payables of $11.1 million, $7.4 million in accrued expense and $9.9 million in accrued salaries, benefits and payroll taxes, this was offset by cash used by increases in accounts receivable of $35.7 million and $6.0 million in inventories, and a decrease of $0.9 million in other liabilities. Our accounts receivables increased at December 31, 2010 primarily due to the increase in our revenues in 2010. Inventories increased at December 31, 2010 primarily due to the acquisition of AWC which had $3.0 million of manufacturing related inventory at December 31, 2010 and also due to an increase in activity. Prepaid expenses and other current assets decreased primarily due to tax prepayments in Argentina being utilized to cover current period income taxes and due to the amortization of insurance premiums that were financed. The decrease in other assets relates to recurring amortization of deferred mobilization costs as well as amortization on oil and gas investments. Our accounts payable and accrued expenses increased primarily due to the increase in costs due to our increase in activity. Approximately $5.0 million of the increase in accrued salaries, benefits and payroll taxes relates to yearend bonus accruals at December 31, 2010 and the rest of the increase relates to general timing differences on when payroll is paid.

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

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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.

Investing Activities

During the year ended December 31, 2010, we used $67.7 million in investing activities, consisting of $102.2 million for capital expenditures, $15.9 million for the acquisition of AWC, offset by a decrease of $18.3 million in deposits on asset commitments, $6.6 million of proceeds from equipment sales and $25.0 million in proceeds from the sale of two drilling rig manufactured in 2008. Included in the $102.2 million for capital expenditures was $26.6 million for our Oilfield Services segment, $38.4 million for two domestic drilling rigs and $21.8 million for additional equipment in our Drilling and Completion segment and $14.6 million for drill pipe and other equipment used in our Rental Services segment. We acquired AWC for a cash payment of $17.2 million directly to the seller and 1.0 million shares of our common stock at a value of $2.0 million. The acquired assets of AWC included $1.2 million in cash. The decrease in deposits on asset commitments was primarily due to the completion of all drilling rigs under construction by December 31, 2010. We also received $6.6 million from the sale of assets during the year ended December 31, 2010, comprised mostly from equipment “lost-in-hole” from our Rental Services segment ($4.0 million) and our Oilfield Services segment ($1.8 million).

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

Financing Activities

During the year ended December 31, 2010, financing activities used $7.3 million in cash. We borrowed a net of $36.5 million under our revolving credit facility and an additional $4.0 million under a term loan facility. We repaid $42.2 million of long-term debt, including a $20.8 million repayment of the rig financing term loan from the proceeds of the two rigs sold in November 2010. We also paid $2.5 million in preferred dividends during the year ended December 31, 2010. We incurred $189,000 in debt issuance costs on the revolving credit facility, primarily to modify our loan covenants. As the result of net exercises of restricted grant vesting, we had a net cash outlay of $1.7 million related to the payment of payroll taxes on those exercises. We recorded an income tax impact of $1.2 million as a result of the expense recorded on restricted stock grants exceeding the actual tax deduction generated by those awards. In addition, we financed our renewal of $2.9 million in insurance policy premiums in non-cash transactions.

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

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

In January 2007, we closed on a private offering, to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, of $250.0 million principal amount of 8.5% senior notes due 2017. The proceeds of the senior notes offering, together with a portion of the proceeds of our concurrent common stock offering, were used to repay the debt outstanding under our $300.0 million bridge loan facility which we incurred to finance our acquisition of substantially all the assets of Oil & Gas Rental Services, Inc. On June 29, 2009, we closed on a tender offer in which we purchased $44.2 million aggregate principal of our 8.5% senior notes for a total consideration of $600 per $1,000 principal amount.

We had a $90.0 million revolving line of credit with a final maturity date of April 26, 2012 pursuant to a revolving credit agreement that contains customary events of default and financial covenants and limits our ability to incur additional indebtedness, make capital expenditures, pay dividends or make other distributions, create liens and sell assets. On April 9, 2009, we amended our revolving credit agreement to modify the leverage and interest coverage ratio covenants. Effective December 31, 2009, we again amended the leverage and interest coverage ratio covenants of the revolving credit agreement. This amendment relaxed the required financial ratios for the quarter ended December 31, 2009 and for each of the quarters in 2010. Our obligations under the amended and restated credit agreement were secured by substantially all of our assets located in the United States. We were in compliance with all debt covenants as of December 31, 2010 and December 31, 2009. As of December 31, 2010, we had $36.5 million of borrowings outstanding and $4.1 million in outstanding letters of credit under our revolving credit facility. As of December 31, 2009, the only usage of our revolving credit facility consisted of $4.2 million in outstanding letters of credit. The interest rate under our revolving credit facility was based on prime or LIBOR plus a margin. The weighted-average interest rate was 7.8% at December 31, 2010. In connection with merger with Seawell, this facility was repaid and cancelled.

As part of our acquisition of DLS, we assumed various bank loans with floating interest rates based on LIBOR plus a margin and terms ranging from 2 to 5 years. The weighted average interest rates on these loans was 2.0% and 2.1% as of December 31, 2010 and 2009, respectively. The outstanding amount due under these bank loans as of December 31, 2010 and 2009 was $350,000 and $1.1 million, respectively.

On February 15, 2008, through our DLS subsidiary in Argentina, we entered into a $25.0 million import finance facility with a bank. Borrowings under this facility were used to fund a portion of the purchase price of the new drilling and service rigs ordered for our Drilling and Completion segment. The loan is repayable over four years in equal semi-annual installments beginning one year after each disbursement with the final principal payment due not later than March 15, 2013. The import finance facility is unsecured and contains customary events of default and financial covenants and limits DLS’ ability to incur additional indebtedness, make capital expenditures, create liens and sell assets. We were in compliance with all debt covenants as of December 31, 2010 and 2009. The bank loan rates are based on LIBOR plus a margin. The weighted average interest rate was 4.2% and 4.4% at December 31, 2010 and 2009, respectively. The outstanding amount under the import finance facility as of December 31, 2010 and 2009 was $14.4 million and $20.1 million, respectively.

As part of our acquisition of BCH, we assumed a $23.6 million term loan credit facility with a bank. The credit agreement was dated June 2007 and contains customary events of default and financial covenants which were based on BCH’s stand-alone financial statements. Obligations under the facility were secured by substantially all of the BCH assets. BCH was in compliance with all debt covenants as of December 31, 2009. The bank waived certain financial ratio covenants for the September 30, 2010 and December 31, 2010 measurement periods. As we could not be certain that BCH would attain compliance with the covenants within one year, we have classified the entire outstanding balance of the loan in the current portion of long-term debt as of December 31, 2010. The facility was repayable in quarterly principal installments plus interest with the final payment due not later than August 2012. The interest rates were based on LIBOR plus a margin. At December 31, 2010 and 2009, the outstanding amount of the loan was $7.0 million and $16.2 million and the interest rate was 3.5%. At the time of the merger, this facility was prepaid.

On May 22, 2009, we drew down $25.0 million on a new term loan credit facility with a lending institution. The facility was utilized to fund a portion of the purchase price of two new drilling rigs. The loan was secured by the equipment and was repaid in November 2010 when the equipment was sold to the manufacturer. The facility was repayable in quarterly installments of approximately $1.4 million of principal and interest and was to mature in May 2015. The loan bore interest at a fixed rate of 9.0%. At December 31, 2009, the outstanding amount of the loan was $23.4 million.

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On February 9, 2010, through our DLS subsidiary, we entered into a $4.0 million term loan facility. The loan is repayable in semi-annual installments beginning April 14, 2011 and bears interest at 8.5% per annum. The final maturity date is April 14, 2014 and the loan is unsecured.

In 2010, we obtained insurance premium financings in the aggregate amount of $2.9 million with a fixed weighted-average interest rate of 4.8%. Under terms of the agreements, amounts outstanding are paid over eight and 11 month repayment schedules. The outstanding balance of these notes was approximately $1.0 million at December 31, 2010. In 2009, we obtained insurance premium financings in the aggregate amount of $3.2 million with a fixed weighted-average interest rate of 4.8%. Under terms of these agreements, amounts outstanding are paid over 10 and 11 month repayment schedules. The outstanding balance of these notes was approximately $0 and $997,000 at December 31, 2010 and 2009, respectively.

As part of our acquisition of BCH, we assumed various capital leases with terms of two to three years. The outstanding balance under these capital leases was $0 and $254,000 at December 31, 2010 and 2009, respectively.

The following table summarizes our obligations and commitments to make future payments under our notes payable, operating leases, employment contracts and consulting agreements for the periods specified as of December 31, 2010.


	Payments by Period
	Total		Less Than 1 Year		1-3 Years		3-5 Years		After 5 Years
	(In thousands)
Contractual Obligations
Long-term debt	$	493,440	$	15,215	$	10,907	$	261,518	$	205,800
Interest payments on long-term debt		174,492		41,450		76,896		35,786		20,360
Operating leases		11,218		3,376		4,095		2,026		1,721
Purchase obligations		21,045		21,045		—		—		—
Employment contracts		2,846		1,915		931		—		—

Total contractual cash obligations	$	703,041	$	83,001	$	92,829	$	299,330	$	227,881

Critical Accounting Policies

We have identified the policies below as critical to our business operations and the understanding of our results of operations. The impact and any associated risks related to these policies on our business operations is discussed throughout 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.

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

Goodwill and Other Intangibles. As of December 31, 2010 we have recorded approximately $46.3 million of goodwill and $33.9 million of other identifiable intangible assets. We perform purchase price allocations to intangible assets when we make a business combination. Business combinations and purchase price allocations have been consummated for acquisitions in all of our reportable segments. The excess of the purchase price after allocation of fair values to tangible assets is allocated to identifiable intangibles and thereafter to goodwill. We make judgments and estimates in conjunction with the carrying value of these assets, including amounts to be capitalized and whether the asset has a finite life for amortization purposes.

Our annual impairment tests involve the use of different valuation techniques, including the income approach and/or market approach, to determine the fair value of our reporting units. Determining the fair value of a reporting unit is a matter of judgment and often involves the use of significant estimates and assumptions. If the fair value of the reporting unit is less than its carrying value, an impairment loss is recorded to the extent that the implied fair value of the reporting 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, 2010 and 2009, no impairment was deeded necessary. Significant and unanticipated changes to these assumptions could require an additional provision for impairment in a future period.

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

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

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

Recently Issued Accounting Standards

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

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Off-Balance Sheet Arrangements

We have no off balance sheet arrangements, other than normal operating leases and employee contracts, that have or are likely to have a current or future material effect on our financial condition, changes in financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources. We have a $90.0 million revolving credit facility with a maturity of April 2012. At December 31, 2010, we had $36.5 million of borrowings on the facility, and availability is reduced by outstanding letters of credit of $4.1 million. We do not guarantee obligations of any unconsolidated entities.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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

Interest Rate Risk

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

At December 31, 2010 we were exposed to interest rate fluctuations on approximately $58.2 million of bank loans carrying variable interest rates. A hypothetical one hundred basis point increase in interest rates for these notes payable would increase our annual interest expense by approximately $582,000. Due to the uncertainty of fluctuations in interest rates and the specific actions that might be taken by us to mitigate the impact of such fluctuations and their possible effects, the foregoing sensitivity analysis assumes no changes in our financial structure.

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

Foreign Currency Exchange Rate Risk

We have designated the United States dollar as the functional currency for our operations in international locations as we contract with customers, purchase equipment and finance capital using the United States dollar. Local currency transaction gains and losses, arising from remeasurement of certain assets and liabilities denominated in local currency, are included in our consolidated statements of income. For the years ended December 31, 2010, 2009 and 2008, we had a net foreign exchange loss of $0.5 million, $0.7 million and $1.2 million, respectively relating to our Drilling and Completion operations. We also conduct international business through our Rental Services and Oilfield Services segments and to control the foreign exchange risk, we provide for payment in United States dollars.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

ALLIS-CHALMERS ENERGY INC. AND SUBSIDIARIES


	Page

Management’s Report to the Stockholders of Allis-Chalmers Energy Inc.		35

Reports of Independent Registered Public Accounting Firm		36

Consolidated Balance Sheets		38

Consolidated Statements of Operations		39

Consolidated Statement of Stockholders’ Equity		40

Consolidated Statements of Cash Flows		41

Notes to Consolidated Financial Statements		42

Supplemental Information to Consolidated Financial Statements—Summarized Quarterly Financial Data		71

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MANAGEMENT’S REPORT TO THE STOCKHOLDERS OF ALLIS-CHALMERS ENERGY INC.

Management’s Report on Internal Control Over Financial Reporting

As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for Allis-Chalmers Energy Inc. and its subsidiaries, or Allis-Chalmers. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing, using the criteria in Internal Control-Integral Framework issued by the Committee of Sponsoring Organization of the Treadway Commission (COSO). Allis-Chalmers’ system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitation, internal control over financial reporting may not prevent or detect misstatements.

Based on our assessment, we have concluded that Allis-Chalmers maintained effective internal control over financial reporting as of December 31, 2010, 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, 2010 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.

By:	/s/ JORGEN RASMUSSEN	By:	/s/ VICTOR M. PEREZ
	Jorgen Rasmussen		Victor Perez
	Chief Executive Officer		Chief Financial Officer

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Allis-Chalmers Energy Inc.:

We have audited the accompanying consolidated balance sheets of Allis-Chalmers Energy Inc. and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the 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 consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Allis-Chalmers Energy Inc. and subsidiaries as of December 31, 2010 and 2009, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Allis-Chalmers Energy Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 15, 2011 expressed an unqualified opinion thereon.

/s/ UHY LLP

Houston, Texas

March 15, 2011

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of

Allis-Chalmers Energy Inc.:

We have audited Allis-Chalmers Energy Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Allis-Chalmers Energy Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying 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, 2010, 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, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2010, and our report dated March 15, 2011 expressed an unqualified opinion thereon.

/s/ UHY LLP

Houston, Texas

March 15, 2011

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ALLIS-CHALMERS ENERGY INC.

CONSOLIDATED BALANCE SHEETS


	December 31,
	2010			2009
	(In thousands, except for share and per share amounts)

ASSETS
Cash and cash equivalents	$	20,940		$	41,072
Trade receivables, net of allowance for doubtful accounts of $4,361 and $4,923 at December 31, 2010 and 2009, respectively		144,960			105,059
Inventories		42,140			34,528
Deferred income tax asset		1,835			3,790
Prepaid expenses and other		9,192			13,799

Total current assets		219,067			198,248

Property and equipment, at cost net of accumulated depreciation of $286,062 and $209,782 at December 31, 2010 and 2009, respectively		723,234			746,478
Goodwill		46,333			40,639
Other intangible assets, net of accumulated amortization of $16,835 and $13,973 at December 31, 2010 and 2009, respectively		33,899			32,649
Debt issuance costs, net of accumulated amortization of $8,490 and $6,314 at December 31, 2010 and 2009, respectively		7,405			9,545
Deferred income tax asset		37,602			22,047
Other assets		8,116			31,014


Total assets	$	1,075,656		$	1,080,620


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current maturities of long-term debt	$	15,215		$	17,027
Trade accounts payable		46,042			34,839
Accrued salaries, benefits and payroll taxes		32,790			22,854
Accrued interest		15,524			15,821
Accrued expenses		30,676			21,918

Total current liabilities		140,247			112,459

Deferred income tax liability		8,240			8,166
Long-term debt, net of current maturities		478,225			475,206
Other long-term liabilities		233			1,142

Total liabilities		626,945			596,973

Commitments and Contingencies

Stockholders’ Equity
Preferred stock, $0.01 par value (25,000,000 shares authorized, 36,393 shares issued and outstanding at December 31, 20010 and 2009)		34,183			34,183
Common stock, $0.01 par value (200,000,000 shares authorized; 73,722,347 issued and outstanding at December 31, 2010 and 71,378,529 issued and outstanding at December 31, 2009)		737			714
Capital in excess of par value		429,924			422,823
(Accumulated deficit) retained earnings		(16,133	)		25,927

Total stockholders’ equity		448,711			483,647


Total liabilities and stockholders’ equity	$	1,075,656		$	1,080,620

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

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ALLIS-CHALMERS ENERGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS


	Years Ended December 31,
	2010			2009			2008
	(In thousands, except per share amounts)

Revenues	$	659,665		$	506,253		$	675,948

Operating costs and expenses
Direct costs		498,120			379,437			443,414
Depreciation		84,118			78,276			63,460
Selling, general and administrative		60,434			50,763			62,774
Loss (gain) on asset dispositions		10,624			1,602			(166	)
Impairment of goodwill		—			—			115,774
Amortization		4,806			4,722			4,212

Total operating costs and expenses		658,102			514,800			689,468


Income (loss) from operations		1,563			(8,547	)		(13,520	)


Other income (expense):
Interest expense		(45,825	)		(48,145	)		(48,411	)
Interest income		537			72			5,617
Gain on debt extinguishment		—			26,365			—
Other		(3,211	)		(798	)		(563	)

Total other expense		(48,499	)		(22,506	)		(43,357	)


Loss before income taxes		(46,936	)		(31,053	)		(56,877	)

Income tax benefit		7,424			9,863			17,413


Net loss		(39,512	)		(21,190	)		(39,464	)

Preferred stock dividend		(2,548	)		(1,302	)		—


Net loss attributed to common stockholders	$	(42,060	)	$	(22,492	)	$	(39,464	)


Loss per common share:
Basic	$	(0.59	)	$	(0.42	)	$	(1.13	)

Diluted	$	(0.59	)	$	(0.42	)	$	(1.13	)


Weighted average number of common shares outstanding:
Basic		71,726			53,669			35,052

Diluted		71,726			53,669			35,052

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

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ALLIS-CHALMERS ENERGY INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY


									Capital in Excess of Par Value			Retained Earnings (Deficit)			Total Stockholders’ Equity
	Preferred Stock				Common Stock
	Shares		Amount		Shares		Amount
					(In thousands, except share amounts)

Balances, December 31, 2007		—	$	—		35,116,035	$	351	$	326,095		$	87,883		$	414,329

Net loss		—		—		—		—		—			(39,464	)		(39,464	)

Issuance of common stock:
Issuance under stock plans		—		—		558,707		6		627			—			633

Stock-based compensation		—		—		—		—		7,902			—			7,902
Tax benefits on stock plans		—		—		—		—		9			—			9


Balances, December 31, 2008		—		—		35,674,742		357		334,633			48,419			383,409

Net loss		—		—		—		—		—			(21,190	)		(21,190	)
Preferred stock dividend		—		—		—		—		—			(1,302	)		(1,302	)

Issuance of common stock:
Rights offering, net of offering costs		36,393		34,183		35,683,688		357		85,683			—			120,223
Issuance under stock plans		—		—		20,099		—		43			—			43

Stock-based compensation		—		—		—		—		4,799			—			4,799
Tax benefits on stock plans		—		—		—		—		(2,335	)		—			(2,335	)


Balances, December 31, 2009		36,393		34,183		71,378,529		714		422,823			25,927			483,647

Net loss		—		—		—		—		—			(39,512	)		(39,512	)
Preferred stock dividend		—		—		—		—		—			(2,548	)		(2,548	)

Issuance of common stock:
Business acquisition		—		—		1,000,000		10		1,990			—			2,000
Issuance under stock plans		—		—		1,343,818		13		(1,735	)		—			(1,722	)

Stock-based compensation		—		—		—		—		8,030			—			8,030
Tax benefits on stock plans		—		—		—		—		(1,184	)		—			(1,184	)


Balances, December 31, 2010		36,393	$	34,183		73,722,347	$	737	$	429,924		$	(16,133	)	$	448,711

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

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ALLIS-CHALMERS ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2010			2009			2008
	(In thousands)
Cash Flows from Operating Activities:
Net loss	$	(39,512	)	$	(21,190	)	$	(39,464	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization		88,924			82,998			67,672
Amortization and write-off of deferred issuance costs		2,214			2,231			2,089
Gain on debt extinguishment		—			(26,365	)		—
Impairment of goodwill		—			—			115,774
Stock-based compensation		8,030			4,799			7,902
Allowance for bad debts		368			2,835			3,283
Deferred income taxes		(17,077	)		(17,883	)		(29,949	)
Loss on investment		1,466			—			—
Equity in loss of unconsolidated affiliates		783			—			—
Loss (gain) on sale of property and equipment		680			(948	)		(1,762	)
Loss (gain) on asset dispositions		10,624			1,602			(166	)
Changes in operating assets and liabilities, net of acquisitions:
Decrease (increase) in trade receivable		(35,683	)		49,977			(27,499	)
Decrease (increase) in inventories		(5,954	)		4,559			(9,719	)
Decrease (increase) in prepaid expenses and other assets		11,142			4,628			(1,623	)
Decrease in other assets		1,746			1,648			1,224
(Decrease) increase in trade accounts payable		11,061			(27,588	)		21,903
(Decrease) increase in accrued interest		(297	)		(2,802	)		567
(Decrease) increase in accrued expenses		7,438			(4,607	)		1,131
(Decrease) in other liabilities		(909	)		(1,051	)		(1,130	)
Increase in accrued salaries, benefits and payroll taxes		9,872			2,662			3,452

Net cash provided by operating activities		54,916			55,505			113,685


Cash Flows from Investing Activities:
Acquisitions, net of cash acquired		(15,935	)		—			(53,709	)
Net sales (purchases) of investment interests		368			(1,102	)		1,374
Purchases of property and equipment		(102,155	)		(78,067	)		(154,468	)
Deposits on asset commitments		18,347			2,685			(9,901	)
Proceeds from asset dispositions		25,000			3,916			3,000
Proceeds from sale of property and equipment		6,638			8,581			11,480

Net cash used in investing activities		(67,737	)		(63,987	)		(202,224	)


Cash Flows from Financing Activities:
Proceeds from issuance of long-term debt		4,000			25,000			25,000
Payments on long-term debt		(42,168	)		(64,755	)		(9,905	)
Net borrowings (repayments) on lines of credit		36,500			(36,500	)		36,500
Proceeds from issuance of stock, net of offering costs		—			120,223			—
Payment of preferred stock dividend		(2,548	)		(665	)		—
Exercise of options and warrants		(1,722	)		43			633
Income tax impact of stock-based compensation plans		(1,184	)		—			9
Debt issuance costs		(189	)		(658	)		(525	)

Net cash (used) provided by financing activities		(7,311	)		42,688			51,712


Net increase (decrease) in cash and cash equivalents		(20,132	)		34,206			(36,827	)
Cash and cash equivalents at beginning of year		41,072			6,866			43,693

Cash and cash equivalents at end of year	$	20,940		$	41,072		$	6,866

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

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ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements

NOTE 1 — NATURE OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization of Business

Allis-Chalmers Energy Inc. (“Allis-Chalmers”, “we”, “our” or “us”) was incorporated in Delaware in 1913. We provide services and equipment to oil and natural gas exploration and production companies throughout the United States including Texas, Louisiana, Pennsylvania, West Virginia, Wyoming, Oklahoma, offshore in the Gulf of Mexico, and internationally, primarily in Argentina, Brazil, Bolivia and Mexico. We operate in three sectors of the oil and natural gas service industry: Oilfield Services; Drilling and Completion and Rental Services.

The nature of our operations and the many regions in which we operate subject us to changing economic, regulatory and political conditions. We are vulnerable to near-term and long-term changes in the demand for and prices of oil and natural gas and the related demand for oilfield service operations.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Future events and their effects cannot be perceived with certainty. Accordingly, our accounting estimates require the exercise of judgment. While management believes that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. Estimates are used for, but are not limited to, determining the following: allowance for doubtful accounts, recoverability of long-lived assets and intangibles, useful lives used in depreciation and amortization, income taxes and valuation allowances. The accounting estimates used in the preparation of the consolidated financial statements may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.

Principles of Consolidation

The consolidated financial statements include the accounts of Allis-Chalmers and its subsidiaries. Our subsidiaries at December 31, 2010 are AirComp LLC, Allis-Chalmers Tubular Services LLC, Allis-Chalmers Directional Drilling Services LLC, Allis-Chalmers Rental Services LLC, Allis-Chalmers Production Services LLC, Allis-Chalmers Management LLC, Allis-Chalmers Holdings Inc., American Well Control LLC (“AWC”), DLS Drilling, Logistics & Services Company (“DLS”), DLS Argentina Limited, Tanus Argentina S.A., Petro-Rentals LLC, Rebel Rentals LLC, Allis-Chalmers Drilling LLC, BCH Ltd. (“BCH”), ALY do Brasil Servicos do Petroleo Ltda, Drilling Logistics and Services de Mexico and BCH Energy do Brasil Servicos de Petroleo Ltda. All significant inter-company transactions have been eliminated.

Revenue Recognition

We provide rental equipment, oilfield services and drilling services to our customers at per day, or daywork, and per job contractual rates and recognize the drilling related revenue as the work progresses and when collectibility is reasonably assured. Revenue from daywork contracts is recognized when it is realized or realizable and earned. On daywork contracts, revenue is recognized based on the number of days completed at fixed rates stipulated by the contract. For certain contracts, we receive lump-sum and other fees for equipment and other mobilization costs. Mobilization fees and the related costs are deferred and amortized over the contract terms when material. We recognize reimbursements received for out-of-pocket expenses incurred as revenues and account for out-of-pocket expenses as direct costs. Payments from customers for the cost of oilfield rental equipment that is damaged or lost-in-hole are reflected as revenues. We recognized revenue from damaged or lost-in-hole equipment of $5.9 million, $4.3 million and $10.6 million for the years ended December 31, 2010, 2009 and 2008, respectively.

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ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

Allowance for Doubtful Accounts

Accounts receivable are customer obligations due under normal trade terms. We sell our services to oil and natural gas exploration and production companies. We perform continuing credit evaluations of its customers’ financial condition and although we generally do not require collateral, letters of credit may be required from customers in certain circumstances.

The allowance for doubtful accounts represents our estimate of the amount of probable credit losses existing in our accounts receivable. Significant individual accounts receivable balances which have been outstanding greater than 90 days are reviewed individually for collectibility. We have a limited number of customers with individually large amounts due at any given date. Any unanticipated change in any one of these customer’s credit worthiness or other matters affecting the collectibility of amounts due from such customers could have a material effect on the results of operations in the period in which such changes or events occur. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. As of December 31, 2010 and 2009, we had recorded an allowance for doubtful accounts of $4.4 million and $4.9 million respectively. Bad debt expense was $368,000, $2.8 million and $3.3 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents.

Inventories

Inventories are stated at the lower of cost or market. Cost is determined using the first - in, first - out (“FIFO”) method or the average cost method, which approximates FIFO, and includes the cost of materials, labor and manufacturing overhead.

Property and Equipment

Property and equipment is recorded at cost less accumulated depreciation. Certain equipment held under capital leases are classified as equipment and the related obligations are recorded as liabilities.

Maintenance and repairs, which do not improve or extend the life of the related assets, are charged to operations when incurred. Refurbishments and renewals are capitalized when the value of the equipment is enhanced for an extended period. When property and equipment are sold or otherwise disposed of, the asset account and related accumulated depreciation account are relieved, and any gain or loss is included in operations. Interest is capitalized on construction in progress at the weighted average cost of debt outstanding during the construction period or at the interest rate on debt incurred for construction.

The cost of property and equipment currently in service is depreciated over the estimated useful lives of the related assets, which range from two to twenty years. Depreciation is computed on the straight-line method for financial reporting purposes. Capital leases are amortized using the straight-line method over the estimated useful lives of the assets and lease amortization is included in depreciation expense. Depreciation expense charged to operations was $84.1 million, $78.3 million and $63.5 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Goodwill, Intangible Assets and Amortization

Goodwill and other intangible assets with infinite lives are not amortized, but tested for impairment annually or more frequently if circumstances indicate that impairment may exist. Intangible assets with finite useful lives are amortized either on a straight-line basis over the asset’s estimated useful life or on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized.

The impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. Reporting units are at a business unit level and is one level below our operating segments. We perform impairment tests on the carrying value of our goodwill on an annual basis as of December 31st for each of our reportable segments. Our annual impairment tests involve the use of different valuation techniques, including the income approach and/or market approach, to determine the fair value of our reporting units. Determining the fair value of a reporting unit is a matter of judgment and often involves the use of significant estimates and assumptions. If the fair value of the reporting unit is less than its carrying value, an impairment loss is recorded to the extent that the implied fair value of the reporting unit’s goodwill is less than its carrying value. As a result we recorded an impairment of $115.8 million at December 31, 2008. At December 31, 2010 and 2009, no impairment was deemed necessary. Significant and unanticipated changes to these assumptions could require an additional provision for impairment in a future period.

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ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

Impairment of Long-Lived Assets

Long-lived assets, which include property, plant and equipment, and other intangible assets, and certain other assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. The determination of recoverability is made based upon the estimated undiscounted future net cash flows, excluding interest expense. The impairment loss is determined by comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value of the related assets.

Financial Instruments

Financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and debt. The carrying value of cash and cash equivalents and accounts receivable and payable approximate fair value due to their short-term nature. We believe the fair values and the carrying value of our debt, excluding the senior notes, would not be materially different due to the instruments’ interest rates approximating market rates for similar borrowings at December 31, 2010 and 2009. Our senior notes, in the aggregate amount of $430.2 million at both December 31, 2010 and 2009, trade “over the counter” in limited amounts and on an infrequent basis. Based on those trades we estimate the fair value of our senior notes to be approximately $436.1 million and $394.2 million at December 31, 2010 and 2009, respectively. The price at which our senior notes trade is based on many factors such as the level of interest rates, the economic environment, the outlook for the oilfield services industry and the perceived credit risk. Additionally, due to the turmoil in the financial markets of 2008 and 2009, and its impact on investors of our senior notes, the price at which our senior notes trade may be affected by the investors’ financial distress and need for liquidity.

Concentration of Credit and Customer Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents and trade accounts receivable. As of December 31, 2010, we have approximately $1.9 million and $2.7 million of cash and cash equivalents residing in Argentina and Brazil, respectively. Cash and cash equivalents of $1.6 million are restricted in conjunction with financial institution obligations in Brazil. We transact our business with several financial institutions. However, the amount on deposit in one financial institution exceeded the $250,000 federally insured limit at December 31, 2010 by a total of $16.7 million. Management believes that the financial institutions are financially sound and the risk of loss is minimal.

We sell our services to major and independent domestic and international oil and natural gas companies. We perform ongoing credit valuations of our customers and provide allowances for probable credit losses where appropriate. In 2010, 2009 and 2008, one of our customers, Pan American Energy LLC Sucursal Argentina, or Pan American Energy, represented 31.1%, 35.5% and 28.5% of our consolidated revenues, respectively. Revenues from Pan American Energy represented 52.5%, 56.6% and 62.0% of our international revenues in 2010, 2009 and 2008, respectively (see Note 14).

Debt Issuance Costs

The costs related to the issuance of debt are capitalized and amortized to interest expense using the straight-line method, which approximates the interest method, over the maturity periods of the related debt. Interest expense related to debt issuance costs were $2.2 million, $2.2 million and $2.1 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Income Taxes

Our income tax expense is based on our income, statutory tax rates and tax planning opportunities available to us in the various jurisdictions in which we operate. We provide for income taxes based on the tax laws and rates in effect in the countries in which operations are conducted and income is earned. Our income tax expense is expected to fluctuate from year to year as our operations are conducted in different taxing jurisdictions and the amount of pre-tax income fluctuates.

The determination and evaluation of our annual income tax provision involves the interpretation of tax laws in various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations and our level of operations or profitability in each jurisdiction may impact our tax liability in any given year. While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined.

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ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in tax rates and changes in prior year tax estimates as returns are filed. Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the enacted tax rates in effect at year end. A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. For United States federal tax purposes, our tax returns for the tax years 2007 through 2009 remain open for examination by the tax authorities. Our foreign tax returns remain open for examination for the tax years 2002 through 2009. Generally, for state tax purposes, our 2004 through 2009 tax years remain open for examination by the tax authorities under a four year statute of limitations, however, certain states may keep their statute open for six to ten years.

It is our intention to permanently reinvest all of the undistributed earnings of our non-United States subsidiaries in such subsidiaries. Accordingly, we have not provided for United States deferred taxes on the $100.2 million of undistributed earnings of our non-United States subsidiaries as of December 31, 2010. If a distribution is made to us from the undistributed earnings of these subsidiaries, we could be required to record additional taxes. Because we cannot predict when, if at all, we will make a distribution of these undistributed earnings, we are unable to make a determination of the amount of unrecognized deferred tax liability.

Stock-Based Compensation

We recognize all share-based payments to employees, including grants of employee stock options, in the financial statements based on their grant-date fair values. We utilize the Black-Scholes model to determine fair value, which incorporates assumptions to value stock-based awards. The dividend yield on our common stock is assumed to be zero as we have historically not paid dividends and have no current plans to do so in the future. The expected volatility is based on historical volatility of our common stock. The risk-free interest rate is the related United States Treasury yield curve for periods within the expected term of the option at the time of grant. We estimate forfeiture rates based on our historical experience.

Our net income (loss) for the years ended December 31, 2010, 2009 and 2008 includes approximately $8.0 million, $4.8 million and $7.9 million of compensation costs related to share-based payments, respectively. The tax benefit recorded in association with the share-based payments was $9,000 for the year-ended December 31, 2008. Due to expired unexercised nonqualified stock options and restricted stock vesting at market prices lower than the grant price, we adjusted $1.2 million and $2.3 million of excess tax asset against additional paid in capital for the years ended December 31, 2010 and 2009, respectively. As of December 31, 2010 there is $6.5 million of unrecognized compensation expense related to non-vested stock based compensation grants.

No options were granted in 2008. See Note 10 for further disclosures regarding stock options. The following assumptions were applied in determining the compensation costs for options granted in 2010 and 2009:


	For the Years Ended December 31,
	2010			2009
Expected dividend yield		—			—
Expected price volatility		89.81	%		77.32	%
Risk-free interest rate		1.41	%		1.37	%
Expected life of options		5 years			5 years
Weighted average fair value of options granted at market value	$	2.63		$	0.77

Income (Loss) Per Common Share

Basic earnings per share are computed on the basis of the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share is similar to basic earnings per share, but presents the dilutive effect on a per share basis of potential common shares (e.g., convertible preferred stock, stock options, etc.) as if they had been converted. Restricted stock grants are legally considered issued and outstanding, but are included in basic and diluted earnings per share only to the extent that they are vested. Unvested restricted stock is included in the computation of diluted earnings per share using the treasury stock method. Potential dilutive common shares that have an anti-dilutive effect (e.g., those that increase income per share) are excluded from diluted earnings (deficit) per share.

- 45 -

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

The components of basic and diluted earnings (deficit) per share are as follows (in thousands, except per share amounts):


	For the Years Ended December 31,
	2010			2009			2008
Numerator:
Net loss	$	(39,512	)	$	(21,190	)	$	(39,464	)
Preferred stock dividend		(2,548	)		(1,302	)		—

Net loss attributed to common stockholders	$	(42,060	)	$	(22,492	)	$	(39,464	)


Denominator:
Weighted average common shares outstanding excluding nonvested restricted stock		71,726			53,669			35,052
Effect of potentially dilutive common shares:
Warrants and share based compensation shares		—			—			—

Weighted average common shares outstanding and assumed conversions		71,726			53,669			35,052


Loss per common share:
Basic	$	(0.59	)	$	(0.42	)	$	(1.13	)

Diluted	$	(0.59	)	$	(0.42	)	$	(1.13	)


Potentially dilutive securities excluded as anti-dilutive		15,680			15,059			1,041

Convertible preferred stock and share based compensation shares of approximately 13.5 million, 7.5 million and 332,000 were excluded in the computation of diluted earnings per share for 2010, 2009 and 2008, respectively as the effect would have been anti-dilutive due to the net loss for the year.

Segments of an Enterprise and Related Information

We designate the internal organization that is used by management for allocating resources and assessing performance as the source of our reportable segments. Please see Note 15 for further disclosure of segment information and disclosures by geographic region.

New Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board, or the FASB, issued authoritative guidance that eliminates the qualifying special purpose entity concept, changes the requirements for derecognizing financial assets and requires enhanced disclosures about transfers of financial assets. The guidance also revises earlier guidance for determining whether an entity is a variable interest entity, requires a new approach for determining who should consolidate a variable interest entity, changes when it is necessary to reassess who should consolidate a variable interest entity, and requires enhanced disclosures related to an enterprise’s involvement in variable interest entities. We adopted this guidance effective January 1, 2010, which did not have a material effect on our financial statements.

In October 2009, the FASB issued authoritative guidance that amends earlier guidance addressing the accounting for contractual arrangements in which an entity provides multiple products or services (deliverables) to a customer. The amendments address the unit of accounting for arrangements involving multiple deliverables and how arrangement consideration should be allocated to the separate units of accounting, when applicable, by establishing a selling price hierarchy for determining the selling price of a deliverable. The selling price used for each deliverable will be based on vendor-specific objective evidence if available, third-party evidence if vendor-specific objective evidence is not available, or estimated selling price if neither vendor-specific nor third-party evidence is available. The amendments also require that arrangement consideration be allocated at the inception of an arrangement to all deliverables using the relative selling price method. This guidance is effective for fiscal years beginning on or after June 15, 2010, with earlier application permitted. We adopted this guidance effective January 1, 2011, which did not have a material effect on our financial statements.

- 46 -

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

In January 2010, the FASB issued authoritative guidance that changes the disclosure requirements for fair value measurements. Specifically, the changes require a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers. The changes also clarify existing disclosure requirements related to how assets and liabilities should be grouped by class and valuation techniques used for recurring and nonrecurring fair value measurements. We adopted this guidance in the first quarter 2010, which did not have a material effect on our financial position, results of operations or cash flows.

In February 2010, the FASB amended guidance on subsequent events to alleviate potential conflicts between FASB guidance and SEC requirements. Under this amended guidance, SEC filers are no longer required to disclose the date through which subsequent events have been evaluated in originally issued and revised financial statements. This guidance was effective immediately and we adopted these new requirements in the first quarter of 2010. The adoption of this guidance did not have a material effect on our financial statements.

NOTE 2 — EMPLOYEE BENEFIT PLANS

On June 30, 2003, we adopted a 401(k) Profit Sharing Plan (the “Plan”). The Plan is a defined contribution savings plan designed to provide retirement income to our eligible employees. The Plan is intended to be qualified under Section 401(k) of the Internal Revenue Code of 1986, as amended. It is funded by voluntary pre-tax contributions from eligible employees who may contribute a percentage of their eligible compensation, limited and subject to statutory limits. The Plan is also funded by discretionary matching employer contributions. Eligible employees cannot participate in the Plan until they have attained the age of 21 and completed three-months of service with us. Each participant is 100% vested with respect to the participants’ contributions and our matching contributions. Contributions are invested, as directed by the participant, in investment funds available under the Plan. Matching contributions of approximately $97,000, $349,000 and $1.5 million were paid in 2010, 2009 and 2008, respectively.

NOTE 3 — ACQUISITIONS AND ASSET DISPOSITIONS

On December 31 2008, we completed the acquisition of all of the outstanding stock of BCH for a total consideration of approximately $56.1 million. Approximately $251,000 of costs were incurred in relation to the BCH acquisition. BCH is a land drilling contractor operating in Brazil. The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired at the date of acquisition (in thousands):


Current assets	$	7,622
Property and equipment		53,369
Intangible assets, including goodwill		26,199

Total assets acquired		87,190

Current liabilities		14,456
Long-term debt, less current portion		16,364

Total liabilities assumed		30,820

Net assets acquired	$	56,370

BCH’s historical property and equipment values were decreased by approximately $2.8 million based on third-party valuations. Intangible assets included approximately $18.5 million assigned to goodwill, $4.9 million to customer contracts, $2.2 million assigned to trade name and $600,000 to non-competes based on third-party valuations. The amortizable intangibles have a weighted-average useful life of 12.6 years. Goodwill was subsequently reduced in 2009 by $1.3 million of insurance proceeds that were received for a rig loss that occurred prior to acquisition and by $1.3 million for the utilization of pre acquisition tax asset. The results of BCH since the acquisition are included in our Drilling and Completion segment.

- 47 -

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

On July 12, 2010, we acquired AWC for a total consideration of approximately $19.2 million, which included approximately $17.2 million in cash and 1.0 million shares of our common stock. AWC is a leading manufacturer of premium high-pressure valves used in hydraulic fracturing in the unconventional gas shale plays. The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired at the date of acquisition (in thousands):


Current assets	$	7,585
Property and equipment		2,756
Intangible assets, including goodwill		11,749
Other long-term assets		2

Total assets acquired		22,092
Current liabilities		1,527
Long-term liabilities		1,401

Net assets acquired	$	19,164

AWC’s historical property and equipment values were increased by approximately $27,000 based on third-party valuations. Goodwill of $5.7 million was recognized for this acquisition and was calculated as the excess of the consideration transferred over the fair value of the net assets acquired. It includes the expected synergies and other benefits that we believe will result from the combined operations and intangible assets that do not qualify for separate recognition such as assembled workforce. Other intangible assets included approximately $5.6 million assigned to customer lists, $400,000 to trade name and $55,000 to non-competes. None of the intangibles are tax deductible. The amortizable intangibles have a weighted-average useful life of 9.9 years. AWC’s financial results since the acquisition are included in our Rental Services segment.

All of the aforementioned acquisitions were accounted for using the purchase method of accounting.

Effective August 1, 2008, we sold our drill pipe tong manufacturing assets for approximately $7.5 million. We received cash of approximately $2.0 million at the time of sale, a 90-day note for $1.0 million and a 10-year non-interest bearing note for $4.5 million. Repayment on the 10-year note is tied to various performance targets and we have assigned a fair value of approximately $3.1 million to this note. We reported a gain of approximately $166,000 on this transaction. The assets sold represented a small portion of our Oilfield Services segment.

During 2009, we recorded a $1.6 million loss on asset disposition in our Drilling and Completion segment. The insurance proceeds of $3.9 million related to damages incurred on a blow-out which destroyed one of our drilling rigs were not sufficient to cover the book value of the rig and related assets.

During 2010, we recorded a $10.6 million loss on asset disposition in our Drilling and Completion segment. We purchased two drilling rigs that we were unable to operate and returned the rigs to the manufacturer. The loss includes an early repayment penalty of $311,000 on the underlying debt and the write-off of $115,000 of deferred financing fees.

NOTE 4 — INVENTORIES

Inventories are comprised of the following as of December 31 (in thousands):


	2010		2009
Manufactured
Finished goods	$	4,238	$	2,983
Work in process		2,990		2,299
Raw materials		3,600		884

Total manufactured		10,828		6,166
Rig parts and related inventory		11,565		10,654
Shop supplies and related inventory		9,620		7,762
Chemicals and drilling fluids		4,814		4,381
Rental supplies		1,761		2,134
Hammers		2,380		2,257
Coiled tubing and related inventory		1,046		939
Drive pipe		126		235

Total inventories	$	42,140	$	34,528

- 48 -

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

NOTE 5 — PROPERTY AND OTHER INTANGIBLE ASSETS

Property and equipment is comprised of the following as of December 31 (in thousands):


	Depreciation Period		2010			2009
Land		—	$	2,452		$	2,211
Building and improvements		15-20 years		10,201			8,611
Transportation equipment		2-10 years		37,060			33,353
Drill pipe and rental equipment		2 -20 years		390,263			380,185
Drilling, workover and pulling rigs		20 years		255,647			248,780
Machinery and equipment		2-20 years		245,609			226,601
Furniture, computers, software and leasehold improvements		3-10 years		10,839			9,128
Construction in progress — equipment		N/A		57,225			47,391

Total				1,009,296			956,260
Less: accumulated depreciation				(286,062	)		(209,782	)

Property and equipment, net			$	723,234		$	746,478

The net book value of equipment recorded under capital leases was $0.0 and $1.0 million as of December 31, 2010 and 2009, respectively. Interest expense capitalized to property and equipment was $827,000, $2.2 million and $1.9 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Other intangible assets are as follows as of December 31 (in thousands):


	Amortization Period		2010			2009
Intellectual property		10-20 years	$	4,229		$	3,829
Non-compete agreements		3-5 years		895			2,640
Customer relationships		10-15 years		43,633			38,033
Patents		12-15 years		1,327			1,327
Other intangible assets		2-10 years		650			793

Total				50,734			46,622
Less: accumulated amortization				(16,835	)		(13,973	)

Other intangibles assets, net			$	33,899		$	32,649


	2010				2009
	Gross Value		Accumulated Amortization		Gross Value		Accumulated Amortization
Intellectual property	$	4,229	$	1,157	$	3,829	$	823
Non-compete agreements		895		576		2,640		1,879
Customer relationships		43,633		13,998		38,033		10,209
Patents		1,327		484		1,327		382
Other intangible assets		650		620		793		680

Total	$	50,734	$	16,835	$	46,622	$	13,973

Amortization expense related to other intangibles was $4.8 million, $4.7 million and $4.2 million for the years ended December 31, 2010, 2009 and 2008, respectively. Future amortization of intangible assets at December 31, 2010 is as follows (in thousands):


	Intangible Amortization by Period
	Years Ended December 31,
	2011		2012		2013		2014		2015 and Thereafter
Intellectual property	$	356	$	356	$	356	$	347	$	1,657
Non-compete agreements		266		43		10		—		—
Customer relationships		4,092		4,092		4,092		4,071		13,288
Patents		102		102		102		102		435
Other intangible assets		28		2		—		—		—

Total intangible amortization	$	4,844	$	4,595	$	4,560	$	4,520	$	15,380

- 49 -

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

NOTE 6 — INCOME TAXES

We had a loss before income taxes of $58.2 million, $43.9 million and $95.3 million for United States tax purposes for the years ended December 31, 2010, 2009 and 2008, respectively. We also had income before income taxes of $11.3 million, $12.9 million and $38.4 million reported in non-United States countries for the years ended December 31, 2010, 2009 and 2008, respectively. We treat the withholding taxes incurred by our United States subsidiaries in foreign countries as foreign tax, and we anticipate using those tax payments to offset United States tax. We are required to file a consolidated United States federal income tax return. We file foreign income tax returns in Argentina, Brazil, Bolivia and Canada related to our Drilling and Completion operations.

We recognize the impact of uncertain tax positions in our financial statements, if a tax position is challenged by a taxing authority and there is a more likely than not chance the tax position will be disallowed, based on the technical merits of the position. We recognize interest and penalties related to uncertain tax positions as a component of income tax expense. We identified no uncertain tax positions for the three years in the period ended December 31, 2010.

The income tax provision consists of the following (in thousands):


	Years Ended December 31,
	2010			2009			2008
Current income tax expense (benefit):
Federal	$	(1,123	)	$	8		$	(1,525	)
State		580			324			471
Foreign		10,196			7,688			13,590

		9,653			8,020			12,536


Deferred income tax expense (benefit):
Federal		(17,059	)		(15,185	)		(28,462	)
State		(317	)		(1,626	)		(1,149	)
Foreign		299			(1,072	)		(338	)

		(17,077	)		(17,883	)		(29,949	)

	$	(7,424	)	$	(9,863	)	$	(17,413	)

Significant components of deferred income tax assets as of December 31, were as follows (in thousands):


	2010			2009
Deferred income tax assets:
Amortization	$	27,473		$	30,902
Net operating loss carryforwards		64,620			40,752
Share-based compensation		1,055			2,199
Foreign tax credits		6,106			992
A-C Product Liability Trust		—			803
Other net future deductible items		2,014			3,083
Valuation allowance		(20,956	)		(13,999	)

Gross deferred income tax assets		80,312			64,732

Deferred income tax liabilities
Depreciation		(48,115	)		(46,050	)
Other net future taxable items		(1,000	)		(1,011	)

Gross deferred income tax liabilities		(49,115	)		(47,061	)

Net deferred income tax assets	$	31,197		$	17,671


Net current deferred income tax assets	$	1,835		$	3,790
Net noncurrent deferred income tax assets		37,602			22,047
Net noncurrent deferred income tax liabilities		(8,240	)		(8,166	)

Net deferred income tax assets	$	31,197		$	17,671

Net future tax-deductible items relate primarily to timing differences. Timing differences are differences between the tax basis of assets and liabilities and their reported amounts in the financial statements that will result in differences between income for tax purposes and income for financial statement purposes in future years.

- 50 -

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

The following table reconciles the statutory tax rates to our actual tax rate:


	Years Ended December 31,
	2010			2009			2008
Statutory income tax rate		34.0	%		34.0	%		34.0	%
State taxes, net of federal benefit		(0.3	)		1.7			0.4
Foreign currency remeasurement		1.1			0.3			2.1
Nondeductible goodwill, permanent differences and other		(19.0	)		(4.2	)		(5.9	)

Effective tax rate		15.8	%		31.8	%		30.6	%

The Tax Reform Act of 1986 contains provisions that limit the utilization of net operating loss and tax credit carry forwards if there has been a “change of ownership” as described in Section 382 of the Internal Revenue Code. Such a change of ownership may limit our utilization of our net operating loss and tax credit carryforwards, and could be triggered by a public offering or by subsequent sales of securities by us or our stockholders. This provision has limited the amount of net operating losses available to us currently. Net operating loss carryforwards for tax purposes at December 31, 2010 and 2009 were $115.7 million and $67.8 million, respectively, expiring through 2030.

A valuation allowance is established for deferred tax assets when management, based upon available information, considers it more likely than not that a benefit from such assets will not be realized. As of December 31, 2010 and 2009, the valuation allowance was $21.0 million and $14.0 million, respectively. The valuation allowances relate to net operating losses incurred by BCH, both pre and post acquisition, in which we currently do not have a tax strategy to utilize.

Approximately $6.3 million and $4.4 million of ad valorem, franchise, income, sales and other tax accruals are included in our accrued expense balances of $30.7 million and $21.9 million as of December 31, 2010 and 2009, respectively.

NOTE 7 — DEBT

Our long-term debt consists of the following as of December 31 (in thousands):


	2010		2009
Senior notes	$	430,238	$	430,238
Revolving line of credit		36,500		—
Bank term loans		25,723		60,744
Insurance premium financing notes		979		997
Capital lease obligations		—		254

Total debt		493,440		492,233
Less: current maturities of long-term debt		15,215		17,027

Long-term debt	$	478,225	$	475,206

Our weighted average interest rate for current and total debt was approximately 4.2% and 8.5% as of December 31, 2010 and 5.0% and 8.4% as of December 31, 2009, respectively.

Maturities of debt obligations as of December 31, 2010 are as follows (in thousands):


	Total
Year Ending:
December 31, 2011	$	15,215
December 31, 2012		6,891
December 31, 2013		4,016
December 31, 2014		261,518
December 31, 2015		—
Thereafter		205,800

Total	$	493,440

- 51 -

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

Senior notes, term loans and line of credit agreements

On May 22, 2009, we drew down $25.0 million on a new term loan credit facility with a lending institution. The facility was utilized to fund a portion of the purchase price of two new drilling rigs. The loan was secured by the equipment and was repaid in November 2010 when the equipment was returned to the manufacturer. The facility was repayable in quarterly installments of approximately $1.4 million of principal and interest and was to mature in May 2015. The loan bore interest at a fixed rate of 9.0%. At December 31, 2009, the outstanding amount of the loan was $23.4 million.

- 52 -

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

Notes payable

Other debt

NOTE 8 — COMMITMENTS AND CONTINGENCIES

We have placed orders for capital equipment totaling $21.0 million to be received and paid for through 2011. Approximately $4.5 million is for drilling equipment for our Drilling and Completion segment, $10.2 million is for drill pipe for our Rental Services segment and $6.3 million is for various equipment to be utilized by our Oilfield Services segment.

We rent office space and certain other facilities and shop yards for equipment storage and maintenance. Facility rent expense for the years ended December 31, 2010, 2009 and 2008 was $3.7 million, $3.3 million and $2.8 million, respectively.

At December 31, 2010, future minimum rental commitments for all operating leases are as follows (in thousands):


Years Ending:
December 31, 2011	$	3,376
December 31, 2012		2,278
December 31, 2013		1,817
December 31, 2014		1,188
December 31, 2015		838
Thereafter		1,721

Total	$	11,218

NOTE 9 — STOCKHOLDERS’ EQUITY

During 2008, we had restricted stock award grants, and options exercised, which resulted in 558,707 shares of our common stock being issued for approximately $633,000. We recognized approximately $7.9 million of compensation expense related to share based payments that was recorded as capital in excess of par value (see Note 1). We also recorded approximately $9,000 of tax benefit related to our stock compensation plans.

In June 2009, we closed our backstopped rights offering and private placement of convertible preferred stock and received proceeds of approximately $120.2 million net of $5.4 million offering expenses. Pursuant to an Investment Agreement, Lime Rock Partners V, L.P., or Lime Rock, agreed to backstop the rights offering by purchasing, at the subscription price, shares of common stock not purchased by our existing stockholders. We sold 15,794,644 shares of our common stock to existing stockholders who exercised their rights through the rights offering and 19,889,044 shares of common stock to Lime Rock, at a price of $2.50 per share. We issued 36,393 shares of 7.0% convertible perpetual preferred stock to Lime Rock and received proceeds of approximately $34.2 million net of $2.2 million offering expenses.

- 53 -

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

The preferred stock has an initial liquidation preference of $1,000 per share and is adjusted to $3,000 per share upon certain liquidation events. Dividends on the preferred stock are declared quarterly if approved by our Board of Directors and dividends accumulate if not paid. The preferred stock is, with respect to dividend rights and rights upon liquidation, winding-up, or dissolution: (1) senior to common stock and any other class or series of capital stock, the terms of which do not expressly provide that such class or series ranks senior to or on parity with the preferred stock; (2) on a parity with any other class or series of capital stock, the terms of which provide that it will rank on a parity with the preferred stock; (3) junior to each class or series of capital stock (other than common stock) established after the original issue date, the terms of which expressly provide that it will rank senior to the preferred stock; and (4) junior to all our existing and future debt obligations and other liabilities, including claims of trade creditors.

During the year ended December 31, 2009, we declared $1.3 million in dividends on our preferred stock. Accrued dividends of approximately $637,000 were included in our accrued expense balance of $21.9 million as of December 31, 2009. The accrued dividends were paid in February 2010.

Each share of the preferred stock is convertible at the holder’s option, at any time into 390.2439 shares of our common stock under certain conditions, subject to specified adjustments. This conversion rate represents an equivalent conversion price of approximately $2.56 per share. Conversion is limited to the earlier of June 26, 2012 or the date on which the transfer restrictions included in the Investment Agreement expire, unless immediately after giving effect to such conversion, such person or group would not beneficially own a number of shares of our common stock exceeding 35% of the total number of issued and outstanding shares of common stock, unless we have given prior written consent to such conversion. In addition, we will be able to cause the preferred stock to be converted into common stock five years after issuance if our common stock is trading at a premium of 300% to the conversion price for 30 consecutive trading days prior to our issuance of a press release announcing the mandatory conversion. Generally, holders of the preferred stock vote together with the common stock on an as-converted basis, however, the preferred stock voting rights held by any person or group when aggregated with common stock is limited to 35% of all the votes to be cast by all stockholders, including holders of common stock.

During 2009, we had restricted stock award grants, and options exercised, which resulted in 20,099 shares of our common stock being issued for approximately $43,000. We recognized approximately $4.8 million of compensation expense related to share based payments that was recorded as capital in excess of par value (see Note 1). Due to expired unexercised nonqualified stock options and restricted stock vesting at market prices lower than the grant price, we adjusted $2.3 million of excess tax asset against additional paid in capital.

We issued 1.0 million shares of our common stock in connection with the acquisition of AWC in July 2010 (see Note 3).

During 2010, we had restricted stock award grants, vested performance-based restricted stock and options exercised, which resulted in 1,343,818 shares of our common stock being issued and due to net exercise provisions of the grants, we paid $1.7 million for payroll taxes on those net exercises. We recognized approximately $8.0 million of compensation expense related to share-based payments that was recorded as capital in excess of par value (see Note 1). Due to restricted stock vesting at market prices lower than the grant price, we adjusted $1.2 million of excess tax asset against additional paid in capital.

During the year ended December 31, 2010, we declared $2.5 million in dividends on our preferred stock. Accrued dividends of approximately $637,000 were included in our accrued expense balance of $30.7 million as of December 31, 2010. The accrued dividends were paid in January 2011.

NOTE 10 — STOCK OPTIONS

In 2000, we issued stock options and promissory notes to certain directors as compensation for services as directors (See Note 7). Options to purchase 4,800 shares of our common stock were granted with an exercise price of $13.75 per share. These options vested immediately and could have been exercised any time prior to March 28, 2010. As of December 31, 2010, none of the stock options remain outstanding. No compensation expense has been recorded for these options as they were issued with an exercise price equal to the fair value of the common stock at the date of grant.

The 2003 Incentive Stock Plan, or 2003 Plan, as amended, permits us to grant to our key employees and outside directors various forms of stock incentives, including, among others, incentive and non-qualified stock options and restricted stock. The 2003 Plan is administered by the Compensation Committee of the Board, which consists of two or more directors appointed by the Board. The following benefits may be granted under the 2003 Plan: (a) stock appreciation rights; (b) restricted stock; (c) performance awards; (d) incentive stock options; (e) nonqualified stock options; and (f) other stock-based awards. Stock incentive terms are not to be in excess of ten years. The maximum number of shares of our common stock that may be issued under the 2003 Plan shall be the lesser of 3,000,000 shares or 15% of the total number of shares of common stock outstanding.

- 54 -

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

The 2006 Incentive Plan, or 2006 Plan, was approved and amended by our stockholders in November 2006 and 2009. The 2006 Plan is administered by the Compensation Committee of the Board. The maximum number of shares of our common stock that may be issued under the 2006 Plan is equal to 8,500,000 shares, subject to adjustment in the event of stock splits and certain other corporate events. The 2006 Plan provides for the grant of any or all of the following types of awards: (i) stock options, including incentive stock options and non-qualified stock options; (ii) bonus stock; (iii) restricted stock awards; (iv) performance awards; and (v) other stock-based awards. Except with respect to awards of incentive stock options, all of our employees, consultants and non-employee directors are eligible to participate in the 2006 Plan. The term of each Award shall be for such period as may be determined by the Committee; provided, that in no event shall the term of any Award exceed a period of ten years from the date of its grant.

A summary of our stock option activity and related information is as follows:


	December 31, 2010					December 31, 2009					December 31, 2008
	Shares Under Option			Weighted Ave. Exercise Price		Shares Under Option			Weighted Ave. Exercise Price		Shares Under Option			Weighted Avg. Exercise Price
Beginning balance		701,732		$	6.31		901,732		$	10.95		986,763		$	10.77
Granted		1,072,253			3.78		125,000			1.23		—			—
Canceled		(21,967	)		8.30		(305,000	)		18.18		(13,328	)		8.87
Exercised		(1,000	)		1.23		(20,000	)		2.75		(71,703	)		8.83

Ending balance		1,751,018		$	4.74		701,732		$	6.31		901,732		$	10.95

The total intrinsic value of stock options (the amount by which the market price of the underlying stock on the date of exercise exceeds the exercise price of the option) exercised was approximately $5,000, $36,000 and $542,000 during the years ended December 31, 2010, 2009 and 2008, respectively. As of December 31, 2010, there was approximately $2.2 million of total unrecognized compensation cost related to stock options, with $535,000, $511,000, $506,000, $506,000 and $129,000 to be recognized during the years ended December 31, 2011 through 2015, respectively.

The following table summarizes additional information about our stock options outstanding as of December 31, 2010:


		Options Outstanding						Options Exercisable
Range of Exercise Prices		Number of options		Weighted Average Remaining Contractual Life (in Years)		Weighted Average Exercise Price		Number of options		Weighted Average Remaining Contractual Life (in Years)		Weighted Average Exercise Price

	$ 1.23-2.75		126,000		8.10	$	1.25		26,000		7.78	$	1.35
	3.77-4.87		1,359,086		8.08		3.87		293,500		4.07		4.18
	10.85-14.74		265,932		4.96		10.86		265,932		4.96		10.86


	$ 1.23-14.74		1,751,018		7.61	$	4.74		585,432		4.64	$	7.09

The aggregate pretax intrinsic value of stock options outstanding and exercisable was approximately $5.1 million and $1.0 million, respectively, at December 31, 2010. The amount represents the value that would have been received by the option holders had the respective options been exercised on December 31, 2010.

- 55 -

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

Restricted Stock Awards

In addition to stock options, our 2003 and 2006 Plans allow for the grant of restricted stock awards, or RSA. A time-lapse RSA is an award of common stock, where each unit represents the right to receive at the end of a stipulated period one unrestricted share of stock with no exercise price. The time-lapse RSA restrictions lapse periodically over an extended period of time not exceeding 10 years. We determine the fair value of RSAs based on the market price of our common stock on the date of grant. Compensation cost for RSAs is primarily recognized on a straight-line basis over the vesting or service period and is net of forfeitures. A performance-based RSA is an award of common stock, where each unit represents the right to receive one unrestricted share of stock with no exercise price at the attainment of established performance criteria. In connection with performance-based RSAs, compensation cost is based on estimated number of shares expected to be issued. During 2010, we granted 1,237,750 performance-based RSAs to executive officers and key employees that vest upon meeting certain financial performance conditions over the next five years. Effective December 29, 2010, we accelerated the vesting of 244,383 shares of time-based restricted stock and 544,000 shares of performance-based restricted stock previously granted to employees. The fair value of the performance-based RSAs were based on third-party valuations.

The following table summarizes activity in our nonvested restricted stock awards:


	December 31, 2010					December 31, 2009					December 31, 2008
	Number of Shares			Weighted Ave. Grant Date Fair Value Per Share		Number of Shares			Weighted Ave. Grant Date Fair Value Per Share		Number of Shares			Weighted Ave. Grant Date Fair Value Per Share
Beginning balance		837,626		$	15.63		953,102		$	15.34		993,203		$	17.45
Granted		2,061,750			3.78		17,000			1.23		258,670			9.47
Vested		(1,193,976	)		8.80		(122,276	)		11.68		(298,771	)		17.26
Forfeited		(3,333	)		3.77		(10,200	)		12.05		—			—

Ending balance		1,702,067		$	6.09		837,626		$	15.63		953,102		$	15.34

The total fair value of RSA shares that vested during 2010 and 2009 was approximately $6.8 million and $371,000, respectively. As of December 31, 2010, there was approximately $4.3 million of total unrecognized compensation cost related to nonvested RSAs, with $1.7 million, $1.0 million, $769,000, $739,000 and $71,000 to be recognized during the years ended December 31, 2011 through 2015, respectively.

NOTE 11 — STOCK PURCHASE WARRANTS

In conjunction with BCH debt financing in January of 2007, BCH issued a common stock warrant for 250,000 shares to a financial institution. The warrant entitles the holder to acquire up to 250,000 shares of common stock of BCH at an exercise price of $10.00 per share over a five-year period.

NOTE 12 — GAIN ON DEBT EXTINGUISHMENT

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

- 56 -

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

NOTE 13 — CONDENSED CONSOLIDATED FINANCIAL INFORMATION

Set forth on the following pages are the condensed consolidating financial statements of (i) Allis-Chalmers Energy Inc., (ii) its subsidiaries that are guarantors of the senior notes and revolving credit facility and (iii) the subsidiaries that are not guarantors of the senior notes and revolving credit facility (in thousands):

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2010


	Allis- Chalmers (Parent/ Guarantor)			Subsidiary Guarantors		Subsidiary Non- Guarantors		Consolidating Adjustments			Consolidated Total
Assets
Cash and cash equivalents	$	—		$	16,380	$	4,560	$	—		$	20,940
Trade receivables, net		—			79,100		77,397		(11,537	)		144,960
Inventories		—			22,066		20,074		—			42,140
Intercompany receivables		—			120,399		—		(120,399	)		—
Note receivable from affiliate		18,359			—		—		(18,359	)		—
Prepaid expenses and other		2,068			5,034		3,925		—			11,027

Total current assets		20,427			242,979		105,956		(150,295	)		219,067
Property and equipment, net		—			461,187		262,047		—			723,234
Goodwill		—			28,944		17,389		—			46,333
Other intangible assets, net		414			27,278		6,207		—			33,899
Debt issuance costs, net		7,405			—		—		—			7,405
Note receivable from affiliates		1,800			—		—		(1,800	)		—
Investments in affiliates		971,661			—		—		(971,661	)		—
Other assets		35,633			7,390		2,695		—			45,718


Total assets	$	1,037,340		$	767,778	$	394,294	$	(1,123,756	)	$	1,075,656


Liabilities and Stockholders’ Equity
Current maturities of long-term debt	$	—		$	979	$	14,236	$	—		$	15,215
Trade accounts payable		—			18,634		38,945		(11,537	)		46,042
Accrued salaries, benefits and payroll taxes		—			8,983		23,807		—			32,790
Accrued interest		15,310			—		214		—			15,524
Accrued expenses		1,192			18,504		10,980		—			30,676
Intercompany payables		105,389			—		15,010		(120,399	)		—
Note payable to affiliate		—			—		18,359		(18,359	)		—

Total current liabilities		121,891			47,100		121,551		(150,295	)		140,247
Long-term debt, net of current maturities		466,738			—		11,487		—			478,225
Note payable to affiliate		—			—		1,800		(1,800	)		—
Other long-term liabilities		—			—		8,473		—			8,473

Total liabilities		588,629			47,100		143,311		(152,095	)		626,945

Commitments and contingencies

Stockholders’ Equity
Preferred Stock		34,183			—		—		—			34,183
Common stock		737			3,527		42,963		(46,490	)		737
Capital in excess of par value		429,924			589,676		137,439		(727,115	)		429,924
Retained earnings (deficit)		(16,133	)		127,475		70,581		(198,056	)		(16,133	)

Total stockholders’ equity		448,711			720,678		250,983		(971,661	)		448,711


Total liabilities and stock holders’ equity	$	1,037,340		$	767,778	$	394,294	$	(1,123,756	)	$	1,075,656

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ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

CONDENSED CONSOLIDATING INCOME STATEMENTS

For the Year Ended December 31, 2010


	Allis- Chalmers (Parent/ Guarantor)			Subsidiary Guarantors			Subsidiary Non- Guarantors			Consolidating Adjustments			Consolidated Total

Revenues	$	—		$	280,919		$	380,308		$	(1,562	)	$	659,665

Operating costs and expenses
Direct costs		—			177,205			322,477			(1,562	)		498,120
Depreciation		—			58,066			26,052			—			84,118
Selling, general and administrative		7,168			38,005			15,261			—			60,434
Loss on asset dispositions		—			10,624			—			—			10,624
Amortization		46			4,014			746			—			4,806

Total operating costs and expenses		7,214			287,914			364,536			(1,562	)		658,102


Income (loss) from operations		(7,214	)		(6,995	)		15,772			—			1,563

Other income (expense):
Equity earnings in affiliates, net of tax		10,118			—			—			(10,118	)		—
Interest, net		(42,476	)		(506	)		(2,306	)		—			(45,288	)
Other		60			(2,322	)		(949	)		—			(3,211	)

Total other income (expense)		(32,298	)		(2,828	)		(3,255	)		(10,118	)		(48,499	)


Income (loss) before income taxes		(39,512	)		(9,823	)		12,517			(10,118	)		(46,936	)

Income tax benefit (expense)		—			17,096			(9,672	)		—			7,424


Net income (loss)		(39,512	)		7,273			2,845			(10,118	)		(39,512	)

Preferred stock dividend		(2,548	)		—			—			—			(2,548	)


Net income (loss) attributed to common stockholders	$	(42,060	)	$	7,273		$	2,845		$	(10,118	)	$	(42,060	)

- 58 -

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW

For the Year Ended December 31, 2010


	Allis- Chalmers (Parent/ Guarantor)			Subsidiary Guarantors			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
Cash Flows from Operating Activities:
Net income (loss)	$	(39,512	)	$	7,273		$	2,845		$	(10,118	)	$	(39,512	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation & amortization		46			62,080			26,798			—			88,924
Amortization and write-off of deferred financing fees		2,192			22			—			—			2,214
Stock based compensation		8,030			—			—			—			8,030
Allowance for bad debts		—			368			—			—			368
Equity earnings in affiliates		(10,118	)		—			—			10,118			—
Deferred income taxes		(14,713	)		(2,757	)		393			—			(17,077	)
Loss on sale of equipment		—			646			34			—			680
Loss on asset dispositions		—			10,624			—			—			10,624
Loss on investment		—			1,466			—			—			1,466
Equity in losses of unconsolidated affiliates		—			783			—			—			783
Changes in operating assets and liabilities, net of acquisitions:
(Increase) in trade receivables		—			(17,248	)		(18,435	)		—			(35,683	)
(Increase) in inventories		—			(4,137	)		(1,817	)		—			(5,954	)
Decrease (increase) in other current assets		(1,917	)		7,533			5,526			—			11,142
Decrease in other assets		—			426			1,320			—			1,746
(Decrease) increase in accounts payable		—			(3,979	)		15,040			—			11,061
(Decrease) in accrued interest		(62	)		(228	)		(7	)		—			(297	)
Increase in accrued expenses		440			5,577			1,421			—			7,438
(Decrease) in other liabilities		—			—			(909	)		—			(909	)
Increase in accrued salaries, benefits and payroll taxes		—			6,157			3,715			—			9,872

Net cash provided (used) by operating activities		(55,614	)		74,606			35,924			—			54,916


Cash Flows from Investing Activities:
Acquisition, net of cash acquired		—			(15,935	)		—			—			(15,935	)
Proceeds from sale of investments		—			368			—			—			368
Purchase of property and equipment		—			(75,488	)		(26,667	)		—			(102,155	)
Deposits on asset commitments		—			18,604			(257	)		—			18,347
Investment in affiliates		(17,165	)		—			—			17,165			—
Notes receivable from affiliates		13,820			—			—			(13,820	)		—
Proceeds from asset dispositions		—			25,000			—			—			25,000
Proceeds from sale of equipment		—			6,181			457			—			6,638

Net cash provided (used) in investing activities		(3,345	)		(41,270	)		(26,467	)		3,345			(67,737	)

- 59 -

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW (Continued)


	Allis- Chalmers (Parent/ Guarantor)			Subsidiary Guarantors			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total

Cash Flows from Financing Activities:
Proceeds from issuance of long-term debt		—			—			4,000			—			4,000
Payments on long-term debt		—			(26,281	)		(15,887	)		—			(42,168	)
Borrowings under line of credit		36,500			—			—			—			36,500
Payment of preferred stock dividend		(2,548	)		—			—			—			(2,548	)
Proceeds from parent contributions		—			17,165			—			(17,165	)		—
Accounts receivable from affiliates		—			(39,698	)		—			39,698			—
Accounts payable to affiliates		28,102			—			11,596			(39,698	)		—
Note payable to affiliate		—			—			(13,820	)		13,820			—
Proceeds from exercise of options		(1,722	)		—			—			—			(1,722	)
Income tax impact of stock-based compensation plans		(1,184	)		—			—			—			(1,184	)
Debt issuance costs		(189	)		—			—			—			(189	)

Net cash provided (used) by financing activities		58,959			(48,814	)		(14,111	)		(3,345	)		(7,311	)


Net increase (decrease) in cash and cash equivalents		—			(15,478	)		(4,654	)		—			(20,132	)
Cash and cash equivalents at beginning of year		—			31,858			9,214			—			41,072

Cash and cash equivalents at end of year	$	—		$	16,380		$	4,560		$	—		$	20,940

- 60 -

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2009


	Allis- Chalmers (Parent/ Guarantor)		Subsidiary Guarantors		Subsidiary Non- Guarantors		Consolidating Adjustments			Consolidated Total
Assets
Cash and cash equivalents	$	—	$	31,858	$	9,214	$	—		$	41,072
Trade receivables, net		—		47,358		58,962		(1,261	)		105,059
Inventories		—		16,271		18,257		—			34,528
Intercompany receivables		—		79,521		767		(80,288	)		—
Note receivable from affiliate		28,379		—		—		(28,379	)		—
Prepaid expenses and other		891		6,826		9,872		—			17,589

Total current assets		29,270		181,834		97,072		(109,928	)		198,248
Property and equipment, net		—		489,921		256,557		—			746,478
Goodwill		—		23,251		17,388		—			40,639
Other intangible assets, net		460		25,236		6,953		—			32,649
Debt issuance costs, net		9,408		137		—		—			9,545
Note receivable from affiliates		4,415		—		—		(4,415	)		—
Investments in affiliates		942,378		—		—		(942,378	)		—
Other assets		24,366		25,039		3,656		—			53,061


Total assets	$	1,010,297	$	745,418	$	381,626	$	(1,056,721	)	$	1,080,620


Liabilities and Stockholders’ Equity
Current maturities of long-term debt	$	—	$	4,444	$	12,583	$	—		$	17,027
Trade accounts payable		—		12,195		23,905		(1,261	)		34,839
Accrued salaries, benefits and payroll taxes		—		2,762		20,092		—			22,854
Accrued interest		15,372		228		221		—			15,821
Accrued expenses		752		11,608		9,558		—			21,918
Intercompany payables		80,288		—		—		(80,288	)		—
Note payable to affiliate		—		—		28,379		(28,379	)		—

Total current liabilities		96,412		31,237		94,738		(109,928	)		112,459
Long-term debt, net of current maturities		430,238		19,941		25,027		—			475,206
Note payable to affiliate		—		—		4,415		(4,415	)		—
Other long-term liabilities		—		—		9,308		—			9,308

Total liabilities		526,650		51,178		133,488		(114,343	)		596,973

Commitments and contingencies

Stockholders’ Equity
Preferred Stock		34,183		—		—		—			34,183
Common stock		714		3,526		42,963		(46,489	)		714
Capital in excess of par value		422,823		570,512		137,439		(707,951	)		422,823
Retained earnings		25,927		120,202		67,736		(187,938	)		25,927

Total stockholders’ equity		483,647		694,240		248,138		(942,378	)		483,647


Total liabilities and stock holders’ equity	$	1,010,297	$	745,418	$	381,626	$	(1,056,721	)	$	1,080,620

- 61 -

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

CONDENSED CONSOLIDATING INCOME STATEMENTS

For the Year Ended December 31, 2009


	Allis- Chalmers (Parent/ Guarantor)			Subsidiary Guarantors			Subsidiary Non- Guarantors			Consolidating Adjustments			Consolidated Total

Revenues	$	—		$	202,727		$	303,579		$	(53	)	$	506,253

Operating costs and expenses
Direct costs		—			133,629			245,861			(53	)		379,437
Depreciation		—			56,886			21,390			—			78,276
Selling, general and administrative		4,054			32,592			14,117			—			50,763
Loss on asset dispositions		—			—			1,602			—			1,602
Amortization		46			3,907			769			—			4,722

Total operating costs and expenses		4,100			227,014			283,739			(53	)		514,800


Income (loss) from operations		(4,100	)		(24,287	)		19,840			—			(8,547	)

Other income (expense):
Equity earnings in affiliates, net of tax		1,051			—			—			(1,051	)		—
Interest, net		(44,568	)		(25	)		(3,480	)		—			(48,073	)
Gain on debt extinguishment		26,365			—			—			—			26,365
Other		62			(155	)		(705	)		—			(798	)

Total other income (expense)		(17,090	)		(180	)		(4,185	)		(1,051	)		(22,506	)


Income (loss) before income taxes		(21,190	)		(24,467	)		15,655			(1,051	)		(31,053	)

Income tax benefit (expense)		—			15,590			(5,727	)		—			9,863


Net income (loss)		(21,190	)		(8,877	)		9,928			(1,051	)		(21,190	)

Preferred stock dividend		(1,302	)		—			—			—			(1,302	)


Net income (loss) attributed to common stockholders	$	(22,492	)	$	(8,877	)	$	9,928		$	(1,051	)	$	(22,492	)

- 62 -

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ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements-(Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW

For the Year Ended December 31, 2009


	Allis- Chalmers (Parent/ Guarantor)			Subsidiary Guarantors			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Total
Cash Flows from Operating Activities:
Net income (loss)	$	(21,190	)	$	(8,877	)	$	9,928		$	(1,051	)	$	(21,190	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation & amortization		46			60,793			22,159			—			82,998
Amortization and write-off of deferred financing fees		2,215			16			—			—			2,231
Gain on debt extinguishment		(26,365	)		—			—			—			(26,365	)
Stock based compensation		4,799			—			—			—			4,799
Allowance for bad debts		—			2,835			—			—			2,835
Equity earnings in affiliates		(1,051	)		—			—			1,051			—
Deferred income taxes		(18,173	)		1,569			(1,279	)		—			(17,883	)
(Gain) loss on sale of equipment		—			(957	)		9			—			(948	)
Loss on asset dispositions		—			—			1,602			—			1,602
Changes in operating assets and liabilities, net of acquisitions:
Decrease in accounts receivables		—			38,074			11,903			—			49,977
Decrease in inventories		—			3,111			1,448			—			4,559
Decrease (increase) in other current assets		7,369			3,279			(6,020	)		—			4,628
Decrease (increase) in other assets		(111	)		223			1,536			—			1,648
(Decrease) in accounts payable		—			(13,346	)		(14,242	)		—			(27,588	)
(Decrease) increase in accrued interest		(2,560	)		228			(470	)		—			(2,802	)
(Decrease) in accrued expenses		(632	)		(2,233	)		(1,742	)		—			(4,607	)
(Decrease) in other liabilities		—			(64	)		(987	)		—			(1,051	)
(Decrease) increase in accrued salaries, benefits and payroll taxes		—			(1,171	)		3,833			—			2,662

Net cash provided (used) by operating activities		(55,653	)		83,480			27,678			—			55,505


Cash Flows from Investing Activities:
Net sales (purchases) of investment interests		(2,393	)		—			1,291			—			(1,102	)
Purchase of property and equipment		—			(58,142	)		(19,925	)		—			(78,067	)
Deposits on asset commitments		—			1,995			690			—			2,685
Investment in affiliates		(4,100	)		—			—			4,100			—
Notes receivable from affiliates		(2,069	)		—			—

Allis Chalmers Energy Inc. 10-K