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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


(Mark One)
þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		FOR THE FISCAL YEAR ENDED DECEMBER 31, 2006
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		FOR THE TRANSITION PERIOD FROM TO

Commission file number 1-2199

ALLIS-CHALMERS ENERGY INC.

(Exact name of registrant as specified in its charter)


Delaware		39-0126090
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

5075 WESTHEIMER, SUITE 890 HOUSTON, TEXAS (Address of principal executive offices)		77056 (Zip code)

(713) 369-0550

Registrant’s telephone number, including area code

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


Title of Security:		Name of Exchange:

Common Stock, par value $0.01 per share		American Stock Exchange

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

NONE

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

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

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

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

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

Large accelerated filer o Accelerated filer þ Non-accelerated filer o

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

The aggregate market value of the common equity held by non-affiliates of the registrant, computed using the closing price of the common stock of $13.59 per share on June 30, 2006, as reported on the American Stock Exchange, was approximately $139,745,249 (affiliates included for this computation only: directors, executive officers and holders of more than 5% of the registrant’s common stock).

As of March 1, 2007 there were 34,251,443 shares of common stock issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

Certain information called for by Items 10, 11, 12, 13 and 14 of Part III will be included in an amendment to this annual report on Form 10-K or incorporated by reference from the registrant’s definitive proxy statement for its 2007 annual meeting of stockholders.

DEFINITIONS


“air 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.

“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.

“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.

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

“laydown machines”		A truck mounted machine used to move drill pipe, casing and tubing onto a pipe rack (from which a derrick crane lifts the drill pipe, casing and tubing and inserts it into the well).

“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.

“logging-while-drilling”		The technique of measuring, in real time, the formation pressure and the position of equipment inside of a well.

“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.

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

“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.

“torque turn service” or “torque turn equipment”		A monitoring device to insure proper makeup of the casing.

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

“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.

“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.

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. Further information about the risks and uncertainties that may impact us are described in “Risk Factors” beginning on page 13 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, domestically in Texas, Louisiana, New Mexico, Colorado, Oklahoma, Mississippi, Utah, Wyoming, Arkansas, Alabama, West Virginia, offshore in the Gulf of Mexico, and internationally primarily in Argentina and Mexico. We operate in six sectors of the oil and natural gas service industry: rental tools, international drilling, directional drilling services; casing and tubing services; compressed air drilling services; and production services. Our central operating strategy is to provide high-quality, technologically advanced services and equipment. As a result of our commitment to customer service, we have developed strong relationships with many of the leading oil and natural gas companies, including both independents and majors.

Our growth strategy is focused on identifying and pursuing opportunities in markets we believe are growing faster than the overall oilfield services industry in which we believe we can capitalize on our competitive strengths. Over the past several years, we have significantly expanded the geographic scope of our operations and the range of services we provide through organic growth and strategic acquisitions. Our organic growth has primarily been achieved through expanding our geographic scope, acquiring complementary property and equipment, hiring personnel to service new regions and cross-selling our products and services from existing operating locations. Since 2001, we have completed 19 acquisitions, including six in 2005 and five significant acquisitions in 2006.

Unless the context requires otherwise, references in this annual report to “Allis-Chalmers,” “we”, “us”, “our” and “ours” refer to Allis-Chalmers Energy Inc., together with its subsidiaries.

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

We have adopted a Code of Business Ethics and Conduct to provide guidance to our directors, officers and employees on matters of business ethics and conduct. Our Code of Business Ethics and Conduct is available on the investor relations section of our website.

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

Divisional and geographic financial information appears in “Item 8. Financial Information — Notes to Consolidated Financial Statements — Note 16.”

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.

	•	In May 2001, under new management we consummated a merger in which we acquired OilQuip Rentals, Inc., or OilQuip, and its wholly-owned subsidiary, Mountain Compressed Air, Inc., or Mountain Air.

	•	In December 2001, we sold Houston Dynamic Services, Inc., our last pre-bankruptcy business.

	•	In February 2002, we acquired approximately 81% of the capital stock of Allis-Chalmers Tubular Services Inc., or Tubular, formerly known as Jens’ Oilfield Service, Inc. and substantially all of the capital stock of Strata Directional Technology, Inc., or Strata.

	•	In July 2003, we entered into a limited liability company operating agreement with M-I L.L.C., or M-I, a joint venture between Smith International and Schlumberger N.V., to form a Delaware limited liability company named AirComp LLC, or AirComp. Pursuant to this agreement, we owned 55% and M-I owned 45% of AirComp.

	•	In September 2004, we acquired the remaining 19% of the capital stock of Tubular.

	•	In September 2004, we acquired all of the outstanding stock of Safco-Oil Field Products, Inc., or Safco.

	•	In November 2004, AirComp acquired substantially all of the assets of Diamond Air Drilling Services, Inc. and Marquis Bit Co., LLC, which we refer to collectively as Diamond Air.

	•	In December 2004, we acquired Downhole Injection Services, LLC, or Downhole.

	•	In January 2005, we changed our name from Allis-Chalmers Corporation to Allis-Chalmers Energy Inc.

	•	In April 2005, we acquired all of the outstanding stock of Delta Rental Service, Inc., or Delta.

	•	In May 2005, we acquired all of the outstanding stock of Capcoil Tubing Services, Inc., or Capcoil.

	•	In July 2005, we acquired M-I’s interest in AirComp, and acquired the compressed air drilling assets of W. T. Enterprises, Inc., or W.T.

	•	Effective August 2005, we acquired all of the outstanding stock of Target Energy Inc., or Target.

	•	In September 2005, we acquired the casing and tubing assets of IHS/Spindletop, a division of Patterson Services, Inc., a subsidiary of RPC, Inc.

	•	In January 2006, we acquired all of the outstanding stock of Specialty Rental Tools, Inc., or Specialty.

	•	In February 2006, we merged Downhole into Capcoil and renamed the merged entity, Allis-Chalmers Production Services Inc. We also merged Specialty and Delta into Safco and renamed the merged entity, Allis-Chalmers Rental Tools, Inc. In December 2006, we renamed to Allis-Chalmers Rental Services Inc, or Rental.

	•	In April 2006, we acquired all of the outstanding stock of Rogers Oil Tool Services, Inc., or Rogers.

	•	In August 2006, we acquired all of the outstanding stock of DLS Drilling, Logistics & Services Corporation, or DLS.

	•	In October 2006, we acquired all of the outstanding stock of Petro-Rentals, Incorporated, or Petro Rentals.

	•	In December 2006, we acquired all of the outstanding stock of Tanus Argentina S.A., or Tanus.

	•	In December 2006, we acquired substantially all of the assets of Oil & Gas Rental Services, Inc., or OGR.

	•	In December 2006, we merged Target into Strata and Rogers into Tubular.

As a result of these transactions, our prior results may not be indicative of current or future operations of those sectors.

Industry Overview

We provide products and services primarily to domestic onshore and offshore oil and natural gas exploration and production companies. The main factor influencing demand for our products and services is the level of drilling activity by oil and natural gas companies, which, in turn, depends largely on current and anticipated future crude oil and natural gas prices and production depletion rates. According to the Energy Information Agency of the U.S. Department of Energy, or EIA, from 1990 to 2005, demand for oil and natural gas in the United States grew at an average annual rate of 1.5%, while supply decreased at an average annual rate of just over 2%. Current industry forecasts suggest an increasing demand for oil and natural gas coupled with a flat or declining production curve, which we believe should result in the continuation of historically high crude oil and natural gas commodity prices. The EIA forecasts that U.S. oil and natural gas consumption will increase at an average annual rate of 1.4% and 1.3% through 2025, respectively. Conversely, the EIA estimates that U.S. oil production will remain flat and natural gas production will increase at an average annual rate of 0.6%.

We anticipate that oil and natural gas exploration and production companies will continue to increase capital spending for their exploration and drilling programs. In recent years, much of this expansion has focused on natural gas drilling activities. According to Baker Hughes rig count data, the average total rig count in the United States increased 91% from 918 in 2000 to 1,752 as of March 2, 2007, while the average natural gas rig count increased 103% from 720 in 2000 to 1,458 as of March 2, 2007. While the number of rigs drilling for natural gas has increased significantly since the beginning of 1996, natural gas production has only increased by approximately 1.5% over the same period of time. This is largely a function of increasing decline rates for natural gas wells in the United States. We believe that a continued increase in drilling activity will be required for the natural gas industry to help meet the expected increased demand for natural gas in the United States.

We believe oil and natural gas producers are becoming increasingly focused on their core competencies in identifying reserves and reducing burdensome capital and maintenance costs. In addition, we believe our customers are currently consolidating their supplier bases to streamline their purchasing operations and benefit from economies of scale.

Competitive Strengths

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

Strategic position in high growth markets. We focus on markets we believe are growing faster than the overall oilfield services industry and in which we can capitalize on our competitive strengths. Pursuant to this strategy, we have become a significant provider of products and services in directional drilling, air drilling and production-related services employing coiled tubing and capillary tubing. We employ approximately 85 full-time directional drillers, and we believe our ability to attract and retain experienced drillers has made us a leader in the segment. We also believe we are one of the largest air drillers based on amount of air drilling equipment. In addition, we have significant operations in what we believe will be among the higher growth oil and natural gas producing regions within the United States and internationally, including the Barnett Shale in North Texas, onshore and offshore Louisiana, the Piceance Basin in Southern Colorado, all five oil and natural gas producing regions in Mexico, and all five major oil and natural gas producing regions of Argentina.

Strong relationships with diversified customer base. We have strong relationships with many of the major and independent oil and natural gas producers and service companies in Texas, Louisiana, New Mexico, Colorado, Oklahoma, Mississippi, Utah, Wyoming, Arkansas, offshore in the Gulf of Mexico, Argentina and Mexico. Our largest customers include Anadarko Petroleum, Apache Corporation, BHP-Billiton, BP, Chevron, ConocoPhilips, Dominion Resources, El Paso Corporation, Materiales y Equipo Petroleo, or Matyep, McMoran Oil & Gas, Murphy Oil, Newfield Exploration, Occidental Petroleum Corporation, Pan American Energy, Petrohawk Energy, Helix Energy Solutions Group, Repsol-YPF and Total Austral. Since 2002, we have broadened our customer base as a result of our acquisitions, technical expertise and reputation for quality customer service and by providing customers with technologically advanced equipment and highly skilled operating personnel.

Successful execution of growth strategy. Over the past five years, we have grown both organically and through successful acquisitions of competing businesses. Since 2001, we have completed 19 acquisitions. We strive to improve the operating performance of our acquired businesses by increasing their asset utilization and operating efficiency. These acquisitions and organic growth have expanded our geographic presence and customer base and, in turn, have enabled us to cross-sell various products and services through our existing operating locations.

Diversified and increased cash flow sources. We operate as a diversified oilfield service company through our six business segments. We believe that our product and service offerings and geographical presence through our six business segments provide us with diverse sources of cash flow. Our acquisition of DLS provides greater international presence coupled with relatively stable long-term drilling contracts. Our acquisition of Petro Rentals significantly enhances our production-related services and equipment, and our recent acquisition of substantially all the assets of OGR further expands our rental tools segment and increases our offshore and international operations.

Experienced management team. Our executive management team has extensive experience in the energy sector, and consequently has developed strong and longstanding relationships with many of the major and independent exploration and production companies. We believe that our management team has demonstrated its ability to grow our businesses organically, make strategic acquisitions and successfully integrate these acquired businesses into our operations.

Business Strategy

The key elements of our growth strategy include:

Mitigate cyclical risk through balanced operations. We strive to mitigate cyclical risk in the oilfield service sector by balancing our operations between onshore versus offshore; drilling versus production; rental tools versus service; domestic versus international; and natural gas versus crude oil. We will continue to shape our organic and acquisition growth efforts to provide further balance across these five categories.

Expand geographically to provide greater access and service to key customer segments. We have locations in Texas, New Mexico, Colorado, Oklahoma and Louisiana in order to enhance our proximity to customers and more efficiently serve their needs. Our acquisition of DLS expanded our geographic footprint into Argentina. We plan to continue to establish new locations in the United States and internationally.

Prudently pursue strategic acquisitions. To complement our organic growth, we seek to opportunistically complete, at attractive valuations, strategic acquisitions that will be accretive to earnings, complement our products and services, expand our geographic footprint and market presence, and further diversify our customer base.

Expand products and services provided in existing operating locations. Since the beginning of 2004, we have invested approximately $62.1 million in capital expenditures to grow our business organically by expanding our product and service offerings. This strategy is consistent with our belief that oil and natural gas producers more heavily favor integrated suppliers that can provide a broad product and service offering in many geographic locations.

Increase utilization of assets. We seek to increase revenues and enhance margins by continuing to increase the utilization of our assets with new and existing customers. We expect to accomplish this through leveraging longstanding relationships with our customers and cross-selling our suite of services and equipment, while taking advantage of continued improvements in industry fundamentals. We also expect to continue to implement this strategy in our recently expanded rental tools segment, thus improving the utilization and profitability of this newly acquired business with minimal additional investment.

Business Segments

Rental Tools. We provide specialized rental equipment, including premium drill pipe, spiral heavy weight drill pipe, tubing work strings, blow out preventors, choke manifolds and various valves and handling

tools, for both onshore and offshore well drilling, completion and workover operations. Most wells drilled for oil and natural gas require some form of rental equipment in both the drilling and completion of a well. We have an inventory of specialized equipment, which includes double studded adapters, test plugs, wear bushings, adaptor spools, baskets, spacer spools and other assorted handling tools in various sizes to meet our customers’ demands. We charge customers for rental equipment on a daily basis. Our customers are liable for the cost of inspection, repairs and lost or damaged equipment. We currently provide rental equipment in Texas, Oklahoma, Louisiana, Mississippi, Colorado, offshore in the Gulf of Mexico and internationally in Malaysia, Colombia, Russia, Mexico and Canada.

Our rental tools segment was established with the acquisition of Safco in September 2004 and of Delta in April 2005. We significantly expanded our rental tools segment in January 2006 with the acquisition of Specialty. Specialty had been in the rental business for over 25 years, providing oil and natural gas operators and oilfield services companies with rental equipment. The acquisition of Specialty gave us a broader scope of rental equipment to offer our existing customer base, and allowed us to better compete in deep water drilling operations in the area of premium drill pipe and handling equipment. The acquisition of Specialty added new customer relationships and enhanced our relationships with key existing customers. In February 2006, we merged Specialty and Delta into Safco and named the entity, Allis-Chalmers Rental Tools, Inc. which we subsequently renamed Allis-Chalmers Rental Services, Inc. We further expanded this segment with the acquisition of substantially all the assets of OGR in December 2006. The assets we acquired included an extensive inventory of premium rental equipment, including drill pipe, spiral heavy weight drill pipe, tubing work strings, landing strings, blow out preventors, choke manifolds and various valves and handling tools for oil and natural gas drilling. Included in the acquisition were OGR’s facilities in Morgan City, Louisiana and Victoria, Texas.

International Drilling. We provide drilling, completion, workover and related services for oil and natural gas wells. Headquartered in Buenos Aires, Argentina, DLS operates out of the San Jorge, Cuyan, Neuquén, Austral and Noroeste basins of Argentina. DLS also offers a wide variety of other oilfield services such as drilling fluids and completion fluids and engineering and logistics to complement its customers’ field organization.

DLS operates a fleet of 51 rigs, including 20 drilling rigs, 18 workover rigs and 12 pulling rigs in Argentina and one drilling rig in Bolivia. Argentine rig operations are generally conducted in remote regions of the country and require substantial infrastructure and support. As of March 1, 2007, all of DLS’ rig fleet was actively marketed, except for one drilling rig that is presently inactive and requires approximately $6.4 million in capital expenditures.

DLS currently services several of the major and independent oil and natural gas producing companies in Argentina, including Pan American Energy, Repsol-YPF, Apache Corporation, Occidental Petroleum Corporation and Total Austral SA. Major competitors of DLS include Pride International, Inc., Servicios WellTech, S.A., Ensign Energy Services Inc. (formerly ODE), Nabors Industries Ltd. and Helmerich & Payne, Inc.

Directional Drilling 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. We also provide logging-while-drilling and measurement-while-drilling services. We have a team of approximately 85 full-time directional drillers and maintain a selection of approximately 160 drilling motors. According to Baker Hughes, as of March 2, 2007, 42% of all wells in the United States are drilled directionally and/or horizontally. Management believes directional drilling offers several advantages over conventional drilling including:


	•	improvement of total cumulative recoverable reserves;

	•	improved reservoir production performance beyond conventional vertical wells; and

	•	reduction of the number of field development wells.

Our straight-hole motors offer opportunity to capture additional market share. We currently provide our directional drilling services in Texas, Louisiana, Oklahoma and Colorado.

Casing and Tubing Services. We provide specialized equipment and trained operators to perform a variety of pipe handling services, including installing casing and tubing, changing out drill pipe and retrieving production tubing for both onshore and offshore drilling and workover operations, which we refer to as casing and tubing services. 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 casing and tubing services primarily in Texas, Louisiana and both onshore and offshore in the Gulf of Mexico and Mexico.

We expanded our casing and tubing services in September 2005 by acquiring the casing and tubing assets of IHS/Spindletop, a division of Patterson Services, Inc., a subsidiary of RPC, Inc. We paid $15.7 million for RPC, Inc.’s casing and tubing assets, which consisted of casing and tubing installation equipment, including hammers, elevators, trucks, pickups, power units, laydown machines, casing tools and torque turn equipment. The acquisition of RPC, Inc.’s casing and tubing assets increased our capability in casing and tubing services and expanded our geographic capability. We opened new field offices in Corpus Christi, Texas, Kilgore, Texas, Lafayette, Louisiana and Houma, Louisiana. The acquisition allowed us to enter the East Texas and Louisiana market for casing and tubing services as well as offshore in the Gulf of Mexico. Additionally, the acquisition greatly expanded our premium tubing services.

We expanded this segment again in April 2006 with the acquisition of Rogers for $13.7 million. Historically, Rogers rented, sold and serviced power drill pipe tongs and accessories and rental tongs for snubbing and well control applications and provided specialized tong operators for rental jobs. In December 2006, we merged Rogers into Tubular.

We provide equipment used in casing and tubing services in Mexico to Matyep. Matyep provides equipment and services for offshore and onshore drilling operations to Petroleos Mexicanos, known as Pemex, in Villahermosa, Reynosa, Veracruz and Ciudad del Carmen, Mexico. Matyep provides all personnel, repairs, maintenance, insurance and supervision for provision of the casing and tubing crew and torque turn service. Services to offshore drilling operations in Mexico are traditionally seasonal, with less activity during the first quarter of each calendar year due to weather conditions.

For the years ended December 31, 2006, 2005 and 2004, our Mexico operations accounted for approximately $6.5 million, $6.4 million and $5.1 million, respectively, of our revenues. We provide extended payment terms to Matyep and maintain a high accounts receivable balance due to these terms. The accounts receivable balance was approximately $3.2 million at December 31, 2006 and approximately $2.2 million at December 31, 2005. Tubular has been providing services to Pemex in association with Matyep since 1997.

Compressed Air Drilling Services. We provide compressed air equipment, chemicals and other specialized products for underbalanced drilling and production applications. With a combined fleet of over 175 compressors and boosters, we believe we are one of the world’s largest providers of compressed air or 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.

Underbalanced drilling shortens the time required to drill a well and enhances production by minimizing formation damage. There is a trend in the industry to drill, complete and workover wells with underbalanced operations and we expect the market to continue to grow.

In July 2005, we purchased the compressed air drilling assets of W. T., operating in West Texas and acquired the remaining 45% equity interest in AirComp from M-I. The acquired assets include air compressors, boosters, mist pumps, rolling stock and other equipment. These assets were integrated into AirComp’s assets and complement and add to AirComp’s product and service offerings. We currently provide compressed air drilling services in Alabama, Arkansas, Colorado, Mississippi, New Mexico, Oklahoma, Texas, Utah, West Virginia and Wyoming.

Production Services. We provide a variety of quality production-related rental tools and equipment and services, including wire line services, land and offshore pumping services and coil tubing. We also provide specialized equipment and trained operators to install and retrieve capillary tubing, through which chemicals are injected into producing wells to increase production and reduce corrosion. Chemicals are injected through

the tubing to targeted zones up to depths of approximately 20,000 feet. The result is improved production from treatment of downhole corrosion, scale, paraffin and salt build-up in producing wells. Natural gas wells with low bottom pressures can experience fluid accumulation in the tubing and well bore. This injection system can inject a foaming agent which lightens the fluids allowing them to flow out of the well. Additionally, corrosion inhibitors can be introduced to reduce corrosion in the well. In addition, we perform workover services with coiled tubing units. Our production services segment was established with the acquisition of Downhole, in December 2004, and the acquisition of Capcoil, in May 2005. In February 2006, we merged Downhole into Capcoil and named the new entity Allis-Chalmers Production Services, Inc., or Production Services. In October 2006, we expanded our production services segment with the acquisition of Petro Rentals. Petro Rentals serves both the onshore and offshore markets, providing a variety of quality rental tools and equipment and services, with an emphasis on production-related equipment and services, including wire line services and equipment, land and offshore pumping services and coiled tubing.

We have an inventory of specialized equipment consisting of capillary and coil tubing units in various sizes ranging from 1/4” to 11/4” along with nitrogen pumping and transportation equipment. We purchased two additional capillary units and two additional coil tubing units in 2006, one additional coil tubing unit was received in the first quarter of 2007 and an additional coil tubing unit is expected to be delivered by the end of the second quarter of 2007. The new coil tubing units range in size from 11/4” to 13/4”. We also maintain a full range of stainless and carbon steel coiled tubing and related supplies used in the installation of the tubing. We sell or rent the tubing and charge a fee for its installation, servicing and removal, which includes the service personnel and associated equipment on a turnkey or hourly basis. We do not provide the chemicals injected into the well. We currently provide production services in Texas, Louisiana, Oklahoma and Mexico.

Cyclical Nature Of Oilfield Services Industry

The oilfield services industry is highly cyclical. The most critical factor in assessing the outlook for the industry is the worldwide supply and demand for oil and the domestic supply and demand for natural gas. The peaks and valleys of demand are further apart than those of many other cyclical industries. This is primarily a result of the industry being driven by commodity demand and corresponding price increases. As demand increases, producers raise their prices. The price escalation enables producers to increase their capital expenditures. The increased capital expenditures ultimately result in greater revenues and profits for services and equipment companies. The increased capital expenditures also ultimately result in greater production which historically has resulted in increased supplies and reduced prices.

Demand for our services has been strong throughout 2004, 2005 and 2006. Management believes demand will remain strong throughout 2007 due to high oil and natural gas prices and the capital expenditure plans of the exploration and production companies. Because of these market fundamentals for oil and natural gas, management believes the long-term trend of activity in our markets is favorable. However, these factors could be more than offset by other developments affecting the worldwide supply and demand for oil and natural gas products.

Customers

In 2006, one of our customers, Pan American Energy LLC Sucursal Argentina, or Pan American Energy, represented 11.7% of our consolidated revenues. In 2005, none of our customers accounted for more than 10% of our revenues. Our primary customers are the major and independent oil and natural gas companies operating in the United States, Argentina and Mexico. In 2004, Matyep in Mexico represented 10.8% and Burlington Resources Inc. represented 10.1% of our consolidated revenues. The loss without replacement of our larger existing customers could have a material adverse effect on our results of operations.

Suppliers

The equipment utilized in our business is generally available new from manufacturers or at auction. Currently, due to the high level of activity in the oilfield services industry, there is a high demand for new and used equipment. Consequently, there is a limited amount of many types of equipment available at auction and significant backlogs on new equipment. However, the cost of acquiring new equipment to expand our business could increase as a result of the high demand for equipment in the industry.

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.

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

Our five largest competitors in the contract drilling and workover service business, which operate primarily in Argentina, are Pride International, Servicios WellTech, Ensign Energy Services (formerly ODE), Nabors and Helmerich & Payne.

We believe that there are five major directional drilling companies, Schlumberger, Halliburton, Baker Hughes, W-H Energy Services (Pathfinder) and Weatherford, that market both worldwide and in the United States as well as numerous small regional players.

Significant competitors in the casing and tubing markets we serve include Frank’s Casing Crew and Rental Tools, Weatherford, BJ Services, Tesco and Premier. These markets remain highly competitive and fragmented with numerous casing and tubing crew companies working in the 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 compressed air 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.

We believe we own approximately 30% of the capillary tubing units in the southwestern United States that are used for capillary chemical injection services. There are two other significant competitors in the capillary chemical injection services portion of the production services market, Weatherford and BJ Services. Additionally, in the coiled tubing services market there are numerous competitors, most of which have larger coiled tubing services operations than us.

Backlog

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

Employees

Our strategy includes acquiring companies with strong management and entering into long-term employment contracts with key employees in order to preserve customer relationships and assure continuity following acquisition. In general, we believe we have good relations with our employees. None of our employees, other than our DLS 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, 2007, we had approximately 2,567 employees. Almost all of DLS’ operations are subject to collective bargaining agreements. We believe that we maintain a satisfactory relationship with the unions to which DLS’ 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. Insurance rates have in the past been subject to wide fluctuation and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions.

Seasonality

Oil and natural gas operations of our customers located offshore and onshore in the Gulf of Mexico and in Mexico may be adversely affected by hurricanes and tropical storms, resulting in reduced demand for our services. For example, in the summer of 2005, the Gulf of Mexico suffered an unusually high number of hurricanes with unusual intensity. 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. As part of our overall corporate strategy to focus on our core business of providing services to the oil and natural gas industry and to increase stockholder value, we are investigating the sale or license of our worldwide rights to trade names and logos for products and services outside the energy sector.


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 Company

We may fail to acquire additional businesses, which will restrict our growth and may have a material adverse effect on our stock price or on our ability to meet our obligations under (and the price of) our securities.

Our business strategy is to acquire companies operating in the oilfield services industry. However, there can be no assurance that we will be successful in acquiring any additional companies. Successful acquisition of new companies will depend on various factors, including but not limited to:


	•	our ability to obtain financing;

	•	the competitive environment for acquisitions; and

	•	the integration and synergy issues described in the next risk factor.

There can be no assurance that we will be able to acquire and successfully operate any particular business or that we will be able to expand into areas that we have targeted. If we fail to acquire additional businesses, our financial condition, our results of operations, the price of our common stock and our ability to meet our obligations under long-term notes may be materially adversely affected.

Difficulties in integrating acquired businesses may result in reduced revenues and income.

We may not be able to successfully integrate the businesses of our operating subsidiaries or any business we may acquire in the future. The integration of the businesses will be complex and time consuming, will

place a significant strain on management and our information systems, and this strain could disrupt our businesses. Furthermore, if our combined businesses continue to grow rapidly, we may be required to replace our current information and accounting systems with systems designed for companies that are larger than ours. We may be adversely impacted by unknown liabilities of acquired businesses. We may encounter substantial difficulties, costs and delays involved in integrating common accounting, information and communication systems, operating procedures, internal controls and human resources practices, including incompatibility of business cultures and the loss of key employees and customers. These difficulties may reduce our ability to gain customers or retain existing customers, and may increase operating expenses, resulting in reduced revenues and income and a failure to realize the anticipated benefits of acquisitions.

In particular, the Specialty, DLS and OGR acquisitions are our largest acquisitions to date and, consequently, the inherent integration risks may have a greater effect on us than the risks posed by our previous acquisitions. We will be conducting parts of the integration of these companies simultaneously, and as a result we could strain our current resources. Furthermore, we will depend on these entities’ continued performance as a source of cash flow to service our debt obligations.

We have made numerous acquisitions during the past five years. As a result of these transactions, our past performance is not indicative of future performance, and investors should not base their expectations as to our future performance on our historical results.

Our acquisition of DLS has substantially changed the nature of our operations and business.

Our acquisition of DLS has substantially changed the nature and geographic location of our operations and business as a result of the character and location of DLS’ businesses, which have substantially different operating characteristics and are in different geographic locations from our other businesses. Prior to our acquisition of DLS, we had operated as an oilfield services company domestically in Texas, Louisiana, New Mexico, Colorado, Oklahoma, Mississippi, Utah, Wyoming, offshore in the Gulf of Mexico, and internationally in Mexico. DLS’ business is located primarily in Argentina, and we have no significant operations in South America other than through DLS. Accordingly, this acquisition has subjected and will continue to subject us to risks inherent in operating in a foreign country where we do not have significant prior experience. DLS’ business consists of employing drilling and workover rigs for drilling, completion and repair services for oil and gas wells. We do not own any drilling rigs or workover rigs other than through DLS, and have not historically provided such services prior to our acquisition of DLS. Consequently, we may not be able to realize the economic benefits of this acquisition as efficiently as in our prior acquisitions, if at all.

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 have recently completed several acquisitions of privately-held businesses, including closely-held entities, and in the future, we may make additional strategic acquisitions of privately-held businesses. Prior to becoming part of our consolidated company, these acquired businesses have not been required to implement or maintain the disclosure controls and procedures or internal controls over financial reporting that federal law requires of publicly-held companies such as ours. Similarly, 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. With respect to our acquisition of DLS and our recent acquisition of substantially all of the assets of OGR, this risk is exacerbated by each of DLS’ and OGR’s relative size, when compared to the rest of our consolidated company.

Likewise, during the course of our integration of any acquired business (including DLS and OGR), we may identify needed improvements to our or such acquired business’ internal controls and may be required to design enhanced processes and controls in order to make such improvements. This could result in significant

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

If we fail to achieve and maintain the adequacy of our disclosure controls and procedures and/or our internal controls, as such standards are modified, supplemented or amended from time to time, we may not be able to conclude that we have effective disclosure controls and procedures and/or effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. If:


	•	we are not successful in improving our financial reporting process, our disclosure controls and procedures and/or our internal controls over financial reporting;

	•	we identify deficiencies and/or one or more material weaknesses in our internal controls over financial reporting; or

	•	we are not successful in integrating acquired businesses (such as DLS and OGR) into our consolidated company’s system of disclosure controls and procedures and internal controls over financial reporting,

then our independent registered public accounting firm may be unable to attest that our management’s assessment of our internal controls over financial reporting is fairly stated, or they may be unable to express an opinion on our management’s evaluation of, or on the effectiveness of, our internal controls.

If it is determined that our disclosure controls and procedures and/or our internal controls over financial reporting are not effective and/or we fail to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act on a timely basis, we may not be able to provide reliable financial and other reports or prevent fraud, which, in turn, 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 and/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, and our outstanding 8.5% senior notes due 2017 (which we refer to collectively as our outstanding senior notes) and any other debt securities we may offer and, ultimately, an acceleration of amounts due thereunder. In addition, a default under the indentures generally will also give rise to a default under our credit agreement and could cause the acceleration of amounts due under the credit agreement. If an acceleration of our outstanding senior notes or our other debt were to occur, we cannot assure you that we would have sufficient funds to repay such obligations.

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 drilling business in the United States, Mexico and elsewhere. Historically, we have been dependent upon a few customers for a significant portion of our revenues. In 2006, one of our customers, Pan American Energy represented 11.7% of our consolidated revenues. In 2005, no single customer generated over 10% of our revenues. In 2004, Matyep represented 10.8% of our revenues, and Burlington Resources represented 10.1% of our revenues. Additionally, DLS currently relies on one customer for a majority of its revenue. In 2006, Pan American Energy represented 51.9% of DLS’ revenues. In 2005, Pan American Energy represented 55% of DLS’ revenues. This concentration of customers may increase our overall exposure to credit risk, and customers will likely be similarly affected by changes in economic and industry conditions. Our financial condition and results of operations will be materially adversely affected if one or more of our significant customers fails to pay us or ceases to contract with us for our services on terms that are favorable to us or at all.

Our international operations may expose us to political and other uncertainties, including risks of:


	•	terrorist acts, war and civil disturbances;

	•	changes in laws or policies regarding the award of contracts; and

	•	the inability to collect or repatriate currency, income, capital or assets.

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.

Environmental liabilities could result in substantial losses.

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

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

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

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

Our products and services are used for the exploration and production of oil and natural gas. These operations are subject to inherent hazards that can cause personal injury or loss of life, damage to or destruction of property, equipment, the environment and marine life, and suspension of operations. Litigation arising from an accident at a location where our products or services are used or provided may cause us to be named as a defendant in lawsuits asserting potentially large claims. We maintain customary insurance to protect our business against these potential losses. Our insurance has deductibles or self-insured retentions and contains certain coverage exclusions. However, we could become subject to material uninsured liabilities that could have a material adverse effect on our financial condition and results of operations.

The loss of key executives would adversely affect our ability to effectively finance and manage our business, acquire new businesses, and obtain and retain customers.

We are dependent upon the efforts and skills of our executives to finance and manage our business, identify and consummate additional acquisitions and obtain and retain customers. These executives include:


	•	Chief Executive Officer and Chairman Munawar H. Hidayatallah; and

	•	Vice Chairman, President and Chief Operating Officer Burt A. Adams.

In December 2006, David Wilde resigned as our President and Chief Operating Officer. In light of Mr. Wilde’s significant contributions to our recent growth, his resignation could have a material adverse effect on our future performance. In addition, our development and expansion will require additional experienced management and operations personnel. No assurance can be given that we will be able to identify and retain these employees. The loss of the services of one or more of our key executives could increase our exposure to the other risks described in this “Risk Factors” section. We do not maintain key man insurance on any of our personnel.

Risks Associated With Our Industry

Cyclical declines in oil and natural gas prices may result in reduced use of our services, affecting our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The oil and natural gas exploration and drilling business is highly cyclical. Generally, as oil and natural gas prices decrease, exploration and drilling activity declines as marginally profitable projects become uneconomic and are either delayed or eliminated. Declines in the number of operating drilling rigs result in reduced use of and prices for our services. Accordingly, when oil and natural gas prices are relatively low, our revenues and income will suffer. 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; and

	•	advances in exploration, development and production technologies.

Depending on the market prices of oil and natural gas, companies exploring for oil and natural gas may cancel or curtail their drilling programs, thereby reducing demand for drilling services. Our contracts are generally short-term, and oil and natural gas companies tend to respond quickly to upward or downward changes in prices. Any reduction in the demand for drilling services may materially erode both pricing and utilization rates for our services and adversely affect our financial results. As a result, we may suffer losses, be unable to make necessary capital expenditures and be unable to meet our financial obligations.

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 recent 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.

We may experience increased labor costs or the unavailability of skilled workers and the failure to retain key personnel could hurt our operations.

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

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.

In addition, oil and natural gas operations of our customers located offshore and onshore in the Gulf of Mexico and in Mexico may be adversely affected by hurricanes and tropical storms, resulting in reduced demand for our services. 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.

Our business may be affected by terrorist activity and by security measures taken in response to terrorism.

We may experience loss of business or delays or defaults in payments from payers that have been affected by actual or potential terrorist activities. Some oil and natural gas drilling companies have implemented security measures in response to potential terrorist activities, including access restrictions, that could adversely affect our ability to market our services to new and existing customers and could increase our costs. Terrorist activities and potential terrorist activities and any resulting economic downturn could adversely impact our results of operations, impair our ability to raise capital or otherwise adversely affect our ability to grow our business.

We are subject to government regulations.

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. 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. Although we are not aware of any proposed material changes in any federal, state, local or foreign statutes, rules or regulations, any changes could materially affect our financial condition and results of operations.

Risks Associated With DLS’ Business and Industry

A material or extended decline in expenditures by oil and gas companies due to a decline or volatility in oil and gas prices, a decrease in demand for oil and gas or other factors may reduce demand for DLS’ services and substantially reduce DLS’ revenues, profitability, cash flows and/or liquidity.

The profitability of DLS’ operations depends upon conditions in the oil and natural gas industry and, specifically, the level of exploration and production expenditures of oil and gas company customers. The oil and natural gas industry is cyclical and subject to governmental price controls. The demand for contract drilling and related services is directly influenced by many factors beyond DLS’ control, including:


	•	oil and gas prices and expectations about future prices;

	•	the demand for oil and gas, both in Latin America and globally;

	•	the cost of producing and delivering oil and natural gas;

	•	advances in exploration, development and production technology;

	•	government regulations, including governmental imposed commodity price controls, export controls and renationalization of a country’s oil and natural gas industry;


	•	local and international political and economic conditions;

	•	the ability of OPEC to set and maintain production levels and prices;

	•	the level of production by non-OPEC countries; and

	•	the policies of various governments regarding exploration and development of their oil and gas reserves.

Depending on the factors outlined above, companies exploring for oil and natural gas may cancel or curtail their drilling programs, thereby reducing demand for drilling services. Such a reduction in demand may erode daily rates and utilization of DLS’ rigs. Any significant decrease in daily rates or utilization of DLS’ rigs could materially reduce DLS’ revenues, profitability, cash flows and/or liquidity.

A majority of DLS’ revenues are derived from one customer. The termination of the contract with this customer could have a significant negative effect on the revenues, results of operations and financial condition of DLS.

A majority of DLS’ revenues are currently received pursuant to a strategic agreement with Pan American Energy. Pan American Energy is a joint venture that is owned 60% by British Petroleum and 40% by Bridas Corporation, an affiliate of the former DLS stockholders from which we acquired DLS, and which we refer to collectively as the DLS sellers. This agreement terminates on June 30, 2008. However, Pan American Energy may terminate the agreement (i) without cause at any time with 60 days’ notice, or (ii) in the event of a breach of the agreement by DLS if such breach is not cured within 20 days of notice of the breach. DLS is currently in negotiations to extend this agreement to December 2010.

Because a majority of DLS’ revenues are currently generated under this agreement, DLS’ revenues and earnings will be materially adversely affected if this agreement is terminated unless DLS is able to enter into a satisfactory substitute arrangement. We cannot assure you that in the event of such a termination DLS would be able to enter into a substitute arrangement on terms similar to those contained in the current agreement with Pan American Energy.

DLS’ operations and financial condition could be affected by union activity and general labor unrest. Additionally, DLS’ labor expenses could increase as a result of governmental regulation of payments to employees.

In Argentina, labor organizations have substantial support and have considerable political influence. The demands of labor organizations 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 DLS will not face labor disruptions in the future or that any such disruptions will not have a material adverse effect on DLS’ financial condition or results of operations.

The Argentine government has in the past and may in the future promulgate laws, regulations and decrees requiring companies in the private sector to maintain minimum wage levels and provide specified benefits to employees, including significant mandatory severance payments. In the aftermath of the Argentine economic crisis of 2001 and 2002, both the government and private sector companies have experienced significant pressure from employees and labor organizations relating to wage levels and employee benefits. In early 2005, the Argentine government promised not to order salary increases by decree. However, there has been no abatement of pressure to mandate salary increases, and it is possible the government will adopt measures that will increase salaries or require DLS to provide additional benefits, which would increase DLS’ costs and potentially reduce DLS’ profitability, cash flow and/or liquidity.

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

DLS often has to make upgrade and refurbishment expenditures for its rig fleet to comply with DLS’ quality management and preventive maintenance system or contractual requirements or when repairs are required in response to an inspection by a governmental authority. DLS may also make significant expenditures when it moves rigs from one location to another. Additionally, DLS 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, including the following:


	•	shortages of material or skilled labor;

	•	unforeseen engineering problems;

	•	unanticipated change orders;

	•	work stoppages;

	•	adverse weather conditions;

	•	long lead times for manufactured rig components;

	•	unanticipated cost increases; and

	•	inability to obtain the required permits or approvals.

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

An oversupply of comparable rigs in the geographic markets in which DLS competes could depress the utilization rates and dayrates for DLS’ rigs and materially reduce DLS’ 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 DLS competes. Improvements in demand in a geographic market may cause DLS’ 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 DLS’ rigs and materially reduce DLS’ revenues and profitability.

Worldwide political and economic developments may hurt DLS’ operations materially.

Currently, DLS derives substantially all of its revenues from operations in Argentina and a small portion from operations in Bolivia. DLS’ operations are subject to the following risks, among others:


	•	expropriation of assets;

	•	nationalization of components of the energy industry in the geographic areas where DLS operates;

	•	foreign currency fluctuations and devaluation;

	•	new economic and tax policies;

	•	restrictions on currency, income, capital or asset repatriation;

	•	political instability, war and civil disturbances;

	•	uncertainty or instability resulting from armed hostilities or other crises in the Middle East or the geographic areas in which DLS operates; and

	•	acts of terrorism.

DLS attempts 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 in U.S. dollars or freely convertible foreign currency. To the extent possible, DLS seeks to limit its exposure to local currencies by matching the acceptance of local currencies to DLS’ expense requirements in those currencies. Although DLS has done this in the past, DLS may not be able to take these actions in the future, thereby exposing DLS to foreign currency fluctuations that could cause its results of operations, financial condition and cash flows to deteriorate materially.

Over the past several years, Argentina and Bolivia have experienced political and economic instability that resulted in significant changes in their general economic policies and regulations.

DLS derives a small portion of its revenues from operating one drilling rig in Bolivia. Recently, Bolivian President Evo Morales announced the nationalization of Bolivia’s natural gas industry and ordered the Bolivian military to occupy Bolivia’s natural gas fields. This measure will likely adversely affect the Bolivian operations of foreign oil and natural gas companies operating in Bolivia, including DLS’ customers and potential future customers, and accordingly, DLS’ prospects for future business in Bolivia may be harmed. In addition, in light of these recent political developments in Bolivia, DLS’ assets in Bolivia may be subject to an increased risk of expropriation or government imposed restrictions on movement to a new location.

In light of the early stage and uncertainty of political developments affecting the energy industry in Bolivia, we are unable to predict the effect that recent events may have on DLS’ operations, financial results or business plans. There is a risk that the changes resulting from the recent events in Bolivia will adversely affect DLS’ financial position or results of operations, and DLS’ operations may be further adversely affected by continuing economic and political instability in Bolivia. Furthermore, if nationalistic measures similar to those developing in Bolivia were to be adopted in other countries where DLS may in the future seek drilling contracts, DLS’ prospects in such countries may be adversely affected.

DLS’ operations are also subject to other risks, including foreign monetary and tax policies, expropriation, nationalization and nullification or modification of contracts. Additionally, DLS’ ability to compete may be limited by foreign governmental regulations that favor or require the awarding of contracts to local contractors or by regulations requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. Furthermore, DLS may face governmentally imposed restrictions from time to time on its ability to transfer funds.

Devaluation of the Argentine peso will adversely affect DLS’ results of operations.

The Argentine peso has been subject to significant devaluation in the past and may be subject to significant fluctuations in the future. Given the economic and political uncertainties in Argentina, it is impossible to predict whether, and to what extent, the value of the Argentine peso may depreciate or appreciate against the U.S. dollar. We cannot predict how these uncertainties will affect DLS’ financial results, but there is a risk that DLS’ 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 DLS’ 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 DLS’ results of operations and financial condition.

In the event of further social or political crisis, companies in Argentina may also face the risk of further civil and social unrest, strikes, expropriation, nationalization, forced renegotiation or modification of existing contracts and changes in taxation policies, including royalty and tax increases and retroactive tax claims.

In addition, investments in Argentine companies may be further affected by changes in laws and policies of the United States affecting foreign trade, taxation and investment.

An increase in inflation could have a material adverse effect on DLS’ results of operations.

The devaluation of the Argentine peso created pressures on the domestic price system that generated high rates of inflation in 2002 before substantially stabilizing in 2003 and remaining stable in 2004. In 2005, however, inflation rates began to increase. In addition, in response to the economic crisis in 2002, the federal government granted the Central Bank greater control over monetary policy than was available to it under the previous monetary regime, known as the “Convertibility” regime, including the ability to print currency, to make advances to the federal government to cover its anticipated budget deficit and to provide financial assistance to financial institutions with liquidity problems. We cannot assure you that inflation rates will remain stable in the future. Significant inflation could have a material adverse effect on DLS’ results of operations and financial condition.

DLS’ customers may seek to cancel or renegotiate some of DLS’ drilling contracts during periods of depressed market conditions or if DLS experiences operational difficulties.

Substantially all of DLS’ contracts with major customers are dayrate contracts, where DLS charges 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, DLS’ customers may have the right to terminate existing contracts if DLS experiences 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 DLS’ drilling contracts could materially reduce DLS’ revenues and profitability.

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

Many aspects of DLS’ operations are subject to laws and regulations that may relate directly or indirectly to the contract drilling and well servicing industries, including those requiring DLS to control the discharge of oil and other contaminants into the environment or otherwise relating to environmental protection. The countries where DLS 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 DLS’ operations. Laws and regulations protecting the environment have become more stringent in recent years and may in certain circumstances impose strict liability, rendering DLS liable for environmental and natural resource damages without regard to negligence or fault on DLS’ part. These laws and regulations may expose DLS 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 DLS’ costs or both.

DLS is subject to hazards customary for drilling operations, which could adversely affect its financial
performance if DLS is not adequately indemnified or insured.

Substantially all of DLS’ operations are subject to hazards that are customary for oil and gas drilling operations, including blowouts, reservoir damage, loss of well control, cratering, oil and gas well fires and explosions, natural disasters, pollution and mechanical failure. Any of these risks could result in damage to or destruction of drilling equipment, personal injury and property damage, suspension of operations or environmental damage. Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer, and DLS generally obtains indemnification from its customers by contract for some of these risks. However, there may be limitations on the enforceability of indemnification provisions that allow a contractor to be indemnified for damages resulting from the contractor’s fault. To the extent that DLS is unable to transfer such risks to customers by contract or indemnification agreements, DLS generally seeks protection through insurance. However, DLS has a significant amount of self-insured retention or deductible

for certain losses relating to workers’ compensation, employers’ liability, general liability and property damage. There is no assurance that such insurance or indemnification agreements will adequately protect DLS 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 DLS is not indemnified against, or the failure of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, there can be no assurance that insurance will continue to be available to cover any or all of these risks, or, even if available, that insurance premiums or other costs will not rise significantly in the future, so as to make the cost of such insurance prohibitive.

Risks Associated With an Investment in Our Common Stock

In connection with our recent acquisitions of DLS and substantially all the assets of OGR, the DLS
sellers have the right to designate two nominees for election to our board of directors and OGR has the right to designate one nominee for election to our board of directors. The interests of the DLS sellers and OGR may be different from yours.

The DLS sellers collectively hold 2.5 million shares of our common stock, representing approximately 7.3% of our issued and outstanding shares as of March 1, 2007. Under the investors rights agreement that we entered into in connection with the DLS acquisition, the DLS sellers have the right to designate two nominees for election to our board of directors. OGR holds 3.2 million shares of our common stock, representing approximately 9.3% of our issued and outstanding shares as of March 1, 2007. Under the investor rights agreement that we entered into in connection with the OGR acquisition, OGR has the right to designate one nominee for election to our board of directors. As a result, the DLS sellers and OGR have a greater ability to determine the composition of our board of directors and to control our future operations and strategy as compared to the voting power and control that could be exercised by a stockholder owning the same number of shares and not benefiting from board designation rights.

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

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

We may have a contingent liability arising out of a possible violation of Section 5 of the Securities Act in connection with electronic communications sent to potential investors in our common stock.

On or about July 20, 2006, one of the proposed underwriters of our common stock offering, which closed on August 14, 2006, sent e-mails and/or instant messages to approximately 20 potential investors in our common stock. Although we did not authorize these communications, and we believe they were not made or intended to be made on our behalf, these communications may have constituted violations of Section 5 of the Securities Act. Accordingly, if the recipients of these emails purchased shares in the August 2006 common stock offering, they might have the right, under certain circumstances, to require us to repurchase those shares. Consequently, we could have a contingent liability arising out of these possible violations of the Securities Act. The magnitude of this liability is presently impossible to quantify, and would depend upon the number of shares purchased by the recipients of such communications and the trading price of our common stock. However, the proposed underwriter who sent these electronic communications did not act as an underwriter in the August 2006 common stock offering, and we and the underwriters that did participate in the August 2006 common stock offering took measures designed to ensure that the recipients of the communications did not have the opportunity to purchase shares in that offering. Furthermore, if any investors in our common stock do assert any such liability, we intend to contest the matter vigorously, and in light of the remedial measures and our belief that the communications were not made or intended to be made on our behalf, we do not believe that any such liability would be material to our financial condition.

Our stock price may decrease in response to various factors, which could adversely affect our business and cause our stockholders to suffer significant losses. These factors include:


	•	decreases in prices for oil and natural gas resulting in decreased demand for our services;

	•	variations in our operating results and failure to meet expectations of investors and analysts;

	•	increases in interest rates;

	•	the loss of customers;

	•	failure of customers to pay for our services;

	•	competition;

	•	illiquidity of the market for our common stock;

	•	developments specifically affecting the Argentine economy;

	•	sales of common stock by existing stockholders; and

	•	other developments affecting us or the financial markets.

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

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

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

We do not expect to pay dividends on our common stock, and investors will be able to receive cash in respect of the shares of common stock only upon the sale of the shares.

We have not paid any cash dividends on our common stock within the last ten years, and we have no intention in the foreseeable future to pay any cash dividends on our common stock. Furthermore, our credit agreement, the indenture governing our outstanding senior notes restrict our ability to pay dividends on our common stock. Therefore, an investor in our common stock will obtain an economic benefit from the common stock only after an increase in its trading price and only by selling the common stock.

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

Sales of a substantial number of shares of common stock, or the perception that such sales could occur, could adversely affect the market price of our common stock by introducing a large number of sellers to the market. Such sales could cause the market price of our common stock to decline.

We have 34,251,443 shares outstanding as of March 1, 2007. At December 31, 2006, we had reserved an additional 3,099,365 shares of common stock for issuance under our equity compensation plans, of which 1,346,365 shares were issuable upon the exercise of outstanding options with a weighted average exercise price of $7.02 per share. In addition, we have reserved 4,000 shares of common stock for issuance upon the exercise of outstanding options (with an exercise price of $13.75 per share) granted to former and continuing board members in 1999 and 2000. At December 31, 2006, we also have reserved 4,000 shares of common stock for issuance upon the exercise of outstanding warrants (with an exercise price of $4.65 per share).

In connection with our acquisition of DLS, we entered into an investors rights agreement with the seller parties to the DLS stock purchase agreement, who collectively hold 2.5 million shares of our common stock. In connection with our acquisition of substantially all the assets of OGR, we entered into an investor rights agreement with OGR, who holds 3.2 million shares of our common stock. Under these agreements, the DLS sellers and OGR are entitled to certain rights with respect to the registration of the sale of such shares under the Securities Act. By exercising their registration rights and causing a large number of shares to be sold in the public market, these holders could cause the market price of our common stock to decline.

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

Risks Associated With Our Indebtedness

We have a substantial amount of debt, which could adversely affect our financial health and prevent us from making principal and interest payments on our outstanding senior notes and our other debt.

At December 31, 2006, after giving effect to the sale of the senior notes and the issuance of our common stock in January 2007 and the application of the proceeds therefrom, as if such transaction had occurred on that date, we had approximately $518.4 million of consolidated total indebtedness outstanding and approximately $15.3 million of additional secured borrowing capacity available under our credit agreement.

Our substantial debt could:


	•	make it more difficult for us to satisfy our obligations with respect to our outstanding senior notes, any other debt securities we may offer and our other debt;

	•	increase our vulnerability to general adverse economic and industry conditions, including declines in oil and natural gas prices and declines in drilling activities;

	•	limit our ability to obtain additional financing for future working capital, capital expenditures, mergers and other general corporate purposes;

	•	require us to dedicate a substantial portion of our cash flow from operations to payments on our debt, thereby reducing the availability of our cash flow for operations and other purposes;

	•	limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

	•	make us more vulnerable to increases in interest rates;

	•	place us at a competitive disadvantage compared to our competitors that have less debt; and

	•	have a material adverse effect on us if we fail to comply with the covenants in the indentures relating to our outstanding senior notes, and any other debt securities we may offer or in the instruments governing our other debt.

In addition, we may incur substantial additional debt in the future. Each of the indentures governing our outstanding senior notes permits (and we anticipate that the indentures governing any other debt securities we may offer will also permit) us to incur additional debt, and our credit agreement permits additional borrowings. If new debt is added to our current debt levels, these related risks could increase.

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

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

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

In order to refinance indebtedness, expand existing operations and acquire additional businesses, we will require substantial amounts of capital. There can be no assurance that financing, whether from equity or debt financings or other sources, will be available or, if available, will be on terms satisfactory to us. If we are unable to obtain such financing, we will be unable to acquire additional businesses and may be unable to meet our obligations under our credit agreement, our senior notes or any other debt securities we may offer.

The indentures governing our outstanding senior notes and our credit agreement impose (and we anticipate that the indentures governing any other debt securities we may offer will also 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 indentures governing our outstanding senior notes and our credit agreement contain (and we anticipate that the indentures governing any other debt securities we may offer will also 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.

The credit agreement also requires us to maintain specified financial ratios and satisfy certain financial tests. Our ability to maintain or meet such financial ratios and tests may be affected by events beyond our control, including changes in general economic and business conditions, and we cannot assure you that we will maintain or meet such ratios and tests or that the lenders under the credit agreement will waive any failure to meet such ratios or tests.

These covenants could materially and adversely affect our ability to finance our future operations or capital needs. Furthermore, they may restrict our ability to expand, to pursue our business strategies and otherwise to conduct our business. Our ability to comply with these covenants may be affected by circumstances and events beyond our control, such as prevailing economic conditions and changes in regulations, and we cannot assure you that we will be able to comply with them. A breach of these covenants could result in a default under the indentures governing our outstanding senior notes and any other debt securities we may offer and/or the credit agreement. If there were an event of default under any of the indentures and/or the credit agreement, the affected creditors could cause all amounts borrowed under these instruments to be due and payable immediately. Additionally, if we fail to repay indebtedness under our credit agreement when it becomes due, the lenders under the credit agreement could proceed against the assets which we have pledged to them as security. Our assets and cash flow might not be sufficient to repay our outstanding debt in the event of a default.


ITEM 1B.	*UNRESOLVED STAFF COMMENTS*

None.


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, 2007. Our principal executive office is rented and located in Houston, Texas and the table below presents all of our operating locations and whether the property is owned or leased.


Business Segment	Location	Owned/Leased

Rental Tools	Houston, Texas	Leased — 2 locations
	Victoria, Texas	Owned
	Broussard, Louisiana	Leased
	Morgan City, Louisiana	Owned
	New Orleans, Louisiana	Leased
International Drilling	Buenos Aires, Argentina	Leased
	Comodoro Rivadavia, Argentina	Owned
	Neuquén, Argentina	Owned
	Rincon de los Sauces, Argentina	Owned
	Tartagal, Argentina	Owned
	Santa Cruz, Bolivia	Leased
Directional Drilling Services	Corpus Christi, Texas	Leased
	Houston, Texas	Leased — 2 locations
	Oklahoma City, Oklahoma	Leased
	Lafayette, Louisiana	Leased
Casing and Tubing Services	Corpus Christi, Texas	Leased
	Edinburg, Texas	Owned
	Kilgore, Texas	Leased
	Pearsall, Texas	Leased
	Broussard, Louisiana	Leased — 2 locations
	Houma, Louisiana	Leased
Compressed Air Drilling Services	Fort Stockton, Texas	Leased
	Grandbury, Texas	Leased
	Houston, Texas	Leased
	San Angelo, Texas	Leased
	Sonora, Texas	Leased
	Carlsbad, New Mexico	Leased
	Farmington, New Mexico	Leased
	Denver, Colorado	Leased
	Grand Junction, Colorado	Leased
	Wilburton, Oklahoma	Leased
Production Services	Alvin, Texas	Leased
	Carthage, Texas	Leased
	Corpus Christi, Texas	Leased
	Kilgore, Texas	Leased — 2 locations
	Midland, Texas	Leased
	Arcadia, Louisiana	Leased
	Broussard, Louisiana	1 Owned & 1 Leased
	Cordell, Oklahoma	Leased
	Houma, Louisiana	Leased


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 and retain no responsibility for the assets transferred to or distributions to be made by such trusts pursuant to our plan of reorganization.

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

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

The EPA and certain state agencies continue from time to time to request information in connection with various waste disposal sites containing products manufactured by us before consummation of the plan of reorganization that were disposed of by other parties. Although we have been discharged of liabilities with respect to hazardous waste sites, we are under a continuing obligation to provide information with respect to our products to federal and state agencies. The A-C Reorganization Trust, under its mandate to provide plan of reorganization implementation services to us, has responded to these informational requests because pre-bankruptcy activities are involved.

We were advised in late 2005 that the A-C Reorganization Trust is in the process of terminating and distributing its assets, and as a result, we will assume the responsibility of responding to claimants and to the EPA and state agencies previously undertaken by the A-C Reorganization Trust. However, we have been advised by the A-C Reorganization Trust that its cost of providing these services has not been material in the past, and therefore we do not expect to incur material expenses as a result of responding to such requests. However, there can be no assurance that we will not be subject to environmental claims relating to pre-bankruptcy activities that would have a material adverse effect on us.

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

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


ITEM 4.	*SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS*

On November 28, 2006, we held our Annual Meeting of Stockholders. At the meeting, the stockholders voted on the following matters:

1. The election of nine directors to serve a one-year term expiring at the 2007 annual meeting of stockholders.

2. The ratification of the appointment of UHY LLP as our independent auditor for the fiscal year ending December 31, 2006.

3. The adoption of our 2006 Incentive Stock Plan.

The nine nominees to our Board of Directors were elected at the meeting, and the other proposals received the affirmative vote required for approval. The number of votes cast for, against or withheld, as well as the number of abstentions and broker non-votes, were as follows:


				Against or		Abstentions and
		For		Withheld		Broker Non-votes

1.	Election of Directors
	Ali H. M. Afdhal		18,981,441		339,698
	Alejandro P. Bulgheroni		18,791,812		529,327
	Carlos A. Bulgheroni		18,791,762		529,377
	Jeffrey R. Freedman		17,759,199		1,561,940
	Victor F. Germack		19,170,055		151,084
	Munawar H. Hidayatallah		19,096,922		224,217
	John E. McConnaughy, Jr.		18,353,294		967,845
	Robert E. Nederlander		19,009,582		311,557
	Leonard Toboroff		18,791,812		529,327
2.	Ratification of UHY LLP as our independent accountants		19,269,608		42,267		9,264
3.	Adoption of 2006 Incentive Stock Plan		7,811,990		3,618,967		7,863,905

PART II


ITEM 5.	*MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.*

MARKET PRICE INFORMATION

Our common stock is traded on the American Stock Exchange under the symbol “ALY”. The following table sets forth, for periods indicated, the range of high and low sale prices of our common stock reported on the American Stock Exchange.


Calendar Quarter	High		Low

2005
First Quarter	$	7.25	$	3.64
Second Quarter		6.00		4.38
Third Quarter		14.70		5.65
Fourth Quarter		13.75		8.61
2006
First Quarter	$	18.50	$	12.46
Second Quarter		17.62		10.85
Third Quarter		19.33		9.80
Fourth Quarter		25.55		12.15

Holders

As of March 1, 2007, there were approximately 1,927 holders of record of our common stock. On March 1, 2007, the closing price for our common stock reported on the American Stock Exchange was $15.99 per share.

Dividends

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

EQUITY COMPENSATION PLAN INFORMATION

The following table provides information as of December 31, 2006 with respect to the shares of our common stock that may be issued under our existing equity compensation plans.

Number of

Securities to be

Weighted

Issued Upon

Average Exercise

Number of Securities

Exercise of

Price of

Remaining Available

Outstanding

for Future Issuance

Options, Warrants

Under Equity

Plan Category

and Rights

Compensation Plans

Equity compensation plans approved by security holders

1,346,365

6.86

1,726,000

Equity compensation plans not approved by security holders

8,000

9.20

—

Total

1,354,365

6.87

1,726,000

Equity Compensation Plans Not Approved By Security Holders

These plans comprise the following:

In 1999 and 2000, the Board compensated former and continuing Board members who had served from 1989 to March 31, 1999 without compensation by issuing promissory notes totaling $325,000 and by granting stock options to these same individuals. Options to purchase 4,800 shares of common stock were granted with an exercise price of $13.75. These options vested immediately and expire in March 2010. As of December 31, 2006, 4,000 of these options remain outstanding.

In connection with the private placement in April 2004, we issued warrants for the purchase of 800,000 shares of our common stock at an exercise price of $2.50 per share. A total of 486,557 of these warrants were exercised in 2005 and the remaining warrants were exercised in 2006. Warrants for 4,000 shares of our common stock at an exercise price of $4.65 were also issued in May 2004 and remained outstanding as of December 31, 2006. The warrants were exercised in January 2007.

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 Nasdaq Market Index and the CoreData Services Oil and Gas Equipment and Services Index for the period commencing January 1, 2001 and ending on December 31, 2006. 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 January 1, 2001 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.

COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN

AMONG ALLIS-CHALMERS ENERGY INC.

NASDAQ MARKET INDEX AND OIL & GAS EQUIPMENT/SERVICES

ASSUMES $100 INVESTED ON JAN. 1, 2001

ASSUMES DIVIDEND REINVESTED

FISCAL YEAR ENDING DEC. 31, 2006

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

Fiscal Year Ending

Company/Index/Market

12/31/2001

12/31/2002

12/31/2003

12/31/2004

12/30/2005

12/29/2006

Allis-Chalmers Energy Inc.

100.00

53.68

54.74

103.16

262.53

485.05

Oil & Gas Equipment/Services

100.00

93.04

113.49

155.77

235.41

277.90

NASDAQ Market Index

100.00

69.75

104.88

113.70

116.19

128.12


ITEM 6.	*SELECTED FINANCIAL DATA.*

The following selected historical financial information for each of the five years ended December 31, 2006, has been derived from our audited consolidated financial statements and related notes. This information is only a summary and should be read in conjunction with material contained in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with our financial statements included elsewhere herein. As discussed in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” we have during the past five years effected a number of business combinations and other transactions that materially affect the comparability of the information set forth below (in thousands, except per share amounts):


	Years Ended December 31,
	2006		2005		2004		2003		2002
					(Restated)		(Restated)

Statement of Operations Data
Revenues	$	307,304	$	105,344	$	47,726	$	32,724	$	17,990
Income (loss) from operations	$	66,656	$	13,218	$	4,227	$	2,625	$	(1,072	)
Net income (loss) from continuing operations	$	35,626	$	7,175	$	888	$	2,927	$	(3,969	)
Net income (loss) attributed to common stockholders	$	35,626	$	7,175	$	764	$	2,271	$	(4,290	)
Per Share Data:
Net Income (loss) from continuing operations per common share:
Basic	$	1.73	$	0.48	$	0.10	$	0.58	$	(1.14	)
Diluted	$	1.66	$	0.44	$	0.09	$	0.50	$	(1.14	)
Weighted average number of common shares outstanding:
Basic		20,548		14,832		7,930		3,927		3,766
Diluted		21,410		16,238		9,510		5,850		3,766


	Consolidated Balance Sheet Data
	As of December 31,
	2006		2005		2004		2003		2002
							(Restated)

Total assets	$	908,326	$	137,355	$	80,192	$	53,662	$	34,778
Long-term debt classified as:
Current	$	6,999	$	5,632	$	5,541	$	3,992	$	13,890
Long-term	$	561,446	$	54,937	$	24,932	$	28,241	$	7,331
Redeemable convertible Preferred stock	$	—	$	—	$	—	$	4,171	$	3,821
Stockholders’ equity	$	253,933	$	60,875	$	35,109	$	4,541	$	1,009
Book value per share (basic)	$	12.36	$	4.10	$	4.43	$	1.16	$	0.27


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

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

Overview of Our Business

We are a multi-faceted oilfield services company that provides services and equipment to oil and natural gas exploration and production companies, domestically in Texas, Louisiana, New Mexico, Colorado, Oklahoma, Mississippi, Utah, Wyoming, Arkansas, Alabama, West Virginia, offshore in the Gulf of Mexico, and internationally, primarily in Argentina and Mexico. We operate in six sectors of the oil and natural gas service industry: rental tools, international drilling, directional drilling services; casing and tubing services; compressed air drilling services; and production services.

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

The number of working drilling rigs, typically referred to as the “rig count,” is an important indicator of activity levels in the oil and natural gas industry. The rig count in the United States increased from 862 as of December 31, 2002 to 1,752 as of March 2, 2007, according to the Baker Hughes rig count. Furthermore, directional and horizontal rig counts increased from 283 as of December 31, 2002 to 738 as of March 2, 2007, which accounted for 33% and 42% of the total U.S. rig count, respectively.

Our cost of revenues represents all direct and indirect costs associated with the operation and maintenance of our equipment. The principal elements of these costs are direct and indirect labor and benefits, repairs and maintenance of our equipment, insurance, equipment rentals, fuel and depreciation. Operating expenses do not fluctuate in direct proportion to changes in revenues because, among other factors, we have a fixed base of inventory of equipment and facilities to support our operations, and in periods of low drilling activity we may also seek to preserve labor continuity to market our services and maintain our equipment.

Cyclical Nature of Equipment Rental and Services Industry

Demand for our services has been strong throughout 2004, 2005 and 2006 due to high oil and natural gas prices and increased demand and declining production costs for natural gas as compared to other energy sources. Management believes the current market fundamentals are indicative of a favorable long-term trend of activity in our markets. However, these factors could be more than offset by other developments affecting the worldwide supply and demand for oil and natural gas products.

Restatement

We understated diluted earnings per share due to an incorrect calculation of our weighted shares outstanding for each of the first three quarters of 2004, for the year ended December 31, 2004 and for the quarter ended March 31, 2005. In addition, we understated basic earnings per share due to an incorrect calculation of our weighted average basic shares outstanding for the quarter ended September 30, 2004. Consequently, we restated our financial statements for each of those periods. The incorrect calculation resulted from a mathematical error and an improper application of Statement of Financial Accounting Standards No. 128, “Earnings Per Share”, or SFAS, No. 128. The effect of the restatement was to reduce weighted average diluted shares outstanding for the relevant periods and to reduce weighted average basic shares

outstanding for the quarter ended September 30, 2004. Therefore, diluted earnings per share were increased for the relevant periods and basic earnings per share were increased for the quarter ended September 30, 2004. (See Note 2 to our consolidated financial statements for the three years ended December 31, 2006).

In connection with the formation of AirComp in 2003, we, along with M-I contributed assets to AirComp in exchange for a 55% interest and 45% interest, respectively, in AirComp. We originally accounted for the formation of AirComp as a joint venture, but in February 2005 determined that the transaction should have been accounted for using purchase accounting pursuant to SFAS No. 141, “Business Combinations” and SEC Staff Accounting Bulletin No. 51 “Accounting for Sales of Stock by a Subsidiary.” Consequently, we restated our financial statements for the first three quarters of 2004 (See Note 2 to our consolidated financial statements for the three years ended December 31, 2006).

Results of Operations

In September 2004, we acquired the remaining 19% of Tubular and we acquired Safco. In November 2004, AirComp acquired substantially all of the assets of Diamond Air and, in December 2004, we acquired Downhole. We consolidated the results of these acquisitions from the day they were acquired.

In April 2005, we acquired Delta and, in May 2005, we acquired Capcoil. We report the operations of Downhole and Capcoil as our production services segment and the operations of Safco and Delta as our rental tools segment. In July 2005, we acquired the 45% interest of M-I in our compressed air drilling subsidiary, AirComp, making us the 100% owner of AirComp. In addition, in July 2005, we acquired the compressed air drilling assets of W. T. On August 1, 2005, we acquired 100% of the outstanding capital stock of Target. The results of Target are included in our directional drilling segment as their measurement while drilling equipment is utilized in that segment. On September 1, 2005, we acquired the casing and tubing service assets of Patterson Services, Inc. We consolidated the results of these acquisitions from the day they were acquired.

In January 2006, we acquired all of the outstanding stock of Specialty and in December 2006, we acquired substantially all of the assets of OGR. We report the operations of Specialty and OGR in our rental tool segment. In April 2006, we acquired all of the outstanding stock of Rogers. We report the operations of Rogers in our casing and tubing services segment. In August 2006, we acquired all of the outstanding stock of DLS and in December 2006, we acquired all of the outstanding stock of Tanus. We report the operations of DLS and Tanus in our international drilling segment. In October 2006, we acquired all of the outstanding stock of Petro Rentals. We report the operations of Petro Rentals in our production services segment. We consolidated the results of these acquisitions from the day they were acquired.

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

Comparison of Years Ended December 31, 2006 and December 31, 2005

Our revenues for the year ended December 31, 2006 was $307.3 million, an increase of 191.7% compared to $105.3 million for the year ended December 31, 2005. Revenues increased in all of our business segments due to the successful integration of acquisitions completed in the third quarter of 2005 and during 2006, the investment in new equipment, improved pricing for our services, the addition of operations and sales personnel and the opening of new operations offices. Revenues increased most significantly due to the acquisition of DLS on August 14, 2006 which expanded our operations to a sixth operating segment, international drilling. Revenues also increased significantly at our rental tools segment due to the acquisition of Specialty effective January 1, 2006. Our casing and tubing services segment also had a substantial increase in revenue, primarily due to the acquisitions of the casing and tubing assets of Patterson Services, Inc. on September 1, 2005, and the acquisition of Rogers as of April 1, 2006, along with the investment in additional equipment, improved market conditions and increased market penetration for our services in South Texas, East Texas, Louisiana and the U.S. Gulf of Mexico. Revenues increased at our compressed air drilling segment due to the purchase of additional equipment and improved pricing for our services. Our directional drilling services segment revenues increased in the 2006 period compared to the 2005 period due to improved pricing for directional drilling services, the August 2005 acquisition of Target which provides measurement-while-drilling tools, or MWD and the purchase of additional down-hole motors and MWDs which increased our capacity and market presence.

Our gross margin for the year ended December 31, 2006 increased 243.8% to $105.1 million, or 34.2% of revenues, compared to $30.6 million, or 29.0%, of revenues for the year ended December 31, 2005. The increase in gross profit is due to the increase in revenues in all of our business segments. The increase in gross profit as a percentage of revenues is primarily due to the acquisition of Specialty as of January 1, 2006, in the high margin rental tool business, the improved pricing for our services generally and the investments in new capital equipment. Also contributing to our improved gross profit margin was the acquisition of Target, the purchase of additional MWD’s and the acquisition of Rogers. The increase in gross profit was partially offset by an increase in depreciation expense of 315.7% to $20.3 million compared to $4.9 million for 2005. The increase is due to additional depreciable assets resulting from the acquisitions and capital expenditures. Our cost of revenues consists principally of our labor costs and benefits, equipment rentals, maintenance and repairs of our equipment, depreciation, insurance and fuel. Because many of our costs are fixed, our gross profit as a percentage of revenues is generally affected by our level of revenues.

General and administrative expense was $35.5 million for the year ended December 31, 2006 compared to $15.6 million for the year ended December 31, 2005. General and administrative expense increased due to additional expenses associated with the acquisitions, and the hiring of additional sales, operations and administrative personnel. General and administrative expense also increased because of increased accounting and consulting fees and other expenses in connection with initiatives to strengthen our internal control processes, costs related to Sarbanes Oxley compliance efforts and increased corporate accounting and administrative staff. As a percentage of revenues, general and administrative expenses were 11.6% in 2006 compared to 14.8% in 2005.

We adopted SFAS No. 123R, Share-Based Payment, effective January 1, 2006. This statement requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their grant-date fair values. We adopted SFAS No. 123R using the modified prospective transition method, utilizing the Black-Scholes option pricing model for the calculation of the fair value of our employee stock options. Under the modified prospective method, we record compensation cost related to unvested stock awards as of December 31, 2005 by recognizing the unamortized grant date fair value of these awards over the remaining vesting periods of those awards with no change in historical reported earnings. Therefore, we recorded an expense of $3.4 million related to stock awards for the year ended December 31, 2006 of which $3.0 million was recorded in general and administrative expense with the balance being recorded as a direct cost. Prior to January 1, 2006, we accounted for our stock-based compensation using Accounting Principle Board Opinion No. 25, or APB No. 25. Under APB No. 25, compensation expense is recognized for stock options with an exercise price that is less than the market price on the grant date of the option. Accordingly, no compensation cost was recognized under APB No. 25.

Amortization expense was $2.9 million for the year ended December 31, 2006 compared to $1.8 million for the year ended December 31, 2005. The increase in amortization expense is due to the amortization of intangible assets in connection with our acquisitions and the amortization of deferred financing costs which included approximately $1.1 million.

Income from operations for the year ended December 31, 2006 totaled $66.7 million, a 404.3% increase over the $13.2 million in income from operations for the year ended December 31, 2005, reflecting the increase in our revenues and gross profit, offset in part by increased general and administrative expenses. Our income from operations as a percentage of revenues increased to 21.7% in 2006 from 12.5% in 2005 due to the increase in our gross margin which offset the increases in amortization expense and general and administrative expenses.

Our net interest expense was $19.3 million for the year ended December 31, 2006, compared to $4.4 million for the year ended December 31, 2005. Interest expense increased in 2006 due to our increased debt. In January of 2006 we issued $160.0 million of senior notes bearing interest at 9.0% to fund the acquisition of Specialty, pay off other outstanding debt and for working capital. In August 2006 we issued an additional $95.0 million of senior notes bearing interest at 9.0% to fund a portion of the acquisition of DLS. On December 18, 2006, we borrowed $300.0 million in a senior unsecured bridge loan to fund the acquisition of OGR. The average interest rate on the bridge loan was approximately 10.6%. Interest expense for 2006 includes the write-off of $453,000 related to financing fees on the bridge loan. This bridge loan was repaid on

January 29, 2007 and the remaining $1.2 million of financing fees will be written off in 2007. In the third quarter of 2005, we incurred debt retirement expense of $1.1 million related to the refinancing of our debt. This amount includes prepayment penalties and the write-off of deferred financing fees from a previous financing.

Minority interest in income of subsidiaries for the year ended December 31, 2006 was $0 compared to $488,000 for the corresponding period in 2005 due to the our acquisition of the minority interest at AirComp on July 11, 2005.

Our provision for income taxes for the year ended December 31, 2006 was $11.4 million, or 24.3% of our net income before income taxes, compared to $1.3 million, or 15.8% of our net income before income taxes for 2005. The increase in our provision for income taxes is attributable to the significant increase in our operating income which resulted in the utilization of our deferred tax assets including our net operating losses, and the increase in percentage of income taxes to net income before income taxes attributable to our operations in Argentina which are taxed at 35.0%.

We had net income attributed to common stockholders of $35.6 million for the year ended December 31, 2006, an increase of 396.5%, compared to net income attributed to common stockholders of $7.2 million for the year ended December 31, 2005.

The following table compares revenues and income from operations for each of our business segments for the years ended December 31, 2006 and December 31, 2005. Income from operations consists of our revenues less cost of revenues, general and administrative expenses, and depreciation and amortization:


	Revenues						Income (Loss) from Operations
	2006		2005		Change		2006			2005			Change
	(In thousands)

Rental tools	$	51,521	$	5,059	$	46,462	$	26,293		$	1,300		$	24,993
International drilling		69,490		—		69,490		12,233			—			12,233
Directional drilling services		72,811		43,901		28,910		17,666			7,389			10,277
Casing and tubing services		50,887		20,932		29,955		12,544			4,994			7,550
Compressed air drilling services		43,045		25,662		17,383		10,810			5,612			5,198
Production services		19,550		9,790		9,760		2,137			(99	)		2,236
General corporate		—		—		—		(15,027	)		(5,978	)		(9,049	)

Total	$	307,304	$	105,344	$	201,960	$	66,656		$	13,218		$	53,438

Rental Tools Segment. Our rental tools revenues were $51.5 million for the year ended December 31, 2006, an increase from the $5.1 million in revenues for the year ended December 31, 2005. Income from operations increased to $26.3 million in 2006 compared to $1.3 million in 2005. The increase in revenue and operating income is primarily attributable to the acquisition of Specialty effective January 1, 2006, improved pricing, improved utilization of our inventory of rental equipment and to a lesser extent, the acquisition of the OGR assets in December 2006.

International Drilling Segment. Our international drilling revenues were $69.5 million for the year ended December 31, 2006, and our income from operations was $12.2 million. This segment of our operations was created with the acquisition of DLS in August of 2006. In November 2006, our DLS employees were involved in a ten-day labor strike in Argentina, which affected the entire oil industry in Argentina and had a negative impact on our results.

Directional Drilling Services Segment. Revenues for the year ended December 31, 2006 for our directional drilling services segment were $72.8 million, an increase of 65.9% from the $43.9 million in revenues for the year ended December 31, 2005. Income from operations increased 139.1% to $17.7 million for 2006 from $7.4 million for 2005. The improved results for this segment are due to the increase in drilling activity in the Texas and Gulf Coast areas, improved pricing, the acquisition of Target as of August 1, 2005

and the purchase of an additional six MWDs. Our increased operating expenses as a result of the addition of operations and personnel were more than offset by the growth in revenues and improved pricing for our services

Casing and Tubing Services Segment. Revenues for the year ended December 31, 2006 for the casing and tubing services segment were $50.9 million, an increase of 143.1% from the $20.9 million in revenues for the year ended December 31, 2005. Revenues from domestic operations increased to $44.4 million in 2006 from $14.5 million in 2005 as a result of the acquisition of Rogers, the acquisition of the casing and tubing assets of Patterson Services, Inc. on September 1, 2005 and investment in new equipment, all of which resulted in increased market penetration for our services in South Texas, East Texas, Louisiana and the U.S. Gulf of Mexico. The year ended December 2005 was also adversely impacted by hurricane activity in September of 2005. Revenues from Mexican operations increased to $6.5 million in 2006 from $6.4 million in 2005. Income from operations increased 151.2% to $12.5 million in 2006 from $5.0 million in 2005. The increase in this segment’s operating income is due to increased revenues both domestically and in our Mexico operations.

Compressed Air Drilling Services Segment. Our compressed air drilling revenues were $43.0 million for the year ended December 31, 2006, an increase of 67.7% compared to $25.7 million in revenues for the year ended December 31, 2005. Income from operations increased 92.6% to $10.8 million in 2006 compared to income from operations of $5.6 million in 2005. Our compressed air drilling revenues and operating income for the 2006 period increased compared to the 2005 period due in part to the acquisition of the air drilling assets of W. T., our investment in additional equipment and improved pricing in West Texas.

Production Services Segment. Our production services revenues were $19.6 million for the year ended December 31, 2006, compared to $9.8 million in revenues for the year ended December 31, 2005. Income from operations was $2.1 million in 2006 compared to a loss from operations of $99,000 in 2005. The increase in revenue is attributable to the acquisition of Petro-Rentals completed in October 2006, the acquisition of Capcoil on May 1, 2005 and improved utilization and pricing for our services. The increase in operating income is primarily related to the operations of Petro-Rentals and the addition of two coil tubing units in the fourth quarter of 2006.

Comparison of Years Ended December 31, 2005 and December 31, 2004

Our revenue for the year ended December 31, 2005 was $105.3 million, an increase of 120.7% compared to $47.7 million for the year ended December 31, 2004. The increase in revenues was principally due to acquisitions completed in the fourth quarter of 2004 and the second and third quarters of 2005, the addition of operations and sales personnel, the opening of new operations offices, and the purchase of additional equipment. Acquisitions completed during this period enabled us to establish our rental tool and production services segments which resulted in an increased offering of products and services and an expansion of our customer base.

Directional drilling services segment revenues increased in the 2005 period compared to the 2004 period due to the addition of operations and sales personnel, the opening of new operations offices and the purchase of additional downhole motors which increased our capacity and market presence. Revenues increased at our compressed air drilling segment due to acquisition of the air drilling assets of W. T. on July 11, 2005, the acquisitions of Diamond Air on November 1, 2004 and improved pricing for our services in West Texas. Revenues increased at our casing and tubing services segment due to the acquisition of the casing and tubing assets of Patterson Services Inc. on September 1, 2005, increased revenues from Mexico, improved market conditions, improved market penetration for our services in South Texas and the addition of operating personnel and equipment which broadened our capabilities. Also contributing to increased revenues were the acquisitions of Safco as of September 1, 2004, Downhole as of December 1, 2004, Delta as of April 1, 2005 and Capcoil as of May 1, 2005. Downhole and Capcoil comprised our production services segment and Safco and Delta comprised our rental tool segment

Our gross margin for the year ended December 31, 2005 increased 146.1% to $30.6 million, or 29.0% of revenues, compared to $12.4 million, or 26.0%, of revenues for the year ended December 31, 2004. The increase is due to increased revenues and improved pricing in the directional drilling services segment,

increased revenues at our compressed air drilling services segment, including revenues resulting from the acquisition of Diamond Air and the compressed air drilling assets of W.T., increased revenues from Mexico, improved market conditions for our domestic casing and tubing segment and the growth of our rental tools segment through the acquisition of Delta on April 1, 2005. Depreciation expense increased 80.4% to $4.9 million in 2005 compared to $2.7 million in 2004. The increase is due to additional depreciable assets resulting from capital expenditures and acquisitions in 2004 and 2005. Our cost of revenues consists principally of our labor costs and benefits, equipment rentals, maintenance and repairs of our equipment, depreciation, insurance and fuel. Because many of our costs are fixed, our gross profit as a percentage of revenues is generally affected by our level of revenues.

General and administrative expense was $15.6 million for the year ended December 31, 2005 compared to $7.3 million for the year ended December 31, 2004. General and administrative expense increased due to the additional expenses associated with the acquisitions completed in the second half of 2004 and in 2005, and the hiring of additional sales and administrative personnel. General and administrative expense also increased because of increased legal and accounting fees and other expenses related to our financing and acquisition activities, increased consulting fees in connection with our internal controls and corporate governance process, and increased corporate accounting and administrative staff. As a percentage of revenues, general and administrative expenses were 14.8% for 2005 and 15.3% for 2004.

Amortization expense was $1.8 million for the year ended December 31, 2005 compared to $0.9 million for the year ended December 31, 2004. The increase in amortization expense is due to the amortization of intangible assets in connection with our acquisitions and the amortization of deferred financing costs.

Income from operations for the year ended December 31, 2005 totaled $13.2 million, a 212.7% increase over the $4.2 million in income from operations for the year ended December 31, 2004, reflecting the increase in our revenues and gross profit, offset in part by increased general and administrative expenses.

Our interest expense was $4.4 million for the year ended December 31, 2005, compared to $2.8 million for the year ended December 31, 2004. Interest expense increased during 2005 due to the increased borrowings associated with the acquisitions completed in the second and third quarters of 2005, equipment purchases and higher average interest rates, offset in part by the prepayment, in December 2004, of our 12% $2.4 million subordinated note. Additionally, in 2005, we incurred debt retirement expense of $1.1 million related to the refinancing of our debt. This amount includes prepayment penalties and the write-off of deferred financing fees from a previous financing.

Minority interest in income of subsidiaries for the year ended December 31, 2005 was $488,000 compared to $321,000 for the corresponding period in 2004 due to the increase in profitability at AirComp due in part to the acquisition of Diamond Air as of November 1, 2004. The minority interest at AirComp was acquired on July 11, 2005 and the minority interest in Tubular, which was 19%-owned by director Jens Mortensen, was acquired on September 30, 2004.

We had net income attributed to common stockholders of $7.2 million for the year ended December 31, 2005, an increase of 839.1%, compared to net income attributed to common stockholders of $0.8 million for the year ended December 31, 2004. The net income attributed to common stockholders in the 2004 period is after $124,000 in preferred stock dividends.

The following table compares revenues and income from operations for each of our business segments for the years ended December 31, 2005 and December 31, 2004. Income from operations consists of our revenues less cost of revenues, general and administrative expenses, and depreciation and amortization:


	Revenues						Income (Loss) from Operations
	2005		2004		Change		2005			2004			Change
	(In thousands)

Rental tools	$	5,059	$	611	$	4,448	$	1,300		$	(71	)	$	1,371
Directional drilling services		43,901		24,787		19,114		7,389			3,061			4,328
Casing and tubing services		20,932		10,391		10,541		4,994			3,217			1,777
Compressed air drilling services		25,662		11,561		14,101		5,612			1,169			4,443
Production services		9,790		376		9,414		(99	)		4			(103	)
General corporate		—		—		—		(5,978	)		(3,153	)		(2,825	)

Total	$	105,344	$	47,726	$	57,618	$	13,218		$	4,227		$	8,991

Rental Tools Segment. Our rental tools revenues were $5.1 million for the year ended December 31, 2005, an increase of 728.0% compared to $0.6 million in revenues for the year ended December 31, 2004. Income from operations increased to $1.3 million in 2005 compared to a loss from operations of $71,000 in 2004. Operations for this segment include Safco, acquired in September 2004, and Delta, acquired in April 2005.

Directional Drilling Services Segment. Revenues for the year ended December 31, 2005 for our directional drilling services segment were $43.9 million, an increase of 77.1% from the $24.8 million in revenues for the year ended December 31, 2004. Income from operations increased 141.4% to $7.4 million for 2005 from $3.1 million for 2004. The improved results for this segment are due to the increase in drilling activity in the Texas and Gulf Coast areas, the establishment of new operations in West Texas and Oklahoma, the addition of operations and sales personnel, the purchase of additional downhole motors which increased our capacity and market presence and the acquisition of Target, a provider of measurement while drilling equipment, effective August 2005. Our operating income increased due to higher revenue explained above and cost savings achieved as a result of the purchases of most of the downhole motors used in directional drilling, which we had previously rented.

Casing and Tubing Services Segment. Revenues for the year ended December 31, 2005 for the casing and tubing services segment were $20.9 million, an increase of 101.4% from the $10.4 million in revenues for the year ended December 31, 2004. Revenues from domestic operations increased to $14.5 million in 2005 from $5.2 million in 2004 as a result of the acquisition of the casing and tubing assets of Patterson Services, Inc. on September 1, 2005, improved market conditions for our services in South Texas and the addition of personnel which added to our capabilities and our offering of services. Revenues from Mexican operations increased to $6.4 million in 2005 from $5.2 million in 2004 as a result of increased drilling activity in Mexico and the addition of equipment that increased our capacity. Income from operations increased 55.2% to $5.0 million in 2005 from $3.2 million in 2004. The increase in this segment’s operating income is due to increased revenues both domestically and in our Mexico operations.

Compressed Air Drilling Services Segment. Our compressed air drilling revenues were $25.7 million for the year ended December 31, 2005, an increase of 122.0% compared to $11.6 million in revenues for the year ended December 31, 2004. Income from operations increased 380.1% to $5.6 million in 2005 compared to income from operations of $1.2 million in 2004. Our compressed air drilling revenues and operating income for the 2005 period increased compared to the 2004 period due in part to the acquisition of the air drilling assets of W. T., the acquisitions of Diamond Air as of November 1, 2004 and improved pricing in West Texas.

Production Services Segment. Our production services revenues were $9.8 million for the year ended December 31, 2005, compared to $376,000 in revenues for the year ended December 31, 2004. Loss from operations was $99,000 in 2005 compared to an operating income of $4,000 in 2004. Operations for this segment consist of Downhole, acquired December 1, 2004, and Capcoil, acquired May 1, 2005. Our results for the year ended December 31, 2005 for this segment were negatively affected by costs incurred to expand our

international presence for production services and by downtime experienced by one of our larger coil tubing units.

Liquidity and Capital Resources

Our on-going capital requirements arise primarily from our need to service our debt, to acquire and maintain equipment, to fund our working capital requirements and to complete acquisitions. Our primary sources of liquidity are proceeds from the issuance of debt and equity securities and cash flows from operations. We had cash and cash equivalents of $39.7 million at December 31, 2006 compared to $1.9 million at December 31, 2005.

Operating Activities

In the year ended December 31, 2006, we generated $53.7 million in cash from operating activities. Net income for the year ended December 31, 2006 was $35.6 million. Non-cash additions to net income totaled $29.7 million in the 2006 period consisting primarily of $23.2 million of depreciation and amortization, $3.4 million related to the expensing of stock options as required under SFAS No. 123R, $2.2 million of deferred income tax, $781,000 for a provision for bad debts and $453,000 of amortization on the bridge loan fees, partially offset by $2.4 million of gain from the disposition of equipment.

During the year ended December 31, 2006, changes in working capital used $9.9 million in cash, principally due to an increase of $23.2 million in accounts receivable, a decrease of $2.3 million in accounts payable, offset in part by an increase of $11.4 million in accrued interest, an increase of $3.4 million in accrued employee benefits and payroll taxes and an increase of $872,000 in accrued expenses. Our accounts receivables increased at December 31, 2006 primarily due to the increase in our revenues in 2006. Accrued interest increased at December 31, 2006 due principally to interest accrued on our 9.0% senior notes which is payable semi-annually. Our accrued employee benefits and payroll taxes and other accrued expenses increased primarily due to the increase in costs due to our growth in revenues and acquisition completed in 2006.

In the year ended December 31, 2005, we generated $3.6 million in cash from operating activities. Net income for the year ended December 31, 2005 was $7.2 million. Non-cash additions to net income totaled $7.4 million in the 2005 period consisting primarily of $6.7 million of depreciation and amortization, $488,000 of minority interest in the income of a subsidiary, $653,000 in write-off of financing fees in conjunction with a refinancing and $219,000 for a provision for bad debts and the $669,000 of gain from the disposition of equipment.

During the year ended December 31, 2005, changes in working capital used $11.0 million in cash, principally due to an increase of $10.7 million in accounts receivable, an increase of $2.1 million in other current assets, an increase in other assets of $936,000, a decrease in other liabilities of $266,000 and a decrease of $97,000 in accrued expenses, offset in part by an increase of $2.4 million in accounts payable, an increase of $324,000 in accrued interest and a increase of $443,000 in accrued employee benefits and payroll taxes. Our accounts receivables increased at December 31, 2005 due primarily to the increase in our revenues in 2005. Other current assets increased $2.1 million due primarily to an increase in inventory. Accounts payable increased by $2.4 million at December 31, 2005 due to the increase in our cost of sales associated with the increase in our revenues and the acquisitions completed in 2005 and 2004.

In the year ended December 31, 2004, we generated $3.3 million in cash from operating activities. Net income before preferred stock dividend for the year ended December 31, 2004 was $888,000. Non-cash additions to net income totaled $4.4 million in the 2004 period consisting of $3.6 million of depreciation and amortization, $321,000 of minority interest in the income of a subsidiary, $350,000 in amortization of discount on debt and $104,000 for a provision for bad debts.

During the year ended December 31, 2004, changes in working capital used $2.0 million in cash, principally due to an increase of $2.4 million in accounts receivable, an increase of $638,000 in other assets, and a decrease of $398,000 in accrued expenses and other liabilities, offset in part by an increase of $1.1 million in accounts payable and an increase of $299,000 in accrued interest. Our accounts receivables increased at December 31, 2004 due primarily to the increase in our revenues in 2004. Current assets increased

$638,000 due primarily to an increase in prepaid insurance premiums. Accounts payable increased by $1.1 million at December 31, 2004 due to the increase in our cost of sales associated with the increase in our revenues and the acquisitions completed in the fourth quarter of 2004.

Investing Activities

During the year ended December 31, 2006, we used $559.4 million in investing activities consisting of six acquisitions and our capital expenditures. During the year ended December 31, 2006, we completed the following acquisitions for a total net cash outlay of $526.6 million, consisting of the purchase price and acquisition costs less cash acquired:


	•	Effective January 1, 2006, we acquired Specialty for a purchase price of $96.0 million in cash.

	•	Effective April 1, 2006, we acquired Rogers for a purchase price of $11.3 million in cash, 125,285 shares of our common stock and a promissory note for $750,000.

	•	On August 14, 2006, we acquired DLS for a purchase price of $93.7 million in cash, 2.5 million shares of our common stock and the assumption of $9.1 million of indebtedness.

	•	On October 16, 2006, we acquired Petro Rentals for a purchase price of $20.2 million in cash, 246,761 shares of our common stock and the payment of approximately $9.6 million of debt.

	•	Effective December 1, 2006, we acquired Tanus for a purchase price of $2.5 million in cash.

	•	On December 18, 2006, we acquired substantially all of the assets of OGR for a purchase price of approximately $291.0 million in cash and 3.2 million shares of our common stock.

In addition we made capital expenditures of approximately $39.7 million during the year ended December 31, 2006, including $4.5 million to replace “lost-in-hole” equipment and to increase our inventory of equipment in the rental tools segment, $5.8 million to purchase, improve and replace equipment in our international drilling segment, $5.1 million to purchase equipment for our directional drilling services segment, $7.7 million to purchase and improve equipment in our compressed air drilling service segment, $11.0 million to purchase and improve our casing equipment and approximately $5.3 million to expand our production services segment. We also received $6.9 million from the sale of assets during the year ended December 31, 2006, comprised mostly from equipment “lost-in-hole” from our rental tools segment ($3.8 million) and our directional drilling segment ($1.8 million).

During the year ended December 31, 2005, we used $53.1 million in investing activities. During the year ended December 31, 2005, we completed the following acquisitions for a total net cash outlay of $36.9 million, consisting of the purchase price and acquisition costs less cash acquired:


	•	On April 1, 2005 we acquired Delta for a purchase price of $4.6 million in cash, 223,114 shares of our common stock and two promissory notes totaling $350,000.

	•	On May 1, 2005, we acquired Capcoil for a purchase price of $2.7 million in cash, 168,161 shares of our common stock and the payment or assumption of approximately $1.3 million of debt.

	•	On July 11, 2005, we acquired the compressed air drilling assets of W.T. for a purchase price of $6.0 million in cash.

	•	On July 11, 2005, we acquired from M-I it’s 45% interest in AirComp and subordinated note in the principal amount of $4.8 million issued by AirComp, for which we paid M-I $7.1 million in cash and reissued a $4.0 million subordinated note.

	•	Effective August 1, 2005, we acquired Target for a purchase price of $1.3 million in cash and forgiveness of a lease receivable of $592,000.

	•	On September 1, 2005, we acquired the casing and tubing service assets of Patterson Services, Inc. for a purchase price of approximately $15.6 million.

In addition we made capital expenditures of approximately $17.8 million during the year ended December 31, 2005, including $2.9 million to purchase equipment for our directional drilling services segment, $7.0 million to purchase and improve equipment in our compressed air drilling service segment, $5.2 million to purchase and improve our casing equipment and approximately $1.5 million to expand our production

services segment. We also received $1.6 million from the sale of assets during the year ended December 31, 2005, comprised mostly from equipment lost in the hole from our directional drilling segment ($1.0 million) and our rental tool segment ($408,000).

During the year ended December 31, 2004, we used $9.1 million in investing activities, consisting principally of capital expenditures of approximately $4.6 million, including $1.6 million to purchase equipment for our directional drilling services segment, $1.3 million to purchase casing equipment and $1.4 million to make capital repairs to existing equipment in our compressed air drilling services segment. During the year ended December 31, 2004, we completed the following acquisitions for a net cash outlay of $4.6 million.


	•	As of September 1, 2004 we completed, for $1.0 million, the acquisition of 100% of the outstanding stock of Safco.

	•	As of November 1, 2004, AirComp acquired substantially all the assets of Diamond Air for $4.6 million in cash and the assumption of approximately $450,000 of debt. We contributed our share of the purchase price, or $2.5 million, to AirComp in order to fund the purchase.

	•	Effective December 1, 2004, we acquired Downhole for approximately $1.1 million in cash, 568,466 shares of our common stock and payment or assumption of $950,000 of debt.

Financing Activities

During the year ended December 31, 2006, financing activities provided a net of $543.6 million in cash. We received $557.8 million in borrowings under long-term debt facilities, consisting primarily of the issuance of $255.0 million of our 9.0% senior notes due 2014 and a $300.0 million senior unsecured bridge loan. The bridge loan, which was repaid on January 29, 2007, was used to fund the acquisition of OGR. We also received $46.3 million in net proceeds from the issuance of 3,450,000 shares of our common stock, $6.4 million on the tax benefit of options and $6.3 million from the proceeds of warrant and option exercises for 1,851,377 shares of our common stock. The proceeds were used to repay long-term debt totaling $54.0 million, repay $6.4 million in net borrowings under our revolving lines of credit, repay related party debt of $3.0 million and to pay $9.9 million in debt issuance costs.

During the year ended December 31, 2005, financing activities provided a net of $44.1 million in cash. We received $56.3 million in borrowings under long-term debt facilities, $15.5 million in net proceeds from the issuance of 1,761,034 shares of our common stock, $2.5 million in net borrowings under our revolving lines of credit and $1.4 million from the proceeds of warrant and option exercises for 1,076,154 shares of our common stock. The proceeds were used to repay long-term debt totaling $28.2 million, repay related party debt of $1.5 million and to pay $1.8 million in debt issuance costs.

During the year ended December 31, 2004, financing activities provided a net of $11.8 million in cash. We received $16.9 million in net proceeds from the issuance of 6,081,301 shares of our common stock, $8.2 million in borrowings under long-term debt facilities and a $689,000 increase in net borrowings under our revolving lines of credit. The proceeds were used to repay long-term debt totaling $13.5 million and to pay $391,000 in debt issuance costs.

On January 18, 2006 and August 14, 2006, we closed on private offerings, to qualified institutional buyers pursuant to Rule 144A under the Securities Act, of $160.0 million and $95.0 million aggregate principal amount of our senior notes, respectively. The senior notes are due January 15, 2014 and bear interest at 9.0%. The proceeds were used to fund the acquisitions of Specialty and DLS, to repay existing debt and for general corporate purposes. Debt repaid included all outstanding balances under our credit agreement, including a $42.1 million term loan and $6.4 million in working capital advances, a $4.0 million subordinated note issued in connection with acquisition of AirComp, approximately $3.0 million subordinated note issued in connection with the acquisition of Tubular, approximately $548,000 on a real estate loan and approximately $350,000 on outstanding equipment financing.

On January 18, 2006, we also executed an amended and restated credit agreement which provides for a $25.0 million revolving line of credit with a maturity of January 2010. This agreement contains customary events of default and financial covenants and limits our ability to incur additional indebtedness, make capital expenditures, pay dividends or make other distributions, create liens and sell assets. Our obligations under the

agreement are secured by substantially all of our assets excluding the DLS assets, but including 2/3 of our shares of DLS. At December 31, 2006, no amounts were borrowed on the facility but availability is reduced by outstanding letters of credit of $9.7 million.

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 margin was 7.0% at December 31, 2006. These bank loans are denominated in U.S. dollars and the outstanding amount due as of December 31, 2006 was $7.3 million.

On December 18, 2006, we closed on the OGR acquisition with the proceeds from a $300.0 million unsecured bridge financing. The bridge loan had a term of 18 months. Tranche A of the bridge was for $225.0 million and bore interest at LIBOR plus 3.75%, and Tranche B was for $75.0 million and bore interest at LIBOR plus 5.75% The bridge was repaid on January 29, 2007 from the proceeds of a private offering of $250.0 million aggregate principal amount of 8.5% senior notes due 2017 and the proceeds from an offering of 6.0 million shares of our common stock.

In connection with the acquisition of Rogers, we issued to the seller a note in the amount of $750,000. The note bears interest at 5.0% and is due April 3, 2009.

As part of the acquisition of Mountain Air in 2001, we issued a note to the sellers of Mountain Air in the original amount of $2.2 million accruing interest at a rate of 5.75% per annum. The note was reduced to $1.5 million as a result of the settlement of a legal action against the sellers in 2003. In March 2005, we reached an agreement with the sellers and holders of the note as a result of an action brought against us by the sellers. Under the terms of the agreement, we paid the holders of the note $1.0 million in cash, and agreed to pay an additional $350,000 on June 1, 2006, and an additional $150,000 on June 1, 2007, in settlement of all claims. At December 31, 2006 the outstanding amounts due were $150,000.

In connection with the purchase of Safco, we agreed to pay a total of $150,000 to the sellers in exchange for a non-compete agreement. We are required to make annual payments of $50,000 through September 30, 2007. In connection with the purchase of Capcoil, we agreed to pay a total of $500,000 to two management employees in exchange for non-compete agreements. We are required to make annual payments of $110,000 through May 2008. Total amounts due under theses non-compete agreements at December 31, 2006 was $270,000.

In 2000 we compensated directors, including current directors Nederlander and Toboroff, who served on the board of directors from 1989 to March 31, 1999 without compensation, by issuing promissory notes totaling $325,000. The notes bore interest at the rate of 5.0%. At December 31, 2006, the principal and accrued interest on these notes totaled approximately $32,000.

We have various equipment financing loans with interest rates ranging from 5.0% to 8.7% and terms ranging from 2 to 5 years. As of December 31, 2006, the outstanding balances for equipment financing loans were $3.5 million. We also have various capital leases with terms that expire in 2008. As of December 31, 2006, amounts outstanding under capital leases were approximately $414,000.

In April 2006 and August 2006, we obtained insurance premium financings in the amount of $1.9 million and $896,000 with fixed interest rates of 5.6% and 6.0%, respectively Under terms of the agreements, amounts outstanding are paid over 10 month and 11 month repayment schedules. The outstanding balances of these notes was approximately $1.0 million as of December 31, 2006.

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, 2006.


	Payments by Period
			Less Than
	Total		1 Year		2-3 Years		4-5 Years		After 5 Years
	(In thousands)

Contractual Obligations
Notes payable(a)	$	518,032	$	6,586	$	4,646	$	1,800	$	505,000
Capital leases(b)		413		413		—		—		—
Interest payments on notes payable(a)		379,759		45,797		88,858		88,456		156,648
Operating leases		5,418		2,013		2,658		277		470
Employment contracts		5,394		3,064		2,330		—		—

Total contractual cash obligations	$	909,016	$	57,873	$	98,492	$	90,533	$	662,118


(a)		Includes obligations on our $255 million 8.5% senior notes closed in January 2007. The proceeds from the 8.5% senior notes and our January 2007 common stock offering were used to repay the $300 million bridge loan facility that was outstanding at December 31, 2006.

(b)		These amounts represent our minimum capital lease payments, net of interest payments totaling $15,000.

We have identified capital expenditure projects that will require up to approximately $80.0 million in 2007, exclusive of any acquisitions. We believe that our cash generated from operations, cash on hand and cash available under our credit facilities will provide sufficient funds for our identified projects.

We intend to implement a growth strategy of increasing the scope of services through both internal growth and acquisitions. We are regularly involved in discussions with a number of potential acquisition candidates. We expect to make capital expenditures to acquire and to maintain our existing equipment. Our performance and cash flow from operations will be determined by the demand for our services which in turn are affected by our customers’ expenditures for oil and natural gas exploration and development and industry perceptions and expectations of future oil and natural gas prices in the areas where we operate. We will need to refinance our existing debt facilities as they become due and provide funds for capital expenditures and acquisitions. To effect our expansion plans, we will require additional equity or debt financing in excess of our current working capital and amounts available under credit facilities. There can be no assurance that we will be successful in raising the additional debt or equity capital or that we can do so on terms that will be acceptable to us.

Recent Developments

In January 2007, we closed on a private offering, to qualified institutional buyers pursuant to Rule 144A under the Securities Act, of $255.0 million principal amount of our 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 million bridge loan facility, which we incurred to finance our acquisition of substantially all the assets of OGR.

In January 2007, we closed on a public offering of 6.0 million shares of our common stock at $17.65 per share. The proceeds of the common stock offering, together with the proceeds of our concurrent senior notes offering, were used to repay the debt outstanding under our $300 million bridge loan facility, which we incurred to finance our acquisition of substantially all the assets of OGR and for general corporate purposes.

On February 7, 2007, Zane Tankel was elected as a member of our Board of Directors.

Critical Accounting Policies

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

is discussed throughout Management’s Discussion and Analysis of Financial Condition and Results of Operations where such policies affect our reported and expected financial results. For a detailed discussion on the application of these and other accounting policies, see Note 1 in the Notes to the Consolidated Financial Statements included elsewhere in this document. Our preparation of this report requires us to make estimates and assumptions that affect the reported amount of assets and liabilities, disclosure of contingent assets and liabilities at the date of our financial statements, and the reported amounts of revenue and expenses during the reporting period. There can be no assurance that actual results will not differ from those estimates.

Allowance For Doubtful Accounts. The determination of the collectibility of amounts due from our customers requires us to use estimates and make judgments regarding future events and trends, including monitoring our customer payment history and current credit worthiness to determine that collectibility is reasonably assured, as well as consideration of the overall business climate in which our customers operate. Those uncertainties require us to make frequent judgments and estimates regarding our customers’ ability to pay amounts due us in order to determine the appropriate amount of valuation allowances required for doubtful accounts. Provisions for doubtful accounts are recorded when it becomes evident that the customers will not be able to make the required payments at either contractual due dates or in the future.

Revenue Recognition. We provide rental equipment and drilling services to our customers at per day and per job contractual rates and recognize the drilling related revenue as the work progresses and when collectibility is reasonably assured. The Securities and Exchange Commission’s Staff Accounting Bulletin No. 104, Revenue Recognition in Financial Statements, provides guidance on the SEC staff’s views on application of generally accepted accounting principles to selected revenue recognition issues. Our revenue recognition policy is in accordance with generally accepted accounting principles and SAB No. 104.

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

Goodwill And Other Intangibles. As of December 31, 2006, we have recorded approximately $125.8 million of goodwill and $32.8 million of other identifiable intangible assets. We perform purchase price allocations to intangible assets when we make a business combination. Business combinations and purchase price allocations have been consummated for acquisitions in all of our reportable segments. The excess of the purchase price after allocation of fair values to tangible assets is allocated to identifiable intangibles and thereafter to goodwill. Subsequently, we perform our initial impairment tests and annual impairment tests in accordance with Financial Accounting Standards Board No. 141, Business Combinations, and Financial Accounting Standards Board No. 142, Goodwill and Other Intangible Assets. These initial valuations used two approaches to determine the carrying amount of the individual reporting units. The first approach is the Discounted Cash Flow Method, which focuses on our expected cash flow. In applying this approach, the cash flow available for distribution is projected for a finite period of years. Cash flow available for distribution is defined as the amount of cash that could be distributed as a dividend without impairing our future profitability or operations. The cash flow available for distribution and the terminal value (our value at the end of the estimation period) are then discounted to present value to derive an indication of value of the business enterprise. This valuation method is dependent upon the assumptions made regarding future cash flow and cash requirements. The second approach is the Guideline Company Method which focuses on comparing us to selected reasonably similar publicly traded companies. Under this method, valuation multiples are: (i) derived from operating data of selected similar companies; (ii) evaluated and adjusted based on our strengths and weaknesses relative to the selected guideline companies; and (iii) applied to our operating data to arrive at an indication of value. This valuation method is dependent upon the assumption that our value can be evaluated by analysis of our earnings and our strengths and weaknesses relative to the selected similar companies.

Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period.

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

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

Recently Issued Accounting Standards

In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments. SFAS No. 155 provides entities with relief from having to separately determine the fair value of an embedded derivative that would otherwise be required to be bifurcated from its host contract in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. SFAS No. 155 allows an entity to make an irrevocable election to measure such a hybrid financial instrument at fair value in its entirely, with changes in fair value recognized in earning. SFAS No. 155 is effective for all financial instruments acquired , issued or subject to a remeasurement event occurring after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We believe that the adoption of SFAS No. 155 will not have a material impact on our financial position, results of operations or cash flows.

In March 2006, the FASB issued SFAS No. 156, Accounting for Servicing of Financial Assets — An Amendment to FASB Statement No. 140. SFAS No. 156 requires entities to recognize a servicing asset or liability each time they undertake an obligation to service a financial asset by entering into a servicing contract in certain situations. This statement also requires all separately recognized servicing assets and servicing liabilities to be initially measured at fair value and permits a choice of either the amortization or fair value measurement method for subsequent measurement. The effective date of this statement is for annual periods beginning after September 15, 2006, with earlier adoption permitted as of the beginning of an entity’s fiscal year provided the entity has not issued any financial statements for that year. We do not plan to adopt SFAS No. 156 early, and we are currently assessing the impact on our Consolidated Financial Statements.

In July 2006, the FASB issued FASB Interpretation, FIN, No. 48, Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109. FIN No. 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. It prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This new standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The provisions of FIN No. 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN No. 48. The cumulative effect of applying the provisions of FIN No. 48 should be reported as an adjustment to the opening balance of

retaining earnings (or other appropriate components of equity or net assets in the statement of financial position) for that fiscal year. The provisions of FIN No. 48 are effective for fiscal years beginning after December 15, 2006. We are currently evaluating the impact of applying the provisions of FIN No. 48.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 clarifies the principle that fair value should be based on the assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, with early adoption permitted. We believe that the adoption of SFAS No. 157 will not have a material impact on our financial position, results of operations or cash flows.

In September 2006, the FASB issued FSP No. AUG AIR-1, Accounting for Planned Major Maintenance Activities. FSP No. AUG AIR-1 prohibits the use of the accrued-in-advance method for accounting for major maintenance activities and confirms the acceptable methods of accounting for planned major maintenance activities. FSP No. AUG AIR-1 is effective the first fiscal year beginning after December 15, 2006. We believe that the adoption of FSP No. AUG AIR-1 will not have a material impact on our financial position, results of operations or cash flows.

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (“SAB 108”). SAB 108 requires that public companies utilize a “dual-approach” to assessing the quantitative effects of financial misstatements. This dual approach includes both an income statement focused assessment and a balance sheet focused assessment. SAB 108 is effective for fiscal years ending after November 15, 2006. We adopted SAB 108 on December 31, 2006, and there was no impact on our consolidated financial statements.

Off-Balance Sheet Arrangements

We have no off balance sheet arrangements, other than normal operating leases and employee contracts, that have or are likely to have a current or future material effect on our financial condition, changes in financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources. We have a $25.0 million revolving line of credit with a maturity of January 2010. At December 31, 2006, no amounts were borrowed on the facility but availability is reduced by outstanding letters of credit of $9.7 million. We do not guarantee obligations of any unconsolidated entities.


ITEM 7A.	*QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.*

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

Interest Rate Risk

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

At December 31, 2006, we were exposed to interest rate fluctuations on approximately $8.1 million of bank loans carrying variable interest rates. A hypothetical one hundred basis point increase in interest rates for these notes payable would increase our annual interest expense by approximately $81,000. Due to the uncertainty of fluctuations in interest rates and the specific actions that might be taken by us to mitigate the impact of such fluctuations and their possible effects, the foregoing sensitivity analysis assumes no changes in our financial structure.

We have also been subject to interest rate market risk for short-term invested cash and cash equivalents. The principal of such invested funds would not be subject to fluctuating value because of their highly liquid short-term nature. As of December 31, 2006, we had $28.3 million invested in short-term maturing investments.

Foreign Currency Exchange Rate Risk

We have designated the U.S. dollar as the functional currency for our operations in international locations as we contract with customers, purchase equipment and finance capital using the U.S. dollar. Local currency transaction gains and losses, arising from remeasurement of certain assets and liabilities denominated in local currency, are included in our consolidated statements of income. For the year ended December 31, 2006, we had a net foreign exchange loss of $515,000 relating to our DLS operations. We conduct business in Mexico through our Mexican partner, Matyep. This business exposes us to foreign exchange risk. To control this risk, we provide for payment in U.S. dollars.


ITEM 8.	*FINANCIAL STATEMENTS.*

INDEX TO FINANCIAL STATEMENTS

ALLIS-CHALMERS ENERGY INC. AND SUBSIDIARIES


	Page

Management’s Report to the Stockholders of Allis-Chalmers Energy Inc.		49
Reports of Independent Registered Public Accounting Firm		50
Consolidated Balance Sheet		52
Consolidated Statement of Operations		53
Consolidated Statement of Stockholders’ Equity		54
Consolidated Statement of Cash Flows		55
Notes to Consolidated Financial Statements		56
Supplemental Information to Consolidated Financial Statements — Summarized Quarterly Financial Data		91

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, 2006, based on criteria in Internal Control-Integrated Framework issued by the COSO. Our assessment of the effectiveness of Allis-Chalmers internal control over financial reporting as of December 31, 2006 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/ Munawar H. Hidayatallah	By:	/s/ Victor Perez
	Munawar H. Hidayatallah		Victor Perez
	Chief Executive Officer		Chief Financial Officer

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Allis-Chalmers Energy Inc.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Allis-Chalmers Energy Inc. and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the 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, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Allis-Chalmers Energy Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2006, 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, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2006, the Company changed its method of accounting for stock-based compensation.

/s/ UHY LLP

Houston, Texas

March 15, 2007

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and

Stockholders of Allis-Chalmers Energy Inc.:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting appearing on Page 49, that Allis-Chalmers Energy Inc. and subsidiaries, or the Company, maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over finance reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting of Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, 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 receipts and expenditures of the company are being made only in accordance with authorization 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, management’s assessment that Allis-Chalmers Energy Inc. and subsidiaries maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control-Integrated Framework issued by Committee of Sponsoring Organizations of the Treadway Commission. Also, in our opinion, Allis-Chalmers Energy Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Allis-Chalmers Energy Inc. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders equity, and cash flows for each of the three years in the period ended December 31, 2006, and our report dated March 15, 2007 expressed an unqualified opinion on those consolidated financial statements.

/s/ UHY LLP

Houston, Texas

March 15, 2007

ALLIS-CHALMERS ENERGY INC.

CONSOLIDATED BALANCE SHEETS


	December 31,
	2006		2005
	(In thousands, except
	for share and per share amounts)

ASSETS
Cash and cash equivalents	$	39,745	$	1,920
Trade receivables, net of allowance for doubtful accounts of $826 and $383 at December 31, 2006 and 2005, respectively		95,766		26,964
Inventories		28,615		5,945
Prepaid expenses and other		16,636		823

Total current assets		180,762		35,652
Property and equipment, at costs net of accumulated depreciation of $29,743 and $9,996 at December 31, 2006 and 2005, respectively		554,258		80,574
Goodwill		125,835		12,417
Other intangible assets, net of accumulated amortization of $4,475 and $3,163 at December 31, 2006 and 2005, respectively		32,840		6,783
Debt issuance costs, net of accumulated amortization of $1,501 and $299 at December 31, 2006 and 2005, respectively		9,633		1,298
Other assets		4,998		631

Total assets	$	908,326	$	137,355


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current maturities of long-term debt	$	6,999	$	5,632
Trade accounts payable		25,666		9,018
Accrued salaries, benefits and payroll taxes		10,888		1,271
Accrued interest		11,867		289
Accrued expenses		16,951		4,350
Accounts payable, related parties		—		60

Total current liabilities		72,371		20,620
Deferred income tax liability		19,953		—
Long-term debt, net of current maturities		561,446		54,937
Other long-term liabilities		623		923

Total liabilities		654,393		76,480
Commitments and Contingencies
Stockholders’ Equity
Preferred stock, $0.01 par value (25,000,000 shares authorized, none issued)		—		—
Common stock, $0.01 par value (100,000,000 shares authorized; 28,233,411 issued and outstanding at December 31, 2006 and 16,859,988 issued and outstanding at December 31, 2005)		282		169
Capital in excess of par value		216,208		58,889
Retained earnings		37,443		1,817

Total stockholders’ equity		253,933		60,875

Total liabilities and stockholders’ equity	$	908,326	$	137,355

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

ALLIS-CHALMERS ENERGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS


	Years Ended December 31,
	2006			2005			2004
							(Restated)
	(In thousands, except per
	share amounts)

Revenues	$	307,304		$	105,344		$	47,726
Cost of revenues
Direct costs		181,919			69,889			32,598
Depreciation		20,261			4,874			2,702

Gross margin		105,124			30,581			12,426
General and administrative expense		35,536			15,576			7,323
Amortization		2,932			1,787			876

Income from operations		66,656			13,218			4,227
Other income (expense):
Interest expense		(20,235	)		(4,446	)		(2,808	)
Interest income		972			49			32
Other		(347	)		186			272

Total other income (expense)		(19,610	)		(4,211	)		(2,504	)

Income before minority interest and income taxes		47,046			9,007			1,723
Minority interest in income of subsidiaries		—			(488	)		(321	)
Provision for income taxes		(11,420	)		(1,344	)		(514	)

Net income		35,626			7,175			888
Preferred stock dividend		—			—			(124	)

Net income attributed to common stockholders	$	35,626		$	7,175		$	764

Income per common share — basic	$	1.73		$	0.48		$	0.10

Income per common share — diluted	$	1.66		$	0.44		$	0.09

Weighted average number of common shares outstanding:
Basic		20,548			14,832			7,930

Diluted		21,410			16,238			9,510

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

ALLIS-CHALMERS ENERGY INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY


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

Balances, December 31, 2003, as restated		3,926,668		39		10,748			(6,246	)		4,541
Net income		—		—		—			888			888
Issuance of common stock:
Acquisitions		1,868,466		19		8,592			—			8,611
Private placement		6,081,301		61		15,600			—			15,661
Services		17,000		—		99			—			99
Conversion of preferred stock		1,718,090		17		4,278			—			4,295
Issuance of stock purchase warrants		—		—		1,138			—			1,138
Accrual of preferred dividends		—		—		(124	)		—			(124	)

Balances, December 31, 2004		13,611,525		136		40,331			(5,358	)		35,109
Net income		—		—		—			7,175			7,175
Issuance of common stock:
Acquisitions		411,275		4		1,746			—			1,750
Secondary public offering, net of offering costs		1,761,034		18		15,441			—			15,459
Stock options and warrants exercised		1,076,154		11		1,371			—			1,382

Balances, December 31, 2005		16,859,988		169		58,889			1,817			60,875
Net income		—		—		—			35,626			35,626
Issuance of common stock:
Acquisitions		6,072,046		61		94,919			—			94,980
Secondary public offering, net of offering costs		3,450,000		34		46,263			—			46,297
Stock options and warrants exercised		1,851,377		18		6,303			—			6,321
Stock based compensation		—		—		3,394			—			3,394
Tax benefits on stock plans		—		—		6,440			—			6,440

Balances, December 31, 2006		28,233,411	$	282	$	216,208		$	37,443		$	253,933

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

ALLIS-CHALMERS ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2006			2005			2004
	(In thousands)

Cash Flows from Operating Activities:
Net income	$	35,626		$	7,175		$	888
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		20,261			4,874			2,702
Amortization		2,932			1,787			876
Write-off of deferred financing fees due to refinancing		453			653			—
Issuance of stock options for services		—			—			14
Stock based compensation		3,394			—			—
Provision for bad debts		781			219			104
Amortization of discount on debt		—			9			350
Imputed interest		355			—			—
Deferred taxes		2,215			—			—
Minority interest in income of subsidiaries		—			488			321
(Gain) on sale of property		(2,444	)		(669	)		—
Changes in working capital:
(Increase) in accounts receivable		(23,175	)		(10,656	)		(2,396	)
(Increase) in due from related party		—			—			(7	)
(Increase) in other current assets		(132	)		(2,143	)		(612	)
Decrease (increase) in other assets		308			(936	)		(19	)
(Decrease) increase in accounts payable		(2,337	)		2,373			1,140
Increase in accrued interest		11,382			324			299
Increase (Decrease) in accrued expenses		872			(97	)		(276	)
(Decrease) in other liabilities		(224	)		(266	)		(141	)
Increase in accrued salaries, benefits and payroll taxes		3,392			443			19

Net cash provided by operating activities		53,659			3,578			3,262
Cash Flows from Investing Activities:
Acquisitions, net of cash acquired		(526,572	)		(36,888	)		(4,459	)
Purchase of property and equipment		(39,697	)		(17,767	)		(4,603	)
Proceeds from sale of property and equipment		6,881			1,579			—

Net cash used in investing activities		(559,388	)		(53,076	)		(9,062	)
Cash Flows from Financing Activities:
Proceeds from issuance of long-term debt		557,820			56,251			8,169
Payments on long-term debt		(54,030	)		(28,202	)		(13,259	)
Payments on related party debt		(3,031	)		(1,522	)		(246	)
Net (repayments) borrowings on lines of credit		(6,400	)		2,527			689
Proceeds from issuance of common stock, net of offering costs		46,297			15,459			16,883
Proceeds from exercise of options and warrants		6,321			1,382			—
Tax benefit on options		6,440			—			—
Debt issuance costs		(9,863	)		(1,821	)		(391	)

Net cash provided by financing activities		543,554			44,074			11,845

Net increase (decrease) in cash and cash equivalents		37,825			(5,424	)		6,045
Cash and cash equivalents at beginning of year		1,920			7,344			1,299

Cash and cash equivalents at end of year	$	39,745		$	1,920		$	7,344

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

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements

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

Organization of Business

Allis-Chalmers Energy Inc. (“Allis-Chalmers”, “we”, “our” or “us”) was incorporated in Delaware in 1913. We are a multi-faceted oilfield services company that provides services and equipment to oil and natural gas exploration and production companies, domestically in Texas, Louisiana, New Mexico, Colorado, Oklahoma, Mississippi, Utah, Wyoming, Arkansas, Alabama, West Virginia, offshore in the Gulf of Mexico, and internationally, primarily in Argentina and Mexico. We operate in six sectors of the oil and natural gas service industry: rental tools, international drilling, directional drilling services; casing and tubing services; compressed air drilling services; and production 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, 2006 are Oil Quip Rentals, Inc. (“Oil Quip”), Mountain Compressed Air Inc. (“Mountain Air”), Allis-Chalmers Tubular Services Inc. (“Tubular”), Strata Directional Technology, Inc. (“Strata”), AirComp LLC (“AirComp”), Allis-Chalmers Rental Services, Inc. (“Rental”), Allis-Chalmers Production Services, Inc. (“Production”), Allis-Chalmers Management LP, Drilling, Logistics & Services Corporation (“DLS”) and Petro-Rentals, Incorporated (“Petro-Rental”). All significant inter-company transactions have been eliminated.

Revenue Recognition

We provide rental equipment and drilling services to our customers at per day and per job contractual rates and recognize the drilling related revenue as the work progresses and when collectibility is reasonably assured. 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 $2.4 million, $970,000 and $41,000 for the year ended December 31, 2006, 2005 and 2004, respectively. The Securities and Exchange Commission’s (SEC) Staff Accounting Bulletin (SAB) No. 104, Revenue Recognition In Financial Statements (“SAB No. 104”), provides guidance on the SEC staff’s views on the application of generally accepted accounting principles to selected revenue recognition issues. Our revenue recognition policy is in accordance with generally accepted accounting principles and SAB No. 104.

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, 2006 and 2005, we had recorded an allowance for doubtful accounts of $826,000 and $383,000 respectively. Bad debt expense was $781,000, $219,000 and $104,000 for the years ended December 31, 2006, 2005 and 2004, respectively.

Cash Equivalents

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

Inventories

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

Property and Equipment

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

Maintenance and repairs, which do not improve or extend the life of the related assets, are charged to operations when incurred. Refurbishments and renewals are capitalized when the value of the equipment is enhanced for an extended period. When property and equipment are sold or otherwise disposed of, the asset account and related accumulated depreciation account are relieved, and any gain or loss is included in operations.

The cost of property and equipment currently in service is depreciated over the estimated useful lives of the related assets, which range from three to twenty years. Depreciation is computed on the straight-line method for financial reporting purposes. Capital leases are amortized using the straight-line method over the estimated useful lives of the assets and lease amortization is included in depreciation expense. Depreciation expense charged to operations was $20.3 million, $4.9 million and $2.7 million for the years ended December 31, 2006, 2005 and 2004, respectively.

Goodwill, Intangible Assets and Amortization

Goodwill, including goodwill associated with equity method investments, and other intangible assets with infinite lives are not amortized, but tested for impairment annually or more frequently if circumstances indicate that impairment may exist. Intangible assets with finite useful lives are amortized either on a straight-

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

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. If the fair value of the reporting unit is less than the book value (including goodwill) then goodwill is reduced to its implied fair value and the amount of the writedown is charged against earnings. We perform impairment tests on the carrying value of our goodwill on an annual basis as of December 31st for each of our reportable segments. As of December 31, 2006 and 2005, no impairment was deemed necessary. Increases in estimated future costs or decreases in projected revenues could lead to an impairment of all or a portion of our goodwill in future period.

Impairment of Long-Lived Assets

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

Financial Instruments

Financial instruments consist of cash and cash equivalents, accounts receivable and payable, and debt. The carrying value of cash and cash equivalents and accounts receivable and payable approximate fair value due to their short-term nature. We believe the fair values and the carrying value of our debt would not be materially different due to the instruments’ interest rates approximating market rates for similar borrowings at December 31, 2006 and 2005.

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, 2006, we have approximately $2.0 million of cash and cash equivalents residing in Argentina. We transact our business with several financial institutions. However, the amount on deposit in six financial institutions exceeded the $100,000 federally insured limit at December 31, 2006 by a total of $10.5 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 2006, one of our customers, Pan American Energy LLC Sucursal Argentina, or Pan American Energy, represented 11.7% of our consolidated revenues. In 2005 none of our customers accounted for more than 10% of our consolidated revenues. In the year ended December 31, 2004, Materiales y Equipo Petroleo, or Matyep in Mexico represented 10.8%, and Burlington Resources represented 10.1% of our consolidated revenues, respectively. Revenues from Matyep represented 8.3%, 94.5% and 98.0% of our international revenues in 2006, 2005 and 2004, respectively. Revenues from Pan American Energy represented 45.6% of our international revenues.

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.

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

Income Taxes

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

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

Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in tax rates and changes in prior year tax estimates as returns are filed. Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the enacted tax rates in effect at year end. A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized.

Stock-Based Compensation

We adopted SFAS No. 123R, Share-Based Payment (“SFAS No. 123R”), effective January 1, 2006. This statement requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their grant-date fair values. Compensation cost for awards granted prior to, but not vested, as of January 1, 2006 would be based on the grant date attributes originally used to value those awards for pro forma purposes under SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS No. 123”). We adopted SFAS No. 123R using the modified prospective transition method, utilizing the Black-Scholes option pricing model for the calculation of the fair value of our employee stock options. Under the modified prospective method, we record compensation cost related to unvested stock awards as of December 31, 2005 by recognizing the unamortized grant date fair value of these awards over the remaining vesting periods of those awards with no change in historical reported earnings. We estimated forfeiture rates for 2006 based on our historical experience.

The Black-Scholes model incorporates assumptions to value stock-based awards. The risk-free rate of interest is the related U.S. Treasury yield curve for periods within the expected term of the option at the time of grant. The dividend yield on our common stock is assumed to be zero as we have historically not paid dividends and have no current plans to do so in the future. The expected volatility is based on historical volatility of our common stock.

Prior to January 1, 2006, we accounted for our stock-based compensation using Accounting Principle Board Opinion No. 25 (“APB No. 25”). Under APB No. 25, compensation expense is recognized for stock options with an exercise price that is less than the market price on the grant date of the option. For stock

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

options with exercise prices at or above the market value of the stock on the grant date, we adopted the disclosure-only provisions of SFAS No. 123. We also adopted the disclosure-only provisions of SFAS No. 123 for the stock options granted to our employees and directors. Accordingly, no compensation cost was recognized under APB No. 25. Our net income for the year ended December 31, 2006 includes approximately $3.4 million of compensation costs related to share-based payments. The tax benefit recorded in association with the share-based payments was $1.2 million for the year-ended December 31, 2006. As of December 31, 2006 there is $1.3 million of unrecognized compensation expense related to non-vested stock based compensation grants.

Had compensation expense for the options granted been recorded based on the fair value at the grant date for the options, consistent with the provisions of SFAS 123, our net income/(loss) and net income/(loss) per share for the years ended December 31, 2005 and 2004 would have been decreased to the pro forma amounts indicated below (in thousands, except per share amounts):


		For the Years Ended December 31,
		2005			2004
					(Restated)

Net income attributed to common stockholders as reported:		$	7,175		$	764
Less total stock based employee compensation expense determined under fair value based method for all awards net of tax related effects			(4,284	)		(1,072	)

Pro-forma net income (loss) attributed to common stockholders		$	2,891		$	(308	)

Net income/(loss) per common share:
Basic	As reported	$	0.48		$	0.10
	Pro forma	$	0.19		$	(0.04	)
Diluted	As reported	$	0.44		$	0.09
	Pro forma	$	0.18		$	(0.04	)

Options were granted in 2006, 2005 and 2004. See Note 12 for further disclosures regarding stock options. The following assumptions were applied in determining the pro forma compensation costs:


	For the Years Ended December 31,
	2006			2005			2004

Expected dividend yield		—			—			—
Expected price volatility		72.28	%		84.28	%		89.76	%
Risk-free interest rate		5.1	%		5.6	%		7.00	%
Expected life of options		7 years			7 years			7 years
Weighted average fair value of options granted at market value		$10.58			$5.02			$3.19

Segments of an Enterprise and Related Information

We disclose the results of our segments in accordance with SFAS No. 131, Disclosures About Segments Of An Enterprise And Related Information (“SFAS No. 131”). We designate the internal organization that is used by management for allocating resources and assessing performance as the source of our reportable segments. SFAS No. 131 also requires disclosures about products and services, geographic areas and major customers Please see Note 16 for further disclosure of segment information in accordance with SFAS No. 131.

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

Income Per Common Share

We compute income per common share in accordance with the provisions of SFAS No. 128, Earnings Per Share (“SFAS No. 128”). SFAS No. 128 requires companies with complex capital structures to present basic and diluted earnings per share. Basic earnings per share are computed on the basis of the weighted average number of shares of common stock outstanding during the period. For periods through April 12, 2004, preferred dividends are deducted from net income and have been considered in the calculation of income available to common stockholders in computing basic earnings per share. 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. Potential dilutive common shares that have an anti-dilutive effect (e.g., those that increase income per share) are excluded from diluted earnings per share.

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


	For the Years Ended December 31,
	2006		2005		2004
					(Restated)

Numerator:
Net income available for common stockholders	$	35,626	$	7,175	$	764
Plus income impact of assumed conversions:
Preferred stock dividends/interest		—		—		124

Net income applicable to common stockholders plus assumed conversions	$	35,626	$	7,175	$	888

Denominator:
Denominator for basic earnings per share — weighted average shares outstanding		20,548		14,832		7,930
Effect of potentially dilutive common shares:
Convertible preferred stock and employee and director stock options		862		1,406		1,580

Weighted average shares outstanding and assumed conversions		21,410		16,238		9,510

Basic earnings per share	$	1.73	$	0.48	$	0.10

Diluted earnings per share	$	1.66	$	0.44	$	0.09

Reclassification

Certain prior period balances have been reclassified to conform to current year presentation.

New Accounting Pronouncements

In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments (“SFAS No. 155”). SFAS No. 155 provides entities with relief from having to separately determine the fair value of an embedded derivative that would otherwise be required to be bifurcated from its host contract in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. SFAS No. 155 allows an entity to make an irrevocable election to measure such a hybrid financial instrument at fair value in its entirely, with changes in fair value recognized in earning. SFAS No. 155 is effective for all financial instruments acquired , issued or subject to a remeasurement event occurring after the beginning of an entity’s

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

first fiscal year that begins after September 15, 2006. We believe that the adoption of SFAS No. 155 will not have a material impact on our financial position, results of operations or cash flows.

In March 2006, the FASB issued SFAS No. 156, Accounting for Servicing of Financial Assets — An Amendment to FASB Statement No. 140 (“SFAS No. 156”). SFAS No. 156 requires entities to recognize a servicing asset or liability each time they undertake an obligation to service a financial asset by entering into a servicing contract in certain situations. This statement also requires all separately recognized servicing assets and servicing liabilities to be initially measured at fair value and permits a choice of either the amortization or fair value measurement method for subsequent measurement. The effective date of this statement is for annual periods beginning after September 15, 2006, with earlier adoption permitted as of the beginning of an entity’s fiscal year provided the entity has not issued any financial statements for that year. We do not plan to adopt SFAS No. 156 early, and we are currently assessing the impact on our Consolidated Financial Statements.

In July 2006, the FASB issued FASB Interpretation, FIN No. 48, Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109 (“FIN No. 48”). FIN No. 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. It prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This new standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The provisions of FIN No. 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN No. 48. The cumulative effect of applying the provisions of FIN No. 48 should be reported as an adjustment to the opening balance of retaining earnings (or other appropriate components of equity or net assets in the statement of financial position) for that fiscal year. The provisions of FIN No. 48 are effective for fiscal years beginning after December 15, 2006. We are currently evaluating the impact of applying the provisions of FIN No. 48.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”). SFAS No. 157 clarifies the principle that fair value should be based on the assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, with early adoption permitted. We believe that the adoption of SFAS No. 157 will not have a material impact on our financial position, results of operations or cash flows.

In September 2006, the FASB issued FSP No. AUG AIR-1, Accounting for Planned Major Maintenance Activities (“FSP No. AUG AIR-1”). FSP No. AUG AIR-1 prohibits the use of the accrued-in-advance method for accounting for major maintenance activities and confirms the acceptable methods of accounting for planned major maintenance activities. FSP No. AUG AIR-1 is effective the first fiscal year beginning after December 15, 2006. We believe that the adoption of FSP No. AUG AIR-1 will not have a material impact on our financial position, results of operations or cash flows.

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

NOTE 2 — RESTATEMENT

Earnings Per Share

We understated diluted earnings per share due to an incorrect calculation of our weighted shares outstanding for each of the first three quarters of 2004, for the year ended December 31, 2004 and for the quarter ended March 31, 2005 In addition, we understated basic earnings per share due to an incorrect calculation of our weighted average basic shares outstanding for the quarter ended September 30, 2004. Consequently, we have restated our financial statements for each of those periods. The incorrect calculation resulted from a mathematical error and an improper application of SFAS No. 128.

A restated earnings per share calculation for all affected periods reflecting the above adjustments to our results as previously restated (see following section), is presented below (amounts in thousands, except per share amounts):


	Three Months Ended March 31, 2005
	As
	Previously					As
	Reported		Adjustments			Restated

Income per common share — diluted	$	0.09	$	0.02		$	0.11

Weighted average number of common shares outstanding:
Diluted		17,789		(3,094	)		14,695


	Year Ended December 31, 2004
	As
	Previously					As
	Reported		Adjustments			Restated

Income per common share — diluted	$	0.07	$	0.02		$	0.09

Weighted average number of common shares outstanding:
Diluted		11,959		(2,449	)		9,510


	Three Months Ended September 30, 2004
	As
	Previously					As
	Reported		Adjustments			Restated

Income per common share — basic	$	0.04	$	0.02		$	0.06

Income per common share — diluted	$	0.04	$	0.01		$	0.05

Weighted average number of common shares outstanding:
Basic		11,599		(3,301	)		8,298

Diluted		14,407		(4,579	)		9,828


	Three Months Ended June 30, 2004
	As
	Previously					As
	Reported		Adjustments			Restated

Income per common share — diluted	$	0.04	$	0.01		$	0.05

Weighted average number of common shares outstanding:
Diluted		10,237		(2,618	)		7,619

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

Three Months Ended March 31, 2004

As

Previously
As

Reported Adjustments Restated

Income per common share — diluted
$ 0.05 $ 0.03 $ 0.08

Weighted average number of common shares outstanding:

Diluted
5,762 478 6,240

AirComp Acquisition

In connection with the formation of AirComp LLC in 2003, we, along with M-I L.L.C. contributed assets to AirComp in exchange for a 55% interest and 45% interest, respectively, in AirComp. We originally accounted for the formation of AirComp as a joint venture. However in February 2005, we determined that the transaction should have been accounted for using purchase accounting pursuant to SFAS No. 141, Business Combinations and recorded the sale of an interest in a subsidiary, in accordance with SEC Staff Accounting Bulletin No. 51, Accounting for Sales of Stock by a Subsidiary. Consequently, we restated our financial statements for the three quarters ended September 30, 2004, to reflect the following adjustments:

Increase in Book Value of Fixed Assets.

Under joint venture accounting, we originally recorded the value of the assets contributed by M-I to AirComp at M-I’s historical cost of $6.9 million. Under purchase accounting, we increased the recorded value of the assets contributed by M-I by approximately $3.3 million to $10.3 million to reflect their fair market value as determined by a third party appraisal. In addition, under joint venture accounting, we established negative goodwill which reduced fixed assets in the amount of $1.6 million. The negative goodwill was amortized by us over the lives of the related fixed assets. Under purchase accounting, we increased fixed assets by $1.6 million to reverse the negative goodwill previously recorded and reversed amortization expenses recorded in 2004. Therefore, the cost of fixed assets was increased by a total of $4.9 million at the time of acquisition. As a result of the increase in fixed assets and the reversal of amortization of negative goodwill, depreciation expense increased.

The 2004 financial statements have been restated from the previously filed interim financial statements included in Form 10-Q for the first, second and third quarters of 2004. The effect of the restatement on the individual quarterly financial statements is as follows (in thousands, except per share amounts):


	Three Months			Three Months			Three Months
	Ended			Ended			Ended
	March 31,			June 30,			September 30,
	2004			2004			2004

Net income (loss) attributed to common stockholders
Previously reported	$	501		$	434		$	576
Adjustment — depreciation expense		(139	)		(79	)		(79	)
Adjustment — minority interest expense		22			22			22

Restated	$	384		$	377		$	519

Net income (loss) per share, basic
Previously reported	$	0.13		$	0.07		$	0.05
Total adjustments		(0.03	)		(0.01	)		(0.01	)

Restated	$	0.10		$	0.06		$	0.04

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

NOTE 3 — POST RETIREMENT BENEFIT OBLIGATIONS

Medical And Life

Pursuant to the Plan of Reorganization that was confirmed by the Bankruptcy Court after acceptances by our creditors and stockholders and was consummated on December 2, 1988, we assumed the contractual obligation to Simplicity Manufacturing, Inc. (SMI) to reimburse SMI for 50% of the actual cost of medical and life insurance claims for a select group of retirees (SMI Retirees) of the prior Simplicity Manufacturing Division of Allis-Chalmers. The actuarial present value of the expected retiree benefit obligation is determined by an actuary and is the amount that results from applying actuarial assumptions to (1) historical claims-cost data, (2) estimates for the time value of money (through discounts for interest) and (3) the probability of payment (including decrements for death, disability, withdrawal, or retirement) between today and expected date of benefit payments. As of December 31, 2006 and 2005, we have post-retirement benefit obligations of $304,000 and $335,000, respectively.

401(k) Savings Plan

On June 30, 2003, we adopted the 401(k) Profit Sharing Plan (the “Plan”). The Plan is a defined contribution savings plan designed to provide retirement income to our eligible employees. The Plan is intended to be qualified under Section 401(k) of the Internal Revenue Code of 1986, as amended. It is funded by voluntary pre-tax contributions from eligible employees who may contribute a percentage of their eligible compensation, limited and subject to statutory limits. The Plan is also funded by discretionary matching employer contributions from us. Eligible employees cannot participate in the Plan until they have attained the age of 21 and completed six-months of service with us. Each participant is 100% vested with respect to the participants’ contributions while our matching contributions are vested over a three-year period in accordance with the Plan document. Contributions are invested, as directed by the participant, in investment funds available under the Plan. Matching contributions of approximately $735,000, $114,000 and $35,000 were paid in 2006, 2005 and 2004, respectively.

NOTE 4 — ACQUISITIONS

In September 2004, we acquired 100% of the outstanding stock of Safco-Oil Field Products, Inc. (“Safco”) for $1.0 million. Safco rented spiral drill pipe to the oil drilling industry. Safco has been renamed and is now Allis-Chalmers Rental Services, Inc.

In September 2004, we acquired the remaining 19% of Tubular in exchange for 1.3 million shares of our common stock. The total value of the consideration paid to the seller, Jens Mortensen, was $6.4 million which was equal to the number of shares of common stock issued to Mr. Mortensen (1.3 million) multiplied by the last sale price ($4.95) of the common stock as reported on the American Stock Exchange on the date of issuance. This amount was treated as a contribution to stockholders’ equity. On the balance sheet, the $1.9 million minority interest in Tubular was eliminated. The balance of the contribution of $4.4 million was allocated as follows: In June 2004, we obtained an appraisal of the fixed assets of Tubular which valued the fixed assets at $20.1 million. The book value of the fixed assets was $15.8 million and the fixed assets appraised value was $4.3 million over the book value. We increased the value of our fixed assets by 19% of the amount of the excess of the appraised value over the book value, or $.8 million. The remaining balance of $3.6 million was allocated to goodwill.

In November 2004, AirComp acquired substantially all the assets of Diamond Air Drilling Services, Inc. and Marquis Bit Co., L.L.C. collectively (“Diamond Air”) for $4.6 million in cash and the assumption of approximately $450,000 of accrued liabilities. We contributed $2.5 million and M-I L.L.C. contributed $2.1 million to AirComp LLC in order to fund the purchase. Goodwill of $375,000 and other intangible assets of $2.3 million were recorded in connection with the acquisition. Diamond Air provided air drilling technology

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

and products to the oil and gas industry in West Texas, New Mexico and Oklahoma. Diamond Air is a leading brand of air hammers and hammer bit products.

In December 2004, we acquired Downhole Injection Services, LLC (“Downhole”) for approximately $1.1 million in cash, 568,466 shares of our common stock and the assumption of approximately $950,000 of debt. Goodwill of $442,000 and other intangible assets of $795,000 were recorded in connection with the acquisition. Downhole provided economical chemical treatments to wells by inserting small diameter, stainless steel coiled tubing into producing oil and gas wells. In 2006, Downhole was merged into Allis-Chalmers Production Services Inc.

On April 1, 2005, we acquired 100% of the outstanding stock of Delta Rental Service, Inc. (“Delta”) for $4.6 million in cash, 223,114 shares of our common stock and two promissory notes totaling $350,000. The purchase price was allocated to fixed assets and inventory. Delta, located in Lafayette, Louisiana, was a rental tool company providing specialty rental items to the oil and gas industry such as spiral heavy weight drill pipe, test plugs used to test blow-out preventors, well head retrieval tools, spacer spools and assorted handling tools. In 2006, Delta was merged into Rental.

On May 1, 2005, we acquired 100% of the outstanding capital stock of Capcoil Tubing Services, Inc. (“Capcoil”) for $2.7 million in cash, 168,161 shares of our common stock and the payment or assumption of approximately $1.3 million of debt. Capcoil, located in Kilgore, Texas, is engaged in downhole well servicing by providing coil tubing services to enhance production from existing wells. Goodwill of $184,000 and other identifiable intangible assets of $1.4 million were recorded in connection with the acquisition. In 2006, Capcoil was renamed Allis-Chalmers Production Services Inc.

On July 11, 2005, we acquired the compressed air drilling assets of W.T Enterprises, Inc., based in South Texas, for $6.0 million in cash. The equipment includes compressors, boosters, mist pumps and vehicles. Goodwill of $82,000 and other identifiable intangible assets of $1.5 million were recorded in connection with the acquisition.

On July 11, 2005, we acquired from M-I L.L.C. (“M-I”) its 45% interest in AirComp and subordinated note in the principal amount of $4.8 million issued by AirComp, for which we paid M-I $7.1 million in cash and issued to M-I a $4.0 million subordinated note bearing interest at 5% per annum. As a result, we now own 100% of AirComp

Effective August 1, 2005, we acquired 100% of the outstanding capital stock of Target Energy Inc. (“Target”) for $1.3 million in cash and forgiveness of a lease receivable of approximately $0.6 million. The purchase price was allocated to the fixed assets of Target. The results of Target are included in our directional and horizontal drilling segment as their Measure While Drilling equipment is utilized in that segment. Target was merged with Strata in December 2006.

On September 1, 2005, we acquired the casing and tubing service assets of Patterson Services, Inc. for approximately $15.6 million. These assets are located in Corpus Christi, Texas; Kilgore, Texas; Lafayette, Louisiana and Houma, Louisiana.

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

Effective January 1, 2006, we acquired 100% of the outstanding stock of Specialty Rental Tools, Inc., or Specialty, for $96.0 million in cash. Specialty, located in Lafayette, Louisiana, was engaged in the rental of high quality drill pipe, heavy weight spiral drill pipe, tubing work strings, blow-out preventors, choke manifolds and various valves and handling tools for oil and natural gas drilling. The following table summarizes the allocation of the purchase price to the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):


Current assets	$	7,645
Property and equipment		90,622

Total assets acquired		98,267

Current liabilities		2,193
Long-term debt		74

Total liabilities assumed		2,267

Net assets acquired	$	96,000

Approximately $588,000 of costs were incurred in relation to the Specialty acquisition. Specialty’s historical property and equipment values were increased by approximately $71.6 million based on third-party valuations. Specialty was merged into Rental in 2006.

Effective April 1, 2006, we acquired 100% of the outstanding stock of Rogers Oil Tools, Inc., or Rogers, based in Lafayette, Louisiana, for a total consideration of approximately $13.7 million, which includes $11.3 million in cash, $1.6 million in our common stock and a $750,000 three-year promissory note. In addition, we purchased all the patents and proprietary technology that Tommie L. Rogers, Rogers’ founder and Chief Executive Officer, developed at Rogers. Rogers sells, services and rents power drill pipe tongs and accessories and rental tongs for snubbing and well control applications. Rogers also provides specialized tong operators for rental jobs. The following table summarizes the allocation of the purchase price to the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):


Current assets	$	4,520
Property and equipment		9,866
Intangible assets		4,941

Total assets acquired		19,327

Current liabilities		1,717
Deferred income tax liabilities		3,760
Other long-term liabilities		150

Total liabilities assumed		5,627

Net assets acquired	$	13,700

Approximately $380,000 of costs were incurred in relation to the Rogers acquisition. Rogers’ historical property and equipment values were increased by approximately $8.4 million based on third-party valuations. Intangible assets include $2.8 million assigned to goodwill, $2.0 million assigned to patents and $150,000 assigned to non-compete based on third-party valuations and employment contracts. The amortizable intangibles have a weighted-average useful life of 11.3 years. Rogers was merged into Tubular in December 2006.

Effective August 14, 2006, we acquired 100% of the outstanding stock of DLS, based in Argentina, for a total consideration of approximately $117.9 million, which includes $93.7 million in cash, $38.1 million in our common stock, $3.4 million of acquisition costs, less approximately $17.3 million of debt assigned to us. DLS

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

operates a fleet of 51 rigs, including 20 drilling rigs, 18 workover rigs and 12 pulling rigs in Argentina and one drilling rig in Bolivia. The following table summarizes the preliminary allocation of the purchase price to the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):


Current assets	$	52,033
Property and equipment		130,389
Other long-term assets		21

Total assets acquired		182,443

Current liabilities		34,386
Long-term debt, less current portion		5,921
Intercompany note		17,256
Deferred tax liabilities		6,948

Total liabilities assumed		64,511

Net assets acquired	$	117,932

Approximately $3.4 million of costs were incurred in relation to the DLS acquisition. DLS’ historical property and equipment values were increased by approximately $22.7 million based on third-party valuations. We do not expect any material differences from the preliminary allocation of the purchase price and the final purchase price allocations.

On October 16, 2006, we acquired 100% of the outstanding stock of Petro Rental, based in Lafayette, Louisiana, for a total consideration of approximately $33.6 million, which includes $20.2 million in cash, $3.8 million in our common stock and payment of $9.6 million of existing Petro Rental debt. Petro-Rental provides a variety of production-related rental tools and equipment and services, including wire line services and equipment, land and offshore pumping services and coiled tubing. The following table summarizes the preliminary allocation of the purchase price to the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):


Current assets	$	8,175
Property and equipment		28,792
Intangible assets		5,811
Other long-term assets		2

Total assets acquired		42,780

Current liabilities		2,135
Deferred tax liabilities		6,954

Total liabilities assumed		9,089

Net assets acquired	$	33,691

Approximately $82,000 of costs were incurred in relation to the Petro Rental acquisition. Petro Rental’s historical property and equipment values were increased by approximately $13.4 million based on third-party valuations. We do not expect any material differences from the preliminary allocation of the purchase price and the final purchase price allocations. Intangible assets include $3.0 million assigned to goodwill and $2.8 million assigned to customer relationships based on third-party valuations. The amortizable intangibles have a weighted-average useful life of 10 years.

Effective December 1, 2006, we acquired 100% of the outstanding stock of Tanus Argentina S.A. (“Tanus”), based in Argentina, for a total consideration of $2.5 million. Tanus is engaged in the research and

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

manufacturing of additives for the oil, natural gas and water well drilling and completion fluids in Argentina. The following table summarizes the preliminary allocation of the purchase price to the estimated fair value of the assets acquired and liabilities assumed at the date of the acquisition (in thousands).


Current assets	$	2,254
Property and equipment		2
Goodwill		1,504

Total assets acquired		3,760
Current liabilities		1,243

Net assets acquired	$	2,517

Approximately $17,000 of costs were incurred in relation to the Tanus acquisition. We do not expect any material differences from the preliminary allocation of the purchase price and the final purchase price allocations. The results of Tanus are reported with DLS under our international drilling segment.

On December 18, 2006, we acquired substantially all of the assets of Oil & Gas Rental Services, Inc., or OGR, based in Morgan City, Louisiana, for a total consideration of approximately $342.4 million, which includes $291.0 million in cash, and $51.4 million in our common stock. The following table summarizes the preliminary allocation of the purchase price to the estimated fair value of the assets acquired at the date of acquisition (in thousands):


Current assets	$	12,735
Property and equipment		199,015
Investments		4,618
Intangible assets		128,976

Total assets acquired	$	345,344

Approximately $3.0 million of costs were incurred in relation to the OGR Rental acquisition. OGR’s historical property and equipment values were increased by approximately $168.9 million based on third-party valuations. We do not expect any material differences from the preliminary allocation of the purchase price and the final purchase price allocations. Intangible assets include $106.1 million assigned to goodwill, $22.0 million to customer relations, $831,000 to patents and $35,000 assigned to employment agreements based on third-party valuations. The amortizable intangibles have a weighted-average useful life of 10.1 years.

The acquisitions were accounted for using the purchase method of accounting. The results of operations of the acquired entities since the date of acquisition are included in our consolidated income statement.

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

The following unaudited pro forma consolidated summary financial information for the year ended December 31, 2006 illustrates the effects of the acquisitions and the related public offerings of debt and equity for Rogers, DLS, Petro-Rentals and OGR as if the acquisitions occurred as of January 1, 2006, based on the historical results of the acquisitions. The following unaudited pro forma consolidated summary financial information for the year ended December 31, 2005 illustrates the effects of the acquisitions and the related public offerings of debt and equity for Delta, Capcoil, W.T., the minority interest in AirComp, Specialty, Rogers, DLS, Petro-Rentals and OGR as if the acquisitions had occurred as of January 1, 2005, based on the historical results of the acquisitions. The following unaudited pro forma consolidated summary financial information for the year ended December 31, 2004 illustrates the effects of the acquisitions and the related public offerings of debt and equity for Diamond Air, Downhole, Delta, Capcoil, W.T., the minority interest in AirComp, Specialty, Rogers, DLS, Petro-Rentals and OGR as if the acquisitions had occurred as of beginning of the period, based on the historical results of the acquisitions (unaudited). The historical results for OGR are based on their historical year end of October 31 (in thousands, except per share amounts):


	Years Ended December 31,
	2006		2005		2004

Revenues	$	502,418	$	346,230	$	273,825
Operating income	$	93,082	$	49,868	$	38,308
Net income (loss)	$	32,358	$	1,264	$	(7,849	)
Net income (loss) per common share
Basic	$	0.96	$	0.04	$	(0.33	)
Diluted	$	0.94	$	0.04	$	(0.33	)

NOTE 5 — INVENTORIES

Inventories are comprised of the following (in thousands):


	December 31,		December 31,
	2006		2005

Manufactured
Finished goods	$	1,476	$	1,402
Work in process		2,266		787
Raw materials		2,638		233

Total manufactured		6,380		2,422
Hammers		1,016		584
Drive pipe		716		666
Rental supplies		1,845		64
Chemicals and drilling fluids		2,673		201
Rig parts and related inventory		9,762		—
Coiled tubing and related inventory		1,627		1,145
Shop supplies and related inventory		4,596		863

Total inventory	$	28,615	$	5,945

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

NOTE 6 — PROPERTY AND OTHER INTANGIBLE ASSETS

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


	Depreciation
	Period		2006			2005

Land		—	$	1,810		$	27
Building and improvements		15-20 years		5,392			637
Transportation equipment		3-10 years		22,744			7,772
Drill pipe and rental equipment		3-20 years		321,821			6,813
Drilling, workover and pulling rigs		20 years		120,517			—
Machinery and equipment		3-20 years		105,926			70,189
Furniture, computers, software and leasehold improvements		3-7 years		3,522			2,073
Construction in progress — equipment		N/A		2,269			3,059

Total				584,001			90,570
Less: accumulated depreciation				(29,743	)		(9,996	)

Property and equipment, net			$	554,258		$	80,574

The net book value of equipment recorded under capital leases was $1.0 million and $1.1 million at December 31, 2006 and 2005, respectively.

Intangible assets are as follows at December 31 (in thousands):


	Amortization
	Period		2006			2005

Intellectual property		20 years	$	1,009		$	1,009
Non-compete agreements		3-5 years		4,580			4,630
Customer relationships		10 years		27,552			2,954
Patent		12-15 years		3,327			496
Other intangible assets		2-10 years		847			857

Total				37,315			9,946
Less: accumulated amortization				(4,475	)		(3,163	)

Intangibles assets, net			$	32,840		$	6,783


	2006						2005
	Gross		Accumulated		Current Year		Gross		Accumulated		Current Year
	Value		Amortization		Amortization		Value		Amortization		Amortization

Intellectual property	$	1,009	$	349	$	55	$	1,009	$	293	$	54
Non-compete agreements		4,580		2,707		1,091		4,630		1,916		884
Customer relationships		27,552		789		449		2,954		540		274
Patent		3,327		203		165		496		39		33
Other intangible assets		847		427		97		857		375		3

Total	$	37,315	$	4,475	$	1,857	$	9,946	$	3,163	$	1,248

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

Future amortization of intangible assets at December 31, 2006 is as follows (in thousands):


	Intangible Amortization by Period
	Years Ended December 31,
									2011 and
	2007		2008		2009		2010		Thereafter

Intellectual property	$	55	$	55	$	55	$	55	$	440
Non-compete agreements		887		564		362		60		—
Customer relationships		2,743		2,740		2,740		2,740		15,800
Patent		274		274		274		274		2,028
Other intangible assets		112		107		90		80		31

Total Intangible Amortization	$	4,071	$	3,740	$	3,521	$	3,209	$	18,299


NOTE 7 —	INCOME TAXES

We had income before income taxes of $35.9 million, $8.5 million and $1.4 million in the U.S. for the years ended December 31, 2006, 2005 and 2004, respectively. In 2006, we also had income before income taxes of $11.1 million in non-U.S. countries. We treat the withholding taxes incurred by our U.S. subsidiaries in foreign countries as foreign tax, although we do anticipate using those tax payments to offset U.S. tax.

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


	Years Ended December 31,
	2006			2005		2004

Current income tax expense:
Federal	$	5,865		$	123	$	—
State		898			595		—
Foreign		2,442			626		514

		9,205			1,344		514
Deferred income tax expense (benefit):
Federal		(946	)		—		—
State		573			—		—
Foreign		2,588			—		—

		2,215			—		—

	$	11,420		$	1,344	$	514

We are required to file a consolidated U.S. federal income tax return. We pay foreign income taxes in Argentina related to DLS’s operations and in Mexico related to Allis-Chalmers Tubular Services’ revenues from Matyep. There are approximately $2.4 million of U.S. foreign tax credits available to us. Our foreign tax credits begin to expire in the year 2007.

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

The following table reconciles the U.S. statutory tax rate to our actual tax rate:


	Years Ended December 31,
	2006			2005			2004

Statutory income tax rate		35.0	%		34.0	%		34.0	%
State taxes, net of federal benefit		2.1			6.1			—
Valuation allowances		(57.7	)		(98.7	)		(209.4	)
Nondeductible items, permanent differences and other		44.9			74.4			212.0

Effective tax rate		24.3	%		15.8	%		36.6	%

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


	2006			2005

Deferred income tax assets:
Net future (taxable) deductible items	$	899		$	384
Share based compensation		578			—
Net operating loss carry forwards		1,698			5,656
Foreign tax credit		2,420			—
A-C Reorganization Trust and Product Liability Trust claims		5,500			29,098

Total deferred income tax assets		11,095			35,138
Valuation allowance		—			(27,131	)

Net deferred income tax assets		11,095			8,007
Deferred income tax liabilities
Depreciation		(28,226	)		(8,007	)

Net deferred income tax assets (liabilities)	$	(17,131	)	$	—

Net current deferred income tax asset	$	2,822		$	—
Net noncurrent deferred income tax liability		(19,953	)		—

Net deferred income tax assets (liabilities)	$	(17,131	)	$	—

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

The Tax Reform Act of 1986 contains provisions that limit the utilization of net operating loss and tax credit carry forwards if there has been a “change of ownership” as described in Section 382 of the Internal Revenue Code. Such a change of ownership may limit our utilization of our net operating loss and tax credit carry forwards, 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, but we are projecting the release of net operating losses under the provisions of Section 382. Net operating loss carry forwards for tax purposes at December 31, 2006 and 2005 were estimated to be $4.9 million and $16.6 million, respectively, expiring through 2024.

Prior to 2006, we did not record an asset for the U.S. foreign tax credit as we believed they would not be recoverable based on our taxable income.

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

Our 1988 Plan of Reorganization established the A-C Reorganization Trust to settle claims and to make distributions to creditors and certain stockholders. We transferred cash and certain other property to the A-C Reorganization Trust on December 2, 1988. Payments made by us to the A-C Reorganization Trust did not generate tax deductions for us upon the transfer but generate deductions for us as the A-C Reorganization Trust makes payments to holders of claims. The Plan of Reorganization also created a trust to process and liquidate product liability claims. Payments made by the A-C Reorganization Trust to the product liability trust did not generate current tax deductions for us upon the payment but generate deductions for us as the product liability trust makes payments to liquidate claims or incurs other expenses. We believe the aforementioned trusts are grantor trusts and therefore we include the income or loss of these trusts in our income or loss for tax purposes, resulting in an adjustment of the tax basis of net operating and capital loss carry forwards. The income or loss of these trusts is not included in our results of operations for financial reporting purposes.

A valuation allowance is established for deferred tax assets when management, based upon available information, considers it more likely than not that a benefit from such assets will not be realized. The valuation allowance was relieved in 2006 due to the increase in our operating results for the year ended December 31, 2006, which we project will utilize all of the net operating loss carryforwards that are available to us and the revaluation of the deferred tax asset related to the A-C Reorganization Trust and Product Liability Trust. In 2005 and 2004, we had a valuation allowance equal to the excess of deferred tax assets over deferred tax liabilities as we were unable to determine that it was more likely than not that the deferred tax asset will be realized.


NOTE 8 —	DEBT

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


	December 31,
	2006		2005

Senior notes	$	255,000	$	—
Bridge loan		300,000		—
Bank term loans		7,302		42,090
Revolving line of credit		—		6,400
Subordinated note payable to M-I LLC		—		4,000
Subordinated seller note		—		3,031
Seller note		900		850
Obligations under non-compete agreements		270		698
Notes payable to former directors		32		96
Real estate loan		—		548
Equipment & vehicle installment notes		3,502		1,939
Insurance premium financing		1,025		—
Capital lease obligations		414		917

Total debt		568,445		60,569
Less: short-term debt and current maturities		6,999		5,632

Long-term debt obligations	$	561,446	$	54,937

As of December 31, 2006 and 2005, our debt was approximately $568.4 million and $60.6 million, respectively. Our weighted average interest rate for all of our outstanding debt was approximately 9.8% at December 31, 2006 and 7.5% at December 31, 2005.

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

Maturities of debt obligations at December 31, 2006 are as follows (in thousands):


	Debt		Capital Leases		Total

Year Ending:
December 31, 2007	$	6,585	$	414	$	6,999
December 31, 2008		53,146		—		53,146
December 31, 2009		1,500		—		1,500
December 31, 2010		1,450		—		1,450
December 31, 2011		350		—		350
Thereafter		505,000		—		505,000

Total	$	568,031	$	414	$	568,445

Senior notes, bank loans and line of credit agreements

On January 18, 2006 and August 14, 2006, we closed on private offerings, to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, of $160.0 and $95.0 million aggregate principal amount of our senior notes, respectively. The senior notes are due January 15, 2014 and bear interest at 9.0%. The proceeds were used to fund the acquisitions of Specialty and DLS, to repay existing debt and for general corporate purposes.

On December 18, 2006, we closed on a $300.0 million senior unsecured bridge loan. The bridge loan is due 18 months after closing and bears a weighted average interest rate of 10.6%. The bridge loan, which was repaid on January 29, 2007, was used to fund the acquisition of OGR.

Prior to January 18, 2006, we were party to a July 2005 credit agreement that provided for the following senior secured credit facilities:


	•	A $13.0 million revolving line of credit. Borrowings were limited to 85% of eligible accounts receivable plus 50% of eligible inventory (up to a maximum of $2.0 million of borrowings based on inventory). This line of credit was to be used to finance working capital requirements and other general corporate purposes, including the issuance of standby letters of credit. Outstanding borrowings under this line of credit were $6.4 million at a margin above prime and LIBOR rates plus margin averaging approximately 8.1% as of December 31, 2005.

	•	Two term loans totaling $42.0 million. Outstanding borrowings under these term loans were $42.0 million as of December 31, 2005. These loans were at LIBOR rates plus a margin which averages approximately 7.8% at December 31, 2005.

Borrowings under the July 2005 credit facilities were to mature in July 2007. Amounts outstanding under the term loans as of July 2006 were to be repaid in monthly principal payments based on a 48 month repayment schedule with the remaining balance due at maturity. Additionally, during the second year, we were to be required to prepay the remaining balance of the term loans by 75% of excess cash flow, if any, after debt service and capital expenditures. The interest rate payable on borrowings was based on a margin over the London Interbank Offered Rate, referred to as LIBOR, or the prime rate, and there was a 0.5% fee on the undrawn portion of the revolving line of credit. The margin over LIBOR was to increase by 1.0% in the second year.

All amounts outstanding under our July 2005 credit agreement were paid off with the proceeds of our senior notes offering on January 18, 2006. On January 18, 2006, we also executed an amended and restated credit agreement which provides for a $25.0 million revolving line of credit with a maturity of January 2010. Our January 2006 amended and restated credit agreement contains customary events of default and financial

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

covenants and limits our ability to incur additional indebtedness, make capital expenditures, pay dividends or make other distributions, create liens and sell assets. Our obligations under the January 2006 amended and restated credit agreement are secured by substantially all of our assets excluding the DLS assets, but including 2/3 of our shares of DLS. At December 31, 2006, no amounts were borrowed on the facility but availability is reduced by outstanding letters of credit of $9.7 million.

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 7.0% at December 31, 2006. The bank loans are denominated in U.S. dollars and the outstanding amount due as of December 31, 2006 was $7.3 million.

Tubular had two bank term loans with a remaining balance $90,000 at December 31, 2005, with interest accruing at a floating interest rate based on prime plus 2.0% (9.25% at December 31, 2005). Monthly principal payments were $13,000 plus interest. The maturity date of one of the loans, with a balance of $60,000, was September 17, 2006, while the second loan, with a balance of $30,000, had a final maturity of January 12, 2007. The balances of these two loans were repaid in full in January 2006 with the proceeds from our senior notes offering.

Notes payable and real estate loan

On July 11, 2005, we acquired from M-I its 45% equity interest in AirComp and the subordinated note in the principal amount of $4.8 million issued by AirComp, for which we paid M-I $7.1 million in cash and issued a new $4.0 million subordinated note bearing interest at 5.0% per annum. The subordinated note issued to M-I required quarterly interest payments and the principal amount was due October 9, 2007. Contingent upon a future equity offering, the subordinated note was convertible into up to 700,000 shares of our common stock at a conversion price equal to the market value of the common stock at the time of conversion. This note was repaid from the proceeds of our offering of $95.0 million of 9.0% senior notes, which we completed in August 2006.

As of December 31, 2005, Tubular had a subordinated note outstanding and payable to Jens Mortensen, the seller of Tubular and one of our directors, in the amount of $3.0 million with a fixed interest rate of 7.5%. Interest was payable quarterly and the final maturity of the note was January 31, 2006. The subordinated note was subordinated to the rights of our bank lenders. The balance of this subordinated note was repaid in full in January 2006 with proceeds from our senior notes offering.

In connection with the purchase of Delta, we issued to the sellers a note in the amount of $350,000. The note bore interest at 2% and the principal and accrued interest was repaid on its maturity of April 1, 2006. At December 31, 2005 the outstanding amounts due was $350,000. The note was repaid during 2006. In connection with the acquisition of Rogers, we issued to the seller a note in the amount of $750,000. The note bears interest at 5.0% and is due April 3, 2009.

In connection with the purchase of Tubular, we agreed to pay a total of $1.2 million to Mr. Mortensen in exchange for a non-compete agreement. Monthly payments of $20,576 are due under this agreement through January 31, 2007. In connection with the purchase of Safco-Oil Field Products, Inc., or Safco, we also agreed

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

to pay a total of $150,000 to the sellers in exchange for a non-compete agreement. We are required to make annual payments of $50,000 through September 30, 2007. In connection with the purchase of Capcoil, we agreed to pay a total of $500,000 to two management employees in exchange for non-compete agreements. We are required to make annual payments of $110,000 through May 2008. Total amounts due under these non-compete agreements at December 31, 2006 and 2005 were $270,000 and $698,000, respectively.

In 2000 we compensated directors, including current directors Nederlander and Toboroff, who served on the board of directors from 1989 to March 31, 1999 without compensation, by issuing promissory notes totaling $325,000. The notes bear interest at the rate of 5.0%. At December 31, 2006 and 2005, the principal and accrued interest on these notes totaled approximately $32,000 and $96,000, respectively.

We also had a real estate loan which was payable in equal monthly installments of $4,344 with the remaining outstanding balance due on January 1, 2010. The loan had a floating interest rate based on prime plus 2.0%. The outstanding principal balance was $548,000 at December 31, 2005. The balance of this loan was repaid in full in January 2006 with proceeds from our senior notes offering.

Other debt

We have various rig and equipment financing loans with interest rates ranging from 5.0% to 8.7% and terms of 2 to 5 years. As of December 31, 2006 and 2005, the outstanding balances for rig and equipment financing loans were $3.5 million and $1.9 million, respectively. In April 2006 and August 2006, we obtained insurance premium financings in the amount of $1.9 million and $896,000 with fixed interest rates of 5.6% and 6.0%, respectively. Under terms of the agreements, amounts outstanding are paid over 10 month and 11 month repayment schedules. The outstanding balance of these notes was approximately $1.0 million as of December 31, 2006. We also have various capital leases with terms that expire in 2008. As of December 31, 2006 and 2005, amounts outstanding under capital leases were $414,000 and $917,000, respectively. In January 2006, we prepaid $350,000 of the outstanding equipment loans with proceeds from our senior notes offering.


NOTE 9 —	COMMITMENTS AND CONTINGENCIES

We have placed orders for capital equipment totaling $42.3 million to be received and paid for through 2007. Of this amount, $27.4 million is for rental equipment, principally drillpipe, $4.6 million is for six measurement while drilling kits and ancillary equipment for our directional drilling segment and $3.4 million is for two new capillary tubing units for our production services segment and $4.5 million is for casing and tubing tools and equipment. The orders are subject to cancellation with minimal loss of prior cash deposits, if any.

We rent office space on a five-year lease which expires November 2009. We also rent certain other facilities and shop yards for equipment storage and maintenance. Facility rent expense for the years ended December 31, 2006, 2005 and 2004 was $1.6 million, $987,000 and $577,000, respectively.

At December 31, 2006, future minimum rental commitments for all operating leases are as follows (in thousands):


Years Ending:
December 31, 2007	$	2,013
December 31, 2008		1,716
December 31, 2009		942
December 31, 2010		160
December 31, 2011		117
Thereafter		470

Total	$	5,418

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

NOTE 10 — STOCKHOLDERS’ EQUITY

On March 3, 2004, we entered into an agreement with an investment banking firm whereby they would provide underwriting and fundraising activities on our behalf. In exchange for their services, the investment banking firm received a stock purchase warrant to purchase 340,000 shares of common stock at an exercise price of $2.50 per share. The warrant was exercised in August of 2005. The fair value of the total warrants issued in connection with the fundraising activities was established in accordance with the Black-Scholes valuation model and as a result, $641,000 was added to stockholders’ equity. The following assumptions were utilized to determine fair value: no dividend yield; expected volatility of 89.7%; risk free interest rate of 7.00%; and expected life of five years.

During 2004, we issued two warrants (“Warrants A and B”) for the purchase of 233,000 total shares of our common stock at an exercise price of $0.75 per share and one warrant for the purchase of 67,000 shares of our common stock at an exercise price of $5.00 per share (“Warrant C”) in connection with subordinated debt financing. Warrants A and B were redeemed for a total of $1,500,000 on December 7, 2004. The fair value of Warrant C was established in accordance with the Black-Scholes valuation model and as a result, $47,000 was added to stockholders’ equity. The following assumptions were utilized to determine fair value: no dividend yield; expected volatility of 67.24%; risk free interest rate of 5.00%; and expected life of four years.

On April 2, 2004, we completed the following transactions:


	•	In exchange for an investment of $2.0 million, we issued 620,000 shares of our common stock for a purchase price equal to $2.50 per share, and issued warrants to purchase 800,000 shares of our common stock at an exercise price of $2.50 per share, expiring on April 1, 2006, to an investor group (the “Investor Group”) consisting of entities affiliated with Donald and Christopher Engel and directors Robert Nederlander and Leonard Toboroff. The aggregate purchase price for the common stock was $1.55 million and the fair value for the warrants was $450,000.

	•	Energy Spectrum converted its 3,500,000 shares of Series A 10% Cumulative Convertible Preferred Stock, including accrued dividend rights, into 1,718,090 shares of common stock. Energy Spectrum was granted the preferred stock in connection with the Strata acquisition.

On August 10, 2004, we completed the private placement of 3,504,667 shares of our common stock at a price of $3.00 per share. Our net proceeds, after selling commissions and expenses, were approximately $9.6 million. We issued shares pursuant to an exemption from the Securities Act of 1933, and agreed to subsequently register the common stock under the Securities Act of 1933 to allow investors to resell the common stock in public markets.

On September 30, 2004, we completed the private placement of 1,956,634 shares of our common stock at a price of $3.00 per share. Our net proceeds, after selling commission and expenses, were approximately $5.3 million. We issued shares pursuant to an exemption from the Securities Act of 1933, and agreed to subsequently register the common stock under the Securities Act of 1933 to allow investors to resell the common stock in public markets.

On September 30, 2004, we issued 1.3 million shares of common stock to Jens Mortensen, a director, in exchange for his 19% interest in Tubular. As a result of this transaction, we own 100% of Tubular. The total value of the consideration paid to Jens was $6.4 million, which was equal to the number of shares of common stock issued to Mr. Mortensen multiplied by the last sale price ($4.95) of the common stock as reported on the American Stock Exchange on the date of issuance. This amount was treated as a contribution to stockholders equity.

On December 10, 2004, we acquired Downhole for approximately $1.1 million in cash, 568,466 shares of our common stock and payment or assumption of $950,000 of debt. Approximately $2.2 million, the value of

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

the common stock issued to Downhole’s sellers based on the closing price of our common stock issued at the date of the acquisition, was added to stockholders’ equity.

As of January 1, 2005, in relation to the acquisition of Downhole, we executed a business development agreement with CTTV Investments LLC, an affiliate of ChevronTexaco Inc., whereby we issued 20,000 shares of our common stock to CTTV and further agreed to issue up to an additional 60,000 shares to CTTV contingent upon our subsidiaries receiving certain levels of revenues in 2005 from ChevronTexaco and its affiliates. CTTV was a minority owner of Downhole, which we acquired in 2004. Based on the terms of the agreement, no additional shares were issued in 2006 or 2005.

On April 1, 2005, we acquired 100% of the outstanding stock of Delta, for $4.6 million in cash, 223,114 shares of our common stock and two promissory notes totaling $350,000. Approximately $1.0 million, the value of the common stock issued to Delta’s sellers based on the closing price of our common stock issued at the date of the acquisition, was added to stockholders’ equity.

On May 1, 2005, we acquired 100% of the outstanding capital stock of Capcoil for $2.7 million in cash, 168,161 shares of our common stock and the payment or assumption of approximately $1.3 million of debt. Approximately $750,000, the value of the common stock issued to Capcoil’s sellers based on the closing price of our common stock issued at the date of the acquisition, was added to stockholders’ equity.

In August 2005, our stockholders approved an amendment to our certificate of incorporation to increase the authorized number of shares of our common stock from 20 million to 100 million and to increase our authorized preferred stock from 10 million shares to 25 million shares and, we completed a secondary public offering in which we sold 1,761,034 shares for approximately $15.5 million, net of expenses.

We also had options and warrants exercised during 2005. Those exercises resulted in 1,076,154 shares of our common stock being issued for $1.4 million.

We issued 125,285, 2.5 million, 246,761 and 3.2 million shares of our common stock in relation to the Rogers, DLS, Petro Rental and OGR acquisition, respectively (see Note 4).

On August 14, 2006 we closed on a public offering of 3,450,000 shares of our common stock at a public offering price of $14.50 per share. Net proceeds from the public offering of $46.3 million were used to fund a portion of our acquisition of DLS.

We also had options and warrants exercised in 2006, which resulted in 1,851,377 shares of our common stock being issued for approximately $6.3 million. We recognized approximately $3.4 million of compensation expense related to stock options in 2006 that was recorded as capital in excess of par value (see Note 1). We also recorded approximately $6.4 million of tax benefit related to our stock compensation plans.

NOTE 11 — REVERSE STOCK SPLIT

We effected a reverse stock split on June 10, 2004. As a result of the reverse stock split, every five shares of our common stock was combined into one share of common stock. The reverse stock split reduced the number of shares of outstanding common stock from 31,393,789 to approximately 6,265,000 and reduced the number of our stockholders from 6,070 to approximately 2,140. All share and related amounts presented have been retroactively adjusted for the stock split.

NOTE 12 — STOCK OPTIONS

In 2000, we issued stock options and promissory notes to certain current and former directors as compensation for services as directors (See Note 8), and our Board of Directors granted stock options to these same individuals. Options to purchase 4,800 shares of our common stock were granted with an exercise price of $13.75 per share. These options vested immediately and may be exercised any time prior to March 28,

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

2010. As of December 31, 2006 4,000 of the stock options remain outstanding. No compensation expense has been recorded for these options that were issued with an exercise price equal to the fair value of the common stock at the date of grant.

On May 31, 2001, the Board granted to Leonard Toboroff, one of our directors, an option to purchase 100,000 shares of our common stock at $2.50 per share, exercisable for 10 years from October 15, 2001. The option was granted for services provided by Mr. Toboroff to OilQuip prior to the merger, including providing financial advisory services, assisting in OilQuip’s capital structure and assisting OilQuip in finding strategic acquisition opportunities. We recorded compensation expense of $500,000 for the issuance of the option for the year ended December 31, 2001. As of December 31, 2006, all of the stock options have been exercised.

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

The 2006 Incentive Plan (“2006 Plan”), was approved by our stockholders in November 2006. The 2006 Plan is administered by the Compensation Committee of the Board, which consists of two or more directors appointed by the Board. The maximum number of shares of the Company’s common stock, par value $0.01 per share (“Common Stock”), that may be issued under the 2006 Plan is equal to 1,500,000 shares, subject to adjustment in the event of stock splits and certain other corporate events. The 2006 Plan provides for the grant of any or all of the following types of awards: (i) stock options, including incentive stock options and non-qualified stock options; (ii) bonus stock; (iii) restricted stock awards; (iv) performance awards; and (v) other stock-based awards. Except with respect to awards of incentive stock options, all employees, consultants and non-employee directors of the Company and its affiliates are eligible to participate in the 2006 Plan. The term of each Award shall be for such period as may be determined by the Committee; provided, that in no event shall the term of any Award exceed a period of ten (10) years from the date of its grant.

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


	December 31, 2006					December 31, 2005					December 31, 2004
	Shares			Weighted Ave.		Shares			Weighted Ave.		Shares			Weighted Avg.
	Under			Exercise		Under			Exercise		Under			Exercise
	Option			Price		Option			Price		Option			Price

Beginning balance		2,860,867		$	5.10		1,215,000		$	3.20		973,300		$	2.78
Granted		15,000			14.74		1,695,000			6.44		248,000			4.85
Canceled		(54,567	)		5.97		(15,300	)		3.33		(6,300	)		2.78
Exercised		(1,470,935	)		3.54		(33,833	)		2.80		—			—

Ending balance		1,350,365		$	6.88		2,860,867		$	5.10		1,215,000		$	3.20

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

The following table summarizes additional information about our stock options outstanding as of December 31, 2006:


				Weighted Average
		Shares Under		Remaining
Exercise Price		Option		Contractual Life		Options Exercisable		Exercise Price

$	2.75		56,300		6.96 years		56,300	$	2.75
$	3.86		429,900		8.09 years		129,899	$	3.86
$	4.85		227,000		7.87 years		227,000	$	4.85
$	4.87		101,165		8.40 years		62,822	$	4.87
$	10.85		517,667		8.96 years		325,988	$	10.85
$	13.75		4,000		3.24 years		4,000	$	13.75
$	14.74		14,333		9.57 years		4,336	$	14.74

$	6.88		1,350,365		8.36 years		810,345	$	7.06

As of December 31, 2006, there was $914,000 of total unrecognized compensation cost related to stock option, with $900,000 to be recognized during the year ended December 31, 2007 and the remaining portion during the year ended December 31, 2008.

Restricted Stock Awards

In addition to stock options, our 2003 and 2006 Plan allow for the grant of restricted stock awards (“RSA”), which is an award of common stock with no exercise price, 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 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.

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


			Weighted Average
			Grant-Date Fair Value
	Number of Shares		per Share

Nonvested at December 31, 2005		—	$	—
Granted		—		—
Vested		27,000		18.30
Forfeited		—		—

Nonvested at December 31, 2006		27,000	$	18.30

As of December 31, 2006, there was $393,000 of total unrecognized compensation cost related to nonvested RSAs, which is expected to be recognized during the year ended December 31, 2007.

NOTE 13 — STOCK PURCHASE WARRANTS

In conjunction with the Mountain Air purchase by OilQuip in February of 2001, Mountain Air issued a common stock warrant for 620,000 shares to a third-party investment firm that assisted us in its initial identification and purchase of the Mountain Air assets. The warrant entitles the holder to acquire up to 620,000 shares of common stock of Mountain Air at an exercise price of $.01 per share over a nine-year period commencing on February 7, 2001.

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

We issued two warrants (“Warrants A and B”) for the purchase of 233,000 total shares of our common stock at an exercise price of $0.75 per share and one warrant for the purchase of 67,000 shares of our common stock at an exercise price of $5.00 per share (“Warrant C”) in connection with our subordinated debt financing for Mountain Air in 2001. Warrants A and B were paid off on December 7, 2004. Warrant C was exercised during November 2006.

On February 6, 2002, in connection with the acquisition of substantially all of the outstanding stock of Strata, we issued a warrant for the purchase of 87,500 shares of our common stock at an exercise price of $0.75 per share over the term of four years. The warrants were exercised in August of 2005.

In connection with the Strata Acquisition, on February 19, 2003, we issued Energy Spectrum an additional warrant to purchase 175,000 shares of our common stock at an exercise price of $0.75 per share. The warrants were exercised in August of 2005.

In March 2004, we issued a warrant to purchase 340,000 shares of our common stock at an exercise price of $2.50 per share to Morgan Joseph & Co., in consideration of financial advisory services to be provided by Morgan Joseph pursuant to a consulting agreement. The warrants were exercised in August 2005.

In April 2004, we issued warrants to purchase 20,000 shares of common stock at an exercise price of $0.75 per share to Wells Fargo Credit, Inc., in connection with the extension of credit by Wells Fargo Credit Inc. The warrants were exercised in August 2005.

In April 2004, we completed a private placement of 620,000 shares of common stock and warrants to purchase 800,000 shares of common stock to the following investors: Christopher Engel; Donald Engel; the Engel Defined Benefit Plan; RER Corp., a corporation wholly-owned by director Robert Nederlander; and Leonard Toboroff, a director. The investors invested $1,550,000 in exchange for 620,000 shares of common stock for a purchase price equal to $2.50 per share, and invested $450,000 in exchange for warrants to purchase 800,000 shares of common stock at an exercise of $2.50 per share, expiring on April 1, 2006. A total of 486,557 of these warrants were exercised in 2005 with the remaining portion exercised during 2006.

In May 2004, we issued a warrant to purchase 3,000 shares of our common stock at an exercise price of $4.75 per share to Jeffrey R. Freedman in consideration of financial advisory services to be provided by Mr. Freedman pursuant to a consulting agreement. The warrants were exercised in May 2004. Mr. Freedman was also granted 16,000 warrants in May of 2004 exercisable at $4.65 per share. These warrants were exercised in November of 2005.

Warrants for 4,000 shares of our common stock at an exercise price of $4.65 were also issued in May 2004 and remain outstanding as of December 31, 2006.

NOTE 14 — CONDENSED CONSOLIDATED FINANCIAL INFORMATION

Set forth on the following pages are the condensed consolidating financial statements of (i) Allis-Chalmers Energy Inc., (ii) its subsidiaries that are guarantors of the senior notes and revolving credit facility and (iii) the subsidiaries that are not guarantors of the senior notes and revolving credit facility (in thousands). Prior to the acquisition of DLS, all of our subsidiaries were guarantors of our senior notes and revolving credit facility, the parent company had no independent assets or operations, the guarantees were full and unconditional and joint and several.

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2006


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

Assets
Cash and cash equivalents	$	—	$	37,769	$	1,976	$	—		$	39,745
Trade receivables, net		—		62,089		33,971		(294	)		95,766
Inventories		—		13,194		15,421		—			28,615
Intercompany receivables		67,909		—		—		(67,909	)		—
Note receivable from affiliate		5,502		—		—		(5,502	)		—
Prepaid expenses and other		5,703		10,200		733		—			16,636

Total current assets		79,114		123,252		52,101		(73,705	)		180,762
Property and equipment, net		—		422,297		131,961		—			554,258
Goodwill		—		124,331		1,504		—			125,835
Other intangible assets, net		598		32,153		89		—			32,840
Debt issuance costs, net		9,633		—		—		—			9,633
Note receivable from affiliates		12,339		—		—		(12,339	)		—
Investments in affiliates		722,202		—		—		(722,202	)		—
Other assets		257		4,719		22		—			4,998

Total assets	$	824,143	$	706,752	$	185,677	$	(808,246	)	$	908,326


Liabilities and Stockholders’ Equity
Current maturities of long-term debt	$	32	$	3,809	$	3,158	$	—		$	6,999
Trade accounts payable		31		13,510		12,125		—			25,666
Accrued salaries, benefits and payroll taxes		—		2,993		7,895		—			10,888
Accrued interest		11,755		—		112		—			11,867
Accrued expenses		135		9,247		7,863		(294	)		16,951
Intercompany payables		—		425,610		17		(425,627	)		—
Note payable to affiliate		—		—		5,502		(5,502	)		—

Total current liabilities		11,953		455,169		36,672		(431,423	)		72,371
Long-term debt, net of current maturities		555,750		770		4,926		—			561,446
Note payable to affiliate		—		—		12,339		(12,339	)		—
Deferred income tax liability		2,203		10,714		7,036		—			19,953
Other long-term liabilities		304		319		—		—			623

Total liabilities		570,210		466,972		60,973		(443,762	)		654,393
Commitments and contingencies

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

Allis-Chalmers
Subsidiary

(Parent/
Subsidiary
Non-
Consolidating
Consolidated

Guarantor) Guarantors Guarantors Adjustments Total

Stockholders’ Equity

Common stock
282 3,526 42,963 (46,489 ) 282

Capital in excess of par value
216,208 167,508 74,969 (242,477 ) 216,208

Retained earnings
37,443 68,746 6,772 (75,518 ) 37,443

Total stockholders’ equity
253,933 239,780 124,704 (364,484 ) 253,933

Total liabilities and stock holders’ equity
$ 824,143 $ 706,752 $ 185,677 $ (808,246 ) $ 908,326

CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Year Ended December 31, 2006


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

Revenues	$	—		$	237,814		$	69,490		$	—		$	307,304
Cost of revenues
Direct costs		—			130,978			50,941			—			181,919
Depreciation		—			16,198			4,063			—			20,261

Total cost of revenues		—			147,176			55,004			—			202,180

Gross margin		—			90,638			14,486			—			105,124
General and administrative		2,643			30,651			2,242			—			35,536
Amortization		1,120			1,801			11			—			2,932

Income from operations		(3,763	)		58,186			12,233			—			66,656
Other income (expense):
Equity earnings in affiliates, net of tax		58,077			—			—			(58,077	)		—
Interest, net		(18,733	)		67			(597	)		—			(19,263	)
Other		45			97			(489	)		—			(347	)

Total other income (expense)		39,389			164			(1,086	)		(58,077	)		(19,610	)

Income before income taxes		35,626			58,350			11,147			(58,077	)		47,046
Provision for income taxes		—			(7,045	)		(4,375	)		—			(11,420	)

Net income	$	35,626		$	51,305		$	6,772		$	(58,077	)	$	35,626

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Year Ended December 31, 2006 (unaudited)


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

Cash Flows from Operating Activities:
Net income	$	35,626		$	51,305		$	6,772		$	(58,077	)	$	35,626
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		—			16,198			4,063			—			20,261
Amortization		1,121			1,811			—			—			2,932
Write-off of deferred financing fees		453			—			—			—			453
Stock based compensation		3,394			—			—			—			3,394
Provision for bad debts		—			781			—			—			781
Imputed interest		—			355			—			—			355
Equity earnings in affiliates		(58,077	)		—			—			58,077			—
Deferred taxes		(619	)		247			2,587			—			2,215
(Gain) on sale of equipment		—			(2,428	)		(16	)		—			(2,444	)
Changes in operating assets and liabilities, net of acquisitions:
(Increase) in accounts receivables		—			(23,144	)		(31	)		—			(23,175	)
(Increase) decrease in other current assets		(2,483	)		1,121			1,230			—			(132	)
(Increase) decrease in other assets		296			101			(89	)		—			308
(Decrease) increase in accounts payable		(82	)		3,587			(5,842	)		—			(2,337	)
(Decrease) increase in accrued interest		11,508			(45	)		(81	)		—			11,382
(Decrease) increase in accrued expenses		(390	)		1,633			(371	)		—			872
(Decrease) increase in accrued salaries, benefits and payroll taxes		(1,951	)		2,780			2,563			—			3,392
(Decrease) increase in other liabilities		(31	)		(193	)		—			—			(224	)

Net cash provided (used) by operating activities		(11,235	)		54,109			10,785			—			53,659

Cash Flows from Investing Activities:
Acquisition of businesses, net of cash		(528,167	)		3,649			(2,054	)		—			(526,572	)
Notes receivable from affiliates		(585	)		—			—			585			—

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

Allis-
Other

Chalmers
Subsidiaries

(Parent/
Subsidiary
(Non-
Consolidating
Consolidated

Guarantor) Guarantors Guarantors) Adjustments Total

Purchase of property and equipment
— (33,930 ) (5,767 ) — (39,697 )

Proceeds from sale of equipment
— 6,730 151 — 6,881

Net cash provided (used) in investing activities
(528,752 ) (23,551 ) (7,670 ) 585 (559,388 )

Cash Flows from Financing Activities:

Proceeds from long-term debt
555,000 2,820 — — 557,820

Payments on long-term debt
(42,414 ) (9,875 ) (1,741 ) — (54,030 )

Payments on related party debt
— (3,031 ) — — (3,031 )

Net (payments) borrowings on lines of credit
(6,400 ) — — — (6,400 )

Accounts receivable from affiliates
(16,444 ) — — 16,444 —

Accounts payable to affiliates
— 16,427 17 (16,444 ) —

Note payable to affiliate
— — 585 (585 ) —

Proceeds from issuance of common stock
46,297 — — — 46,297

Proceeds from exercise of options and warrants
6,321 — — — 6,321

Tax benefit on options
6,440 — — — 6,440

Debt issuance costs
(9,863 ) — — (9,863 )

Net cash provided (used) by financing activities
538,937 6,341 (1,139 ) (585 ) 543,554

Net change in cash and cash equivalents
(1,050 ) 36,899 1,976 — 37,825

Cash and cash equivalents at beginning of year
1,050 870 — — 1,920

Cash and cash equivalents at end of period
$ — $ 37,769 $ 1,976 $ — $ 39,745


NOTE 15 —	RELATED PARTY TRANSACTIONS

In July 2005, we entered into a lease of a yard in Buffalo, Texas which is part owned by our former Chief Operating Officer, David Wilde. The monthly rent was $3,500.

Until December 2004, our Chief Executive Officer and Chairman, Munawar H. Hidayatallah and his wife were personal guarantors of substantially all of the financing extended to us by commercial banks. In December 2004, we refinanced most of our outstanding bank debt and obtained the release of certain guarantees. After the refinancing, Mr. Hidayatallah continued to guarantee the Tubular $4.0 million subordinated seller note until July 2005. We paid Mr. Hidayatallah an annual guarantee fee equal to one-quarter of one percent of the total amount of the debt guaranteed by Mr. Hidayatallah. These fees aggregated to $7,250 during 2005 and were paid quarterly, in arrears, based upon the average amount of debt outstanding in the prior quarter.

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

In April 2004, we entered into an oral consulting agreement with Leonard Toboroff, one of our directors, pursuant to which we pay him $12,000 per month in 2006 and $10,000 per month in 2005 to advise us regarding financing and acquisition opportunities.

Jens Mortensen, one of our former directors, is the former owner of Tubular and held a 19% minority interest in Tubular until September 30, 2004. He was also the holder of a $4.0 million subordinated note payable issued by Tubular and at December 31, 2005 was owed $60,000 in accrued interest and $267,000 related to a non-compete agreement. (See Note 8). The subordinated note was repaid in January of 2006 and the accrued interest was paid in January 2006. Mr. Mortensen, formerly the sole proprietor of Tubular, owns a shop yard which he leases to Jens’ on a monthly basis. Lease payments made under the terms of the lease were $0, $16,800 and $28,800 for the years ended December 31, 2006, 2005 and 2004, respectively. In addition, Mr. Mortensen and members of his family own 100% of Tex-Mex Rental & Supply Co., a Texas corporation, that sold approximately $0, $0 and $167,000 of equipment and other supplies to Tubular for the years ended December 31, 2006, 2005 and 2004, respectively.

DLS was acquired from three British Virgin Island corporations. Two of our Directors; Alejandro P. Bulgheroni and Carlos A. Bulgheroni, indirectly beneficially own substantially all of the shares of the DLS sellers. DLS’ largest customer is Pan American Energy which is a joint venture by British Petroleum and Bridas Corporation. Alejandro P. Bulgheroni and Carlos A. Bulgheroni, indirectly beneficially own substantially all of the shares of the Bridas Corporation.

As described in Note 8, several of our former directors were issued promissory notes in 2000 in lieu of compensation for services. Our current maturities of long-term debt includes $32,000 and $96,000 as of December 31, 2006 and 2005, respectively, relative to these notes.


NOTE 16 —	SEGMENT INFORMATION

At December 31, 2006, we had six operating segments including: Rental Tools, International Drilling, Directional Drilling Services, Casing and Tubing Services, Compressed Air Drilling Services and Production Services. All of the segments provide services to the energy industry. The revenues, operating income (loss), depreciation and amortization, capital expenditures and assets of each of the reporting segments plus the Corporate function are reported below (in thousands):


	Years Ended December 31,
	2006		2005		2004

Revenues:
Rental tools	$	51,521	$	5,059	$	611
International drilling		69,490		—		—
Directional drilling services		72,811		43,901		24,787
Casing and tubing services		50,887		20,932		10,391
Compressed air drilling services		43,045		25,662		11,561
Production services		19,550		9,790		376

Total revenues	$	307,304	$	105,344	$	47,726

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

Years Ended December 31,

2006 2005 2004

Operating Income (Loss):

Rental tools
$ 26,293 $ 1,300 $ (71 )

International drilling
12,233 — —

Directional drilling services
17,666 7,389 3,061

Casing and tubing services
12,544 4,994 3,217

Compressed air drilling services
10,810 5,612 1,169

Production services
2,137 (99 ) 4

General corporate
(15,027 ) (5,978 ) (3,153 )

Total income from operations
$ 66,656 $ 13,218 $ 4,227

Depreciation and Amortization Expense:

Rental tools
$ 7,268 $ 492 $ 40

International drilling
4,074 — —

Directional drilling services
1,464 887 466

Casing and tubing services
3,908 2,006 1,597

Compressed air drilling services
3,057 1,946 1,329

Production services
2,005 912 26

General corporate
1,417 418 120

Total depreciation and amortization expense
$ 23,193 $ 6,661 $ 3,578

Capital Expenditures:

Rental tools
$ 4,538 $ 435 $ 232

International drilling
5,770 — —

Directional drilling services
5,128 2,922 1,552

Casing and tubing services
10,980 5,207 1,285

Compressed air drilling services
7,716 7,008 1,399

Production services
5,253 1,514 106

General corporate
312 681 29

Total capital expenditures
$ 39,697 $ 17,767 $ 4,603

Goodwill:

Rental tools
$ 106,132 $ — $ —

International drilling
1,504 — —

Directional drilling services
4,168 4,168 4,168

Casing and tubing services
6,464 3,673 3,673

Compressed air drilling services
3,950 3,950 3,510

Production services
3,617 626 425

General corporate
— — —

Total goodwill
$ 125,835 $ 12,417 $ 11,776

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

NOTE 17 — SUPPLEMENTAL CASH FLOWS INFORMATION (in thousands)


	Years Ended December 31,
	2006			2005		2004
						(Restated)

Interest paid	$	8,571		$	3,924	$	2,159

Income taxes paid	$	5,796		$	676	$	514

Other non-cash investing and financing transactions:
Insurance premiums financed		2,871			—		—
Purchase of equipment financed through assumption of debt or accounts payable		—			592		—
Non-cash investing and financing transactions in connection with acquisitions:
Fair value of net assets acquired	$	—		$	—	$	(4,867	)
Goodwill and other intangibles		(4,010	)		—		(3,839	)
Value of common stock, issued		94,980			1,750		2,177
Seller financed note		750			—		—
Deferred tax liability		17,662			—		—
Accrued expenses		250			—		—
Value of minority interest contribution		—			—		2,070

	$	109,632		$	1,750	$	(4,459	)

Acquisition of the remaining 19% of Jens:
Fair value of net assets acquired	$	—		$	—	$	(813	)
Goodwill and other intangibles		—			—		(3,676	)
Value of common stock issued		—			—		6,434
Value of minority interest retirement		—			—		(1,945	)

	$	—		$	—	$	—

NOTE 18 — LEGAL MATTERS

We are named from time to time in legal proceedings related to our activities prior to our bankruptcy in 1988; however, we believe that we were discharged from liability for all such claims in the bankruptcy and believe the likelihood of a material loss relating to any such legal proceeding is remote.

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

NOTE 19 — SUBSEQUENT EVENTS

In January 2007, we closed on a private offering, to qualified institutional buyers pursuant to Rule 144A under the Securities Act, of $255.0 million principal amount of our 8.5% senior notes due 2017. The proceeds of the senior notes offering, together with a portion of the proceeds of our concurrent common stock offering, were used to repay the debt outstanding under our $300.0 million bridge loan facility, which we incurred to finance our acquisition of substantially all the assets of OGR.

ALLIS-CHALMERS ENERGY INC.

Notes to Consolidated Financial Statements — (Continued)

In January 2007, we closed on a public offering of 6.0 million shares of our common stock at $17.65 per share. The proceeds of the common stock offering, together with the proceeds of our concurrent senior notes offering, were used to repay the debt outstanding under our $300.0 million bridge loan facility, which we incurred to finance our acquisition of substantially all the assets of OGR and for general corporate purposes.


NOTE 20 —	SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED) (in thousands, except per share amounts)


	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter

Year 2006
Revenues	$	47,028	$	60,470	$	85,738	$	114,068
Operating income		8,633		15,871		19,054		23,098
Net income	$	4,423	$	9,594	$	11,252	$	10,356

Income per common share:
Basic	$	0.26	$	0.53	$	0.52	$	0.41

Diluted	$	0.23	$	0.50	$	0.50	$	0.40


	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
	(Restated)

Year 2005
Revenues	$	19,334	$	23,588	$	28,908	$	33,514
Operating income		2,247		2,914		3,524		4,533
Net income	$	1,567	$	1,769	$	1,293	$	2,546

Income per common share:
Basic	$	0.12	$	0.13	$	0.09	$	0.15

Diluted	$	0.11	$	0.12	$	0.08	$	0.14


ITEM 9.	*CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE*

None.


ITEM 9A.	*CONTROLS AND PROCEDURES*


(a)	Evaluation Of Disclosure Controls And Procedures

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as that term is defined in Exchange Act Rule 13a-15(f). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Our control environment is the foundation for our system of internal control over financial reporting and is an integral part of our Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, which sets the tone of our company. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements. Our evaluation did not include companies which were acquired during fiscal year 2006, except for Specialty Rental Tools, Inc., since, under SEC guidelines, acquisitions do not have to evaluated until twelve months after the acquisition date.

In order to evaluate the effectiveness of our internal control over financial reporting as of December 31, 2006, as required by Section 404 of the Sarbanes-Oxley Act of 2002, our management conducted an assessment, including testing, based on the criteria set forth in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting and, based on that assessment, and concluded that, as of December 31, 2006, our internal controls over financial reporting are effective based on these criteria.


(b)	Change in Internal Control Over Financial Reporting.

During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management Report on Internal Control Over Financial Reporting.

Our Management Report on Internal Controls Over Financial Reporting can be found in Item 8 of this report. UHY LLP, the Independent Registered Public Accounting Firm’s attestation report on management’s assessment of the effectiveness of our internal control over financial reporting can also be found in Item 8 of this report.


ITEM 9B.	*OTHER INFORMATION*

None.

PART III


ITEM 10.	*DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT*

Pursuant to General Instructions G(3), information on directors and executive officers of Allis-Chalmers will be filed in an amendment to this Annual Report on Form 10-K or incorporated by reference from Allis-Chalmers’ Definitive Proxy Statement for the 2007 annual meeting of stockholders within 120 days of the end of our fiscal year ending December 31, 2006.


ITEM 11.	*EXECUTIVE COMPENSATION*

Pursuant to General Instructions G(3), information on executive compensation will be filed in an amendment to this Annual Report on Form 10-K or incorporated by reference from Allis-Chalmers’ Definitive Proxy Statement for the 2007 annual meeting of stockholders within 120 days of the end of our fiscal year ending December 31, 2006.


ITEM 12.	*SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT*

Pursuant to General Instruction G(3), information on security ownership of certain beneficial owners and management will be filed in an amendment to this Annual Report on Form 10-K or incorporated by reference from Allis-Chalmers’ Definitive Proxy Statement for the 2007 annual meeting of stockholders within 120 days of the end of our fiscal year ending December 31, 2006.


ITEM 13.	*CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS*

Pursuant to General Instruction G(3), information on security ownership of certain beneficial owners and management will be filed in an amendment to this Annual Report on Form 10-K or incorporated by reference from the Company’s Definitive Proxy Statement for the 2007 annual meeting of stockholders within 120 days of the end of our fiscal year ending December 31, 2006.


ITEM 14.	*PRINCIPAL ACCOUNTANT FEES AND SERVICES*

Pursuant to General Instruction G(3), information on principal accountant fees and services will be filed in an amendment to this Annual Report on Form 10-K or incorporated by reference from the Company’s Definitive Proxy Statement for the 2007 annual meeting of stockholders within 120 days of the end of our fiscal year ending December 31, 2006.

PART IV


ITEM 15.	*EXHIBITS AND FINANCIAL STATEMENT SCHEDULES*

(a)(1) Financial Statements

All financial statements of the Registrant as set forth under Item 8 of this Annual Report on Form 10-K.

(2) Financial Statement Schedules

Schedule II — Valuation and Qualifying Accounts

(3) Exhibits

The exhibits listed on the Exhibit index located on page 96 of this Annual report are filed as part of this 10-K.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on March 14, 2007.

/s/ MUNAWAR H. HIDAYATALLAH

Munawar H. Hidayatallah

Chief Executive Officer and Chairman

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, this report has been signed on the date indicated by the following persons on behalf of the registrant and in the capacities indicated.


Name	Title	Date

/s/ MUNAWAR H. HIDAYATALLAH Munawar H. Hidayatallah	Chairman and Chief Executive Officer (Principle Executive Officer)	March 14, 2007

/s/ VICTOR M. PEREZ Victor M. Perez	Chief Financial Officer (Principal Financial Officer)	March 14, 2007

/s/ BRUCE SAUERS Bruce Sauers	Chief Accounting Officer (Principal Accounting Officer)	March 14, 2007

/s/ BURT A. ADAMS Burt A. Adams	Vice Chairman, President and Chief Operating Officer	March 14, 2007

/s/ ALI H. M. AFDHAL Ali H. M. Afdhal	Director	March 14, 2007

Alejandro P. Bulgheroni	Director	March 14, 2007

Carlos A. Bulgheroni	Director	March 14, 2007

/s/ JEFFREY R. FREEDMAN Jeffrey R. Freedman	Director	March 14, 2007

/s/ VICTOR F. GERMACK Victor F. Germack	Director	March 14, 2007

/s/ JOHN E. MCCONNAUGHY, JR. John E. McConnaughy, Jr.	Director	March 14, 2007

/s/ ROBERT E. NEDERLANDER Robert E. Nederlander	Director	March 14, 2007

/s/ ZANE TANKEL Zane Tankel	Director	March 14, 2007

/s/ LEONARD TOBOROFF Leonard Toboroff	Director	March 14, 2007

EXHIBIT INDEX


Exhibit			Description

	2	.1	First Amended Disclosure Statement pursuant to Section 1125 of the Bankruptcy Code, dated September 14, 1988, which includes the First Amended and Restated Joint Plan of Reorganization dated September 14, 1988 (incorporated by reference to Registrant’s Current Report on Form 8-K dated December 1, 1988).
	2	.2	Reorganization Trust Agreement dated September 14, 1988 by and between Registrant and John T. Grigsby, Jr., Trustee (incorporated by reference to Exhibit D of the First Amended and Restated Joint Plan of Reorganization dated September 14, 1988 included in Registrant’s Current Report on Form 8-K dated December 1, 1988).
	2	.3	Agreement and Plan of Merger dated as of May 9, 2001 by and among Registrant, Allis-Chalmers Acquisition Corp. and OilQuip Rentals, Inc. (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed May 15, 2001).
	2	.4	Stock Purchase Agreement dated February 1, 2002 by and between Registrant and Jens H. Mortensen, Jr. (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed February 21, 2002).
	2	.5	Stock Purchase Agreement dated February 1, 2002 by and among Registrant, Energy Spectrum Partners LP, and Strata Directional Technology, Inc. (incorporated by reference to Exhibit 2.10 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2001).
	2	.6	Stock Purchase Agreement dated August 10, 2004 by and among Allis-Chalmers Corporation and the investors named thereto (incorporated by reference to Exhibit 10.37 to the Registration Statement on Form S-1 (Registration No. 118916) filed on September 10, 2004).
	2	.7	Amendment to Stock Purchase Agreement dated August 10, 2004 (incorporated by reference to Exhibit 10.38 to the Registration Statement on Form S-1 (Registration No. 118916) filed on September 10, 2004).
	2	.8	Addendum to Stock Purchase Agreement dated September 24, 2004 (incorporated by reference to Exhibit 10.55 to Registrant’s Current Report on Form 8-K filed on September 30, 2004).
	2	.9	Asset Purchase Agreement dated November 10, 2004 by and among AirComp LLC, a Delaware limited liability company, Diamond Air Drilling Services, Inc., a Texas corporation, and Marquis Bit Co., L.L.C., a New Mexico limited liability company, Greg Hawley and Tammy Hawley, residents of Texas and Clay Wilson and Linda Wilson, residents of New Mexico (incorporated by reference to the Current Report on Form 8-K filed on November 15, 2004).
	2	.10	Purchase Agreement and related Agreements by and among Allis-Chalmers Corporation, Chevron USA, Inc., Dale Redman and others dated December 10, 2004 (incorporated by reference to Exhibit 10.63 to the Registrant’s Current Report on Form 8-K filed on December 16, 2004).
	2	.11	Stock Purchase Agreement dated April 1, 2005, by and among Allis-Chalmers Energy Inc., Thomas Whittington, Sr., Werlyn R. Bourgeois and SAM and D, LLC. (incorporated by reference to Exhibit 10.51 to the Registrant’s Current Report on Form 8-K filed on April 5, 2005).
	2	.12	Stock Purchase Agreement effective May 1, 2005, by and among Allis-Chalmers Energy Inc., Wesley J. Mahone, Mike T. Wilhite, Andrew D. Mills and Tim Williams (incorporated by reference to Exhibit 10.51 to the Registrant’s Current Report on Form 8-K filed on May 6, 2005).
	2	.13	Purchase Agreement dated July 11, 2005 among Allis-Chalmers Energy Inc., Mountain Compressed Air, Inc. and M-I, L.L.C. (incorporated by reference to Exhibit 10.42 to the Registrant’s Current Report on Form 8-K filed on July 15, 2005).
	2	.14	Asset Purchase Agreement dated July 11, 2005 between AirComp LLC, W.T. Enterprises, Inc. and William M. Watts (incorporated by reference to Exhibit 10.43 to the Registrant’s Current Report on Form 8-K filed on July 15, 2005).
	2	.15	Asset Purchase Agreement by and between Patterson Services, Inc. and Allis-Chalmers Tubular Services, Inc. (incorporated by reference to Exhibit 10.44 to the Registrant’s Current Report on Form 8-K filed on September 8, 2005).


Exhibit			Description

	2	.16	Stock Purchase Agreement dated as of December 20, 2005 between the Registrant and Joe Van Matre (incorporated by reference to Exhibit 10.33 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2005).
	2	.17	Stock Purchase Agreement, dated as of April 27, 2006, by and among Bridas International Holdings Ltd., Bridas Central Company Ltd., Associated Petroleum Investors Limited, and the Registrant. (incorporated by reference to Exhibit 2.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006)
	2	.18	Stock Purchase Agreement, dated as of October 17, 2006, by and between Allis-Chalmers Production Services, Inc. and Randolph J. Hebert (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on October 19, 2006).
	2	.19	Asset Purchase Agreement, dated as of October 25, 2006, by and between Allis-Chalmers Energy Inc. and Oil & Gas Rental Services, Inc. (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on October 26, 2006).
	3	.1	Amended and Restated Certificate of Incorporation of Registrant (incorporated by reference to Exhibit 3.1 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2001).
	3	.2	Certificate of Designation, Preferences and Rights of the Series A 10% Cumulative Convertible Preferred Stock ($.01 Par Value) of Registrant (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed February 21, 2002).
	3	.3	Amended and Restated By-laws of Registrant (incorporated by reference to Exhibit 3.3. to the Registrant’s Annual Report of Form 10-K for the year ended December 31, 2001).
	3	.4	Certificate of Amendment of Certificate of Incorporation filed with the Delaware Secretary of State on June 9, 2004 (incorporated by reference to Exhibit 3.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004).
	3	.5	Certificate of Amendment of Certificate of Incorporation filed with the Delaware Secretary of State on January 5, 2005 (incorporated by reference to Exhibit 3.5 to the Registrant’s Current Report on Form 8-K filed January 11, 2005).
	3	.6	Certificate of Amendment of Certificate of Incorporation filed with the Delaware Secretary of State on August 16, 2005 (incorporated by reference to Exhibit 3.5 to the Registrant’s Current Report on Form 8-K filed August 17, 2005).
	4	.1	Specimen Stock Certificate of Common Stock of Registrant (incorporated by reference to Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004).
	4	.2	Registration Rights Agreement dated as of March 31, 1999, by and between Allis-Chalmers Corporation and the Pension Benefit Guaranty Corporation (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999).
	4	.3	Registration Rights Agreement dated April 2, 2004 by and between Registrant and the Stockholder signatories thereto (incorporated by reference to Exhibit 10.43 to Amendment No. 1 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003).
	4	.4	Registration Rights Agreement dated as of January 29, 2007 by and among Allis-Chalmers Energy Inc., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on January 29, 2007).
	4	.5	Registration Rights Agreement dated as of January 18, 2006 by and among Allis-Chalmers Energy Inc., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on January 24, 2006).
	4	.6	Registration Rights Agreement dated as of August 14, 2006 by and among the Registrant, the guarantors listed on Schedule A thereto and RBC Capital Markets Corporation (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on August 14, 2006).
	4	.7	Indenture dated as of January 18, 2006 by and among the Registrant, the Guarantors named therein and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on January 24, 2006).


Exhibit			Description

	4	.8	First Supplemental Indenture dated as of August 11, 2006 by and among Allis-Chalmers GP, LLC, Allis-Chalmers LP, LLC, Allis-Chalmers Management, LP, Rogers Oil Tool Services, Inc., the Registrant, the other Guarantors (as defined in the Indenture referred to therein) and Wells Fargo Bank, N.A (incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed on August 14, 2006).
	4	.9	Second Supplemental Indenture dated as of January 23, 2007 by and among Petro-Rentals, Incorporated, the Registrant, the other Guarantor parties thereto and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on January 24, 2007).
	4	.10	Indenture, dated as of January 29, 2007, by and among the Registrant, the Guarantors named therein and Wells Fargo Bank, N.A. (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on January 29, 2007).
	4	.11	Form of 9.0% Senior Note due 2014 (incorporated by reference to Exhibit A to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on January 24, 2006).
	4	.12	Form of 8.5% Senior Note due 2017 (incorporated by reference to Exhibit A to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on January 29, 2007).
	9	.1	Shareholders Agreement dated February 1, 2002 by and among Registrant and the stockholder and warrant holder signatories thereto (incorporated by reference to Exhibit 2.12 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2001).
	10	.1	Amended and Restated Retiree Health Trust Agreement dated September 14, 1988 by and between Registrant and Wells Fargo Bank (incorporated by reference to Exhibit C-1 of the First Amended and Restated Joint Plan of Reorganization dated September 14, 1988 included in Registrant’s Current Report on Form 8-K dated December 1, 1988).
	10	.2	Amended and Restated Retiree Health Trust Agreement dated September 18, 1988 by and between Registrant and Firstar Trust Company (incorporated by reference to Exhibit C-2 of the First Amended and Restated Joint Plan of Reorganization dated September 14, 1988 included in Registrant’s Current Report on Form 8-K dated December 1, 1988).
	10	.3	Product Liability Trust Agreement dated September 14, 1988 by and between Registrant and Bruce W. Strausberg, Trustee (incorporated by reference to Exhibit E of the First Amended and Restated Joint Plan of Reorganization dated September 14, 1988 included in Registrant’s Current Report on Form 8-K dated December 1, 1988).
	10	.4*	Allis-Chalmers Savings Plan (incorporated by reference to Registrant’s Annual Report on Form 10-K for the year ended December 31, 1988).
	10	.5*	Allis-Chalmers Consolidated Pension Plan (incorporated by reference to Registrant’s Annual Report on Form 10-K for the year ended December 31, 1988).
	10	.6	Agreement dated as of March 31, 1999 by and between Registrant and the Pension Benefit Guaranty Corporation (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999).
	10	.7	Shareholders Agreement dated February 1, 2002 by and among Jens’ Oilfield Service, Inc., a Texas corporation, Jens H. Mortensen, Jr., and Registrant (incorporated by reference to Exhibit 2.9 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2001).
	10	.8	Letter Agreement dated May 9, 2001 by and between Registrant and the Pension Benefit Guarantee Corporation (incorporated by reference to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002).
	10	.9	Termination Agreement dated May 9, 2001 by and between Registrant, the Pension Benefit Guarantee Corporation and others (incorporated by reference to Registrant’s Current Report on Form 8-K filed on May 15, 2002).
	10	.10*	Employment Agreement dated July 1, 2003 by and between AirComp LLC and Terry Keane (incorporated by reference to Exhibit 10.37 to the Registrant’s Current Report on Form 8-K filed July 16, 2003).


Exhibit			Description

	10	.11*	Employment Agreement dated as of April 1, 2004 between Registrant and Munawar H. Hidayatallah (incorporated by reference to Exhibit 10.47 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004).
	10	.12*	Employment Agreement dated as of April 1, 2004 between Registrant and David Wilde (incorporated by reference to Exhibit 10.48 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004).
	10	.13*	Employment Agreement dated July 26, 2004 by and between the Registrant and Victor M. Perez (incorporated by reference to Exhibit 10.36 to the Registration Statement on Form S-1 (Registration No. 118916) filed on September 10, 2004).
	10	.14*	Employment Agreement dated October 11, 2004, between the Registrant and Theodore F. Pound III (incorporated by reference to Exhibit 10.60 to the Registrant’s Current Report on Form 8-K filed on October 15, 2004).
	10	.15*	Employment Agreement, dated December 18, 2006, by and between the Registrant and Burt A. Adams (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on December 19, 2006).
	10	.16	Fifth Amendment to Credit Agreement dated as of April 6, 2004 by and between Strata Directional Technology, Inc., and Wells Fargo Credit Inc. (incorporated by reference to Exhibit 10.53 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004).
	10	.17	Third Amendment to Credit Agreement dated as of April 6, 2004 by and between Jens’ Oilfield Service, Inc. and Wells Fargo Credit Inc. (incorporated by reference to Exhibit 10.54 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004).
	10	.18	Letter Agreement dated February 13, 2004 by and between Registrant and Morgan Joseph & Co., Inc. (incorporated by reference to Exhibit 10.26 to the Registration Statement on Form S-1 (Registration No. 118916) filed on September 10, 2004).
	10	.19	Letter Agreement dated June 8, 2004 by and between the Registrant and Morgan Keegan & Company, Inc. (incorporated by reference to Exhibit 10.35 to the Registration Statement on Form S-1 (Registration No. 118916) filed on September 10, 2004).
	10	.20	Letter Agreement relating to Stock Purchase Agreement dated August 5, 2004 (incorporated by reference to Exhibit 10.39 to the Registration Statement on Form S-1 (Registration No. 118916) filed on September 10, 2004).
	10	.21	Amended and Restated Credit Agreement dated as of December 7, 2004, between AirComp LLC and Wells Fargo Bank, NA (incorporated by reference to Exhibit 10.62 to the Registrant’s Current Report on Form 8-K filed on December 13, 2004).
	10	.22	First Amendment to Stockholder Agreement by and among Allis-Chalmers Energy Inc. and the Stockholders named therein (incorporated by reference to Exhibit 10.44 to the Registrant’s Current Report on Form 8-K filed on August 5, 2005).
	10	.23	Purchase Agreement dated as of January 12, 2006 by and among Allis-Chalmers Energy Inc, the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on January 24, 2006).
	10	.24	Purchase Agreement dated as of August 8, 2006 by and between the Registrant, the guarantors listed on Schedule B thereto and RBC Capital Markets Corporation (incorporated by reference to Exhibit 10.4 to the Registrant’s Form 8-K filed on August 14, 2006).
	10	.25	Purchase Agreement dated as of January 24, 2007 by and among Allis-Chalmers Energy Inc., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on January 29, 2007).
	10	.26	Amended and Restated Credit Agreement dated as of January 18, 2006 by and among Allis-Chalmers Energy Inc., as borrower, Royal bank of Canada, as administrative agent and Collateral Agent, RBC Capital Markets, as lead arranger and sole bookrunner, and the lenders party thereto (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on January 24, 2006).
	10	.27	First Amendment to Amended and Restated Credit Agreement dated as of August 8, 2006, by and among the Registrant, the guarantors named thereto and Royal Bank of Canada (incorporated by reference to Exhibit 10.3 to the Registrant’s Form 8-K filed on August 14, 2006).


Exhibit			Description

	10	.28	Senior Unsecured Bridge Loan Agreement, dated December 18, 2006, by and among the Registrant, Royal Bank of Canada, as administrative agent, RBC Capital Markets Corporation, as exclusive lead arranger and sole bookrunner, and the guarantors and institutional lenders named thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 19, 2006).
	10	.29	Strategic Agreement dated July 1, 2003 between Pan American Energy LLC Sucursal Argentina and DLS Argentina Limited Sucursal Argentina (incorporated by reference to Exhibit 10.13 to the Registrant’s Quarterly Report on Form 10-Q filed on December 29, 2006).
	10	.30	Amendment No. 1 dated May 18, 2005 to Strategic Agreement between Pan American Energy LLC Sucursal Argentina and DLS Argentina Limited Sucursal Argentina (incorporated by reference to Exhibit 10.14 to the Registrant’s Quarterly Report on Form 10-Q filed on December 29, 2006).
	10	.31	Amendment No. 2 dated January 1, 2006 between Pan American Energy LLC Sucursal Argentina and DLS Argentina Limited Sucursal Argentina (incorporated by reference to Exhibit 10.15 to the Registrant’s Quarterly Report on Form 10-Q filed on December 29, 2006).
	10	.32	Investor Rights Agreement, dated December 18, 2006, by and between the Registrant and Oil & Gas Rental Services, Inc. (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on December 19, 2006).
	10	.33	Investors Rights Agreement dated as of August 18, 2006 by and among the Registrant and the investors named on Exhibit A thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on August 14, 2006).
	10	.34*	2003 Incentive Stock Plan (incorporated by reference to Exhibit 4.12 to the Registrant’s Current Report on Form 8-K filed August 17, 2005).
	10	.35*	Form of Option Certificate issued pursuant to 2003 Incentive Stock Plan (incorporated by reference to Exhibit 10.41 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003).
	10	.36*	2006 Incentive Plan (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on September 18, 2006).
	10	.37*	Form of Employee Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed on September 18, 2006).
	10	.38*	Form of Employee Nonqualified Stock Option Agreement (incorporated by reference to Exhibit 10.3 to the Registrant’s Form 8-K filed on September 18, 2006).
	10	.39*	Form of Employee Incentive Stock Option Agreement (incorporated by reference to Exhibit 10.4 to the Registrant’s Form 8-K filed on September 18, 2006).
	10	.40*	Form of Non-Employee Director Restricted Stock Agreement (incorporated by reference to Exhibit 10.5 to the Registrant’s Form 8-K filed on September 18, 2006).
	10	.41*	Form of Non-Employee Director Nonqualified Stock Option Agreement (incorporated by reference to Exhibit 10.6 to the Registrant’s Form 8-K filed on September 18, 2006).
	14	.1	Code of Ethics (incorporated by reference to the Form 8-K filed on December 1, 2004).
	16	.1	Letter from Gordon Hughes & Banks LLP dated October 5, 2004, to the Securities and Exchange Commission (incorporated by reference to Registrant’s Current Report on Form 8-K filed on October 6, 2004).
	21	.1	Subsidiaries of Registrant.
	23	.1	Consent of UHY LLP.
	31	.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31	.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32	.1	Certification of the Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Compensation Plan or Agreement

100


		Page

PART I
Item 1.	Business		5
Item 1A.	Risk Factors		13
Item 1B.	Unresolved Staff Comments		26
Item 2.	Properties		27
Item 3.	Legal Proceedings		27
Item 4.	Submission of Matters to a Vote of Security Holders		29

PART II

Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters		29
Item 6.	Selected Financial Data		32
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		32
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		47
Item 8.	Financial Statements		48
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		92
Item 9A.	Controls and Procedures		92
Item 9B.	Other Information		92

PART III

Item 10.	Directors and Executive Officers of the Registrant		93
Item 11.	Executive Compensation		93
Item 12.	Security Ownership of Certain Beneficial Owners and Management		93
Item 13.	Certain Relationships and Related Transactions		93
Item 14.	Principal Accountant Fees and Services		93

PART IV

Item 15.	Exhibits and Financial Statement Schedules		93
Signatures and Certifications			95
Subsidiaries
Consent of UHY LLP
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO & CFO Pursuant to Section 302


	Three Months Ended March 31, 2004
	As
	Previously				As
	Reported		Adjustments		Restated

Income per common share — diluted	$	0.05	$	0.03	$	0.08

Weighted average number of common shares outstanding:
Diluted		5,762		478		6,240


			Additions
	Balance at		Charged to					Balance at
	Beginning		Costs and					End of
Description	of Period		Expense		Deductions			Period
	(In thousands)

Year Ended December 31, 2006:
Allowance for doubtful accounts		383		781		(338	)		826
Deferred tax assets valuation allowance		27,131		—		(27,131	)		—
Year Ended December 31, 2005:
Allowance for doubtful accounts		265		219		(101	)		383
Deferred tax assets valuation allowance		30,367		—		(3,236	)		27,131
Year Ended December 31, 2004:
Allowance for doubtful accounts		168		104		(7	)		265
Deferred tax assets valuation allowance		38,475		—		(8,108	)		30,367



AirComp L.L.C.		Delaware
Allis-Chalmers GP, LLC		Delaware
Allis-Chalmers LP, LLC		Delaware
Allis-Chalmers Management, LP		Texas
Allis-Chalmers Production Services, Inc.		Texas
Allis-Chalmers Rental Services, Inc.		Texas
Allis-Chalmers Tubular Services, Inc.		Texas
DLS Argentina Limited		British Virgin Islands
DLS Drilling, Logistics and Services Company		British Virgin Islands
Mountain Compressed Air, Inc.		Texas
Petro-Rentals, Inc.		Louisiana
OilQuip Rentals, Inc.		Delaware
Strata Directional Technology, Inc.		Texas
Tanus Argentina S.A.		Argentina