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

 

 

 

 

Form 10-K

 

 

 

 

 

Commission File No. 1-32858

 

 

 

 

Complete Production Services, Inc.

(Exact name of registrant as specified in its charter)

 

 

 

 

 

Registrant’s telephone number, including area code: (281) 372-2300

 

 

 

 

Securities registered pursuant to Section 12(b) of the Act:

 

 

Securities registered pursuant to Section 12(g) of the Act:

None

 

 

 

 

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

 

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

 

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

 

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

 

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

 

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

 

(Do not check if a smaller reporting company)

 

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

 

As of June 30, 2010, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $935,388,997 based upon the closing price on the New York Stock Exchange on that date.

 

Number of shares of the Common Stock of the registrant outstanding as of February 14, 2011: 78,592,455

 

 

 

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the registrant’s proxy statement to be furnished to the stockholders in connection with its 2011 Annual Meeting of Stockholders are incorporated by reference in Part III, Items 10-14 of this Annual Report on Form 10-K for the fiscal year ending December 31, 2010 (this “Annual Report”).

 

 

Complete Production Services, Inc.

 

TABLE OF CONTENTS

 

 

Unless otherwise indicated, all references to “we,” “us,” “our,” “our company,” or “Complete” include Complete Production Services, Inc. and its consolidated subsidiaries.

 

 

Our Company

 

Complete Production Services, Inc., formerly named Integrated Production Services, Inc., is a Delaware corporation formed on May 22, 2001. We focus on providing specialized completion and production services and products that help oil and gas companies develop hydrocarbon reserves, reduce costs and enhance production. We operate in basins within North America that we believe have attractive long-term potential for growth, and we deliver targeted, value-added services and products required by our customers within each specific basin. We believe our range of services and products positions us to meet many needs of our customers at the wellsite, from drilling and completion through production and eventual abandonment. We seek to differentiate ourselves from our competitors through our local leadership, our basin-level expertise and the innovative application of proprietary and other technologies. We deliver solutions to our customers that we believe lower their costs and increase their production in a safe and environmentally friendly manner. Virtually all of our operations are located in basins within North America, where we manage our operations from regional field service facilities located throughout the U.S. Rocky Mountain region, Texas, Oklahoma, Louisiana, Arkansas, Pennsylvania, western Canada and Mexico. We also have operations in Southeast Asia.

 

Company History

 

On September 12, 2005, Integrated Production Services, Inc. (“IPS”), Complete Energy Services, Inc. and I.E. Miller Services, Inc. were combined and became Complete Production Services, Inc. in a transaction in which IPS served as the acquirer.

 

In April 2006, we completed our initial public offering and became subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

 

Our Operating Segments

 

Our business is comprised of three segments:

 

Completion and Production Services.  Through our completion and production services segment, we establish, maintain and enhance the flow of oil and gas throughout the life of a well. This segment is divided into the following primary service lines:

 

 

Drilling Services.  Through our drilling services segment, we provide contract drilling and specialized rig relocation and logistics services.

 

Product Sales.  We provide oilfield service equipment and refurbishment of used equipment through our Southeast Asian business, and we provide repair work and fabrication services for our customers at a business located in Gainesville, Texas.

 

Our Industry

 

Our business depends on the level of exploration, development and production expenditures made by our customers. These expenditures are driven by the current and expected future prices for oil and gas, and the perceived stability and sustainability of those prices, as well as production depletion rates and the resultant levels of cash flows generated and allocated by our customers to their drilling and workover budgets. Our business is primarily driven by oil, natural gas and associated natural gas liquids-directed drilling activity in North America.

 

As illustrated in the table below, natural gas and oil commodity prices had risen in recent years but then began to decline in late 2008. While the price of oil rebounded somewhat in 2009 and continued to rise throughout 2010, the price of natural gas remained relatively low in 2010. The WTI Cushing spot price of a barrel of crude oil reached an all-time high of $145.31 per barrel in July 2008 and then dropped sharply by the end of the year, falling as low as $30.28 per barrel on December 23, 2008 before trending upwards again in late 2009 and reaching a high of $91.48 towards the end of 2010. The number of drilling rigs under contract in the United States and Canada and the number of active well service rigs decreased in 2009 but rebounded in 2010, according to Baker Hughes Incorporated (“BHI”) and the Cameron International Corporation/Guiberson/AESC Service Rig Count for “Active Rigs.” The table below sets forth average daily closing prices for the WTI Cushing spot oil price and the average daily closing prices for the Henry Hub price for natural gas since 2001:

 

 

 

Source: Bloomberg NYMEX prices.

 

The closing spot price of a barrel of WTI Cushing oil at December 31, 2010 was $91.38, and the closing spot price for Henry Hub natural gas ($/mcf) was $4.41. At February 14, 2011, the closing spot price of a barrel of WTI Cushing oil was $84.81 and the closing spot price for Henry Hub natural gas was $3.92.

 

Trends which we believe are affecting, and will continue to affect, our industry include:

 

Trend toward drilling and developing unconventional North American hydrocarbon resources.  Due to the maturity of conventional North American oil and gas reservoirs and the relative abundance of undeveloped unconventional resources, an increasing proportion of future North American oil and gas will come from unconventional resources, which include tight sands, shales and coalbed methane. Development of unconventional resources typically require more wells to be drilled and maintained on tighter acreage spacing and often employ horizontal drilling and completion techniques, which are more service intensive. The appropriate technology to recover unconventional gas resources varies from region to region; therefore, knowledge of local conditions and operating procedures, and selection of the right technologies, is key to providing customers with appropriate solutions.

 

The advent of the resource play.  A “resource play” is a term used to describe an accumulation of hydrocarbons known to exist over a large area which, when compared to a conventional play, has lower commercial development risks and a higher average decline rate. Once identified, resource plays have the potential to make a material impact because of their size and long reserve life. The application of appropriate technology and program execution are important to obtain value from resource plays. Resource play

developments occur over long periods of time, well by well, in large-scale developments that repeat common tasks in an assembly-line fashion and capture economies of scale to drive down costs.

 

Complex technologies, techniques and equipment.  The development of unconventional oil and gas resources is driving the need for complex, new technologies, completion techniques and equipment to help increase recovery rates, lower production costs and accelerate field development.

 

Increased Service Intensity.  Advances in horizontal drilling and completion technologies and techniques have made the development of many unconventional resources such as oil and natural gas shale formations economically attractive. The North American horizontal rig count has risen from 335 at the beginning of 2007 to 947 at the end of December 2010, according to Baker Hughes, Inc. Additionally, the length of well laterals has increased and the intervals between stages has decreased over the past several years. The longer laterals and increasing number of stages has enhanced recoveries and lowered field development costs while causing the number of completion stages to grow at a faster rate than the horizontal rig count, creating an increased demand for completion related services.

 

Enhanced Economics in Oil- and Liquids-Rich Formations.  While the majority of U.S. drilling rigs are currently drilling in natural gas formations, there is increasing horizontal drilling and completion related activity in oil- and liquid-rich formations such as the Eagle Ford, Bakken and Niobrara Shales and various other plays in Texas and Oklahoma, including the Granite Wash. We believe that the oil and natural gas liquids content in these plays significantly enhance the returns for our customers relative to opportunities in dry gas basins due to the significant disparity between oil and natural gas prices on a Btu basis. We believe the price disparity will continue over the near to mid-term resulting in increasing demand for services in oil- and liquid-rich basins.

 

Our Business Strategy

 

Our goal is to build the leading oilfield services company focused on the completion and production phases in the life of an oil and gas well. We intend to capitalize on the emerging trends in the North American marketplace through the execution of a growth strategy that consists of the following components:

 

Focus on execution and performance.  We have established and intend to develop further a culture of performance and accountability. Senior management spends a significant portion of its time ensuring that our customers receive the highest levels of service quality and execution at the well site by focusing on the following:

 

 

Expand and capitalize on local leadership and basin-level expertise.  A key component of our strategy is to build upon our base of strong local leadership and basin-level expertise. We have a significant presence in most of the key onshore continental U.S. and Canadian resource plays that we believe have the potential for long-term growth. Our position in these basins capitalizes on our local leadership as these employees have accumulated a valuable knowledge base and strong customer relationships. We intend to leverage our existing market presence, expertise and customer relationships to expand our business within these resource plays. We also intend to replicate this approach in new regions by building and acquiring new businesses that have strong regional management with extensive local knowledge.

Develop and deploy technical and operational solutions.  We are focused on developing and deploying technical services, equipment and expertise that lower our customers’ costs.

 

Capitalize on organic and acquisition-related growth opportunities.  We believe there are numerous opportunities to expand our service offerings in our current geographic areas and to sell our current services and products to customers in new geographic areas. We have a proven track record of organic growth and successful acquisitions, and we intend to continue using capital investments and acquisitions to strategically expand our business over the long-term. In 2009, we significantly reduced our capital expenditures and did not complete any cash acquisitions primarily due to difficult market conditions. In 2010, we increased our capital investment significantly compared to the prior year and we acquired three small strategic businesses. We continue to evaluate additional business acquisition opportunities.

 

Our Competitive Strengths

 

We believe that we are well positioned to execute our strategy and capitalize on opportunities in the North American oil and gas market based on the following competitive strengths:

 

Strong local leadership and basin-level expertise.  We operate our business with a focus on each regional basin complemented by our local reputations. We believe our local and regional businesses, some of which have been operating for more than 50 years, provide us with a significant advantage over many of our competitors. Our managers, sales engineers and field operators have extensive expertise in their local geological basins and understand the regional challenges our customers face. We support our local operations personnel through corporate teams that provide service specific technical support and executive level contacts. We have long-term relationships with many customers, and most of the services and products we offer are sold or contracted at a local level, allowing our operations personnel to leverage all of our expertise to establish ourselves as the preferred provider of our services in the basins in which we operate.

 

Significant presence in major North American basins.  We operate in major oil and gas producing regions of the U.S. Rocky Mountains, Texas, Louisiana, Arkansas, Pennsylvania, Oklahoma, western Canada and Mexico, with concentrations in key “resource play” and unconventional basins. Resource plays are expected to continue to increase in importance in future North American oil and gas production as more conventional resources enter later stages of the exploration and development cycle. We believe we have an excellent position in highly active markets such as the Bakken Shale area of North Dakota, the Niobrara Shale of northeast Colorado and southeast Wyoming, the Granite Wash of northern Texas and western Oklahoma, the Marcellus Shale of Pennsylvania, the Barnett Shale of north Texas, the Haynesville Shale area of east Texas and northern Louisiana and the Eagle Ford shale in south Texas. Each of these markets is among the most active areas for exploration and development of onshore oil and gas. Accelerating production and driving down development and production costs are key goals for oil and gas operators in these areas, resulting in higher demand for our services and products. In addition, our presence in these regions allows us to build solid customer relationships and take advantage of cross-selling opportunities.

 

Focus on complementary production and field development services.  Our breadth of service and product offerings positions us well relative to our competitors. Our services encompass the entire lifecycle of a well from drilling and completion, through production and eventual abandonment. We deliver complementary services and products, which we may provide in tandem or sequentially over the life of the well. This suite of services and products gives us the opportunity to cross-sell to our customer base throughout our geographic regions. Leveraging our local leadership and basin-level expertise, we are able to offer expanded services and products to existing customers or current services and products to new customers.

 

Innovative approach to technical and operational solutions.  We develop and deploy services and products that enable our customers to increase production rates, stem production declines and reduce the costs of drilling, completion and production. The significant expertise we have developed in our areas of operation offers our customers customized operational solutions to meet their particular needs. Our ability to develop these technical and operational solutions is possible due to our understanding of applicable technology, our basin-level expertise and our close local relationships with customers.

Modern and active asset base.  We have a modern and well-maintained fleet of coiled tubing units, pressure pumping equipment, wireline units, well service rigs, snubbing units, fluid transports, frac tanks and other specialized equipment. We believe our ongoing investment in our equipment allows us to better serve the diverse and increasingly challenging needs of our customer base. New equipment is generally less costly to maintain and operate on an annual basis and is more efficient for our customers. Modern equipment reduces downtime, including associated costs and expenditures, and enables increased utilization of our assets. We believe our future expenditures will be used to capitalize on growth opportunities within the areas we currently operate and to build out platforms in new regions.

 

Experienced management team with proven track record.  Each member of our operating management team has extensive experience in the oilfield services industry. We believe that their considerable knowledge of and experience in our industry enhances our ability to operate effectively throughout industry cycles. Our management also has substantial experience in identifying, completing and integrating acquisitions. In addition, our management supports local leadership by developing corporate strategy, overseeing corporate governance procedures and administering a company-wide safety program.

 

Overview of Our Segments

 

We manage our business through three segments: completion and production services, drilling services and product sales. Within each of these segments, we perform services and deliver products, as detailed in the table below. We constantly monitor the North American market for opportunities to expand our business by building our presence in existing regions and expanding our services and products into attractive, new regions.

 

See Note 15 of the notes to the consolidated financial statements included elsewhere in this Annual Report for financial information about our operating segments and about geographic areas.

 

 

 

“ü”  denotes a service or product currently offered by us in this area.

 

Completion and Production Services (87% of Revenue for the Year Ended December 31, 2010)

 

Through our completion and production services segment, we establish, maintain and enhance the flow of oil and gas throughout the life of a well. This segment is divided into intervention services, downhole and wellsite services and fluid handling.

Intervention Services

 

We use our intervention assets, which include coiled tubing units, pressure pumping equipment, nitrogen units, well service rigs and snubbing units to perform three major types of services for our customers:

 

 

The key intervention assets we use to perform intervention services are as follows:

 

Coiled Tubing Units and Nitrogen Units

 

We are one of the leading providers of coiled tubing services in North America. We operate a fleet of coiled tubing units, as well as nitrogen units. We use these assets to perform a variety of wellbore applications, including plug drilling, foam washing, acidizing, displacing, cementing, gravel packing, fishing and jetting. Coiled tubing is a key segment of the well service industry today, which allows operators to continue production during service operations without shutting in the well, thereby reducing the risk of formation damage. The growth in deep well and horizontal drilling has increased the market for coiled tubing. We provide coiled tubing services primarily in Oklahoma, Texas, Louisiana, Arkansas, Pennsylvania, Wyoming, North Dakota and Mexico.

 

Pressure Pumping Services

 

We operate fleets of pressure pumping equipment in the Barnett Shale of north Texas, in the Bakken Shale of North Dakota, in the Marcellus Shale of Pennsylvania and in the Eagle Ford shale of south Texas through which we provide stimulation and cementing services principally to oil and gas production companies.

 

Stimulation services primarily consist of hydraulic fracturing of hydrocarbon bearing formations which lack permeability to permit the natural flow. The fracturing process consists of pumping fluids into a well at pressures that are sufficient enough to fracture the formation. Materials such as sand and synthetic proppants are pumped into the fracture to prop open the fracture, permitting the hydrocarbons in the formation to flow into the wellbore and ultimately to the surface. Various pieces of specialized equipment are used in the process, including a blender, which is used to blend the proppant into the fluid, multiple high pressure pumping units capable of pumping significant volumes at high pressures, and real-time monitoring equipment where the progress of the process is controlled. Our fracturing units are capable of pumping slurries at pressures up to 10,000 pounds per square inch.

Cementing services consist of blending special cement with water and various solid and liquid additives to form a cement slurry that can be pumped into a well between the casing and the wellbore. Cementing services are principally performed in connection with primary cementing, where the casing used to line a wellbore after a well has been drilled is cemented into place. The purpose of primary cementing is to isolate fluids behind the casing between productive formations and non-productive formations that could damage the productivity of the well or damage the quality of freshwater acquifers, seal the casing from corrosive formation fluids and to provide structural support for the casing string.

 

Well Service Rigs

 

We own and operate a large fleet of well service rigs, of which a significant number were either recently constructed or have been recently rebuilt. We believe we have leading market positions in the Barnett Shale region of north Texas, the Haynesville Shale of east Texas and northern Louisiana and in some of the most active basins of the U.S. Rocky Mountain region. We also operate swabbing units, some of which are highly customized hydraulic units which we use to diagnose and remediate gas well production problems. We provide well service rig operations in Wyoming, Colorado, Utah, Montana, North Dakota, Pennsylvania, Louisiana, Oklahoma and Texas. These rigs are used to perform a variety of completion, workover and maintenance services, such as installations, completions, assisting with perforating, removing defective equipment and sidetracking wells.

 

Snubbing Units

 

We operate a fleet of snubbing units, several of which are rig assist units. Snubbing services use specialized hydraulic well service units that permit an operator to repair damaged casing, production tubing and downhole production equipment in high-pressure, “live-well” environments. A snubbing unit makes it possible to remove and replace downhole equipment while maintaining pressure in the well. Applications for snubbing units include “live-well” completions and workovers, underground blowout control, underbalanced completions, underbalanced drilling and the snubbing of tubing, casing or drillpipe into or out of the wellbore. Our snubbing units operate primarily in Texas, Wyoming and Pennsylvania.

 

Downhole and Wellsite Services

 

We provide an array of complementary downhole and wellsite services that we classify into four groups: wireline services; production optimization services; production testing services; and rental, fishing and pressure testing services.

 

Wireline Services.  We own and operate a fleet of wireline units in North America and provide both electric-line and slickline services. Wireline services are used to evaluate downhole well conditions, to initiate production from a formation by perforating a well’s casing, and to provide mechanical services such as setting equipment in the well, or fishing lost equipment out of a well. We provide wireline services in the western Canadian Sedimentary Basin, Wyoming, Colorado, North Dakota, Pennsylvania, Oklahoma and Texas.

 

With our fleet of wireline equipment we provide the following services:

 

Electric-Line Services:

 

 

 

Production Optimization Services.  Our production optimization services provide customers with technical solutions to stem declining production that results from liquid loading, reduced bottom-hole pressures or improper wellsite designs. We assist in identifying candidates, designing solutions, executing on-site and following up to ensure continued performance. We have developed proprietary technologies that allow us to enhance recovery for our customers and provide on-going service. We offer production optimization services to customers across the United States and in Canada. Specific services we provide include:

 

 

Production Testing Services.  Production testing is a service required by exploration and production companies to evaluate and clean out new and existing wells. We provide production testing services in Wyoming, Utah, Colorado, Texas and Mexico.

 

Production testing has the following primary applications:

 

 

 

Rental Equipment, Fishing and Pressure Testing Services.  Oil and gas producers and drilling contractors often need specialized tools, drillpipe, pressure testing equipment and other equipment and need qualified personnel to operate this equipment. In response to this need, we provide the following services and products:

 

 

Fluid Handling

 

Oil and gas operations use and produce significant quantities of fluids. We provide a variety of services to assist our customers to obtain, move, store and dispose of fluids that are involved in the development and production of their reservoirs. We provide fluid handling services in Texas, Oklahoma, Louisiana, Colorado, Wyoming, Arkansas, North Dakota and Montana.

 

 

Drilling Services (11% of Revenue for the Year Ended December 31, 2010)

 

Through our drilling services segment, we deliver services that initiate oil and gas production by providing land drilling and specialized rig logistics.

 

Contract Drilling

 

We provide contract drilling services to major oil companies and independent oil and gas producers in and around the Barnett Shale region of north Texas and the Permian Basin in west Texas. Contract drilling services are primarily provided under a standard day rate, and, to a lesser extent, footage or turnkey contracts. Drilling rigs vary in size and capability and may include specialized equipment. The majority of our drilling rig fleet is equipped with mechanical power systems and has depth ratings ranging from approximately 8,000 to 15,000 feet.

 

Drilling Logistics

 

Through our owned and operated fleet of specialized trucks, we provide drilling rig mobilization services primarily in Louisiana, Texas, North Dakota, Colorado and Arkansas. Our capabilities allow us to move the largest rigs in the United States. Our operations are strategically located in regions where approximately 50% of the land drilling rigs in the United States are located. We believe our highly skilled personnel position us as one of the leading rig moving companies in the industry.

 

Product Sales (2% of Revenue for the Year Ended December 31, 2010)

 

Through our product sales segment, we provide a variety of equipment used by oil and gas companies throughout the lifecycle of their wells. We assemble and refurbish equipment at our fabrication shop in north Texas. In addition, we operate an oilfield sales, service and rental business based in Singapore. This business sells new and reconditioned equipment used in the construction and upgrade of offshore drilling rigs; rents mud coolers, tubular handling equipment, BOPs and other service tools; and provides machining and repair services.

 

Sales and Marketing

 

Most sales and marketing activities are performed through our local operations in each geographical region. We believe our local field sales personnel have an excellent understanding of basin-specific issues and customer operating procedures and, therefore, can effectively target marketing activities. We supplement our field sales efforts with corporate teams that provide service specific technical support and executive level contacts.

 

Customers

 

Our customers consist of large multi-national and independent oil and gas producers, as well as smaller independent producers and the major land-based drilling contractors in North America. Our top ten customers accounted for approximately 52%, 49% and 45% of our revenue for the years ended December 31, 2010, 2009 and 2008, respectively. Our top two customers provided 12.2% and 10.7% of our total annual revenue in 2010, and the same two customers provided 9.9% and 9.7% of our total annual revenue in 2009. No customer represented more than 10% of our total annual revenue in 2008. We believe we have a broad customer base and wide geographic coverage of operations, which somewhat insulates us from regional or customer specific circumstances.

Our top ten customers for the year ended December 31, 2010 were as following (in alphabetical order):

 

 

Seasonality

 

Our completion and production services business generally experiences a decline in sales for our Canadian operations during the second quarter of each year due to seasonality, as weather conditions make oil and gas operations in this region difficult during this period. Our Canadian operations accounted for approximately 5% of total revenues from continuing operations for each of the years ended December 31, 2010, 2009 and 2008. To a lesser extent, seasonality can affect our operations in the Appalachian region and certain parts of the Rocky Mountain and Mid-continent regions, which may be subject to periods of reduced activity due to inclement weather conditions, road restrictions and environmental stipulations.

 

Operating Risk and Insurance

 

Our operations are subject to hazards inherent in the oil and gas industry, such as accidents, blowouts, explosions, fires and oil spills that can cause:

 

 

In addition, claims for loss of oil and gas production and damage to formations can occur in the well services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in our being named as a defendant in lawsuits asserting large claims.

 

Because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents which may result in spills, property damage and personal injury.

 

Despite our efforts to maintain high safety standards, we have suffered accidents in the past and anticipate that we will experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability and our relationships with customers, employees and regulatory agencies. Any significant increase in the frequency or severity of these incidents, or the general level of compensation awards, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations.

 

Although we maintain insurance coverage of types and amounts that we believe to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of the high premium costs. We do maintain commercial general liability, workers’ compensation, business auto, excess auto liability, commercial property, rig physical damage and contractor’s equipment, motor truck cargo, umbrella liability and excess liability, non-owned aircraft liability, directors and officers, employment practices liability, fiduciary and commercial crime insurance policies. However, any insurance obtained by us may not be adequate to cover any losses or liabilities and this insurance may not continue to be available or available on terms which are

acceptable to us. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on us. See Item 1A. “Risk Factors.”

 

Competition

 

The markets in which we operate are highly competitive. To be successful, a company must provide services and products that meet the specific needs of oil and gas exploration and production companies and drilling services contractors at competitive prices.

 

We provide our services and products across North America, and we compete against different companies in each service and product line we offer. Our competition includes many large and small oilfield service companies, including the largest integrated oilfield services companies.

 

Our major competitors for our completion and production services segment include Schlumberger Ltd., Baker Hughes Incorporated, Halliburton Company, Weatherford International Ltd., Key Energy Services, Inc., Basic Energy Services, Inc., Nabors Industries Ltd., RPC Inc. and a significant number of locally-oriented businesses. In our drilling services segment, our primary competitors include Nabors Industries Ltd., Patterson-UTI Energy, Inc., Unit Corporation, Helmerich & Payne and Precision Drilling Corporation. Our principal competitors in our product sales segment include National Oilwell Varco, Inc. and various smaller providers of equipment. We believe that the principal competitive factors in the market areas that we serve are quality of service and products, reputation for safety and technical proficiency, availability and price. While we must be competitive in our pricing, we believe our customers select our services and products based on local leadership and basin-expertise that our personnel use to deliver quality services and products.

 

Government Regulation

 

We operate under the jurisdiction of a number of regulatory bodies that regulate worker safety standards, the handling of hazardous materials, the transportation of explosives, the protection of the environment and driving standards of operation. Regulations concerning equipment certification create an ongoing need for regular maintenance which is incorporated into our daily operating procedures. The oil and gas industry is subject to environmental regulation pursuant to local, state and federal legislation.

 

Among the services we provide, we operate as a motor carrier and therefore are subject to regulation by the U.S. Department of Transportation and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety, financial reporting and certain mergers, consolidations and acquisitions. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period, onboard black box recorder devices or limits on vehicle weight and size.

 

Interstate motor carrier operations are subject to safety requirements prescribed by the U.S. Department of Transportation. To a large degree, intrastate motor carrier operations are subject to safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations. Department of Transportation regulations mandate drug testing of drivers.

 

From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.

 

Environmental Matters

 

Our operations are subject to numerous federal, state, local and foreign environmental laws and regulations governing the release and/or discharge of materials into the environment or otherwise relating to environmental

protection. Numerous governmental agencies issue regulations to implement and enforce these laws, for which compliance is often costly and difficult. The violation of these laws and regulations may result in the denial or revocation of permits, issuance of corrective action orders, assessment of administrative and civil penalties, and even criminal prosecution. We believe that we are in substantial compliance with applicable environmental laws and regulations. Further, we do not anticipate that compliance with existing environmental laws and regulations will have a material effect on our consolidated financial statements. However, it is possible that substantial costs for compliance or penalties for non-compliance may be incurred in the future. Moreover, it is possible that other developments, such as the adoption of stricter environmental laws, regulations, and enforcement policies, could result in additional costs or liabilities that we cannot currently quantify.

 

We generate wastes, including hazardous wastes, which are subject to the federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. The U.S. Environmental Protection Agency, or EPA, the Nuclear Regulatory Commission, and state agencies have limited the approved methods of disposal for some types of hazardous and nonhazardous wastes. Some wastes handled by us in our field service activities that currently are exempt from treatment as hazardous wastes may in the future be designated as “hazardous wastes” under RCRA or other applicable statutes. If this were to occur, we would become subject to more rigorous and costly operating and disposal requirements.

 

The federal Comprehensive Environmental Response, Compensation, and Liability Act, CERCLA or the “Superfund” law, and comparable state statutes impose liability, without regard to fault or legality of the original conduct, on classes of persons that are considered to have contributed to the release of a hazardous substance into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed of or arranged for the disposal of hazardous substances at offsite locations such as landfills. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We currently own, lease, or operate numerous properties and facilities that for many years have been used for industrial activities, including oil and gas production operations. Hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of hazardous substances, wastes, or hydrocarbons, was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes (including substances disposed of or released by prior owners or operators), remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills), or perform remedial plugging of disposal wells or pit closure operations to prevent future contamination. These laws and regulations may also expose us to liability for our acts that were in compliance with applicable laws at the time the acts were performed.

 

In the course of our operations, some of our equipment may be exposed to naturally occurring radiation associated with oil and gas deposits, and this exposure may result in the generation of wastes containing naturally occurring radioactive materials or “NORM.” NORM wastes exhibiting trace levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping, and work area affected by NORM may be subject to remediation or restoration requirements. Because many of the properties presently or previously owned, operated, or occupied by us have been used for oil and gas production operations for many years, it is possible that we may incur costs or liabilities associated with elevated levels of NORM.

 

The Federal Water Pollution Control Act, also known as the Clean Water Act, and applicable state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into jurisdictional waters is prohibited unless the discharge is permitted by the EPA or applicable state agencies. Many of our properties and operations require permits for discharges of wastewater and/or stormwater, and we have a system for securing and maintaining these permits. In addition, the Oil Pollution Act of 1990 imposes a variety of requirements on responsible parties related to the prevention of oil spills and

liability for damages, including natural resource damages, resulting from such spills in waters of the United States. A responsible party includes the owner or operator of a facility. The Federal Water Pollution Control Act and analogous state laws provide for administrative, civil and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges.

 

Our underground injection operations are subject to the federal Safe Drinking Water Act, as well as analogous state and local laws and regulations. Under Part C of the Safe Drinking Water Act, the EPA established the Underground Injection Control program, which established the minimum program requirements for state and local programs regulating underground injection activities. The Underground Injection Control program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. State regulations require us to obtain a permit from the applicable regulatory agencies to operate our underground injection wells. We believe that we have obtained the necessary permits from these agencies for our underground injection wells and that we are in substantial compliance with permit conditions and state rules. Nevertheless, these regulatory agencies have the general authority to suspend or modify one or more of these permits if continued operation of one of our underground injection wells is likely to result in pollution of freshwater, substantial violation of permit conditions or applicable rules, or leaks to the environment. Although we monitor the injection process of our wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third parties for property damages and personal injuries. In addition, our sales of residual crude oil collected as part of the saltwater injection process could impose liability on us in the event that the entity to which the oil was transferred fails to manage the residual crude oil in accordance with applicable environmental health and safety laws.

 

Some of our operations also result in emissions of regulated air pollutants. The federal Clean Air Act and analogous state laws require permits for facilities that have the potential to emit substances into the atmosphere that could adversely affect environmental quality. Failure to obtain a permit or to comply with permit requirements could result in the imposition of substantial administrative, civil and even criminal penalties.

 

The U.S. Congress is considering legislation to reduce emissions of greenhouse gases. President Obama has expressed support for legislation to restrict or regulate emissions of greenhouse gases. In addition, more than one-third of the states, either individually or through multi-state regional initiatives, have already begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Depending on the particular program, our customers could be required to purchase and surrender allowances for greenhouse gas emissions resulting from their operations. This requirement could increase our customers’ operational and compliance costs and result in reduced demand for their products, which would have a material adverse effect on the demand for our services and our business.

 

Also, as a result of the United States Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may regulate greenhouse gas emissions from mobile sources such as cars and trucks even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases, including carbon dioxide, fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources. In July 2008, the EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act, in response to the Supreme Court’s decision in Massachusetts. In the notice, the EPA evaluated the potential regulation of greenhouse gases under the Clean Air Act and other potential methods of regulating greenhouse gases. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any new federal, regional or state

restrictions on emissions of carbon dioxide or other greenhouse gases that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions on our customers. Such legislation could potentially make our customers products more expensive and thus reduce demand for them, which could have a material adverse effect on the demand for our services and our business.

 

Many foreign nations, including Canada, have agreed to limit emissions of greenhouse gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” In December 2002, Canada ratified the Kyoto Protocol. The Kyoto Protocol requires Canada to reduce its emissions of greenhouse gases to 6% below 1990 levels by 2012. The implementation of the Kyoto Protocol in Canada is expected to affect the operation of all industries in Canada, including the well service industry and its customers in the oil and natural gas industry. On April 26, 2007, the Government of Canada released its Action Plan to Reduce Greenhouse Gases and Air Pollution (the Action Plan) also known as ecoACTION, which includes the regulatory framework for air emissions. This Action Plan covers not only large industry, but regulates the fuel efficiency of vehicles and strengthens energy standards for a number of products. On March 10, 2008, the Government of Canada released details of the Action Plan’s regulatory framework, which includes a requirement that all covered industrial sectors, including upstream oil and gas facilities meeting certain threshold requirements, reduce their emissions from 2006 levels by 18% by 2010. The Government of Canada is in the process of developing regulations to implement the Action Plan. As precise details of the implementation of the Action Plan have not yet been finalized, the exact effect on our operations in Canada cannot be determined at this time. It is possible that already stringent air emissions regulations applicable to our operations and the operations of our customers in Canada will be replaced with even stricter requirements prior to 2012. These requirements could increase the cost of doing business for us and our customers, reduce the demand for the oil and gas our customers produce, and thus have an adverse effect on the demand for our products and services.

 

We are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

 

Employees

 

As of December 31, 2010, we had 6,572 employees. Of our total employees, 5,890 were in the United States, 301 were in Canada, 298 were in Mexico and 83 were in Singapore and other locations in Southeast Asia. We are a party to certain collective bargaining agreements in Mexico. Other than these agreements in Mexico, we are not a party to any collective bargaining agreements, and we consider our relations with our employees to be satisfactory.

 

Website Access to Our Periodic SEC Reports

 

We periodically file or furnish documents to the Securities and Exchange Commission (“SEC”), including our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports as required. These reports are linked to and available from our corporate website free of charge, as soon as reasonably practicable after we file such material, or furnish it to the SEC. Our primary internet address is: http://www.completeproduction.com. Our website also includes certain corporate governance documentation such as our business ethics policy. As permitted by the SEC rules, we may occasionally provide important disclosures to investors by posting them in the investor relations section of our website. However, the information contained on our website is not incorporated by reference into this Annual Report and should not be considered part of this report.

 

The information we file with the SEC may also be read and copied at the SEC’s Public Reference Room at 100F Street, N.E., Washington, D.C. 20549. In addition, the SEC maintains a website at: http://www.sec.gov which contains reports, proxy and other documents regarding our company which are filed electronically with the SEC.

Forward-looking Statements

 

Certain statements and information in this Annual Report on Form 10-K may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Act of 1995. These forward-looking statements are based on our current expectations, assumptions, estimates and projections about us and the oil and gas industry. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. These forward-looking statements involve risks and uncertainties that may be outside of our control and could cause actual results to differ materially from those in the forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to: market prices for oil and gas, the level of oil and gas drilling, economic and competitive conditions, capital expenditures, regulatory changes and other uncertainties. Other factors that could cause our actual results to differ from our projected results are described in: Item 1A. “Risk Factors.” See Item 1A. “Risk Factors” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview” for a discussion of trends and factors affecting us and our industry. Also see Item 8. “Financial Statements and Supplementary Data, Note 15 — Segment Reporting” for financial information about each of our business segments.

 

Although we believe that the forward-looking statements contained in this Annual Report are based upon reasonable assumptions, the forward-looking events and circumstances discussed in this document may not occur and actual results could differ materially from those anticipated or implied in the forward-looking statements.

 

Important factors that may affect our expectations, estimates or projections include:

 

 

In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this Annual Report may not occur, and therefore, our forward-looking statements speak only as of the date of this Annual Report. Unless otherwise required by law, we undertake no obligation and do not intend to update publicly any forward-looking statements, even if new information becomes available or other events occur in the future. These cautionary statements qualify all such forward-looking statements attributable to us or persons acting on our behalf.

 

 

An investment in our common stock involves a degree of risk. You should carefully consider the following risk factors, together with the other information contained in this Annual Report and other public filings with the SEC, before deciding to invest in our common stock. Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business. If any of these risks develop into actual events, our business, financial condition, results of operations or cash flows could be materially adversely affected, and you could lose all or part of your investment.

Risks Related to Our Business and Our Industry

 

Our business depends on the oil and gas industry and particularly on the level of activity for North American oil and gas. Our markets may be adversely affected by industry conditions that are beyond our control.

 

We depend on our customers’ willingness to make operating and capital expenditures to explore for, develop and produce oil and gas in North America. If these expenditures decline, our business may suffer. Our customers’ willingness to explore, develop and produce depends largely upon prevailing industry conditions that are influenced by numerous factors over which management has no control, such as:

 

 

The level of activity in the North American oil and gas exploration and production industry is volatile. Expected trends in oil and gas production activities may not continue and demand for the services provided by us may not reflect the level of activity in the industry. Oil and natural gas prices and rotary rig counts declined sharply in the fourth quarter of 2008 and remained relatively low throughout 2009 compared to the levels in mid-2008. Although activity began to recover at the end of 2009 and improved throughout 2010, an unexpected material decline in oil and gas prices or North American activity levels could occur again and have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, a decrease in the development rate of oil and gas reserves in our market areas may also have an adverse impact on our business, even in an environment of stronger oil and gas prices.

 

Because the oil and gas industry is cyclical, our operating results may fluctuate.

 

Oil and gas prices are volatile. WTI oil commodity prices reached historic highs in 2008 then declined substantially by year end and remained at depressed levels through much of 2009. Oil prices rebounded in 2010, reaching a high of $91.48 towards the end of the year. Henry Hub natural gas prices averaged $8.89 per mcf in 2008, but exceeded $12.00 per mcf in June of 2008, before falling below $6.00 per mcf at the end of 2008. Natural gas prices did not exceed $6.11 per mcf in 2009 and averaged $3.94 per mcf during that year. Prices for natural gas rebounded somewhat in 2010, although the average was only $4.38 per mcf. Declines in oil and gas prices result in a decrease in the expenditure levels of oil and gas companies and drilling contractors which in turn adversely affects us. We have experienced in the past, and may experience in the future, significant fluctuations in operating results as a result of the reactions of our customers to actual and anticipated changes in oil and gas prices. We reported income from continuing operations in 2010 of $84.2 million, a loss from continuing operations of $181.7 million in 2009 which included a goodwill impairment loss of $97.6 million and fixed asset and other intangible impairment losses totaling $38.6 million, and a loss from continuing operations of $84.7 million in 2008 which included a goodwill impairment loss of $272.0 million.

With the exception of our pressure pumping operations, substantially all of the service and rental revenue we earn is based upon a charge for a relatively short period of time (an hour, a day, a week) for the actual period of time the service or rental is provided to our customer. By contracting services on a short-term basis, we are exposed to the risks of a rapid reduction in market price and utilization and volatility in our revenues. Product sales are recorded when the actual sale occurs, title or ownership passes to the customer and the product is shipped or delivered to the customer.

 

Our business depends upon our ability to obtain key materials and specialized equipment from suppliers. Shortages of these materials or equipment or an increase in the cost of these items which are used in our operations or an increase in the cost to manufacture this equipment could adversely affect our operations in the future.

 

We do not have long-term contracts with the third party suppliers of many of the products that we use in large volumes in our operations, including many parts we use in the manufacture of our fracturing units and pumps, coiled tubing pipe, some of the chemicals and sand we use in fracturing fluids and the fuel we use in our equipment and vehicles. During periods in which certain of our services are in high demand, the availability of the key products used in our industry decreases and the price of such products increases. Our industry has faced sporadic proppant shortages associated with pressure pumping operations requiring work stoppages which adversely impacted the operating results of several competitors and, in the fourth quarter of 2010, we experienced logistical constraints in North Dakota adversely impacting our results. In addition, rising diesel fuel prices have had a significant impact on our expenses, and adversely impacted our earnings in some periods. We are dependent on a small number of suppliers for certain parts that are in high demand in our industry. Our reliance on a small number of suppliers could increase the difficulty of obtaining such parts in the event of a shortage of those parts in our industry. Should our current suppliers be unable to provide the necessary raw materials (proppant, chemicals, cement or explosives) or finished products (such as workover rigs or fluid-handling equipment) or otherwise fail to deliver the products timely and in the quantities required, any resulting delays in the provision of services could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

We rely on certain related parties (e.g., companies majority-owned by certain of our directors or current or former officers or employees) for the purchase and manufacture of a significant amount of the equipment, including pressure pumping units, used in our operations. Concentrating our equipment supply needs on one or more related parties could adversely impact our results of operations if any of the related parties experience shortages or other interruptions to their businesses. See Note 19, “Related party transactions” in our notes to consolidated financial statements included elsewhere in this Annual Report.

 

There is potential for excess capacity in our industry.

 

Because oil and gas prices and drilling activity are at high levels and service companies are seeing increasing demand for services and attractive returns on investments, oilfield service companies are ordering new equipment to expand their services. A growing supply of equipment may result in an increasingly competitive environment for oilfield service companies, which may lead to lower prices and utilization for our services which would adversely affect our business.

 

We are subject to federal, state and local laws and regulations regarding issues of health, safety and protection of the environment, including climate change. Under these laws and regulations, we may become liable for penalties, damages or costs of remediation or other corrective measures. Any changes in laws or government regulations could increase our costs of doing business.

 

Our operations are subject to stringent federal, state and local laws and regulations relating to, among other things, protection of natural resources, wetlands, endangered species, the environment, health and safety, waste management, waste disposal, and transportation of waste and other materials. Such laws and regulations include the Resource Recovery and Conservation Act, the Comprehensive Environmental Response, Compensation, and Liability Act, the Clean Water Act, the Safe Drinking Water Act and analogous state laws. Our operations pose risks of environmental liability, including leakage from our operations to surface or subsurface soils, surface water or groundwater. Some environmental laws and regulations may impose strict, joint and several liability. Therefore in

some situations we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, third parties. Actions arising under these laws and regulations could result in the shutdown of our operations, fines and penalties, expenditures for remediation or other corrective measures, and claims for liability for property damage, exposure to hazardous materials or hazardous waste, or personal injuries. Sanctions for noncompliance with applicable environmental laws and regulations also may include the assessment of administrative, civil or criminal penalties, revocation of permits, temporary or permanent cessation of operations in a particular location and issuance of corrective action orders. Such claims or sanctions and related costs could cause us to incur substantial costs or losses and could have a material adverse effect on our business, financial condition and results of operations. An increase in regulatory requirements on oil and gas exploration and completion activities could significantly delay or interrupt our operations.

 

If we do not perform in accordance with government, industry or our own safety standards, we could lose business from certain customers, many of whom have an increased focus on safety issues as a result of recent incidents, such as the Macondo Well event in the Gulf of Mexico, and governmental initiatives on safety and environmental issues related to E&P activities.

 

On June 9, 2009, companion bills entitled the Fracturing Responsibility and Awareness of Chemicals (FRAC) Act of 2009 were introduced in the United States Senate (S. 1215) and House of Representatives (H.R. 2766). Currently, unless the fracturing fluid used in the hydraulic fracturing process contains diesel, hydraulic fracturing operations are exempt from regulation under the federal Safe Drinking Water Act. The FRAC Act would remove the permit exemption and require the United States Environmental Protection Agency (the “EPA”), to promulgate regulations on hydraulic fracturing. Further, states with delegated authority to implement the Safe Drinking Water Act would have to modify their programs to remain consistent with any new federal regulations. The FRAC Act would also require persons conducting hydraulic fracturing, such as us, to disclose the chemical constituents of their fracturing fluids to a regulatory agency. This Act would make the information public via the internet, which could make it easier for third parties opposed to the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect the environment, including groundwater, soil or surface water. If this or similar legislation becomes law, the legislation could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs, making it more difficult to perform hydraulic fracturing and increasing our costs of compliance and doing business. Currently, neither S. 1215 nor H.R. 2766 is scheduled for consideration by the Senate or the House, and it is not clear whether the 111th Congress will act on either bill. Compliance or the consequences of any failure to comply by us could have a material adverse effect on our business, financial condition and operational results.

 

Another bill has been introduced in Congress in 2010 that would require disclosure of chemicals used in hydraulic fracturing operations. The Clean Energy Jobs and Oil Company Accountability Act of 2010 (S. 3663) remains on the Senate Legislative Calendar under General Orders, and would amend the Emergency Planning and Community Right-to-Know Act by requiring any person using hydraulic fracturing for an oil or natural gas well to submit to the state, or make publicly available, the list of chemicals used in each hydraulic fracturing process (identified by well location and number), including the chemical constituents of mixtures, Chemical Abstracts Service registry numbers, and material safety data sheets. S. 3663 would not, however, require public disclosure of “proprietary chemical formulas.”

 

Several states have considered, or are considering, legislation or regulations similar to the federal legislation described above or are taking action to restrict hydraulic fracturing in certain jurisdictions. In June 2010, the Wyoming Oil and Gas Conservation Commission passed a rule requiring disclosure of hydraulic fracturing fluid content. In October 2010, the Governor of Pennsylvania issued a moratorium on new natural gas development on state forest lands. In November 2010, the Pennsylvania Environmental Quality Board proposed regulations that would require reporting of the chemicals used in fracturing fluids. At this time, it is not possible to estimate the potential impact on our business of these state actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing.

 

On February 18, 2010, the Energy and Commerce Committee of the United States House of Representatives requested that we and other companies provide information concerning the chemicals used in hydraulic fracturing. Subsequently, we received follow-up requests from the Committee for additional information and documentation.

We have worked with the Committee’s staff to provide information concerning such chemicals while at the same time acting to protect our proprietary interests and to fulfill our contractually imposed confidentiality obligations to certain customers.

 

Also, the EPA is reviewing the scope of its existing regulatory authority and evaluating whether and how it can regulate hydraulic fracturing. The EPA recently requested additional information from us and several other service companies concerning hydraulic fracturing. In addition, in March 2010, the EPA announced its intention to conduct a comprehensive research study, ordered by Congress, on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. As part of this study, the EPA is conducting public hearings across the country. Even if the FRAC Act or similar legislation is not adopted, the EPA study, depending on its results, could spur further initiatives to regulate hydraulic fracturing under the Safe Drinking Water Act or otherwise. The EPA has announced that the energy extraction sector is one of the sectors designated for increased enforcement over the next three to five years.

 

Additionally, the EPA’s Tier IV regulations apply to certain off-road diesel engines that are used by us to power equipment in the field. Under these regulations, we are limited in the number of non-compliant off-road diesel engines we can purchase. Until Tier IV-compliant engines that meet our needs are available, these regulations could limit our ability to acquire a sufficient number of diesel engines to expand our fleet and to replace existing engines as they are taken out of service.

 

Laws protecting the environment generally have become more stringent over time and we expect them to continue to do so, which could lead to material increases in our costs for future environmental compliance and remediation. The effect of environmental laws and regulations on our business is discussed in greater detail in Item 1, “Business — Environmental Matters” of this Annual Report.

 

We may be exposed to certain regulatory and financial risks related to climate change.

 

Current and future regulatory initiatives directed at climate change may increase our operating costs and may, in the future, reduce the demand for hydrocarbons that our customers produce. In 2009 and 2010, the United States Congress considered a variety of legislation on climate change. These bills or new legislation may be considered by the current Congress. In substance, most legislative proposals contain a “cap and trade” approach to greenhouse gas regulation. Under such an approach, companies would be required to hold sufficient emission allowances to cover their greenhouse gas emissions. Over time, the total number of allowances would be reduced or expire, thereby relying on market-based incentives to allocate investment in emission reductions across the economy. As the number of available allowances declines, the cost would presumably increase. In addition to the prospect of federal legislation, several states have adopted or are in the process of adopting greenhouse gas reporting or cap-and-trade programs. Therefore, while the outcome of the federal and state legislative processes is currently uncertain, if such an approach were adopted (either by domestic legislation, international treaty obligation or domestic regulation), our operating costs could increase as could the operating costs of our customers, as they buy additional allowances or embark on emission reduction programs. Such legislation could have both a direct and indirect effect on our business.

 

Even without further federal legislation, the EPA has begun to regulate greenhouse gas emissions. In December 2009, the EPA released an Endangerment and Cause or Contribute Findings for Greenhouse Gases, which became effective in January 2010. This regulatory finding sets the foundation for future EPA greenhouse gas regulation under the Clean Air Act. The EPA also promulgated a new greenhouse gas reporting rule, which became effective in December 2009, and which requires facilities that emit more than 25,000 tons per year of carbon dioxide-equivalent emissions to prepare and file certain emission reports. On May 12, 2010, the EPA issued a new “tailoring” rule, which proposed and imposes additional permitting requirements on certain stationary sources emitting over 75,000 tons per year of carbon dioxide equivalent emissions. The EPA is considering additional rulemaking to apply these requirements to broader classes of emission sources by 2012, which may apply to some of our facilities. Finally, on November 8, 2010, the EPA adopted rules expanding the industries subject to greenhouse gas reporting to include certain petroleum and natural gas facilities. These rules require data collection beginning in 2011 and reporting beginning in 2012. Many of our customer’s facilities are subject to these rules. As a result of these regulatory initiatives, our operating costs may increase in compliance with these programs, although we are

not situated differently in this respect from our competitors in the industry. Our customer’s operating costs may also increase, thereby having a potential indirect effect on our business.

 

Future growth in our business could strain our resources, causing us to lose customers and increase our operating expenses.

 

The expansion of our business through organic growth can impact us. We have experienced short-term logistical constraints in positioning assets during 2010, and expect that we might incur such constraints in the future. In addition, as we expand into new geographic regions and service lines and add new equipment, we could incur delays and will incur costs to attract, train and retain staff to crew the equipment as well as costs to adequately train these new employees. Our inability to manage our growth effectively or to maintain the quality of our services, products and personnel could have a material adverse effect on our business, financial condition or results of operations.

 

Changes in trucking regulations may increase our costs and negatively impact our results of operations.

 

We operate trucks and other heavy equipment associated with many of our service offerings. We therefore are subject to regulation as a motor carrier by the United States Department of Transportation and by various state agencies, whose regulations include certain permit requirements of state highway and safety authorities. These regulatory authorities exercise broad powers over our trucking operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing and specifications and insurance requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations by requiring changes in fuel emissions limits, the hours of service regulations that govern the amount of time a driver may drive or work in any specific period, limits on vehicle weight and size and other matters, including safety requirements. On May 21, 2010 the Obama Administration announced proposed regulations that would set mileage requirements and emissions limits for medium- and heavy-duty trucks. A final rule is expected by July 30, 2011 effective for the 2014 model year. Associated with this ruling, we may experience an increase in costs related to truck purchases or maintenance. Proposals to increase federal, state, or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. We cannot predict whether, or in what form, any legislative or regulatory changes applicable to our trucking operations will be enacted.

 

Our indebtedness could restrict our operations and make us more vulnerable to adverse economic conditions.

 

As of December 31, 2010, our long-term debt, including current maturities, was $650 million. Our level of indebtedness may adversely affect operations and limit our growth, and we may have difficulty making debt service payments on our indebtedness as such payments become due. Our level of indebtedness may affect our operations in several ways, including the following:

 

 

We may not be able to provide services that meet the specific needs of oil and gas exploration and production companies at competitive prices.

 

The markets in which we operate are highly competitive and have relatively few barriers to entry. The principal competitive factors in our markets are product and service quality and availability, responsiveness, experience, technology, equipment quality, reputation for safety and price. We compete with large national and multi-national companies that have longer operating histories, greater financial, technical and other resources and greater name recognition than we do. Several of our competitors provide a broader array of services and have a stronger presence

in more geographic markets. In addition, we compete with several smaller companies capable of competing effectively on a regional or local basis. Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. Some contracts are awarded on a bid basis, which further increases competition based on price. As a result of competition, we may lose market share or be unable to maintain or increase prices for our present services or to participate in additional business opportunities, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, competition among oilfield service and equipment providers is affected by each provider’s reputation for safety and quality. Although we believe that our reputation for safety and quality service is good, we cannot assure that we will be able to maintain our competitive position.

 

Our executive officers and certain key personnel are critical to our business and these officers and key personnel may not remain with us in the future.

 

Our future success depends upon the continued service of our executive officers and other key personnel. If we lose the services of one or more of our executive officers or key employees, our business, operating results and financial condition could be harmed.

 

Our inability to control the inherent risks of acquiring and integrating businesses could adversely affect our operations.

 

Acquisitions have been, and our management believes acquisitions will continue to be, a key element of our business strategy. We may not be able to identify and acquire acceptable acquisition candidates on favorable terms in the future. We may be required to incur substantial indebtedness to finance future acquisitions and also may issue equity securities in connection with such acquisitions. We may not be able to secure additional capital to fund acquisitions. If we are able to obtain financing, such additional debt service requirements may impose a significant burden on our results of operations and financial condition. The issuance of additional equity securities could result in significant dilution to stockholders. Acquisitions may not perform as expected when the acquisition was made and may be dilutive to our overall operating results. Additional risks we will face include:

 

 

If we fail to manage these risks successfully, our business could be harmed.

 

Our customer base is concentrated within the oil and gas production industry and loss of a significant customer could cause our revenue to decline substantially.

 

Our top five customers accounted for approximately 39%, 33% and 28% of our revenue for the years ended December 31, 2010, 2009 and 2008, respectively. Our top ten customers represented approximately 52%, 49% and 45% of our revenue for the years then ended. Our top two customers provided 12.2% and 10.7% of our total annual revenue in 2010, and these same two customers provided 9.9% and 9.7% of our total annual revenue in 2009. It is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers in the future. If a major customer decided not to continue to use our services, revenue would decline and our operating results and financial condition could be harmed. For a list of our top ten customers, see Item 1. “Business — Customers.”

We may be unable to attract and retain a sufficient number of skilled and qualified workers.

 

The delivery of our services and products requires personnel with specialized skills and experience who can perform physically demanding work. As a result of the volatility of the oilfield service industry and the demanding nature of the work, workers may choose to pursue employment in fields that offer a more desirable work environment. Our ability to be productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled workers is high, and the supply is limited, particularly in the U.S. Rocky Mountain region, which is one of our key regions. In addition, although our employees in the United States are not covered by a collective bargaining agreement, some of our employees have in the past been targeted by labor unions in an effort to organize such employees. A significant increase in the wages paid by competing employers or the unionization of groups of our employees could result in a reduction of our skilled labor force, increases in the wage rates that we must pay, or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.

 

Our operations are subject to hazards inherent in the oil and gas industry.

 

Risks inherent to our industry, such as equipment defects, vehicle accidents, explosions and uncontrollable flows of gas or well fluids, can cause personal injury, loss of life, suspension of operations, damage to formations, damage to facilities, business interruption and damage to or destruction of property, equipment and the environment. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and gas production, pollution and other environmental damages. The frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators. In particular, our customers may elect not to purchase our services if they view our safety record as unacceptable, which could cause us to lose customers and substantial revenues. In addition, these risks may be greater for us because we sometimes acquire companies that have not allocated significant resources and management focus to safety and have a poor safety record.

 

Our operations have experienced fatalities. Many of the claims filed against us arise from vehicle-related accidents that have in certain specific instances resulted in the loss of life or serious bodily injury. Our safety procedures may not always prevent such damages. Our insurance coverage may be inadequate to cover our liabilities. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable and commercially justifiable and insurance may not continue to be available on terms as favorable as our current arrangements. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations and cash flows. Although our senior management is committed to improving our overall safety record, they may not be successful in doing so.

 

If we are not able to implement commercially competitive services and access commercially competitive products in a timely manner in response to changes in technology, our business and revenue could be materially and adversely affected.

 

The market for our services and products is characterized by continual technological developments to provide better and more reliable performance and services. If we are not able to implement commercially competitive services and access commercially competitive products in a timely manner in response to changes in technology, our business and revenue could be materially and adversely affected. Likewise, if our proprietary technologies, equipment and facilities, or work processes become obsolete, we may no longer be competitive, and our business and revenue could be materially and adversely affected.

 

We are self-insured for certain health care benefits for our employees.

 

We are self-insured for claims arising from healthcare benefits provided to certain of our employees in the United States. Under this self-insurance program, we use the services of an insurance company, the former provider of full insurance coverage prior to the inception of the program in 2007, to administer the program on a fee-per-participant

basis, and we have purchased a stop-loss policy with this provider to insure for individual claims which exceed a designated ceiling. Pursuant to this program, we accrue expense based upon expected claims, and make periodic claim payments to the administrator, who then facilitates claim payments to the medical care providers. With the passage of time and as our business expands and more employees enroll in our healthcare benefit plan, we may choose or be required to maintain higher self-insured retention levels. There is a risk that our actual claims incurred may exceed the projected claims, and we may incur more expense than expected for health insurance coverage. There is also a risk that we may not adequately accrue for claims that are incurred but not reported. Either of these events could have a material adverse effect on our financial position, results of operations or cash flows.

 

If we become subject to product liability claims, it could be time-consuming and costly to defend.

 

Since our customers use our products, or third party products that we sell or rent, errors, defects or other performance problems could result in financial or other damages to us. Our customers could seek damages from us for losses associated with these errors, defects or other performance problems. If successful, these claims could have a material adverse effect on our business, operating results or financial condition. Our existing product liability insurance may not be enough to cover the full amount of any loss we might suffer. A product liability claim brought against us, even if unsuccessful, could be time-consuming and costly to defend and could harm our reputation.

 

Impairment of Long-term Assets

 

We evaluate our long-term assets including property, plant and equipment, identifiable intangible assets and goodwill in accordance with generally accepted accounting principles in the U.S. In performing this assessment, we project future cash flows on a discounted basis for goodwill, and on an undiscounted basis for other long-term assets, and compare these cash flows to the carrying amount of the related net assets. The cash flow projections are based on our current operating plan, estimates and judgmental assessments. We perform this assessment of potential impairment at least annually, but also whenever facts and circumstances indicate that the carrying value of the net assets may not be recoverable due to various external or internal factors, termed a “triggering event.” We have recorded goodwill impairment charges of $97.6 million and $272.0 million for the years ended December 31, 2009 and 2008, respectively, with no goodwill impairment charges for the year ended December 31, 2010. In 2009, management performed additional analysis and determined that further write-downs were necessary, which resulted in a fixed asset impairment in our drilling services segment of $36.2 million recorded in September 2009, and an intangible asset impairment in our completion and production services segment totaling $2.5 million recorded in December 2009. Based on our annual impairment test results in 2010, we did not record any significant impairment losses for the year ended December 31, 2010. While we did not incur impairment charges in 2010, if we determine that our estimates of future cash flows were inaccurate or our actual results for 2011 are materially different than expected, we could record additional impairment charges at interim periods during 2011 or in future years, which could have a material adverse effect on our financial position and results of operations.

 

Many of our customers’ activity levels, spending for our products and services, and payment patterns may be impacted by deterioration in the credit markets.

 

Many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. In late 2008 and throughout 2009, there was a significant decline in the credit markets and the availability of credit. Additionally, many of our customers’ equity values substantially declined. The combination of a reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction in our customers’ spending for our products and services. A prolonged reduction in spending could have a material adverse effect on our operations.

 

In addition, while historically our customer base has not presented significant credit risks, the same factors that may lead to a reduction in our customers’ spending also may increase our exposure to the risks of nonpayment and nonperformance by our customers. A significant reduction in our customers’ liquidity may result in a decrease in their ability to pay or otherwise perform on their obligations to us. Any increase in the nonpayment of and nonperformance by our counterparties, either as a result of recent changes in financial and economic conditions or otherwise, could have an adverse impact on our operating results and could adversely affect our liquidity.

We participate in a capital intensive business. We may not be able to finance future growth of our operations or future acquisitions.

 

Historically, we have funded the growth of our operations and our acquisitions from bank debt, private placement of shares, our initial public offering in April 2006, a private placement of debt in December 2006, as well as cash generated by our business. In the future, we may not be able to continue to obtain sufficient bank debt at competitive rates or complete equity and other debt financings. If we do not generate sufficient cash from our business to fund operations, our growth could be limited unless we are able to obtain additional capital through equity or debt financings. Our inability to grow as planned may reduce our chances of maintaining and improving profitability.

 

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud.

 

Effective internal controls are necessary for us to provide reliable financial reports and effectively prevent fraud. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. Our efforts to maintain internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future, including compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective controls or to make effective improvements to our internal controls could harm our operating results.

 

In 2010, our management approved a plan to implement new accounting software which will replace our existing accounting systems at several of our operating divisions in a phased approach. Two divisions converted during the fourth quarter of 2010 and two divisions will convert during 2011. In addition, we implemented a new chart of accounts which is being adopted as these divisions convert to the new software. Although we believe the new software, once implemented, will enhance our internal control over financial reporting and we believe that we have taken the necessary steps to maintain appropriate internal control over financial reporting during this period of system change, we will continuously monitor controls through and around the system to provide reasonable assurance that controls are effective during and after each step of this implementation process.

 

Conservation measures and technological advances could reduce demand for oil and gas.

 

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and gas. Management cannot predict the impact of the changing demand for oil and gas services and products, and any major changes may have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

Fluctuations in currency exchange rates in Canada could adversely affect our business.

 

We have operations in Canada. As a result, fluctuations in currency exchange rates in Canada could materially and adversely affect our business. For each of the years ended December 31, 2010, 2009 and 2008, our Canadian operations represented approximately 5% of our revenue from continuing operations. Our Canadian operations recorded income from continuing operations before taxes of $1.3 million for the year ended December 31, 2010 and recorded losses of $11.1 million and $26.7 million for the years ended December 31, 2009 and 2008, respectively. The loss in 2008 primarily resulted from a goodwill impairment charge.

 

Our operations in Mexico are subject to specific risks, including dependence on Petróleos Mexicanos (“PEMEX”) as the primary customer, exposure to fluctuation in the Mexican peso and workforce unionization.

 

The majority of our business in Mexico is performed for PEMEX pursuant to multi-year contracts. These contracts are generally two years in duration, specify an authorized spending amount and are subject to competitive bid for renewal. Any failure by us to renew or extend our existing contracts, or win award of contracts that replace expiring contracts, could have an adverse effect on our financial condition, results of operations and cash flows. Additionally, PEMEX is experiencing budget limitations that may affect its ability to make timely payments

to us under our existing contracts. Recent regulatory and financial uncertainty regarding PEMEX’s drilling programs and development budget could adversely impact PEMEX’s ability to fulfill certain of its payment obligations under these contracts in a timely manner. A failure of PEMEX to make required payments to us would adversely affect our Mexico-based financial performance.

 

The PEMEX contracts provide that 70% to 80% of the value of our billings under the contracts is charged to PEMEX in U.S. dollars with the remainder billed in Mexican pesos. The portion billed in U.S. dollars to PEMEX is converted to pesos on the date of payment. Invoices are paid approximately 45 days after the invoice date. As such, we are exposed to fluctuations in the value of the peso. A material decrease in the value of the Mexican peso relative to the U.S. dollar could negatively impact our revenues, cash flows and net income.

 

Our operations in Mexico are party to a collective labor contract most recently modified on and effective as of October 2008 between Servicios Petrotec S.A. DE C.V., one of our subsidiaries, and Unión Sindical de Trabajadores de la Industria Metálica y Similares, the metal and similar industry workers labor union. We have not experienced work stoppages in the past but cannot guarantee that we will not experience work stoppages in the future. A prolonged work stoppage could negatively impact our revenues, cash flows and net income.

 

Mexico has experienced a period of increasing criminal violence and such activities could affect our Mexico-based operations and financial performance.

 

Recently, Mexico has experienced a period of increasing criminal violence, primarily due to the activities of drug cartels and related organized crime. Although the Mexican government has implemented various security measures and strengthened its military and police forces, drug-related crime continues to exist in Mexico and has impacted our ability to safely conduct business in certain areas of the country. Our inability to conduct business in certain areas of Mexico, and the safety risks in the areas of Mexico where we do conduct business, could have a negative impact on our Mexico-based financial performance.

 

We could be adversely affected by violations of the U.S. Foreign Corrupt Practices Act and similar worldwide anti-bribery laws.

 

We are subject to the U.S. Foreign Corrupt Practices Act (the “FCPA”), which generally prohibits companies and their intermediaries from making payments to non-U.S. government officials for the purpose of obtaining or retaining business or securing any other improper advantage. We are also subject to anti-bribery laws in the jurisdictions in which we operate. Although we have policies and procedures designed to ensure that we, our employees and our agents comply with the FCPA and other anti-bribery laws, there is no assurance that such policies or procedures will protect us against liability under the FCPA or other laws for actions taken by our agents, employees and intermediaries with respect to our business or any businesses that we acquire. We do business in countries in which FCPA violations have recently been enforced. Failure to comply with the FCPA, other anti-bribery laws or other laws governing the conduct of business with foreign government entities, including local laws, could disrupt our business and lead to severe criminal and civil penalties, including imprisonment, criminal and civil fines, loss of our export licenses and suspension of our ability to do business with the federal government. Other remedial measures could include further changes or enhancements to our procedures, policies, and controls and potential personnel changes and/or disciplinary actions, any of which could have a material adverse affect on our business, financial condition, results of operations and liquidity. We could also be adversely affected by any allegation that we violated such laws.

 

Severe weather conditions may affect our operations.

 

Our business may be materially affected by severe weather conditions in areas where we operate. This may entail the evacuation of personnel and stoppage of services which could adversely affect our financial condition, results of operations and cash flows. Hurricanes and the threat of hurricanes during this period will often result in the shut-down of oil and gas operations in the Gulf of Mexico as well as land operations within the hurricane path. During a shut-down period, we are unable to access wellsites and our services are also shut down. This situation can therefore create unpredictability in activity and utilization rates, which can have a material adverse impact on our business, financial conditions, results of operations and cash flows. In addition, the extreme winter weather

conditions in the first quarter of 2011 have adversely affected our operations in North Dakota, Oklahoma and North Texas.

 

Our operations are directly affected by seasonal differences in weather in Canada. The level of activity in the Canadian oilfield services industry declines significantly in the second calendar quarter, when the ground thaws and many secondary roads are temporarily rendered incapable of supporting the weight of heavy equipment. The duration of this period is referred to as “spring breakup” and has a direct impact on our activity levels in Canada. The timing and duration of “spring breakup” depend on weather patterns but generally “spring breakup” occurs in April and May. Additionally, if an unseasonably warm winter prevents sufficient freezing, we may not be able to access wellsites and our operating results and financial condition may, therefore, be adversely affected. The demand for our services may also be affected by the severity of the Canadian winters. In addition, during excessively rainy periods, equipment moves may be delayed, thereby adversely affecting operating results. The volatility in weather and temperature in the Canadian oilfield can therefore create unpredictability in activity and utilization rates. As a result, full-year results are not likely to be a direct multiple of any particular quarter or combination of quarters.

 

When rig counts are low, our rig relocation customers may not have a need for our services.

 

Many of the major U.S. onshore drilling services contractors have capabilities to move their own drilling rigs and related oilfield equipment and to erect rigs. When regional rig counts are high, drilling services contractors exceed their own capabilities and contract for additional oilfield equipment hauling and rig erection capacity. Our rig relocation business activity is highly correlated to the rig count; however, the correlation varies over the rig count range. As rig count drops, some drilling services contractors reach a point where all of their oilfield equipment hauling and rig erection needs can be met by their own fleets. If one or more of our rig relocation customers reaches this “tipping point,” our revenues attributable to rig relocation will decline much faster than the corresponding overall decline in the rig count. This non-linear relationship between our rig relocation business activity and the rig count in the areas in which we have rig relocation operations can significantly increase our earnings volatility with respect to rig relocation.

 

Covenants in our debt agreements restrict our business in many ways.

 

The indenture governing our senior notes contains various covenants that limit our ability and/or our restricted subsidiaries’ ability to, among other things:

 

 

In addition, our amended revolving credit facility contains restrictive covenants and requires us to maintain a fixed charge coverage ratio based on borrowing base limitations and satisfy other financial condition tests. Our ability to meet those financial requirements can be affected by adverse industry conditions and other events beyond our control, and we cannot assure you that we will meet those requirements. A breach of any of these covenants could result in a default under our amended revolving credit facility and/or the notes. Upon the occurrence of an event of default under our amended revolving credit facility, the lenders could elect to declare all amounts outstanding to be immediately due and payable and terminate all commitments to extend further credit. We had no

borrowings outstanding under our amended credit facility at December 31, 2010. However, if we borrowed under this facility and if we were unable to repay those amounts, the lenders under our amended revolving credit facility could proceed against the collateral granted to them to secure that indebtedness. We have pledged a significant portion of our assets as collateral under our amended revolving credit facility. If the lenders under our amended revolving credit facility accelerate the repayment of borrowings, we cannot assure you that we will have sufficient assets to repay indebtedness under our amended revolving credit facility and our other indebtedness, including our senior notes.

 

Borrowings under our amended revolving credit facility would bear interest at variable rates and could expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income would decrease.

 

 

None.

 

 

As of December 31, 2010, we owned 57 offices, facilities and yards, of which 15 were in Texas, 18 were in Oklahoma, one was in Arkansas, three were in North Dakota, one was in Montana, one was in Wyoming, 10 were in Colorado, one was in Louisiana, three were in Pennsylvania, two were in Alberta, Canada, one was in Poza Rica, Mexico and one was in Singapore.

 

As of December 31, 2010, we owned or operated 64 saltwater disposal wells, of which 29 were in Texas, 32 were in Oklahoma, two were in Colorado, and one was in Arkansas. In addition, we owned one and leased two drilling mud disposal facilities in Oklahoma and one produced water evaporation facility in Wyoming.

 

In addition, as of December 31, 2010, we leased 209 offices, facilities and yards, of which 74 were in Texas, 25 were in Oklahoma, 18 were in Wyoming, 25 were in Colorado, 22 were in Pennsylvania, three were in North Dakota, 10 were in Louisiana, three were in Arkansas, two were in Utah, 14 were in Alberta, Canada, one was in British Columbia, Canada, six were in Mexico and six were in Singapore.

 

We lease our corporate headquarters in Houston, Texas, as well as administrative offices in Gainesville, Texas; Enid, Oklahoma; Fredrick, Colorado; Eunice, Louisiana; Shelocta, Pennsylvania; Calgary, Alberta, Canada; and additional office space in Houston, Texas.

 

 

In the normal course of our business, we are a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including warranty and product liability claims and occasional claims by individuals alleging exposure to hazardous materials, on the job injuries and fatalities as a result of our products or operations. Many of the claims filed against us relate to motor vehicle accidents which can result in the loss of life or serious bodily injury. Some of these claims relate to matters occurring prior to our acquisition of businesses. In certain cases, we are entitled to indemnification from the sellers of such businesses.

 

Although we cannot know or predict with certainty the outcome of any claim or proceeding or the effect such outcomes may have on us, we believe that any liability resulting from the resolution of any of these matters, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our financial position, results of operations or liquidity.

 

We have historically incurred additional insurance premium related to a cost-sharing provision of our general liability insurance policy, and we cannot be certain that we will not incur additional costs until either existing claims become further developed or until the limitation periods expire for each respective policy year. Any such additional premiums should not have a material adverse effect on our financial position, results of operations or liquidity.

 

 

 

At February 14, 2011, we had 78,592,455 shares of common stock outstanding, of which 1,353,996 shares were non-vested restricted stock subject to forfeiture restrictions. The common shares outstanding at February 14, 2011 were held by 57 record holders, excluding stockholders for whom shares are held in “nominee” or “street” name. We had 5,000,000 authorized shares of $0.01 par value preferred stock, of which none was issued and outstanding at December 31, 2010 or February 14, 2011.

 

On April 21, 2006, our common stock began trading on the New York Stock Exchange under the symbol “CPX.” On April 26, 2006, we completed our initial public offering.

 

The following table presents the high and low sales prices of our common stock reported on the New York Stock Exchange for each of the calendar quarters in 2009 and 2010:

 

 

The year-end closing sales price of our common stock was $13.00 on December 31, 2009, the last trading day of 2009, and $29.55 on December 31, 2010, the last trading day of 2010.

 

Issuer Purchases of Equity Securities:

 

In accordance with the provisions of the 2008 Incentive Award Plan, holders of unvested restricted stock were given the option to either remit to us the required withholding taxes associated with the vesting of restricted stock, or to authorize us to repurchase shares equivalent to the cost of the withholding tax and to remit the withholding taxes on behalf of the holder. We made no repurchases of our common stock during the year ended December 31, 2008. However, pursuant to this provision, we repurchased 18,743 shares in 2009 and 113,330 shares in 2010, of which the following shares were purchased during the quarter ended December 31, 2010:

 

 

 

 

Equity Compensation Plans:

 

The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information as set forth in Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” contained herein.

 

Dividends:

 

We paid no dividends on our outstanding $0.01 par value common stock for the years ended December 31, 2010, 2009 or 2008. We currently do not intend to pay dividends in the foreseeable future, but rather plan to reinvest such funds in our business. Furthermore, our credit facility and the indenture governing our senior notes contain covenants which restrict us from paying future dividends on our common stock.

Performance Graph:

 

The information in this section of the Annual Report pertaining to our performance relative to our peers is being furnished but not filed with the SEC, and as such, the information is neither subject to Regulation 14A or 14C or to the liabilities of Section 18 of the Exchange Act of 1934.

 

The following chart presents a comparative analysis of the stock performance of our common stock (“CPX”) relative to an industry index, the Philadelphia Oil Service Sector Index (“OSX”), and a broader market index, Standard & Poor’s 500 Index (“S&P”). This analysis assumes a $100 investment in the underlying common stock of CPX, OSX and S&P on April 21, 2006, the date of our initial public offering, through December 31, 2010. This analysis does not purport to be a representation of the actual market performance of our stock or these indexes. This chart has been provided for informational purposes to assist the reader in evaluating the market performance of our common stock compared to other market participants.

 

Notwithstanding anything to the contrary set forth in our previous filings under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, which might incorporate future filings made by us under those statutes, the following Stock Performance Graph will not be deemed incorporated by reference into any future filings made by us under those statutes.

 

COMPARISON OF 56 MONTH CUMULATIVE TOTAL RETURN*
Among Complete Production Services, Inc, the S&P 500 Index
And The PHLX Oil Service Sector Index

 

 

 

Copyright ^© 2011 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.

 

The following table presents selected historical consolidated financial and operating data for the periods shown. The selected consolidated financial data as of December 31, 2006, 2007, 2008, 2009 and 2010 and for each of the years then ended have been derived from our audited consolidated financial statements for those dates and periods, adjusted for discontinued operations, as indicated. The following information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes included elsewhere in this Annual Report.

 

 

 

 

 

 

 

Reconciliation of Adjusted EBITDA

 

 

 

The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included within this Annual Report. This discussion contains forward-looking statements based on our current expectations, assumptions, estimates and projections about us and the oil and gas industry. See “Forward-Looking Statement” contained in Item 1. “Business.” These forward-looking statements involve risks and uncertainties that may be outside of our control and could cause actual results to differ materially from those in the forward-looking statements. For examples of those risks and uncertainties, see the cautionary statements contained in Item 1A. “Risk Factors.” Factors that could cause or contribute to such differences include, but are not limited to: market prices for oil and gas, the level of oil and gas drilling, economic and competitive conditions, capital expenditures, regulatory changes and other uncertainties. In light of these risks, uncertainties and assumptions, the forward-looking events discussed below may not occur. Unless otherwise required by law, we undertake no obligation to publicly update any forward-looking statements, even if new information becomes available or other events occur in the future.

The words “believe,” “may,” “will,” “estimate,” “continue,” “anticipate,” “intend,” “plan,” “expect” and similar expressions are intended to identify forward-looking statements. All statements other than statements of current or historical fact contained in this Annual Report are forward-looking statements.

 

Overview

 

We are a leading provider of specialized completion and production services and products focused on helping oil and gas companies develop hydrocarbon reserves, reduce operating costs and enhance production. We focus on basins within North America that we believe have attractive long-term potential for growth, and we deliver targeted, value-added services and products required by our customers within each specific basin. We believe our range of services and products positions us to meet the many needs of our customers at the wellsite, from drilling and completion through production and eventual abandonment. We manage our operations from regional field service facilities located throughout the U.S. Rocky Mountain region, Texas, Oklahoma, Louisiana, Arkansas, Pennsylvania, western Canada, Mexico and Southeast Asia.

 

We operate in three business segments:

 

Completion and Production Services.  Through our completion and production services segment, we establish, maintain and enhance the flow of oil and gas throughout the life of a well. This segment is divided into the following primary service lines:

 

 

Drilling Services.  Through our drilling services segment, we provide services and equipment that initiate or stimulate oil and gas production by providing land drilling and specialized rig logistics services.

 

Product Sales.  We provide oilfield service equipment and refurbishment of used equipment through our Southeast Asian business, and we provide repair work and fabrication services for our customers at a business located in Gainesville, Texas.

 

Substantially all service and rental revenue we earn is based upon a charge for a period of time (an hour, a day, a week) for the actual period of time the service or rental is provided to our customer, on a fixed per-stage-completed fee or pursuant to a long-term contract which may include take-or-pay provisions. Product sales are recorded when the actual sale occurs and title or ownership passes to the customer.

 

Our customers include large multi-national and independent oil and gas producers, as well as smaller independent producers and the major land-based drilling contractors in North America (see “Customers” in Item 1 of this Annual Report on Form 10-K). The primary factors influencing demand for our services and products are the level of drilling and workover activity of our customers and the complexity of such activity, which in turn, depends on current and anticipated future oil and gas prices, production depletion rates and the resultant levels of cash flows generated and allocated by our customers to their drilling and workover budgets. As a result, demand for our services and products is cyclical, substantially depends on activity levels in the North American oil and gas industry and is highly sensitive to current and expected oil and natural gas prices. The following tables summarize average North American drilling and well service rig activity, as measured by Baker Hughes Incorporated (“BHI”) and the

Cameron International Corporation/Guiberson/AESC Service Rig Count for “Active Rigs,” respectively, and historical commodity prices as provided by Bloomberg:

 

AVERAGE RIG COUNTS

 

 

 

Source: BHI (www.BakerHughes.com)

 

 

 

Source: Cameron International Corporation/Guiberson/AESC Well Service Rig Count for “Active Rigs.”

 

Service rig counts for active rigs for December 2010 was 2,682 according to the Cameron International Corporation/Guiberson/AESC Well Service Rig Count for “Active Rigs” and was 2,713 as of January 31, 2011.

 

AVERAGE OIL AND GAS PRICES

 

 

 

Source: Bloomberg NYMEX prices.

 

The closing spot price of a barrel of WTI Cushing oil at December 31, 2010 was $91.38 and the closing spot price for Henry Hub natural gas ($/mcf) was $4.41. At February 14, 2011, the closing spot price of a barrel of WTI Cushing oil was $84.81 and the closing spot price for Henry Hub natural gas was $3.92.

We consider the drilling and well service rig counts to be an indication of spending by our customers in the oil and gas industry for exploration and development of new and existing hydrocarbon reserves. These spending levels are a primary driver of our business, and we believe that our customers tend to invest more in these activities when oil and gas prices are at higher levels or are increasing. The utilization of our assets and the performance of our business can be impacted by these and other external and internal factors. See Item 1A. “Risk Factors.”

 

We generally charge for our services either on a dayrate or per-stage-completed basis. Depending on the specific service, charges may include one or more of these components: (1) a set-up charge, (2) an hourly service rate based on equipment and labor, (3) a stage-completed charge, (4) an equipment rental charge, (5) a consumables charge, and (6) a mileage and fuel charge. We generally determine the rates charged through a competitive process on a job-by-job basis. Typically, work is performed on a “call out” basis, whereby the customer requests services on a job-specific basis, but does not guarantee work levels beyond the specific job bid. For contract drilling services, fees are charged based on standard dayrates or, to a lesser extent, as negotiated by footage contracts. Product sales generated through our Southeast Asian business are typically based on a pre-determined price book.

 

We have entered into long-term take or pay contracts on the majority of our pressure pumping capacity. These agreements are typically for three-year terms and require our customers to pay us a minimum daily rate for not less than five days per week and provide for an option to operate seven days per week. We are typically paid within 30 — 60 days for services provided during the previous month. The contracts typically provide incentives to compensate us for better efficiencies and services provided at higher pressures, extended pump times and flow rates. We are also able to pass-through increases in costs associated with certain consumables used in pressure pumping operations. Our customers would be required to pay us substantial fees for the early termination of the contracts.

 

Outlook

 

Our growth strategy is focused on internal growth in the basins in which we currently operate, maximizing equipment utilization, adding additional like-kind equipment and expanding our service and product offerings. We seek new basins in which to replicate this approach and augment our internal growth with strategic acquisitions. Our business is impacted by changes in the oil and gas cycle. Oil and gas commodity prices rose steadily throughout the decade culminating in 2008, then declined sharply in late 2008 and the early part of 2009, primarily due to the global financial crisis. Oil prices recovered through the remainder of 2009 and continued a gradual improvement during the course of 2010 along with the global economy. The price of natural gas in North America has remained subdued as a result of storage levels remaining above historical averages caused primarily by increasing gas production from unconventional resource plays. As a result, exploration and production companies are shifting a greater portion of their activities into emerging oil and liquid-rich plays and our business has shifted from a predominantly gas-oriented business, to a majority oil and liquids-oriented business.

 

In 2010, we remained disciplined with our financial investments in capital expenditures, targeted specific acquisitions, which were additive to our business objectives and responded to our customers’ needs for quality services in the emerging oil and liquid-rich plays. We redeployed equipment and personnel into the emerging basins while continuing to maintain a strong presence in our historical markets.

 

 

For 2011, we anticipate that activity levels will remain strong and a greater percentage of activity will be directed at increasingly more service intensive, multi-stage, horizontal wells. Current oil prices are encouraging increased investments in oil plays and in gas fields that have meaningful natural gas liquids content. Additionally, drilling and completion activity required to retain leases and service capacity shortages, which have led to a backlog of wells to be completed, should support activity in dry gas basins through the first half of the year.

 

As a result of our positive outlook for North America in 2011 we have expanded our capital expenditure program which includes: (1) roughly 170,000 hydraulic horse power of pressure pumping equipment; (2) five larger-diameter coiled tubing units with extended reach capabilities; and (3) meaningful investments in fluid handling and well servicing assets. Additionally, we continue to seek strategic acquisitions to enhance service offerings and extend our presence in new service areas.

 

We, and many of our competitors, are investing in new equipment, some of which requires long lead-times to manufacture. As more of this equipment is available to be placed into service there could be additional excess capacity in the industry, which may negatively impact utilization rates and pricing and put inflationary pressure on labor costs. To improve efficiencies for us and our customers and due to the concern associated with excess capacity we have entered into long-term take-or-pay contracts on the majority of our pressure pumping capacity. Additionally, we continue to monitor our equipment utilization and poll our customers to assess demand levels. As equipment enters the marketplace or competition for existing customers increases, we believe our customers will rely upon service providers who provide quality services and have positioned themselves to be responsive to customer’s needs which we believe we have and which constitutes a fundamental aspect of our growth strategy.

 

Our business continues to be impacted by seasonality and inclement weather, including the effects of harsh winter weather conditions which occurred during the past few months in North Dakota, Oklahoma and north Texas, the normal second quarter Canadian “break-up,” as well as the impact of Gulf of Mexico tropical weather systems.

 

We believe our customers will continue to rely upon service providers with local knowledge and a proven ability to effectively execute complex services on more service intensive, longer-lateral horizontal wells, particularly in oil and liquid-rich basins. We believe we are well positioned in high-growth basins and our core services, which include pressure pumping, coiled tubing, well servicing and fluid handling, will benefit from these secular trends.

 

Significant Transactions

 

During 2010, we acquired substantially all the assets or all of the equity interests in three oilfield service companies, for $33.7 million in cash, resulting in goodwill of approximately $6.9 million.

 

 

 

During 2008, we acquired substantially all the assets or all of the equity interests in four oilfield service companies, for $180.2 million in cash, resulting in goodwill of approximately $71.2 million.

 

 

We have accounted for our acquisitions using the purchase method of accounting, whereby the purchase price is allocated to the fair value of net assets acquired, including intangibles and property, plant and equipment at depreciated replacement costs with the excess to goodwill. Results of operations related to each of the acquired companies have been included in our accounts and results of operations as of the date of acquisition.

 

In March 2009, our Canadian subsidiary exchanged certain non-monetary assets with a net book value of $9.3 million related to our production testing business for certain e-line assets of a competitor. We recorded a non-cash loss on the transaction of $4.9 million, which represented the difference between the carrying value and the fair

market value of the assets surrendered. We believe the e-line assets will generate incremental future cash flows compared to the production testing assets exchanged.

 

In May 2008, our Board of Directors authorized and committed to a plan to sell certain operations in the Barnett Shale region of north Texas, consisting primarily of our supply store business, as well as certain non-strategic drilling logistics assets and other completion and production services assets. On May 19, 2008, we sold these operations to Select Energy Services, L.L.C., a company owned by a former officer of one of our subsidiaries, for which we received proceeds of $50.2 million in cash and assets with a fair market value of $8.0 million. The carrying value of the net assets sold was approximately $51.4 million, excluding $11.1 million of allocated goodwill associated with the combination that formed Complete Production Services, Inc. in September 2005. We recorded a loss on the sale of this disposal group totaling approximately $6.9 million, which included $2.6 million related to income taxes. In accordance with the sales agreement, we sublet office space to Select Energy Services, L.L.C. and provided certain administrative services for an initial term of one year, at an agreed-upon rate.

 

On October 31, 2006, we completed the sale of a disposal group which included certain manufacturing and production enhancement operations of a subsidiary located in Alberta, Canada, as well as operations in south Texas. We sold this disposal group to an oilfield service company located in Calgary, Alberta, Canada. In conjunction with this asset disposal, the buyer issued a note to us for $2.0 million denominated in Canadian dollars. During the second quarter of 2010, we were notified that the seller was in default on a term loan and security agreement which was senior to our note. Therefore, management recorded a provision of $1.9 million for bad debt associated with this note as of June 30, 2010, but we will continue to pursue our interest in this note to the extent a portion may be recoverable in a future period.

 

Market Environment

 

We operate in a highly competitive industry. Our competition includes many large and small oilfield service companies. As such, we price our services and products to remain competitive in the markets in which we operate, adjusting our rates to reflect current market conditions as necessary. We examine the rate of utilization of our equipment as one measure of our ability to compete in the current market environment.

 

Critical Accounting Policies and Estimates

 

The preparation of our consolidated financial statements in conformity with Generally Accepted Accounting Principles (“GAAP”) requires the use of estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, and provide a basis for making judgments about the carrying value of assets and liabilities that are not readily available through open market quotes. Estimates and assumptions are reviewed periodically, and actual results may differ from those estimates under different assumptions or conditions. We must use our judgment related to uncertainties in order to make these estimates and assumptions.

 

In the selection of our critical accounting policies, the objective is to properly reflect our financial position and results of operations for each reporting period in a consistent manner that can be understood by the reader of our financial statements. Our accounting policies and procedures are explained in Note 2, “Significant accounting policies,” in our notes to consolidated financial statements included elsewhere in this Annual Report. We consider an estimate to be critical if it is subjective and if changes in the estimate using different assumptions would result in a material impact on our financial position or results of operations.

 

We have identified the following as the most critical accounting policies and estimates, and have provided: (1) a description, (2) information about variability and (3) our historical experience, including a sensitivity analysis, if applicable.

 

Revenue Recognition

 

We recognize service revenue as services are performed and when realized or earned. Revenue is deemed to be realized or earned when we determine that the following criteria are met: (1) persuasive evidence of an arrangement

exists; (2) delivery has occurred or services have been rendered; (3) the fee is fixed or determinable; and (4) collectibility is reasonably assured. These services are generally provided over a relatively short period of time pursuant to short-term contracts at pre-determined dayrate fees, or on a day-to-day basis. Revenue and costs related to drilling contracts are recognized as work progresses. Progress is measured as revenue is recognized based upon dayrate charges. For certain contracts, we may receive lump-sum payments from our customers related to the mobilization of rigs and other drilling equipment. Under these arrangements, we defer revenues and the related cost of services and recognize them over the term of the drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Revenues associated with product sales are recorded when product title is transferred to the customer.

 

Under current GAAP, revenue is to be recognized when it is realized or realizable and earned. The SEC’s rules and regulations provide additional guidance for revenue recognition under specific circumstances, including bill and hold transactions. There is a risk that our results of operations could be misstated if we do not record revenue in the proper accounting period.

 

The nature of our business has been such that we generally bill for services over a relatively short period of time or bill for services on a stage-completed basis under a longer-term contract with take-or-pay provisions and record revenues as products are sold. We did not record material adjustments resulting from revenue recognition issues for the years ended December 31, 2010, 2009 and 2008.

 

Impairment of Long-Lived Assets

 

Based on guidance from the Financial Accounting Standards Board (“FASB”) regarding accounting for the impairment or disposal of long-lived assets, we evaluate potential impairment of long-lived assets and intangibles, excluding goodwill and other intangible assets without defined service lives, when indicators of impairment are present. If such indicators are present, we project the fair value of the assets by estimating the undiscounted future cash in-flows to be derived from the long-lived assets over their remaining estimated useful lives, as well as any salvage value. Then, we compare this fair value estimate to the carrying value of the assets and determine whether the assets are deemed to be impaired. For goodwill and other intangible assets without defined service lives, we perform an annual impairment test, whereby we estimate the fair value of the asset by discounting future cash flows at a projected cost of capital rate. If the fair value estimate is less than the carrying value of the asset, an additional test is required whereby we apply a purchase price analysis similar to a purchase price allocation for a business combination. If impairment is still indicated, we would record an impairment loss in the current reporting period for the amount by which the carrying value of the intangible asset exceeds its projected fair value.

 

Our industry is highly cyclical and the estimate of future cash flows requires the use of assumptions and our judgment. Periods of prolonged down cycles in the industry could have a significant impact on the carrying value of these assets and may result in impairment charges. If our estimates do not approximate actual performance or if the rates we used to discount cash flows vary significantly from actual discount rates, we could overstate our assets and an impairment loss may not be timely identified.

 

We tested goodwill for impairment for each of the years ended December 31, 2010, 2009 and 2008. Management prepared a discounted cash flow analysis to determine the fair market value of the reportable units as of the annual testing date. Projected cash flows were based on certain management assumptions related to expected growth, capital investment and terminal value, discounted at a market-participant weighted average cost of capital, refined to reflect our current and anticipated capital structure. Based on this analysis, management determined that goodwill was not impaired as of our annual testing date in 2010, but was impaired in 2009 and 2008. In accordance with the FASB’s guidance for goodwill, management performed a step-two analysis to calculate the amount by which the carrying value of the reporting units exceeded the projected fair market value of such units as of the respective annual testing dates. We performed our impairment calculations as of December 31, 2008, incorporating our assumptions of future earnings and cash flows. Based on this testing, we determined that the goodwill associated with most of our reporting units had been impaired. We recorded an impairment charge of $272.0 million at December 31, 2008. In calculating this impairment charge, management made assumptions about future earnings by reportable unit, which may differ from actual future earnings for these operations. In 2009, management performed additional analysis and determined that further write-downs were necessary. We recorded a

goodwill impairment charge of $97.6 million associated with several of our reportable units at December 31, 2009. In addition, pursuant to an undiscounted cash flow analysis, we recorded a fixed asset impairment in our drilling services segment of $36.2 million and an intangible asset impairment in our completion and production services segment totaling $2.5 million during 2009. A significant decline in expected future cash flow, a further erosion of market conditions or a lower-than-expected recovery of the oil and gas industry activity levels in future years, could result in an additional impairment charge.

 

Stock Options and Other Stock-Based Compensation

 

We have issued stock-based compensation to certain employees, officers and directors in the form of stock options and restricted stock. In accordance with U.S. GAAP, we account for grants made prior to September 30, 2005, the date of our initial filing with the SEC, using the minimum value method, whereby no compensation expense is recognized for stock-based compensation grants that have an exercise price equal to the fair value of the stock on the date of grant. For grants of stock-based compensation between October 1, 2005 and December 31, 2005, we utilized the modified prospective transition method to record expense associated with these options, whereby we did not record compensation expense associated with these grants during the period October 1, 2005 through December 31, 2005 but provided pro forma disclosure of this expense, and, then began recognizing compensation expense related to these grants over the remaining vesting period after December 31, 2005 based upon a calculated fair value. These grants were fully vested as of December 31, 2009. For grants of stock-based compensation on or after January 1, 2006, we recognize expense associated with new awards of stock-based compensation, as determined using a Black-Scholes pricing model over the expected term of the award. In addition, we record compensation expense associated with restricted stock which has been granted to certain of our directors, officers and employees. In accordance with current U.S. GAAP, we calculate compensation expense on the date of grant (number of options granted multiplied by the fair value of our common stock on the date of grant) and recognize this expense, adjusted for forfeitures, ratably over the applicable vesting period.

 

U.S. GAAP permits the use of various models to determine the fair value of stock options and the variables used for the model are highly subjective. For purposes of determining compensation expense associated with stock options granted after January 1, 2006, we are required to determine the fair value of the stock options by applying a pricing model which includes assumptions for expected term, discount rate, stock volatility, expected forfeitures and a dividend rate. The use of different assumptions or a different model may have a material impact on our financial disclosures.

 

For the years ended December 31, 2010, 2009 and 2008, we applied a Black-Scholes model with similar assumptions for expected term (based on a probability analysis and ranging from 2.2 to 5.1 years), risk free rate (based upon published rates for U.S. Treasury notes), zero dividend rate and stock volatility, which we determined based on our historical common stock volatility for grants after June 2008 and estimated based on the historical volatility rates of several peer companies prior to that time. In addition, we estimated a forfeiture rate based upon our historical experience. We have recorded compensation expense associated with stock option and restricted stock grants totaling $11.6 million, $12.2 million and $12.4 million for the years ended December 31, 2010, 2009 and 2008, respectively.

 

Allowance for Bad Debts and Inventory Obsolescence

 

We record trade accounts receivable at billed amounts, less an allowance for bad debts. Inventory is recorded at cost, less an allowance for obsolescence. To estimate these allowances, management reviews the underlying details of these assets as well as known trends in the marketplace, and applies historical factors as a basis for recording these allowances. If market conditions are less favorable than those projected by management, or if our historical experience is materially different from future experience, additional allowances may be required.

 

There is a risk that management may not detect uncollectible accounts or unsalvageable inventory in the correct accounting period.

 

Bad debt expense (recovery) has been less than 1% of sales for the years ended December 31, 2010, 2009 and 2008. If bad debt expense had increased by 1% of sales, net income would have decreased by $9.7 million for the year ended December 31, 2010 and net loss would have increased by $7.8 million and $11.9 million for the years

ended December 2009 and 2008, respectively. Our obsolescence and other inventory reserves were approximately 7%, 2% and 2% of our inventory balances at December 31, 2010, 2009 and 2008, respectively. A 1% increase in inventory reserves, from 7% to 8%, at December 31, 2010 would have decreased net income by $0.2 million for the year then ended.

 

Property, Plant and Equipment

 

We record property, plant and equipment at cost less accumulated depreciation. Major betterments to existing assets are capitalized, while repairs and maintenance costs that do not extend the service lives of our equipment are expensed. We determine the useful lives of our depreciable assets based upon historical experience and the judgment of our operating personnel. We generally depreciate the historical cost of assets, less an estimate of the applicable salvage value, on the straight-line basis over the applicable useful lives. Upon disposition or retirement of an asset, we record a gain or loss if the proceeds from the transaction differ from the net book value of the asset at the time of the disposition or retirement.

 

U.S. GAAP permits various depreciation methods to recognize the use of assets. Use of a different depreciation method or different depreciable lives could result in materially different results. If our depreciation estimates are not correct, we could over- or understate our results of operations, such as recording a disproportionate amount of gains or losses upon disposition of assets. There is also a risk that the useful lives we apply for our depreciation calculation will not approximate the actual useful life of the asset. We believe our estimates of useful lives are materially correct and that these estimates are consistent with industry averages.

 

We evaluate property, plant and equipment for impairment when there are indicators of impairment. We did not record any significant impairment charges related to our long-term assets for the year ended December 31, 2010. During September 2009, we evaluated the fair market value of assets in our contract drilling business with the assistance of a third-party appraiser and determined that the carrying value of certain of these drilling rigs exceeded the fair market value estimates. We projected the undiscounted cash flows associated with these rigs, including an estimate of salvage value, and compared these expected future cash flows to the carrying amount of the rigs. If the undiscounted cash flows exceeded the carrying amount, no further testing was performed and the rig was deemed to not be impaired. If the undiscounted cash flows did not exceed the carrying value, we estimated the fair market value of the equipment based on management estimates and general market data obtained by the third-party appraiser using the sales comparison market approach, which included the analysis of recent sales and offering prices of similar equipment to arrive at an indication of the most probable net sales proceeds for the equipment. The result of this analysis was a calculated fixed asset impairment of $36.2 million, which was recorded as an impairment loss in September 30, 2009. This impairment charge was allocated entirely to the drilling services business segment. This impairment was deemed necessary due to an overall decline in oil and gas exploration and production activity in late 2008 which extended throughout 2009, as well as management’s expectation of future operating results for this business segment. There were no significant impairment charges related to our long-term assets during the year ended December 31, 2008. Depreciation and amortization expense for the years ended December 31, 2010 and 2009 represented 19% of the average depreciable asset base for each year. An increase in depreciation expense relative to the depreciable base of 1%, from 19% to 20%, would have reduced net income by approximately $5.9 million for the year ended December 31, 2010.

 

Self Insurance

 

On January 1, 2007, we began a self-insurance program to pay claims associated with health care benefits provided to certain of our employees in the United States. Pursuant to this program, we have purchased a stop-loss insurance policy from an insurance company. Our accounting policy for this self-insurance program is to accrue expense based upon the number of employees enrolled in the plan at pre-determined rates. As claims are processed and paid, we compare our claims history to our expected claims in order to estimate incurred but not reported claims. If our estimate of claims incurred but not reported exceeds our current accrual, we record additional expense during the current period. There is a risk that we may not estimate our incurred but not reported claims correctly or that our stop-loss provision may not be adequate to insure us against losses in the future. At December 31, 2010, we accrued $4.7 million pursuant to this self-insurance program. A 10% increase in this self-insurance accrual would reduce our net income for the year ended December 31, 2010 by $0.4 million.

Deferred Income Taxes

 

Our income tax expense includes income taxes related to the United States, Canada and other foreign countries, including local, state and provincial income taxes. We account for tax ramifications pursuant to U.S. GAAP for income taxes and record deferred income tax assets and liabilities based upon temporary differences between the carrying amount and tax basis of our assets and liabilities and measure tax expense using enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect of a change in tax rates is recognized in income in the period of the change. Furthermore, we record a valuation allowance for any deferred income tax assets which we believe are likely to not be used through future operations. As of December 31, 2010, 2009 and 2008, we recorded a valuation allowance of less than $1.0 million related to certain deferred tax assets in Canada. If our estimates and assumptions related to our deferred tax position change in the future, we may be required to record additional valuation allowances against our deferred tax assets and our effective tax rate may increase, which could adversely affect our financial results. As of December 31, 2010, we did not provide deferred U.S. income taxes on approximately $28.6 million of undistributed earnings of our foreign subsidiaries in which we intend to indefinitely reinvest. Upon distribution of these earnings in the form of dividends or otherwise, we may be subject to U.S. income taxes and foreign withholding taxes. On January 1, 2007, we adopted the FASB interpretation that provides guidance to account for uncertain tax positions. Annually, we perform an evaluation of our tax positions. We have evaluated our tax positions at December 31, 2010 and believe these positions are deemed appropriate for all significant matters.

 

There is a risk that estimates related to the use of loss carry forwards and the realizability of deferred tax accounts may be incorrect, and that the result could materially impact our financial position and results of operations. In addition, future changes in tax laws or GAAP requirements could result in additional valuation allowances or the recognition of additional tax liabilities.

 

Historically, we have utilized net operating loss carry forwards to partially offset current tax expense, and we have recorded a valuation allowance to the extent we expect that our deferred tax assets will not be utilized through future operations. Deferred income tax assets totaled $30.5 million at December 31, 2010, against which we recorded a valuation allowance of $0.3 million, leaving a net deferred tax asset of $30.2 million deemed realizable. Changes in our valuation allowance would affect our net income on a dollar for dollar basis.

 

Discontinued Operations

 

We account for discontinued operations in accordance with the FASB guidance on accounting for the impairment or disposal of long-lived assets. U.S. GAAP requires that we classify the assets and liabilities of a disposal group as held for sale if the following criteria are met: (1) management, with appropriate authority, commits to a plan to sell a disposal group; (2) the asset is available for immediate sale in its current condition; (3) an active program to locate a buyer and other actions to complete the sale have been initiated; (4) the sale is probable; (5) the disposal group is being actively marketed for sale at a reasonable price; and (6) actions required to complete the plan of sale indicate it is unlikely that significant changes to the plan of sale will occur or that the plan will be withdrawn. Once deemed held for sale, we no longer depreciate the assets of the disposal group. Upon sale, we calculate the gain or loss associated with the disposition by comparing the carrying value of the assets less direct costs of the sale with the proceeds received. In conjunction with the sale, we settle inter-company balances between us and the disposal group and allocate interest expense to the disposal group for the period the assets were held for sale. In the statement of operations, we present discontinued operations, net of tax effect, as a separate caption below net income from continuing operations.

Results of Operations for the Years Ended December 31, 2010 and 2009

 

The following tables set forth our results of continuing operations, including amounts expressed as a percentage of total revenue, for the periods indicated (in thousands, except percentages).

 

 

“Corporate” includes amounts related to corporate personnel costs, other general expenses and stock-based compensation charges.

 

“Adjusted EBITDA” consists of net income (loss) from continuing operations before net interest expense, taxes, depreciation and amortization, non-controlling interest and impairment loss. Adjusted EBITDA is a non-GAAP measure of performance. We use Adjusted EBITDA as the primary internal management measure for evaluating performance and allocating additional resources. The following table reconciles Adjusted EBITDA for the years ended December 31, 2010 and 2009 to the most comparable U.S. GAAP measure, operating income (loss). The calculation of Adjusted EBITDA is different from the calculation of “EBITDA,” as defined and used in our credit facilities. For a discussion of the calculation of “EBITDA” as defined under our existing credit facilities, as recently amended, see Note 11, “Long-term debt” in our notes to consolidated financial statements included elsewhere in this Annual Report.

 

Reconciliation of Adjusted EBITDA to Most Comparable GAAP Measure — Operating Income (Loss)

 

Reconciliation of Net Income (Loss) to Adjusted EBITDA

 

 

Below is a detailed discussion of our operating results by segment for these periods.

 

Year Ended December 31, 2010 Compared to the Year ended December 31, 2009

 

Revenue

 

Revenue from continuing operations for the year ended December 31, 2010 increased by $505.0 million, or 48%, to $1,561.4 million from $1,056.4 million for the year ended December 31, 2009. This increase by segment was as follows:

 

 

Service and Product Expenses

 

Service and product expenses include labor costs associated with the execution and support of our services, materials used in the performance of those services and other costs directly related to the support and maintenance of equipment. These expenses increased $285.7 million, or 39%, to $1,011.0 million for the year ended December 31, 2010 from $725.4 million for the year ended December 31, 2009. The increase in service and product expenses was consistent with an overall increase in revenues resulting from improvements in oilfield activity in the

U.S. and Canada in 2010. The following table summarizes service and product expenses as a percentage of revenues for the years ended December 31, 2010 and 2009:

 

Service and Product Expenses as a Percentage of Revenue

 

 

Service and product expenses as a percentage of revenue improved to 65% for the year ended December 31, 2010 compared to 69% for the year ended December 31, 2009. Margins by business segment were impacted primarily by utilization and pricing.

 

 

Selling, General and Administrative Expenses

 

Selling, general and administrative expenses include salaries and other related expenses for our selling, administrative, finance, information technology and human resource functions. Selling, general and administrative expenses decreased $6.0 million, or 3%, to $175.4 million for the year ended December 31, 2010 from $181.4 million for the year ended December 31, 2009. The results for 2009 included incremental bad debt charges associated with specifically-identified uncollectible accounts of $10.9 million, incremental losses on the retirement of fixed assets of $12.8 million and certain insignificant inventory adjustments. In addition, we recorded a loss on the non-monetary exchange of certain assets in Canada during the first quarter of 2009 which totaled $4.9 million. The overall decrease in selling, general and administrative expense in 2010 was partially offset by higher incentive compensation based on earnings, increased payroll costs, higher insurance costs and the write-off of a $1.9 million note receivable in Canada. Excluding the impact of the non-monetary asset exchange in Canada, the incremental charges to bad debt expense and losses on the retirement of fixed assets, as a percentage of revenues, selling, general and administrative expense was 11% and 14% for the years ended December 31, 2010 and 2009, respectively.

 

Depreciation and Amortization

 

Depreciation and amortization expense decreased $18.9 million, or 9%, to $181.8 million for the year ended December 31, 2010 from $200.7 million for the year ended December 31, 2009. The decrease in depreciation and amortization expense was attributable to the normal run-off of depreciation associated with existing assets, asset retirements in 2009, a $36.2 million impairment of our drilling rigs as of September 30, 2009, sale-leaseback transactions associated with our small vehicle fleet as well as a facility in Wyoming and an impairment charge in

late 2009 related to certain intangible assets acquired in 2008. Although we increased our capital expenditures in 2010 compared to 2009, approximately half of those additions were incurred during the second half of the year, resulting in overall lower depreciation and amortization expense year-over-year. As a percentage of revenue, depreciation and amortization expense decreased to 12% from 19% for the years ended December 31, 2010 and 2009, respectively.

 

Fixed Asset and Other Intangible Impairment Loss

 

We did not record any impairment charges in 2010. For the year ended December 31, 2009, we recorded a fixed asset and other intangible impairment loss of $38.6 million. We recorded a charge of $36.2 million related to our contract drilling business in the third quarter of 2009 after determining that the carrying value of certain of these drilling rigs exceeded the undiscounted cash flows associated with these assets and the fair market value estimates for these assets. In the fourth quarter of 2009, we recorded an impairment of intangible assets of $2.5 million related to our completion and production business.

 

Goodwill Impairment Loss

 

We did not record any goodwill impairment in 2010. For the year ended December 31, 2009, we recorded a goodwill impairment loss of $97.6 million. The write-downs of goodwill was associated with several of our reporting units and was based upon several valuation techniques including a discounted cash flow analysis of expected future earnings associated with these businesses. Our analysis of future cash flows was impacted significantly by the overall decline in oilfield activity in late 2008 which continued throughout 2009.

 

Taxes

 

Tax expense (benefit) is comprised of current income taxes and deferred income taxes. The current and deferred taxes added together provide an indication of an effective rate of income tax.

 

We recorded a tax provision of $51.6 million, at an effective rate of 38%, for the year ended December 31, 2010 compared to a tax benefit of $63.1 million for the year ended December 31, 2009 at an effective rate of approximately 25.8%. The lower effective tax rate in 2009 was primarily due to the impairment of goodwill with limited tax basis. Excluding the impact of the goodwill impairment charges, our effective tax rate for the year ended December 31, 2009 would have been 33.9%.

Results of Operations for the Years Ended December 31, 2009 and 2008

 

The following tables set forth our results of continuing operations, including amounts expressed as a percentage of total revenue, for the periods indicated (in thousands, except percentages).