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:

Common Stock, $.01 par value

(Title of class)

 

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

None

 

 

 

 

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

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 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 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.:

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

 

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, 2006, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $993,166,209, based upon the price at which our common stock was last sold on that date.

 

Number of shares of the Common Stock of the registrant outstanding as of March 1, 2007: 72,277,676

 

 

 

 

DOCUMENTS INCORPORATED BY REFERENCE

 

 

 

Complete Production Services, Inc.

 

TABLE OF CONTENTS

 

 

Our Company

 

Complete Production Services, Inc., formerly named Integrated Production Services, Inc., is a Delaware corporation formed on May 22, 2001. We provide specialized services and products focused on helping oil and gas companies develop hydrocarbon reserves, reduce 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 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 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, Kansas, western Canada and Mexico. We also have operations in Southeast Asia.

 

The Combination

 

Prior to 2001, SCF Partners, a private equity firm that focuses on investments in the oilfield services segment of the energy industry, began to target investment opportunities in service oriented companies in the North American natural gas market with specific focus on the completion and production phase of the exploration and production cycle. On May 22, 2001, SCF Partners through a limited partnership, SCF-IV, L.P. (“SCF”), formed Saber, a new company, in connection with its acquisition of two companies primarily focused on completion and production related services in Louisiana. In July 2002, SCF became the controlling stockholder of Integrated Production Services, Ltd., a production enhancement company that, at the time, focused its operation in Canada. In September 2002, Saber acquired this company and changed its name to Integrated Production Services, Inc. (“IPS”). Subsequently, IPS began to grow organically and through several acquisitions, with the ultimate objective of creating a technical leader in the enhancement of natural gas production. In November 2003, SCF formed another production services company, Complete Energy Services, Inc. (“CES”), establishing a platform from which to grow in the Barnett Shale region of north Texas. Subsequently, through organic growth and several acquisitions, CES extended its presence to the U.S. Rocky Mountain and the Mid-continent regions. In the summer of 2004, SCF formed I.E. Miller Services, Inc. (“IEM”), which at the time had a presence in Louisiana and Texas. During 2004, IPS and IEM independently began to execute strategic initiatives to establish a presence in both the Barnett Shale and U.S. Rocky Mountain regions.

 

On September 12, 2005, IPS, CES and IEM were combined and became Complete Production Services, Inc. in a transaction we refer to as the “Combination.” In the Combination, IPS served as the acquirer. Immediately after the Combination, SCF held approximately 70% of our outstanding common stock, the former CES stockholders (other than SCF) in the aggregate held approximately 18.8% of our outstanding common stock, the former IEM stockholders (other than SCF) in the aggregate held approximately 2.4% of our outstanding common stock and the former IPS stockholders (other than SCF) in the aggregate held approximately 8.4% of our outstanding common stock.

 

On April 20, 2006, we entered into an underwriting agreement in connection with our initial public offering and became subject to the reporting requirements of the Securities Exchange Act of 1934. 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.

 

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 services and equipment that initiate or stimulate oil and gas production by providing land drilling, specialized rig logistics and site preparation. Our drilling rigs currently operate in and around the Barnett Shale region of north Texas.

 

Product Sales.  Through our product sales segment, we provide a variety of equipment used by oil and gas companies throughout the lifecycle of their wells. Our current product offering includes completion, flow control and artificial lift equipment as well as tubular goods. We sell products throughout North America primarily through our supply stores. We also sell products through agents in markets outside of North America.

 

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. Our business is primarily driven by natural gas drilling activity in North America. We believe the following two principal economic factors will positively affect our industry in the coming years:

 

 

As a result of the above factors, we expect that there will continue to be a tight supply of, and high demand for, natural gas in North America. We believe this will continue to support high natural gas prices and high levels of drilling activity.

 

As illustrated in the table below, 2005 marked the third consecutive year of gas price increases and the fourth consecutive year of oil price increases. During 2006, oil commodity prices continued to increase due to worldwide demand for energy and other global and domestic economic factors, while natural gas prices decreased from recent record levels due to short-term oversupply in the market, but still remained high compared to historical averages. The price of a barrel of crude oil reached an all-time high during 2006. The number of drilling rigs under contract in the United States and Canada and the number of well service rigs have increased over the three-year period ended December 31, 2006, according to Baker Hughes Incorporated (“BHI”). 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 1999:

 

 

 

 

Continued demand for natural gas and a constrained gas supply have resulted in higher prices and increased drilling activity. The increase in prices and drilling activity are driving the following long-term trends that we believe will benefit us:

 

Trend toward drilling and developing unconventional North American natural gas resources.  Due to the maturity of conventional North American oil and gas reservoirs and their accelerating production decline rates, unconventional oil and gas resources will comprise an increasing proportion of future North American oil and gas production. Unconventional resources include tight sands, shales and coalbed methane. These resources require more wells to be drilled and maintained, frequently on tighter acreage spacing. 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 and Equipment.  Increasing prices and the development of unconventional oil and gas resources are driving the need for complex, new technologies and equipment to help increase recovery rates, lower production costs and accelerate field development.

 

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:

 

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 gas plays we believe have the potential for long-term growth. Our position in these basins capitalizes on our strong local leadership that has 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 gas 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 sell new services and products to customers 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. We employ a rigorous acquisition screening process and have developed comprehensive post-acquisition integration capabilities designed to ensure each acquisition is effectively assimilated. We use a returns method for evaluating capital investment opportunities, and we apply a disciplined approach to adding new equipment.

 

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 quality of service by focusing on the following:

 

 

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 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 bring their expertise to bear while selling services and products to our

customers. We strive to leverage this basin-level 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, Kansas and Oklahoma, western Canada and Mexico, with concentrations in key “resource play” and unconventional basins. Resource plays are expected to become increasingly important 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 Barnett Shale region of north Texas, the Fayetteville Shale in Arkansas and the Piceance Basin in Colorado, for example. 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 strong demand for our services and products. In addition, our strong 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 and throughout our geographic regions. Leveraging our strong 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 the downtime and associated expenditures and enables the 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 new platforms obtained through targeted acquisitions.

 

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, implementing corporate governance procedures and overseeing 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 17 of the notes to the consolidated financial statements included elsewhere in this Annual Report on Form 10-K 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 (72% of Revenue for the Year Ended December 31, 2006)

 

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 the above services are as follows:

 

Coiled Tubing 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 foam washing, acidizing, displacing, cementing, gravel packing, plug drilling, 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. Our pressure pumping services typically are performed at pressures of less than 10,000 pounds per square inch. We have developed innovative equipment configurations to capitalize on emerging market opportunities. For example, in the Barnett Shale region of north Texas, we have introduced advanced coiled tubing units that have electric-line conductors within the units’ coiled tubing string. These specially configured units provide electric-line and coiled tubing controls in one fully integrated package, and allow us to deploy perforating guns, logging tools and plugs in high inclination wells for our customers. We provide coiled tubing services primarily in Wyoming, Colorado, Oklahoma, Texas, Louisiana, Arkansas, Kansas, Mexico and offshore in the Gulf of Mexico.

 

Pressure Pumping Services

 

We operate a fleet of pressure pumping equipment in the Barnett Shale of north Texas through which we provide stimulation and cementing services principally to natural gas drilling and producing companies. Stimulation services primarily consist of hydraulic fracturing of hydrocarbon bearing formations having permeability that restricts the natural flow. The fracturing process consists of pumping fluids into a cased 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 rebuilt over the past five years. We believe we have a leading market position in the Barnett Shale region of north Texas 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, 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, Oklahoma and Wyoming.

 

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. Truck and skid mounted 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, Oklahoma, Texas, Kansas, Louisiana and offshore in the Gulf of Mexico.

 

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

 

 

 

 

Production Optimization Services.  Our production optimization services provide customers with technical solutions to stem declining production that result 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. Specific services we provide include:

 

 

 

We offer production optimization services to customers across the United States and in Canada. We provide production optimization services in Canada through our 50% joint venture with Premier Production Services Ltd.

 

Production Testing Services.  Production testing is a service required by exploration and production companies to evaluate and clean out new and existing wells. We use a proprietary technology and service approach and are a leading independent provider in North America. We provide production testing services throughout the western Canadian Sedimentary Basin and also 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 find it uneconomical to maintain complete inventories of tools, drillpipe, pressure testing equipment and other specialized equipment and to retain the qualified personnel to operate this equipment. 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, Colorado, Wyoming, Arkansas, Kansas, North Dakota and Montana.

 

 

Drilling Services (18% of Revenue for the Year Ended December 31, 2006)

 

Through our drilling services segment, we deliver services that initiate or stimulate oil and gas production by providing land drilling, specialized rig logistics and site preparation. Our drilling rigs currently operate in and around the Barnett Shale region of north Texas.

 

Contract Drilling

 

We provide contract drilling services to major oil companies and independent oil and gas producers in north 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 have depth ratings ranging from approximately 8,000 to 15,000 feet. We placed into service several land drilling rigs during 2006.

 

Drilling Logistics

 

We provide a variety of drilling logistic services as follows:

 

 

 

Product Sales (10% of Revenue for the Year Ended December 31, 2006)

 

Through our product sales segment, we provide a variety of equipment used by oil and gas companies throughout the lifecycle of their wells. Our current product offering includes completion, flow control and artificial lift equipment as well as tubular goods. We sell products throughout North America primarily through our supply stores and through distributors on a wholesale basis. We also sell products through agents in markets outside of North America.

 

Supply Stores

 

We own and operate supply stores that provide products and services to the oil and gas industry. We have supply stores and sales offices in Texas, Colorado, Louisiana and Oklahoma. We market tubular products, drill pipe, flow control and completion equipment, valves, fittings and other oilfield products.

 

Overseas Operations

 

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 also have a small corporate sales team located in Houston, Texas that supplements our field sales efforts and focuses on large accounts and selling technical services.

 

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 37% and 35% of our revenue for the years ended December 31, 2006 and 2005, respectively, with no one customer representing more than 10% of our revenue in either of these years. We believe we have a broad customer base and wide geographic coverage of operations, which somewhat insulates us from regional or customer specific circumstances.

 

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, commercial crime and kidnap and ransom 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.

 

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., BJ Services Company, Halliburton Company, Weatherford International Ltd., Baker Hughes Inc., Key Energy Services, Inc., Basic Energy Services, Inc., Superior Energy Services, Inc., Tetra Technologies, 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 and Helmerich & Payne, Grey Wolf Inc. Our principal competitors in our product sales segment include National Oilwell Varco, Inc., Smith International, 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 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 foreign, federal, state and local 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 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, that 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 or arranged for 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.

 

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, 2006, we had 6,397 employees. Of our total employees, 5,620 were in the United States, 551 were in Canada, 158 were in Mexico and 68 were in Singapore and other locations in the Far East. 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. Our primary internet address is: http://www.completeproduction.com. Our website 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 on Form 10-K and should not be considered part of this report.

 

The information we file with the SEC may 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

 

This Annual Report on Form 10-K contains forward-looking statements that are not limited to historical facts, but reflect our current beliefs, expectations or intentions regarding future events. All forward-looking statements involve risks and uncertainties that 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.” 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 17 - Segment Reporting” for financial information about each of our business segments.

 

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 on Form 10-K are forward-looking statements.

 

Although we believe that the forward-looking statements contained in this Annual Report on Form 10-K 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:

 

 

 

Our forward-looking statements speak only as of the date of this Annual Report on Form 10-K. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

 

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 on Form 10-K and other public filings with the Securities and Exchange Commission, before deciding to invest in our common stock. If any of the following 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. Any prolonged substantial reduction in oil and gas prices would

likely affect oil and gas production levels and therefore affect demand for the services we provide. A material decline in oil and gas prices or North American activity levels could 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. For example, over the last three years, the WTI Cushing crude oil spot price has ranged from approximately $27.00 to $77.00 per barrel. The Henry Hub natural gas spot price has ranged from approximately $4.00 to approximately $15.50 per thousand cubic feet (“mcf”). Until recently, these prices have generally been at historically high levels. Gas prices have recently declined substantially from historically high levels. Oil prices have also declined. The increase in prices over the last few years has caused oil and gas companies and drilling contractors to change their strategies and expenditure levels, which has benefited us. However, the recent decline in oil and gas prices may result in a decrease in the expenditure levels of oil and gas companies and drilling contractors which would in turn adversely affect 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 changes in oil and gas prices. We reported a loss in 2002, and our income from continuing operations for the years ended December 31, 2006, 2005, 2004 and 2003 was $137.3 million, $50.9 million, $11.3 million and $0.3 million, respectively.

 

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.

 

There is potential for excess capacity in our industry.

 

Because oil and gas prices and drilling activity have been at historically high levels, oilfield service companies have been acquiring new equipment to meet their customers’ increasing demand for services. If these levels of price and activity decrease, there is a potential for excess capacity in the oilfield service industry. This could result in an increased competitive environment for oilfield service companies, which could lead to lower prices and utilization for our services and could adversely affect our business.

 

We may be unable to employ 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. A significant increase in the wages paid by competing employers 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 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 operating history may not be sufficient for investors to evaluate our business and prospects.

 

We are a company with a short combined operating history. In addition, two of our combining companies, IPS and CES, have grown significantly over the last few years through acquisitions. This may make it more difficult for investors to evaluate our business and prospects and to forecast our future operating results. Our historical combined financial statements are based on the separate businesses of IPS, CES and IEM for the periods prior to the Combination. As a result, the historical and pro forma information may not give you an accurate indication of what our actual results would have been if the Combination had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. Our future results will depend on our ability to efficiently manage our combined operations and execute our business strategy.

 

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 recent private placement of senior notes, 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.

 

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. 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 23% of our revenue for the years ended December 31, 2006 and 2005. Although none of our customers accounted for more than 10% of our revenue during the years ended December 31, 2006 and 2005, our top ten customers represented approximately 37% and 35% of our revenue for the years then ended. 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.

 

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

 

As of December 31, 2006, our long-term debt, including current maturities, was $751.6 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:

 

 

Our business depends upon our ability to obtain key raw materials and specialized equipment from suppliers.

 

Should our current suppliers be unable to provide the necessary raw materials 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 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 acquire additional business opportunities, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

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 Complete’s overall safety record, they may not be successful in doing so.

 

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 through our supply stores, 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.

 

We are subject to extensive and costly environmental laws and regulations that may require us to take actions that will adversely affect our results of operations.

 

Our business is significantly affected by stringent and complex foreign, federal, state and local laws and regulations governing the discharge of substances into the environment or otherwise relating to environmental protection. As part of our business, we handle, transport, and dispose of a variety of fluids and substances used or produced by our customers in connection with their oil and gas exploration and production activities. We also generate and dispose of hazardous waste. The generation, handling, transportation, and disposal of these fluids, substances, and waste are regulated by a number of laws, including 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. Failure to properly handle, transport, or dispose of these materials or otherwise conduct our operations in accordance with these and other environmental laws could expose us to liability for governmental penalties, cleanup costs associated with releases of such materials, damages to natural resources, and other damages, as well as potentially impair our ability to conduct our operations. We could be exposed to liability for cleanup costs, natural resource damages and other damages under these and other environmental laws as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Environmental laws and regulations have changed in the past, and they are likely to change in the future. If existing regulatory requirements or enforcement policies change, we may be required to make significant unanticipated capital and operating expenditures.

 

Any failure by us to comply with applicable environmental laws and regulations may result in governmental authorities taking actions against our business that could adversely impact our operations and financial condition, including the:

 

 

• imposition of limitations on our operations; and

 

 

The effect of environmental laws and regulations on our business is discussed in greater detail under “Environmental Matters” included in Item 1 of this Annual Report on Form 10-K.

The nature of our industry subjects us to compliance with other regulatory laws.

 

Our business is significantly affected by state and federal laws and other regulations relating to the oil and gas industry in general, and more specifically with respect to health and safety, waste management and the manufacture, storage, handling and transportation of hazardous materials and by changes in and the level of enforcement of such laws. The failure to comply with these rules and regulations can result in substantial penalties, revocation of permits, corrective action orders and criminal prosecution. The regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability. We may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances. It is impossible for management to predict the cost or impact of such laws and regulations on our future operations.

 

If we fail to develop or 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 continue to develop and 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. We must comply with Section 404 for our fiscal year ending December 31, 2007. Any failure to develop or maintain effective controls, or difficulties encountered in our implementation or other effective improvement of our internal controls, could harm our operating results.

 

A terrorist attack or armed conflict could harm our business.

 

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

 

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 substantial operations in Canada. As a result, fluctuations in currency exchange rates in Canada could materially and adversely affect our business. For the year ended December 31, 2006, our Canadian operations represented approximately 7% of our revenue from continuing operations and 3% of our net income from continuing operations before taxes and minority interest, compared to approximately 9% of our revenue from continuing operations and 4% of our net income from continuing operations before taxes and minority interest for the year ended December 31, 2005.

 

We are susceptible to seasonal earnings volatility due to adverse weather conditions in Canada.

 

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 frost leaves the ground 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.

 

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.

 

Our business in Mexico is substantially all performed for PEMEX pursuant to multi-year contracts. These contracts are generally two years in duration and are subject to competitive bid for renewal. Any failure by us to renew our contracts could have a material adverse effect on our financial condition, results of operations and cash flows.

 

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 made effective as of October 2006 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.

 

Our U.S. operations are adversely impacted by the hurricane season in the Gulf of Mexico, which generally occurs in the third calendar quarter.

 

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.

 

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 significant 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 reach 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 increase significantly our earnings volatility with respect to rig relocation.

 

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

 

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. 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 state safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations.

 

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.

 

Risks Related to Our Relationship with SCF

 

L.E. Simmons, through SCF, may be able to control the outcome of stockholder voting and may exercise this voting power in a manner adverse to you.

 

SCF owns approximately 35% of our outstanding common stock. L.E. Simmons is the sole owner of L.E. Simmons and Associates, Incorporated, the ultimate general partner of SCF. Accordingly, Mr. Simmons, through his ownership of the ultimate general partner of SCF, may be in a position to control the outcome of matters requiring a stockholder vote, including the election of directors, adoption of amendments to our certificate of incorporation or bylaws or approval of transactions involving a change of control. The interests of Mr. Simmons may differ from yours, and SCF may vote its common stock in a manner that may adversely affect you.

 

Two of our directors may have conflicts of interest because they are affiliated with SCF. The resolution of these conflicts of interest may not be in our or your best interests.

 

Two of our directors, David C. Baldwin and Andrew L. Waite, are current officers of L.E. Simmons and Associates, Incorporated, the ultimate general partner of SCF. This may create conflicts of interest because these directors have responsibilities to SCF and its owners. Their duties as officers of L.E. Simmons and Associates, Incorporated may conflict with their duties as directors of our company regarding business dealings between SCF and us and other matters. The resolution of these conflicts may not always be in our or your best interests.

 

We have renounced any interest in specified business opportunities, and SCF and its director nominees on our board of directors generally have no obligation to offer us those opportunities.

 

SCF has investments in other oilfield service companies that may compete with us, and SCF and its affiliates, other than our company, may invest in other such companies in the future. We refer to SCF and its other affiliates and its portfolio companies as the SCF group. Our certificate of incorporation provides that, so long as we have a director or officer that is affiliated with SCF (an “SCF Nominee”), we renounce any interest or expectancy in any business opportunity in which any member of the SCF group participates or desires or seeks to participate in and that involves any aspect of the energy equipment or services business or industry, other than (i) any business opportunity that is brought to the attention of an SCF Nominee solely in such person’s capacity as a director or officer of our company and with respect to which no other member of the SCF group independently receives notice or otherwise identifies such opportunity and (ii) any business opportunity that is identified by the SCF group solely through the disclosure of information by or on behalf of our company. We are not prohibited from pursuing any business opportunity with respect to which we have renounced any interest.

Risks Related to Our Senior Notes

 

We may not be able to generate sufficient cash to service all of our indebtedness, including the notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.

 

Our ability to make scheduled payments or to refinance our debt obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We cannot assure you that we will maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

 

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets or operations, seek additional capital or restructure or refinance our indebtedness, including the notes. We cannot assure you that we would be able to take any of these actions, that these actions would be successful and permit us to meet our scheduled debt service obligations or that these actions would be permitted under the terms of our existing or future debt agreements including our amended revolving credit facility and the indenture that will govern the notes. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our amended revolving credit facility and the indenture that will govern the notes will restrict our ability to dispose of assets and use the proceeds from the disposition. We may not be able to consummate those dispositions or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due.

 

If we cannot make scheduled payments on our debt, we will be in default and, as a result:

 

 

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 specified financial ratios and satisfy other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those tests. 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. 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.

 

Our borrowings under our amended revolving credit facility are, and are expected to continue to be, at variable rates of interest and 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.

 

If we default on our obligations to pay our indebtedness we may not be able to make payments on our senior notes.

 

Any default under the agreements governing our indebtedness, including a default under our amended revolving credit facility that is not waived by the required lenders, and the remedies sought by the holders of such indebtedness, could render us unable to pay principal, premium, if any, and interest on the notes and substantially decrease the market value of the notes. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness (including covenants in our amended revolving credit facility), we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our amended revolving credit facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. If our operating performance declines, we may in the future need to obtain waivers from the required lenders under our amended revolving credit facility to avoid being in default. If we breach our covenants under our amended revolving credit facility and seek a waiver, we may not be able to obtain a waiver from the required lenders. If this occurs, we would be in default under our amended revolving credit facility, the lenders could exercise their rights, as described above, and we could be forced into bankruptcy or liquidation.

 

Our senior notes and the guarantees will be effectively subordinated to all of our secured debt, and, if a default occurs, we may not have sufficient funds to fulfill our obligations under the notes and the guarantees.

 

Our senior notes are general senior unsecured obligations that rank equally in right of payment with all of our existing and future unsubordinated indebtedness. The notes are effectively subordinated to all our and our subsidiary guarantors’ secured indebtedness to the extent of the value of the assets securing that indebtedness. We have approximately $11.3 million in outstanding letters of credit at December 31, 2006. Our amended revolving credit facility is secured and provides for future borrowings of up to $350.0 million. All borrowings under the amended revolving credit facility are secured by substantially all of our assets and rank effectively senior to the notes and the guarantees. In addition, the indenture governing the notes does, subject to some limitations, permit us to incur additional secured indebtedness, and the senior notes are effectively junior to any additional secured indebtedness we may incur.

 

In the event of our bankruptcy, liquidation, reorganization or other winding up, our assets that secure our secured indebtedness, including our amended revolving credit facility, will be available to pay obligations on the notes only after all secured indebtedness, together with accrued interest, has been repaid in full from our assets. Our failure to comply with the terms of the amended revolving credit facility would entitle those lenders to declare all the funds borrowed thereunder, together with accrued interest, immediately due and payable. Such lenders could then seek to foreclose on substantially all of our assets that serve as collateral. In this event, our secured lenders

would be entitled to be repaid in full from the proceeds of the liquidation of those assets before those assets would be available for distribution to other creditors, including holders of the notes. Holders of the notes will participate in our remaining assets ratably with all holders of our unsecured indebtedness that is deemed to be of the same class as the notes, and potentially with all of our other general creditors. We advise you that there may not be sufficient assets remaining to pay amounts due on any or all the notes then outstanding. The guarantees of the notes will have a similar ranking with respect to secured and unsecured senior indebtedness of the subsidiary guarantors as the notes do with respect to our secured and unsecured senior indebtedness, as well as with respect to any unsecured obligations expressly subordinated in right of payment to the guarantees.

 

We may not be able to repurchase the notes upon a change of control.

 

Upon the occurrence of specific kinds of change of control events, we will be required to offer to repurchase all outstanding notes at 101% of their principal amount plus accrued and unpaid interest. We may not be able to repurchase the notes upon a change of control because we may not have sufficient funds. Further, we may be contractually restricted under the terms of our amended revolving credit facility or other future senior indebtedness from repurchasing all of the notes tendered by holders upon a change of control. Accordingly, we may not be able to satisfy our obligations to purchase the notes unless we are able to refinance or obtain waivers under our amended revolving credit facility. Our failure to repurchase the notes upon a change of control would cause a default under the indenture and a cross default under our amended revolving credit facility. Our amended revolving credit facility also provides that a change of control, as defined in such agreement, will be a default that permits lenders to accelerate the maturity of borrowings thereunder and, if such debt is not paid, to enforce security interests in the collateral securing such debt, thereby limiting our ability to raise cash to purchase the notes, and reducing the practical benefit of the offer to purchase provisions to the holders of the notes. Any of our future debt agreements may contain similar provisions.

 

In addition, the change of control provisions in the indenture may not protect you from certain important corporate events, such as a leveraged recapitalization (which would increase the level of our indebtedness), reorganization, restructuring, merger or other similar transaction, unless such transaction constitutes a “Change of Control” under the indenture. Such a transaction may not involve a change in voting power or beneficial ownership or, even if it does, may not involve a change that constitutes a “Change of Control” as defined in the indenture that would trigger our obligation to repurchase the notes. Therefore, if an event occurs that does not constitute a “Change of Control” as defined in the indenture, we will not be required to make an offer to repurchase our senior notes and the holder may be required to continue to hold the notes despite the event.

 

We may incur substantially more debt. This could further exacerbate the risks described above.

 

We and our subsidiary guarantors may be able to incur substantial additional indebtedness in the future. The terms of the indenture do not fully prohibit us or our subsidiary guarantors from doing so. If we incur any additional indebtedness, including trade payables, that ranks equally with the notes, the holders of that debt will be entitled to share ratably with the holders of the notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding up of our company. This may have the effect of reducing the amount of proceeds available to repay the notes. We have a $350.0 million revolving credit facility with over $200 million of undrawn availability as of December 31, 2006. All of those borrowings will be secured by substantially all of our assets and will rank effectively senior to the notes and the guarantees. If new debt is added to our current debt levels, the related risks that we and our subsidiary guarantors now face could intensify. The subsidiaries that guarantee our senior notes will also be guarantors under our amended revolving credit facility.

 

As a holding company, Complete’s main source of cash is distributions from its subsidiaries.

 

We conduct our operations primarily through our subsidiaries, and these subsidiaries directly own substantially all of our operating assets. Therefore, our operating cash flow and ability to meet our debt obligations depend principally on the cash flow provided by our subsidiaries in the form of loans, dividends or other payments to us as an equity holder, service provider or lender. The ability of our subsidiaries to make such payments to the parent company will depend on their earnings, tax considerations, legal restrictions and contractual restrictions imposed by their own indebtedness. Although our debt facilities limit the right of certain of our subsidiaries to enter into

consensual restrictions on their ability to pay dividends and make other payments to us, these limitations are subject to a number of significant qualifications and exceptions.

 

In addition, not all of our subsidiaries guarantee our obligation under the senior notes. Creditors of such subsidiaries (including trade creditors) generally will be entitled to payment from the assets of those subsidiaries before those assets can be distributed to us. As a result, our senior notes are effectively subordinated to the prior payment of all of the debts (including trade payables) of our non-guarantor subsidiaries.

 

None.

 

As of December 31, 2006, we owned 51 offices, facilities and yards, of which 11 were in Texas, 22 were in Oklahoma, two were in Arkansas, one was in North Dakota, one was in Montana, six were in Wyoming, three were in Colorado, three were in Louisiana, one was in Alberta, Canada, and one was in Poza Rica, Mexico. As of December 31, 2006, we owned 51 saltwater disposal wells, of which 17 were in Texas, 32 were in Oklahoma and two were in Arkansas. In addition, we owned one drilling mud disposal facility in Oklahoma and one produced water evaporation facility in Wyoming.

 

In addition, as of December 31, 2006, we leased 199 offices, facilities and yards, of which 63 were in Texas, 29 were in Oklahoma, 24 were in Wyoming, 27 were in Colorado, four were in Louisiana, seven were in Arkansas, two were in Kansas, two were in Utah, 28 were in Alberta, Canada, one was in British Columbia, Canada, five were in Mexico and seven were in Singapore. As of December 31, 2006, we leased two drilling mud disposal facilities in Oklahoma and we leased two salt water disposal wells in Texas.

 

In addition, we also leased our corporate headquarters in Houston, Texas, as well as administrative offices in Gainesville, Texas; Enid, Oklahoma; Fredrick, Colorado; Eunice, Louisiana; Calgary, Alberta, Canada; and additional office space in Houston, Texas.

 

We are 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 that 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 businesses.

 

Although we cannot know the outcome of pending legal proceedings and the effect such outcomes may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, 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.

 

None.

 

We have 200,000,000 authorized shares of $0.01 par value common stock, of which 72,108,546 shares were outstanding at December 31, 2006 including 690,073 shares of non-vested restricted stock for which the forfeiture restrictions have not lapsed. At March 1, 2007, we had 72,277,676 shares of common stock outstanding, of which 746,873 shares were non-vested restricted stock subject to forfeiture restrictions. The common shares outstanding at March 1, 2007 were held by 170 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, 2006 or March 1, 2007.

 

On April 20, 2006, we entered into an underwriting agreement in connection with our initial public offering and became subject to the reporting requirements of the Securities Exchange Act of 1934. 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 by the New York Stock Exchange for the period April 20, 2006 through June 30, 2006, and the calendar quarters ended September 30, 2006 and December 31, 2006:

 

 

Issuer Purchases of Equity Securities:

 

We made no repurchases of our common stock during the year ended December 31, 2006.

 

Dividends:

 

On September 12, 2005, we paid a dividend of $2.62 per share for an aggregate payment of approximately $146.9 million to stockholders of record on that date. We 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 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, 2006. 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 8 MONTH CUMULATIVE TOTAL RETURN*

Among Complete Production Services, Inc, The S & P 500 Index

And The PHLX Oil Service Sector Index

 

 

 

Copyright ^© 2007, Standard & Poor’s, a division of The McGraw-Hill Companies, Inc. All rights reserved. www.researchdatagroup.com/S&P.htm

 

The following table presents selected historical consolidated financial and operating data for the periods shown. The selected consolidated financial data as of December 31, 2002 and for the year then ended have been derived from the consolidated financial statements of IPS for such date and period. The selected consolidated financial data as of December 31, 2003 has been derived from our consolidated financial statements. The selected consolidated financial data as of December 31, 2004, 2005 and 2006 and for each of the years then ended have been derived from our audited consolidated financial statements for those dates and periods. 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 in this Annual Report on Form 10-K.

 

 

 

 

 

 

 

Reconciliation of EBITDA

 

 

 

The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included within this Annual Report on Form 10-K. This discussion contains forward-looking statements based on our current expectations, assumptions, estimates and projections about us and the oil and gas industry. These forward-looking statements involve risks and uncertainties that may be outside of our control. Our actual results could differ materially from those indicated in these 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, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in “Risk Factors.” In light of these risks, uncertainties and assumptions, the forward-looking events discussed below may not occur. Except to the extent required by law, we undertake no obligation to update publicly any forward-looking statements, even if new information becomes available or other events occur in the future.

 

Overview

 

We are a leading provider of specialized 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, Kansas, western Canada, Mexico and Southeast Asia.

 

On September 12, 2005, we completed the Combination (see “Business  — The Combination”) of Complete Energy Services, Inc. (“CES”), Integrated Production Services, Inc. (“IPS”) and I.E. Miller Services, Inc. (“IEM”) pursuant to which the CES and IEM shareholders exchanged all of their common stock for common stock of IPS.

The Combination was accounted for using the continuity of interests method of accounting, which yields results similar to the pooling of interest method. Subsequent to the Combination, IPS changed its name to Complete Production Services, Inc.

 

On April 26, 2006, we completed our initial public offering and our common stock is currently trading on the New York Stock Exchange under the symbol “CPX”. The total offering amount was approximately $718 million, consisting of approximately $312 million in a primary offering (less underwriters’ fees and discounts) and approximately $406 million in a secondary offering by selling stockholders.

 

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, specialized rig logistics and site preparation. Our drilling rigs currently operate exclusively in and around the Barnett Shale region of north Texas.

 

Product Sales.   Through our product sales segment, we provide a variety of equipment used by oil and gas companies throughout the lifecycle of their wells. Our current product offering includes completion, flow control and artificial lift equipment as well as tubular goods. We sell products throughout North America primarily through our supply stores. We also sell products through agents in markets outside of North America.

 

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. 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 factor influencing demand for our services and products is the level of drilling and workover activity of our customers, 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 historical commodity prices as provided by Bloomberg:

 

AVERAGE RIG COUNTS

 

 

 

Source:  BHI (www.BakerHughes.com)

 

AVERAGE OIL AND GAS PRICES

 

 

 

Source:  Bloomberg NYMEX prices.

 

We consider the number of 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. We evaluate the utilization of our assets as a measure of operating performance. This utilization can be impacted by these and other external and internal factors. See “Risk Factors.”

 

We generally charge for our services on a dayrate basis. Depending on the specific service, a dayrate may include one or more of these components: (1) a set-up charge, (2) an hourly service rate based on equipment and labor, (3) an equipment rental charge, (4) a consumables charge, and (5) 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 or through turnkey contracts. Product sales are generated through our supply stores and through wholesale distributors, using a purchase order process and a pre-determined price book.

 

Outlook

 

Our growth strategy includes a focus on internal growth in our current basins by increasing current equipment utilization, adding additional like-kind equipment and expanding service and product offerings. In addition, we identify new basins in which to replicate this approach. We also augment our internal growth through strategic acquisitions.

 

 

In recent months, oil and gas commodity prices have declined from historical highs. This trend could be the result of a number of macro-economic factors, such as a perceived excess supply of natural gas, lower demand for oil and gas or the use of alternate fuels, market expectations of weather conditions and lower-than-expected utilization of heating fuels, the cyclical nature of the oil and gas industry and other general market conditions for the U.S. economy. Although we cannot determine the impact that lower commodity prices may have on our business or whether such a decline in commodity prices will be long-term, we believe that North American oilfield activity levels will remain robust through 2007, especially in the Rocky Mountain region, Barnett Shale of north Texas, Anadarko basin in the Mid-continent region and the Arkoma Basin, including the Fayetteville Shale in Arkansas. We believe the outlook remains favorable from an activity and pricing perspective. We are currently evaluating our acquisition prospects and expect to acquire businesses during 2007 which provide a future benefit in terms of service offerings and synergies with our current operations.

 

Significant Acquisitions

 

 

 

 

In addition, we completed several other smaller acquisitions, each of which has contributed to the expansion of our business into new geographic regions or enhanced our service and product offerings.

 

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, with the exception of the Combination, which was accounted for using the continuity of interest accounting method. Results of operations related to each of the acquired companies have been included in our combined operations as of the date of acquisition.

 

On October 31, 2006, we completed the sale of the disposal group which included certain manufacturing and production enhancement product operations of a subsidiary located in Alberta, Canada, as well as operations in south Texas, for approximately $19.3 million in cash, with an additional amount subject to a working capital adjustment, and a $2.0 million Canadian dollar denominated note which matures on October 31, 2009 and accrues interest at a specified Canadian bank prime rate plus 1.50% per annum. We sold this disposal group to Paintearth Energy Services, Inc., an oilfield service company located in Calgary, Alberta, Canada, that employs two of our former employees as key managers. The carrying value of the related net assets was $21.7 million on October 31, 2006. We recorded a loss on the sale of this disposal group totaling approximately $0.6 million, which included a transaction gain associated with the release of cumulative translation adjustment associated with this business, and a $1.0 million charge to expense related to capital taxes in Canada. The sales agreement allowed Paintearth Energy Services, Inc. to use our subsidiary’s trade name for a period of 120 days from November 1, 2006 through February 28, 2007.

 

Marketing 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.

 

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 7% and 9% of total revenues from continuing operations during the years ended December 31, 2006 and 2005, respectively.

 

Critical Accounting Policies and Estimates

 

The preparation of our consolidated financial statements in conformity with 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 1 of the notes to the consolidated financial statements contained elsewhere in this Annual Report on Form 10-K. 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.

 

Continuity of Interests Accounting

 

We applied the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 141, “Business Combinations” to account for the formation of Complete. SFAS No. 141 permits us to account for the combination of several predecessor companies using a method similar to a pooling of interests if each is controlled by a common stockholder. In connection with the Combination, we paid a dividend to our stockholders of $2.62 per share and adjusted the number of shares subject to, and exercise price of, outstanding stock options and restricted shares in accordance with Financial Accounting Standards Board (“FASB”) Interpretation No. 44, “Accounting for Certain Transactions Involving Stock Compensation, an Interpretation of Accounting Principles Board (“APB”) Opinion No. 25.” On September 12, 2005, we completed the transaction, pursuant to which CES and IEM stockholders exchanged all of their common stock for common stock of IPS. CES stockholders received 19.704 shares of IPS common stock for each share of CES common stock, and IEM stockholders received 19.410 shares of IPS common stock for each share of IEM common stock. In connection with the Combination, IPS changed its name to Complete Production Services, Inc. We acquired the interests of the minority stockholders in these predecessor companies as of the date of the consummation and accounted for these transactions using the purchase method of accounting, resulting in goodwill of $93.8 million, which represented the excess of the purchase price over the carrying value of the net assets acquired.

 

Application of SFAS No. 141 is required under U.S. GAAP when entities under common control are combined.

 

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 day-rate 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 day rate 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 and record revenues as products are sold. We did not record material adjustments resulting from revenue recognition issues for the years ended December 31, 2006, 2005 and 2004.

 

Impairment of Long-Lived Assets

 

We evaluate potential impairment of long-lived assets and intangibles, excluding goodwill and other intangible assets without defined services lives, when indicators of impairment are present, as defined in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” 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 apply the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets,” which requires an annual impairment test, whereby we estimate the fair value of the asset by discounting future cash flows at our 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 consistent with that described in SFAS No. 141. 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, 2006, 2005, and 2004, and management determined that goodwill was not impaired. A significant decline in expected future cash flow as a result of lower sales could result in an impairment charge. A 10% impairment of goodwill at December 31, 2006 would have decreased our operating income by $55.3 million for the year then ended.

 

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 non-vested restricted stock. We adopted SFAS No. 123R, “Share-Based Payment,” on January 1, 2006, which impacted our accounting treatment of employee stock options. As required by SFAS No. 123R, we continue to account for stock-based compensation for grants made prior to September 30, 2005, the date of our initial filing with the SEC, using the minimum value method prescribed by APB No. 25, 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. However, for grants of stock-based compensation between October 1, 2005 and December 31, 2005 (prior to adoption of SFAS No. 123R), we have utilized the modified prospective transition method to record expense associated with these options. Under this transition method, we did not record compensation expense associated with these stock option grants during the period October 1, 2005 through December 31, 2005, but will provide pro forma disclosure of this expense as appropriate. However, we will recognize expense related to these

grants over the remaining vesting period, based upon a calculated fair value. For grants of stock-based compensation on or after January 1, 2006, we apply the prospective transition method under SFAS No. 123R, whereby 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 non-vested restricted stock which has been granted to certain of our directors, officers and employees. In accordance with SFAS No. 123R, 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.

 

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 years ended on or before December 31, 2005, we determined the value of our stock options by applying the minimum value method permitted by APB No. 25 and, in connection with estimating compensation expense that would be required to be recognized under SFAS No. 123, “Accounting for Stock-Based Compensation,” we used a Black-Scholes model including assumptions for expected term (ranging from 3 to 4.5 years as of December 31, 2005), risk- free rate (based upon published rates for U.S. Treasury notes with a similar term), zero dividend rate and a volatility rate of zero. For the year ended December 31, 2006, we applied a Black-Scholes model with similar assumptions, except we estimated our stock volatility by examining the volatility rates of several peer companies, we estimated a forfeiture rate based upon our historical experience and we estimated the expected term of the options using a probability analysis. For the year ended December 31, 2006, we have recorded compensation expense totaling $1.8 million related to our stock option grants and $2.8 million related to our non-vested restricted stock.

 

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 has been less than 1% of sales for the years ended December 31, 2006, 2005 and 2004. If bad debt expense had increased by 1% of sales for the years ended December 31, 2006, 2005 and 2004, net income would have declined by $7.7 million, $4.4 million and $1.8 million, respectively. Our obsolescence and other inventory reserves as of December 31, 2006, 2005 and 2004 have ranged from 4% to 8%. Our obsolescence and other inventory reserves were approximately 4% and 6% of inventory at December 31, 2006 and 2005, respectively. A 1% increase in inventory reserves, from 4% to 5%, at December 31, 2006 would have decreased net income by $0.3 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.

 

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. There have been no significant impairment charges related to our long-term assets during the years ended December 31, 2006, 2005 and 2004. Depreciation and amortization expense for the years ended December 31, 2006 and 2005 represented 15% and 16% of the average depreciable asset base for the respective years. An increase in depreciation relative to the depreciable base of 1%, from 15% to 16%, would have reduced net income by approximately $3.4 million for the year ended December 31, 2006.

 

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 using SFAS No. 109, “Accounting for Income Taxes.” Under SFAS No. 109, we 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, SFAS No. 109 requires us to record a valuation allowance for any net deferred income tax assets which we believe are likely to not be used through future operations. As of December 31, 2006, 2005 and 2004, 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, 2006, we did not provide deferred U.S. income taxes on approximately $11.3 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. We are currently evaluating the impact of FIN 48 on our financial position, results of operations and cash flows. FIN 48 became effective on January 1, 2007.

 

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 $5.4 million at December 31, 2006, against which we recorded a valuation allowance of $0.7 million, leaving a net deferred tax asset of $4.7 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 SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 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, 2006 and 2005

 

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.

 

“EBITDA” consists of net income (loss) from continuing operations before interest expense, taxes, depreciation and amortization and minority interest. EBITDA is a non-cash measure of performance. We use EBITDA as the primary internal management measure for evaluating performance and allocating additional resources. See the discussion of EBITDA at Note 3 under Item 6 (“Selected Financial Data”) of this Annual Report on Form 10-K. The following table reconciles EBITDA for the years ended December 31, 2006 and 2005 to the most comparable GAAP measure, operating income (loss).

 

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

 

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

 

Year Ended December 31, 2006 Compared to the Year ended December 31, 2005

 

Revenue

 

Revenue for the year ended December 31, 2006 increased by $492.2 million, or 68%, to $1,212.4 million from $720.2 million for the year ended December 31, 2005. 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 $260.2 million, or 58%, to $711.0 million for the year ended December 31, 2006 from $450.7 million for the year ended December 31, 2005. The following table summarizes service and product expenses as a percentage of revenues for the years ended December 31, 2006 and 2005:

 

Service and Product Expenses as a Percentage of Revenue

 

 

The decline in service and product expenses as a percentage of revenue reflects improved margins as a result of: (1) a favorable mix of services and products, (2) improved pricing for our services, as more revenue was earned in 2006 from higher margin services in the United States and (3) a general increase in customer demand for oil and gas services and products throughout 2006, offset partially by rising labor, fuel, insurance and equipment costs. We were able to obtain more favorable pricing for our completion and production services segment and drilling services segment for these periods as a result of higher customer demand for these services primarily in the Barnett Shale region of north Texas, and the impact of acquired businesses. Margins associated with our product sales business declined slightly compared to the respective period in 2005, due primarily to the product mix and costs associated with opening new supply stores.

 

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 increased $58.6 million, or 54%, for the year ended December 31, 2006 to $167.3 million from $108.8 million during the year ended December 31, 2005. These expense increases were primarily due to acquisitions, which provided additional headcount, property rental expense, insurance expense and other administrative costs, as well as additional expense for incentive compensation accruals based on earnings. In addition, as a result of the Combination, we employed additional senior officers and key members of management at our corporate office. Furthermore, we incurred consulting costs associated with information technology and Sarbanes-Oxley projects, additional outside accounting, tax and legal fees associated with audits of subsidiaries, tax compliance and legal matters, and recorded incremental costs of approximately $1.0 million related to amortization of non-vested restricted stock and approximately $1.8 million of expense associated with employee stock options as a result of the adoption of SFAS No. 123R on January 1, 2006. As a percentage of revenues, selling, general and administrative expense declined to 14% for the year ended December 31, 2006 compared to 15% for the year ended December 31, 2005.

 

Depreciation and Amortization

 

Depreciation and amortization expense increased $31.0 million, or 64%, to $79.5 million for the year ended December 31, 2006 from $48.5 million for the year ended December 31, 2005. The increase in depreciation and amortization expense was the result of placing into service equipment that was purchased during 2006. Capital expenditures for equipment in 2006 totaled $303.9 million. In addition, we recorded depreciation and amortization expense related to businesses acquired in 2005 and assets purchased and placed into services throughout 2005, which contributed a full year of depreciation expense in 2006 compared to a partial year of depreciation expense in 2005, and we recorded depreciation and amortization associated with business acquisitions in 2006. As a percentage of revenue, depreciation and amortization expense decreased by less than 1% for the year ended December 31, 2006 compared to the year ended December 31, 2005.

 

Interest Expense

 

Interest expense was $40.8 million and $24.5 million for the years ended December 31, 2006 and 2005, respectively. The increase in interest expense was attributable to an increase in the average amount of debt outstanding, including amounts borrowed to fund the dividend paid in connection with the Combination, borrowings for investment in capital expenditures, and acquisitions. In December 2006, we retired all outstanding borrowings under the term loan portion of our credit facility with proceeds from the issuance of 8% senior notes. The weighted-average interest rate of borrowings outstanding at December 31, 2006 and 2005 was approximately 7.84% and 7.22%, respectively. The increase in the borrowing rate was due to higher average borrowings under variable interest rate facilities in 2006 compared to 2005, a higher fixed interest rate on our senior notes issued in December 2006 compared to the average variable interest rate on our facilities outstanding in 2005, and a general increase in LIBOR and the U.S. prime interest rate throughout this two-year period.

 

Interest Income

 

Interest income was $1.4 million for the year ended December 31, 2006. This interest income was primarily earned on cash invested in short-term municipal bond funds and similar investments. The cash was received as a portion of the net proceeds from our initial public offering in April 2006, and was utilized for the purchase of equipment, business acquisitions and other corporate purposes throughout the period from the date of the initial public offering through December 31, 2006.

 

Taxes

 

Tax expense 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.

 

Tax expense was 36.2% and 39.2% of pretax income for the years ended December 31, 2006 and 2005, respectively. The change in the effective tax rate in 2006 compared to 2005 reflects the composition of earnings in domestic versus foreign tax jurisdictions, the effect of state and provincial income taxes, the timing of the use of net operating loss carry forwards and the benefit of the recently enacted domestic production activities deduction. The effective rates for 2006 also reflect the benefit derived from tax-free and tax-advantaged interest income received during the year ended December 31, 2006.

 

Write-off of Deferred Financing Costs

 

The write-off of $3.3 million of deferred financing costs in 2005 represents the remaining unamortized debt issuance costs associated with a term loan and revolving credit facility that was retired at the time of the Combination and replaced with our new credit facility. In December 2006, we retired all outstanding borrowings under Pumpco’s term loan facility, which was assumed at the date of acquisition, resulting in the write-off of the remaining unamortized debt issuance costs totaling $0.2 million.

 

Minority Interest

 

Minority interest was comprised entirely of an ownership interest by an unrelated third party in the assets of Premier Integrated Technologies, Inc. (“Premier”), a company that we acquired on January 1, 2005. We have consolidated Premier in our accounts since the date of acquisition and record minority interest to reflect the ownership held by this third party. Prior to the Combination, IPS recorded the stock ownership of the minority shareholders in CES and IEM as minority interest. Upon consummation of the Combination, this minority interest was removed.

 

Discontinued Operations

 

Discontinued operations represent the results of operations, net of tax, of certain manufacturing and production enhancement operations of a Canadian subsidiary, including related assets located in south Texas. This disposal group was sold on October 31, 2006.

 

Results of Operations for Years Ended December 31, 2005 and 2004

 

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