Item 1.
Business
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, Pennsylvania, 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 into 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.
In April 2006, we completed our initial public offering and became subject to the reporting requirements of the Securities Exchange Act of 1934.
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:
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Intervention Services. Well intervention requires the use of specialized equipment to perform an array of wellbore services. Our fleet of intervention service equipment includes coiled tubing units, pressure pumping units, nitrogen units, well service rigs, snubbing units and a variety of support equipment. Our intervention services provide customers with innovative solutions to increase production of oil and gas.
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Downhole and Wellsite Services. Our downhole and wellsite services include electric-line, slickline, production optimization, production testing, rental and fishing services.
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Fluid Handling. We provide a variety of services to help our customers obtain, move, store and dispose of fluids that are involved in the development and production of their reservoirs. Through our fleet of specialized trucks, frac tanks and other assets, we provide fluid transportation, heating, pumping and disposal services for our customers.
Drilling Services. Through our drilling services segment, we provide services and equipment that initiate or stimulate oil and gas production by providing land drilling and specialized rig logistics services. Our drilling rigs operate primarily in and around the Barnett Shale region of north Texas.
Product Sales. We provide oilfield service equipment and refurbishment of used equipment through our Southeast Asian business, and we provide repair work and fabrication services for our customers at a location in Gainesville, Texas.
Our Industry
Our business depends on the level of exploration, development and production expenditures made by our customers. These expenditures are driven by the current and expected future prices for oil and gas, and the perceived stability and sustainability of those prices. Our business is primarily driven by natural gas drilling activity in North America. While demand for natural gas has recently declined, due in part to the global recession, we believe that the long-term demand for natural gas in North America will be high and that supply may be constrained as natural gas basins become more mature and experience declines.
As illustrated in the table below, natural gas and oil commodity prices had risen in recent years but began to decline in late 2008. While the price of oil rebounded somewhat in 2009, the price of natural gas remained relatively low. The WTI Cushing spot price of a barrel of crude oil reached an all-time high of $145.31 per barrel in July 2008 and then dropped sharply by the end of the year, falling as low as $30.28 per barrel on December 23, 2008 before trending upwards again in late 2009. The number of drilling rigs under contract in the United States and Canada and the number of active well service rigs decreased in 2009, according to Baker Hughes Incorporated (“BHI”) and the Cameron International Corporation/Guiberson/AESC Service Rig Count for “Active Rigs.” The table below sets forth average daily closing prices for the WTI Cushing spot oil price and the average daily closing prices for the Henry Hub price for natural gas since 2000:
Source: Bloomberg NYMEX prices.
The closing spot price of a barrel of WTI Cushing oil at December 31, 2009 was $79.36, and the closing spot price for Henry Hub natural gas ($/mcf) was $5.82.
Long-term trends which we believe will affect our industry include:
Trend toward drilling and developing unconventional North American hydrocarbon resources. Due to the maturity of conventional North American oil and gas reservoirs and their accelerating production decline rates, unconventional 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 are more service-intensive and may require more wells to be drilled and maintained 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, techniques and equipment. The development of unconventional oil and gas resources is driving the need for complex, new technologies, completion techniques and equipment to help increase recovery rates, lower production costs and accelerate field development.
Natural gas is generally placed into storage during the warmer months of the year and withdrawn during colder months. The amount of natural gas in storage can impact current natural gas prices and prices quoted on futures exchanges. Although economic conditions may reduce demand for natural gas near-term, we believe the long-term fundamentals for our industry are positive. Additionally, natural gas prices can be impacted by the ability to move
gas from producing areas to consuming areas of North America from time to time. For example, due to the significant level of natural gas drilling in western Colorado and southwest Wyoming, pipeline capacity became constrained in late 2006 and continued into 2007, contributing to a short-term decline in natural gas prices in these areas until additional pipeline capacity was added. Fluctuations in commodity prices and availability of gas supply through pipeline capacity can impact the level of drilling activity by our customers as they adjust investment levels commensurate with their revenues.
Our Business Strategy
Our goal is to build the leading oilfield services company focused on the completion and production phases in the life of an oil and gas well. We intend to capitalize on the emerging trends in the North American marketplace through the execution of a growth strategy that consists of the following components:
Focus on execution and performance. We have established and intend to develop further a culture of performance and accountability. Senior management spends a significant portion of its time ensuring that our customers receive the highest levels of service quality and execution at the well site by focusing on the following:
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clear business direction;
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thorough planning process;
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clearly defined targets and accountabilities;
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close performance monitoring;
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safety objectives;
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performance incentives for management and employees; and
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effective communication.
Expand and capitalize on local leadership and basin-level expertise. A key component of our strategy is to build upon our base of strong local leadership and basin-level expertise. We have a significant presence in most of the key onshore continental U.S. and Canadian resource plays that we believe have the potential for long-term growth. Our position in these basins capitalizes on our local leadership who 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 resource plays. We also intend to replicate this approach in new regions by building and acquiring new businesses that have strong regional management with extensive local knowledge.
Develop and deploy technical and operational solutions. We are focused on developing and deploying technical services, equipment and expertise that lower our customers’ costs.
Capitalize on organic and acquisition-related growth opportunities. We believe there are numerous opportunities to expand our service offerings in our current geographic areas and to sell our current services and products to customers in new geographic areas. We have a proven track record of organic growth and successful acquisitions, and we intend to continue using capital investments and acquisitions to strategically expand our business over the long-term. In 2009, we significantly reduced our capital expenditures and did not complete any cash acquisitions primarily due to difficult market conditions. We will continue to monitor the market in 2010, but anticipate that we will invest more in capital expenditures in 2010 compared to 2009.
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, Pennsylvania, Oklahoma, western Canada and Mexico, with concentrations in key “resource play” and unconventional basins. Resource plays are expected to continue to increase in importance in future North American oil and gas production as more conventional resources enter later stages of the exploration and development cycle. We believe we have an excellent position in highly active markets such as the Bakken Shale area of North Dakota, the Haynesville Shale area of east Texas and northern Louisiana, the Marcellus Shale area of Pennsylvania, the Barnett Shale region of north Texas, the Fayetteville Shale in Arkansas and the Woodford Shale area in Oklahoma, 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 higher demand for our services and products. In addition, our presence in these regions allows us to build solid customer relationships and take advantage of cross-selling opportunities.
Focus on complementary production and field development services. Our breadth of service and product offerings positions us well relative to our competitors. Our services encompass the entire lifecycle of a well from drilling and completion, through production and eventual abandonment. We deliver complementary services and products, which we may provide in tandem or sequentially over the life of the well. This suite of services and products gives us the opportunity to cross-sell to our customer base throughout our geographic regions. Leveraging our local leadership and basin-level expertise, we are able to offer expanded services and products to existing customers or current services and products to new customers.
Innovative approach to technical and operational solutions. We develop and deploy services and products that enable our customers to increase production rates, stem production declines and reduce the costs of drilling, completion and production. The significant expertise we have developed in our areas of operation offers our customers customized operational solutions to meet their particular needs. Our ability to develop these technical and operational solutions is possible due to our understanding of applicable technology, our basin-level expertise and our close local relationships with customers.
Modern and active asset base. We have a modern and well-maintained fleet of coiled tubing units, pressure pumping equipment, wireline units, well service rigs, snubbing units, fluid transports, frac tanks and other specialized equipment. We believe our ongoing investment in our equipment allows us to better serve the diverse and increasingly challenging needs of our customer base. New equipment is generally less costly to maintain and operate on an annual basis and is more efficient for our customers. Modern equipment reduces downtime, including associated costs and expenditures, and enables increased utilization of our assets. We believe our future expenditures will be used to capitalize on growth opportunities within the areas we currently operate and to build out 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, overseeing corporate governance procedures and administering a company-wide safety program.
Overview of Our Segments
We manage our business through three segments: completion and production services, drilling services and product sales. Within each of these segments, we perform services and deliver products, as detailed in the table
below. We constantly monitor the North American market for opportunities to expand our business by building our presence in existing regions and expanding our services and products into attractive, new regions.
See Note 15 of the notes to the consolidated financial statements included elsewhere in this Annual Report for financial information about our operating segments and about geographic areas.
“ü” denotes a service or product currently offered by us in this area.
Completion and Production Services (85% of Revenue for the Year Ended December 31, 2009)
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:
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Completion Services. As newly drilled oil and gas wells are prepared for production, our operations may include selectively perforating the well casing to access producing zones, stimulating and testing these zones and installing downhole equipment. We provide intervention services and products to assist in the performance of these services. The completion process typically lasts from a few days to several weeks, depending on the nature and type of the completion. Oil and gas producers use our intervention services to complete their wells because we have well-maintained equipment, well-trained employees, the experience necessary to perform such services and a strong record for safety and reliability.
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Workover Services. Producing oil and gas wells occasionally require major repairs or modifications, called “workovers.” These services include extensions of existing wells to drain new formations either through deepening wellbores to new zones or by drilling horizontal lateral wellbores to improve reservoir drainage patterns. In less extensive workovers, we provide services and products to seal off depleted zones in existing wellbores and access previously bypassed productive zones. Other workover services which we provide include: major subsurface repairs, such as casing repair or replacement; recovery of tubing and removal of foreign objects in the wellbore; repairing downhole equipment failures; plugging back the bottom of a well
to reduce the amount of water being produced; cleaning out and recompleting a well if production has declined; and repairing leaks in the tubing and casing.
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Maintenance Services. Maintenance services are required throughout the life of most producing oil and gas wells to ensure efficient and continuous operation. We provide services that include mechanical repairs necessary to maintain production from the well, such as repairing inoperable pumping equipment or replacing defective tubing, and removing debris from the well. Other services include pulling rods, tubing, pumps and other downhole equipment out of the wellbore to identify and repair a production problem.
The key intervention assets we use to perform intervention services follow:
Coiled Tubing Units and Nitrogen Units
We are one of the leading providers of coiled tubing services in North America. We operate a fleet of coiled tubing units, as well as nitrogen units. We use these assets to perform a variety of wellbore applications, including plug drilling, foam washing, acidizing, displacing, cementing, gravel packing, fishing and jetting. Coiled tubing is a key segment of the well service industry today, which allows operators to continue production during service operations without shutting in the well, thereby reducing the risk of formation damage. The growth in deep well and horizontal drilling has increased the market for coiled tubing. We provide coiled tubing services primarily in Oklahoma, Texas, Louisiana, Arkansas, Pennsylvania, Wyoming, North Dakota, Mexico and offshore in the Gulf of Mexico.
Pressure Pumping Services
We operate fleets of pressure pumping equipment in the Barnett Shale of north Texas, in the Bakken Shale of North Dakota and in the Marcellus Shale of Pennsylvania through which we provide stimulation and cementing services principally to oil and gas production companies.
Stimulation services primarily consist of hydraulic fracturing of hydrocarbon bearing formations which lack permeability to permit the natural flow. The fracturing process consists of pumping fluids into a well at pressures that are sufficient enough to fracture the formation. Materials such as sand and synthetic proppants are pumped into the fracture to prop open the fracture, permitting the hydrocarbons in the formation to flow into the wellbore and ultimately to the surface. Various pieces of specialized equipment are used in the process, including a blender, which is used to blend the proppant into the fluid, multiple high pressure pumping units capable of pumping significant volumes at high pressures, and real-time monitoring equipment where the progress of the process is controlled. Our fracturing units are capable of pumping slurries at pressures up to 10,000 pounds per square inch.
Cementing services consist of blending special cement with water and various solid and liquid additives to form a cement slurry that can be pumped into a well between the casing and the wellbore. Cementing services are principally performed in connection with primary cementing, where the casing used to line a wellbore after a well has been drilled is cemented into place. The purpose of primary cementing is to isolate fluids behind the casing between productive formations and non-productive formations that could damage the productivity of the well or damage the quality of freshwater acquifers, seal the casing from corrosive formation fluids, and to provide structural support for the casing string.
Well Service Rigs
We own and operate a large fleet of well service rigs, of which a significant number were either recently constructed or have been rebuilt over the past six years. We believe we have leading market positions in the Barnett Shale region of north Texas, the Haynesville Shale of east Texas and northern Louisiana and in some of the most active basins of the U.S. Rocky Mountain region. We also operate swabbing units, some of which are highly customized hydraulic units which we use to diagnose and remediate gas well production problems. We provide well service rig operations in Wyoming, Colorado, Utah, Montana, North Dakota, Louisiana, Oklahoma and Texas. These rigs are used to perform a variety of completion, workover and maintenance services, such as installations, completions, assisting with perforating, removing defective equipment and sidetracking wells.
Snubbing Units
We operate a fleet of snubbing units, several of which are rig assist units. Snubbing services use specialized hydraulic well service units that permit an operator to repair damaged casing, production tubing and downhole production equipment in high-pressure, “live-well” environments. A snubbing unit makes it possible to remove and replace downhole equipment while maintaining pressure in the well. Applications for snubbing units include “live-well” completions and workovers, underground blowout control, underbalanced completions, underbalanced drilling and the snubbing of tubing, casing or drillpipe into or out of the wellbore. Our snubbing units operate primarily in Texas 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. Wireline services are used to evaluate downhole well conditions, to initiate production from a formation by perforating a well’s casing, and to provide mechanical services such as setting equipment in the well, or fishing lost equipment out of a well. We provide wireline services in the western Canadian Sedimentary Basin, Wyoming, Colorado, North Dakota, Pennsylvania, Oklahoma and Texas.
With our fleet of wireline equipment we provide the following services:
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Electric-Line Services:
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Perforating Services. Perforating involves positioning a perforating gun that contains explosive jet charges down the wellbore next to a productive zone. A detonator is fired and primer cord is ignited, which then detonates the jet charges. The resulting explosion burns a hole through the wellbore casing and cement and into the formation, thus allowing the formation fluid to flow into the wellbore and be produced to the surface. The perforating gun may be deployed in a number of ways. The gun can be conveyed by a conventional wireline cable if the wellbore geometry allows, it may be conveyed on coiled tubing, it may be conveyed on conventional tubing or the gun may be “pumped-down” to the correct depth in the wellbore.
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Logging Services. Logging requires the use of a single or multi-conductor, braided steel cable (electric-line), mounted on a hydraulically operated drum, and a specialized logging truck. Electronic instruments are attached to the end of the cable and lowered to the bottom of the well and the line is slowly pulled out of the well, transmitting wellbore data up the cable to the surface where the information is processed by a surface computer system and displayed on a graph in a logging format. This information is used by customers to analyze different downhole formation structures, to detect the presence of oil, gas and water and to check the integrity of the casing or the cement behind the pipe. Logs are also used to detect gas or fluid migration between zones or to the surface.
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Slickline Services. Slickline services are used primarily for well maintenance. The line used for this application is generally a small single steel line. Typical applications of this service would include bottom hole pressure surveys, running temperature gradients, setting tubing plugs, opening and closing sliding sleeves, fishing operations, plunger lift installations, gas lift installations and other maintenance services that a well might require during its lifecycle.
Production Optimization Services. Our production optimization services provide customers with technical solutions to stem declining production that results from liquid loading, reduced bottom-hole pressures or improper wellsite designs. We assist in identifying candidates, designing solutions, executing on-site and following up to ensure continued performance. We have developed proprietary technologies that allow us to enhance recovery for our customers and provide on-going service. Specific services we provide include:
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Plunger Lift Services and Products. We provide plunger lift candidate selection, installation and maintenance services which may incorporate the use of our patented Pacemaker Plunger Lift System.
Plunger lift systems facilitate the removal of fluids that restrict the production of natural gas wells. Removing fluids that accumulate in wells increases production and, in many cases, slows decline rates. The proprietary design of our Pacemaker Plunger Lift System incorporates a large bypass area which allows it to make more trips per day and remove more wellbore fluids, versus other plunger lift designs, in wells with certain characteristics.
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Acoustic Pressure Surveys. We provide acoustic pressure surveys, an analytical technique that assists our customers in determining static reservoir pressure and the existence of near wellbore formation damage.
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Dynamometer Analysis. Our dynamometer analysis services include the analysis of reciprocating rod pumping systems (pumpjacks) to determine pump performance and provide our customers with critical information for well performance used to optimize the production and recovery of oil and gas.
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Fluid Level Analysis. We provide fluid level analysis services which record an acoustic pulse as it travels down the wellbore in order to determine the fluid depth.
We offer production optimization services to customers across the United States and in Canada.
Production Testing Services. Production testing is a service required by exploration and production companies to evaluate and clean out new and existing wells. We provide production testing services in Wyoming, Utah, Colorado, Texas and Mexico.
Production testing has the following primary applications:
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Well clean-ups or flowbacks are done shortly after completing or stimulating a well and are designed to remove damaging drilling fluids, completion fluids, sand and other debris. This “clean-up” prevents damage to the permanent production facilities and flowlines, thereby improving production. Our clean-up offering includes our Green Flowback services, which permit the flow of gas to our customers while performing drill-outs and flowback operations, increasing production, accelerating time to production and eliminating the need to flare gas.
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Exploration well testing measures how a reservoir performs under various flow conditions. These measurements allow reservoir and production engineers and geologists to understand well or reservoir production capabilities. Exploration testing jobs can last from a few days to several months.
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In-line production testing measures well flow rates, oil, gas and water composition, pressure and temperature. These measurements are used by engineers to identify and solve well and reservoir problems. In-line production testing is performed after a well has been completed and is already producing. In-line tests can run from several hours to more than several months.
Rental Equipment, Fishing and Pressure Testing Services. Oil and gas producers and drilling contractors often need specialized tools, drillpipe, pressure testing equipment and other equipment and need qualified personnel to operate this equipment. In response to this need, we provide the following services and products:
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Rental Equipment and Services. We rent specialized tools, equipment and tubular goods for the drilling, completion and workover of oil and gas wells. Items rented include pressure control equipment, drill string equipment, pipe handling equipment, fishing and downhole tools, as well as other equipment such as stabilizers, power swivels and bottom-hole assemblies.
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Fishing Services. We provide highly skilled downhole services, including fishing, milling and cutting services, which consist of removing or otherwise eliminating “fish” or “junk” (a piece of equipment, a tool, a part of the drill string or debris) in a well that is causing an obstruction. We also install whipstocks to sidetrack wells, provide plugging and abandonment services, as well as pipe and wireline recovery services, foam services and casing patch installation.
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Pressure Testing Services. We provide specialized pressure testing services which involve the use of truck-mounted equipment designed to carry small fluid volumes with high pressure pumps and hydraulic torque equipment. This equipment is primarily used to perform pressure tests on flow line, pressure vessels,
lubricators, well heads and casings and tubing strings. The units are also used to assemble and disassemble blowout preventors (“BOPs”) for the drilling and work over sector. We have developed specialized, multi-service pressure testing units that enable one or two employees to complete multiple services simultaneously. We have multi-service pressure testing units that we operate in Colorado, Utah, Wyoming and Mexico.
Fluid Handling
Oil and gas operations use and produce significant quantities of fluids. We provide a variety of services to assist our customers to obtain, move, store and dispose of fluids that are involved in the development and production of their reservoirs. We provide fluid handling services in Texas, Oklahoma, Louisiana, Colorado, Wyoming, Arkansas, North Dakota and Montana.
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Fluid Transportation. We operate specialized transport trucks to deliver, transport and dispose of fluids safely and efficiently. We transport fresh water, completion fluids, produced water, drilling mud and other fluids to and from our customers’ wellsites. Our assets include U.S. Department of Transportation certified equipment for transportation of hazardous waste.
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Frac Tank Rental. We operate a fleet of frac tanks that are often used during hydraulic fracturing operations. We use our fleet of fluid transport assets to fill and empty these tanks and we deliver and remove these tanks from the wellsite with our fleet of winch trucks.
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Fluid Disposal. We own salt water disposal wells in Oklahoma, Texas and Arkansas and one evaporation facility in Wyoming. These facilities are used to dispose of water from fracturing operations and from fluids produced during the routine production of oil and gas.
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Other Services. We own and operate a fleet of hot oilers and superheaters, which are assets capable of heating high volumes of fluids. We also sell fluids used during well completions, such as fresh water and potassium chloride, and drilling mud, which we move to our customers’ wellsites using our fluid transportation services.
Drilling Services (11% of Revenue for the Year Ended December 31, 2009)
Through our drilling services segment, we deliver services that initiate oil and gas production by providing land drilling and specialized rig logistics. Our drilling rigs primarily 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 has depth ratings ranging from approximately 8,000 to 15,000 feet.
Drilling Logistics
Through our owned and operated fleet of specialized trucks, we provide drilling rig mobilization services primarily in Louisiana, Texas, North Dakota and Arkansas. Our capabilities allow us to move the largest rigs in the United States. Our operations are strategically located in regions where approximately 50% of the land drilling rigs in the United States are located. We believe our highly skilled personnel position us as one of the leading rig moving companies in the industry.
Product Sales (4% of Revenue for the Year Ended December 31, 2009)
Through our product sales segment, we provide a variety of equipment used by oil and gas companies throughout the lifecycle of their wells. We sell oilfield service equipment and refurbish used equipment through our Southeast Asian business and a fabrication shop in north Texas.
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 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 49%, 45% and 42% of our revenue for the years ended December 31, 2009, 2008 and 2007, respectively. No customer represented more than 10% of our revenues in 2008 and 2007, however in 2009 we had two customers who represented 9.9% and 9.7% of our revenue. We believe we have a broad customer base and wide geographic coverage of operations, which somewhat insulates us from regional or customer specific circumstances.
Seasonality
Our completion and production services business generally experiences a decline in sales for our Canadian operations during the second quarter of each year due to seasonality, as weather conditions make oil and gas operations in this region difficult during this period. Our Canadian operations accounted for approximately 5% of total revenues from continuing operations for each of the years ended December 31, 2009, 2008 and 2007. To a lesser extent, seasonality can affect our operations in the Appalachian region and certain parts of the Rocky Mountain and Mid-Continent regions, which may be subject to periods of reduced activity due to inclement weather conditions, road restrictions and environmental stipulations.
Operating Risk and Insurance
Our operations are subject to hazards inherent in the oil and gas industry, such as accidents, blowouts, explosions, fires and oil spills that can cause:
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personal injury or loss of life;
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damage or destruction of property, equipment and the environment; and
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suspension of operations.
In addition, claims for loss of oil and gas production and damage to formations can occur in the well services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in our being named as a defendant in lawsuits asserting large claims.
Because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents which may result in spills, property damage and personal injury.
Despite our efforts to maintain high safety standards, we have suffered accidents in the past and anticipate that we will experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability and our relationships with
customers, employees and regulatory agencies. Any significant increase in the frequency or severity of these incidents, or the general level of compensation awards, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations.
Although we maintain insurance coverage of types and amounts that we believe to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of the high premium costs. We do maintain commercial general liability, workers’ compensation, business auto, excess auto liability, commercial property, rig physical damage and contractor’s equipment, motor truck cargo, umbrella liability and excess liability, non-owned aircraft liability, directors and officers, employment practices liability, fiduciary and commercial crime insurance policies. However, any insurance obtained by us may not be adequate to cover any losses or liabilities and this insurance may not continue to be available or available on terms which are acceptable to us. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on us. See Item 1A.
Item 1A. “Risk Factors.” See Item 1A. “Risk Factors” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Overview” for a discussion of trends and factors affecting us and our industry. Also see Item 8. “Financial Statements and Supplementary Data, Note 15 - Segment Reporting” for financial information about each of our business segments.
Although we believe that the forward-looking statements contained in this Annual Report are based upon reasonable assumptions, the forward-looking events and circumstances discussed in this document may not occur and actual results could differ materially from those anticipated or implied in the forward-looking statements.
Important factors that may affect our expectations, estimates or projections include:
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general economic and market conditions;
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our access to current or future financing arrangements;
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a decline in or substantial volatility of oil and gas prices, and any related changes in expenditures by our customers;
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the effects of future acquisitions on our business;
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changes in customer requirements in markets or industries we serve;
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competition within our industry;
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our ability to replace or add workers at economic rates;
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environmental and other governmental regulations including climate change related legislation; and
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the effects of severe weather on our services centers or equipment.
In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this Annual Report may not occur, and therefore, our forward-looking statements speak only as of the date of this Annual
Report. Unless otherwise required by law, we undertake no obligation and do not intend to update publicly any forward-looking statements, even if new information becomes available or other events occur in the future. These cautionary statements qualify all such forward-looking statements attributable to us or persons acting on our behalf.
Item 1A.
Risk Factors.
An investment in our common stock involves a degree of risk. You should carefully consider the following risk factors, together with the other information contained in this Annual Report and other public filings with the SEC, before deciding to invest in our common stock. Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business. If any of these risks develop into actual events, our business, financial condition, results of operations or cash flows could be materially adversely affected, and you could lose all or part of your investment.
Risks Related to Our Business and Our Industry
Our business depends on the oil and gas industry and particularly on the level of activity for North American oil and gas. Our markets may be adversely affected by industry conditions that are beyond our control.
We depend on our customers’ willingness to make operating and capital expenditures to explore for, develop and produce oil and gas in North America. If these expenditures decline, our business may suffer. Our customers’ willingness to explore, develop and produce depends largely upon prevailing industry conditions that are influenced by numerous factors over which management has no control, such as:
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the supply of and demand for oil and gas, including current natural gas storage capacity and usage;
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the level of prices, and expectations about future prices, of oil and gas;
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the cost of exploring for, developing, producing and delivering oil and gas;
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the expected rates of declining current production;
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the discovery rates of new oil and gas reserves;
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available pipeline and other transportation capacity;
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weather conditions, including hurricanes that can affect oil and gas operations over a wide area;
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domestic and worldwide economic conditions;
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political instability in oil and gas producing countries;
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technical advances affecting energy consumption;
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the price and availability of alternative fuels;
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the access to and cost of capital for oil and gas producers; and
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merger and divestiture activity among oil and gas producers.
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. Natural gas prices have recently declined significantly from historical highs and rotary rig counts declined sharply in the fourth quarter of 2008 and remain relatively low compared to the levels in mid-2008. Although activity began to recover at the end of 2009, we expect the activity levels for 2010 to remain below those of 2008. An unexpected material decline in oil and gas prices or North American activity levels, or a slower than expected recovery in the oil and gas industry, 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. Oil commodity prices reached historic highs in 2008 then declined substantially by year end. Henry Hub natural gas prices averaged $8.89 per mcf in 2008, but exceeded $12.00 per mcf in June of 2008, before falling below $6.00 per mcf at year-end. Natural gas prices did not exceed $6.11 per mcf in 2009 and averaged $3.94 per mcf during the year. The recent decline in oil and gas prices has and will result in a decrease in the expenditure levels of oil and gas companies and drilling contractors which in turn adversely affects us. We have experienced in the past, and may experience in the future, significant fluctuations in operating results as a result of the reactions of our customers to actual and anticipated changes in oil and gas prices. We reported a loss from continuing operations in 2009 of $181.7 million, which included a goodwill impairment of $97.6 million and fixed asset and other intangible impairments totaling $38.6 million, a loss from continuing operations in 2008 of $84.7 million, which included a goodwill impairment of $272.0 million and income from continuing operations for the year ended December 31, 2007 of $146.4 million.
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.
Many of our customers’ activity levels, spending for our products and services, and payment patterns may be impacted by a deterioration in the credit markets.
Many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. In late 2008 and early 2009, there was a significant decline in the credit markets and the availability of credit. Additionally, many of our customers’ equity values substantially declined. The combination of a reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction in our customers’ spending for our products and services. For example, a number of our customers reduced their capital expenditures in 2009 and may not significantly increase their spending in 2010. A prolonged reduction in spending could have a material adverse effect on our operations.
In addition, while historically our customer base has not presented significant credit risks, the same factors that may lead to a reduction in our customers’ spending also may increase our exposure to the risks of nonpayment and nonperformance by our customers. A significant reduction in our customers’ liquidity may result in a decrease in their ability to pay or otherwise perform on their obligations to us. Any increase in the nonpayment of and nonperformance by our counterparties, either as a result of recent changes in financial and economic conditions or otherwise, could have an adverse impact on our operating results and could adversely affect our liquidity. We have written - off some uncollectible accounts in 2009 and expect to continue to experience these write-offs until market conditions improve. We have experienced an increase in bad debt expense in 2009 compared to prior years. For the years ended December 31, 2009, 2008 and 2007, we recorded bad debt expense totaling $10.8 million, $4.3 million and $7.3 million, respectively. A further decline in market conditions could result in additional bad debt charges in the future.
We participate in a capital intensive business. We may not be able to finance future growth of our operations or future acquisitions.
Historically, we have funded the growth of our operations and our acquisitions from bank debt, private placement of shares, our initial public offering in April 2006, a private placement of debt in December 2006, as well as cash generated by our business. In the future, we may not be able to continue to obtain sufficient bank debt at competitive rates or complete equity and other debt financings. If we do not generate sufficient cash from our business to fund operations, our growth could be limited unless we are able to obtain additional capital through equity or debt financings. Our inability to grow as planned may reduce our chances of maintaining and improving profitability.
Our indebtedness could restrict our operations and make us more vulnerable to adverse economic conditions.
As of December 31, 2009, our long-term debt, including current maturities, was $650.2 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:
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our vulnerability to general adverse economic and industry conditions;
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the covenants that are contained in the agreements that govern our indebtedness limit our ability to borrow funds, dispose of assets, pay dividends and make certain investments;
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any failure to comply with the financial or other covenants of our debt could result in an event of default, which could result in some or all of our indebtedness becoming immediately due and payable; and
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our level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or other general corporate purposes.
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. In addition, competition among oilfield service and equipment providers is affected by each provider’s reputation for safety and quality. Although we believe that our reputation for safety and quality service is good, we cannot assure that we will be able to maintain our competitive position.
Impairment of Long-term Assets
We evaluate our long-term assets including property, plant and equipment, identifiable intangible assets and goodwill in accordance with generally accepted accounting principles in the U.S. In performing this assessment, we project future cash flows on a discounted basis for goodwill, and on an undiscounted basis for other long-term assets, and compare these cash flows to the carrying amount of the related net assets. The cash flow projections are based on our current operating plan, estimates and judgmental assessments. We perform this assessment of potential impairment at least annually, but also whenever facts and circumstances indicate that the carrying value of the net assets may not be recoverable due to various external or internal factors, termed a “triggering event.” We have recorded goodwill impairment charges of $97.6 million and $272.0 million for the years ended December 31, 2009 and 2008, respectively. In 2009, management performed additional analysis and determined that further write-downs were necessary, which resulted in a fixed asset impairment in our drilling services segment of $36.2 million recorded in September 2009, and an intangible asset impairment in our completion and production services segment totaling $2.5 million recorded in December 2009. If we determine that our estimates of future cash flows were inaccurate or our actual results for 2010 are materially different than expected, we could record additional impairment charges at interim periods during 2010 or in future years, which could have a material adverse effect on our financial position and results of operations.
There is potential for excess capacity in our industry.
Because oil and gas prices and drilling activity were recently at historically high levels, oilfield service companies acquired new equipment to meet their customers’ increasing demand for services. This resulted in an increased competitive environment for oilfield service companies, which led to lower prices and utilization for our services and could continue to adversely affect our business.
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. 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.
Our inability to control the inherent risks of acquiring and integrating businesses could adversely affect our operations.
Acquisitions have been, and our management believes acquisitions will continue to be, a key element of our business strategy. We may not be able to identify and acquire acceptable acquisition candidates on favorable terms in the future. We may be required to incur substantial indebtedness to finance future acquisitions and also may issue equity securities in connection with such acquisitions. We may not be able to secure additional capital to fund acquisitions. If we are able to obtain financing, such additional debt service requirements may impose a significant burden on our results of operations and financial condition. The issuance of additional equity securities could result in significant dilution to stockholders. Acquisitions may not perform as expected when the acquisition was made and may be dilutive to our overall operating results. Additional risks we will face include:
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retaining and attracting key employees;
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retaining and attracting new customers;
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increased administrative burden;
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developing our sales and marketing capabilities;
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managing our growth effectively;
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integrating operations;
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operating a new line of business; and
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increased logistical problems common to large, expansive operations.
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 33%, 28% and 27% of our revenue for the years ended December 31, 2009, 2008 and 2007, respectively. Our top ten customers represented approximately 49%, 45% and 42% of our revenue for the years then ended. No customer represented more than 10% of our revenues in 2008 and
2007, however in 2009 we had two customers who represented 9.9% and 9.7% of our revenue. 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 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 (proppant, cement, explosives) or finished products (such as workover rigs or fluid-handling equipment) or otherwise fail to deliver the products timely and in the quantities required, any resulting delays in the provision of services could have a material adverse effect on our business, financial condition, results of operations and cash flows. During 2008, our industry faced sporadic proppant shortages associated with pressure pumping operations requiring work stoppages which adversely impacted the operating results of several competitors.
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 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 are not able to implement commercially competitive services and access commercially competitive products in a timely manner in response to changes in technology, our business and revenue could be materially and adversely affected.
The market for our services and products is characterized by continual technological developments to provide better and more reliable performance and services. If we are not able to implement commercially competitive services and access commercially competitive products in a timely manner in response to changes in technology, our business and revenue could be materially and adversely affected. Likewise, if our proprietary technologies, equipment and facilities, or work processes become obsolete, we may no longer be competitive, and our business and revenue could be materially and adversely affected.
Our operations may incur substantial liabilities to comply with climate change legislation and regulatory initiatives.
The U.S. Congress is considering legislation to reduce emissions of greenhouse gases and more than one-third of the states, either individually or through multi-state initiatives, have already begun implementing legal measures to reduce emissions of greenhouse gases. Also, the U.S. Supreme Court’s holding in its 2007 decision, Massachusetts, et al. v. EPA, that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act could result in future regulation of greenhouse gas emissions from stationary sources, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. In July 2008, the EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future. In addition, the Government of Canada has announced a regulatory framework to reduce greenhouse gas emissions, which includes a requirement that all covered industrial sectors, including upstream oil and gas facilities meeting certain threshold requirements, reduce their emissions from 2006 levels by 18% by 2010. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions for us and our customers, and could have a material adverse effect on our business or demand for the our services. See Item 1. Environmental Matters for a more detailed description of our climate-change related risks.
We are self-insured for certain health care benefits for our employees.
We are self-insured for claims arising from healthcare benefits provided to certain of our employees in the United States. Under this self-insurance program, we use the services of an insurance company, the former provider of full insurance coverage prior to the inception of the program in 2007, to administer the program on a fee-per-participant basis, and we have purchased a stop-loss policy with this provider to insure for individual claims which exceed a designated ceiling. Pursuant to this program, we accrue expense based upon expected claims, and make periodic claim payments to the administrator, who then facilitates claim payments to the medical care providers. With the passage of time and as our business expands and more employees enroll in our healthcare benefit plan, we are required to maintain higher self-insured retention levels. There is a risk that our actual claims incurred may exceed the projected claims, and we may incur more expense than expected for health insurance coverage. There is also a risk that we may not adequately accrue for claims that are incurred but not reported. Either of these events could have a material adverse effect on our financial position, results of operations or cash flows.
If we become subject to product liability claims, it could be time-consuming and costly to defend.
Since our customers use our products, or third party products that we sell or rent, errors, defects or other performance problems could result in financial or other damages to us. Our customers could seek damages from us for losses associated with these errors, defects or other performance problems. If successful, these claims could have a material adverse effect on our business, operating results or financial condition. Our existing product liability insurance may not be enough to cover the full amount of any loss we might suffer. A product liability claim brought against us, even if unsuccessful, could be time-consuming and costly to defend and could harm our reputation.
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:
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issuance of administrative, civil and criminal penalties;
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denial or revocation of permits or other authorizations;
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imposition of limitations on our operations; and
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performance of site investigatory, remedial or other corrective actions.
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 maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud.
Effective internal controls are necessary for us to provide reliable financial reports and effectively prevent fraud. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. Our efforts to maintain internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future, including compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective controls or to make effective improvements to our internal controls could harm our operating results.
Conservation measures and technological advances could reduce demand for oil and gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and gas. Management cannot predict the impact of the changing demand for oil and gas services and products, and any major changes may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Fluctuations in currency exchange rates in Canada could adversely affect our business.
We have operations in Canada. As a result, fluctuations in currency exchange rates in Canada could materially and adversely affect our business. For each of the years ended December 31, 2009, 2008 and 2007, our Canadian operations represented approximately 5% of our revenue from continuing operations. For the years ended December 31, 2009, 2008 and 2007, our Canadian operations recorded losses from continuing operations before taxes and minority interest of $11.1 million, $26.7 million and $13.5 million, respectively. The losses in 2008 and 2007 primarily resulted from goodwill impairment charges.
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 the ground thaws and many secondary roads are temporarily rendered incapable of supporting the weight of heavy equipment. The duration of this period is referred to as “spring breakup” and has a direct impact on our activity levels in Canada. The timing and duration of “spring breakup” depend on weather patterns but generally “spring breakup” occurs in April and May. Additionally, if an unseasonably warm winter prevents sufficient freezing, we may not be able to access wellsites and our operating results and financial condition may, therefore, be adversely affected. The demand for our services may also be affected by the severity of the Canadian winters. In addition, during excessively rainy periods, equipment moves may be delayed, thereby adversely affecting operating results. The volatility in weather and temperature in the Canadian oilfield can therefore create unpredictability in activity and utilization rates. As a result, full-year results are not likely to be a direct multiple of any particular quarter or combination of quarters.
Our operations in Mexico are subject to specific risks, including dependence on Petróleos Mexicanos (“PEMEX”) as the primary customer, exposure to fluctuation in the Mexican peso and workforce unionization.
The majority of our business in Mexico is performed for PEMEX pursuant to multi-year contracts. These contracts are generally two years in duration 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 most recently modified on and effective as of October 2008 between Servicios Petrotec S.A. DE C.V., one of our subsidiaries, and Unión Sindical de Trabajadores de la Industria Metálica y Similares, the metal and similar industry workers labor union. We have not experienced work stoppages in the past but cannot guarantee that we will not experience work stoppages in the future. A prolonged work stoppage could negatively impact our revenues, cash flows and net income.
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.
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:
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incur or assume liens or additional debt or provide guarantees in respect of obligations of other persons;
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issue redeemable stock and certain preferred stock;
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pay dividends or distributions or redeem or repurchase capital stock;
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prepay, redeem or repurchase subordinated debt;
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make loans and investments;
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enter into agreements that restrict distributions from our subsidiaries;
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sell assets and capital stock of our subsidiaries;
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enter into certain transactions with affiliates;
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consolidate or merge with or into, or sell substantially all of our assets to, another person; and
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enter into new lines of business.
In addition, our amended revolving credit facility contains restrictive covenants and requires us to maintain a fixed charge coverage ratio based on borrowing base limitations and satisfy other financial condition tests. Our ability to meet those financial requirements can be affected by adverse industry conditions and other events beyond our control, and we cannot assure you that we will meet those requirements. A breach of any of these covenants could result in a default under our amended revolving credit facility and/or the notes. Upon the occurrence of an event of default under our amended revolving credit facility, the lenders could elect to declare all amounts outstanding to be immediately due and payable and terminate all commitments to extend further credit. 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.
Although we have no amounts outstanding under our amended revolving credit facility at December 31, 2009, such borrowings would be, 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.
Item 1B.
Item 1B.
Unresolved Staff Comments.
None.
Item 2.
Item 2.
Properties.
As of December 31, 2009, we owned 51 offices, facilities and yards, of which 11 were in Texas, 20 were in Oklahoma, one was in Arkansas, two were in North Dakota, one was in Montana, four were in Wyoming, three were in Colorado, one was in Louisiana, three were in Pennsylvania, one was in Utah, one was in Alberta, Canada, one was in Poza Rica, Mexico and one was in Singapore.
As of December 31, 2009, we owned or operated 58 saltwater disposal wells, of which 28 were in Texas, 29 were in Oklahoma and one was 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, 2009, we leased 209 offices, facilities and yards, of which 64 were in Texas, 23 were in Oklahoma, 13 were in Wyoming, 32 were in Colorado, 18 were in Pennsylvania, three were in North Dakota, seven were in Louisiana, five were in Arkansas, six were in Utah, one was in New York, 24 were in Alberta, Canada, two were in British Columbia, Canada, six were in Mexico and five were in Singapore. As of December 31, 2009, we leased two drilling mud disposal facilities in Oklahoma.
We lease our corporate headquarters in Houston, Texas, as well as administrative offices in Gainesville, Texas; Enid, Oklahoma; Fredrick, Colorado; Eunice, Louisiana; Shelocta, Pennsylvania; Calgary, Alberta, Canada; and additional office space in Houston, Texas.
Item 3.
Item 3.
Legal Proceedings.
In the normal course of our business, we are a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including warranty and product liability claims and occasional claims by individuals alleging exposure to hazardous materials, on the job injuries and fatalities as a result of our products or operations.
Many of the claims filed against us relate to motor vehicle accidents which can result in the loss of life or serious bodily injury. Some of these claims relate to matters occurring prior to our acquisition of businesses. In certain cases, we are entitled to indemnification from the sellers of such businesses.
Although we cannot know or predict with certainty the outcome of any claim or proceeding or the effect such outcomes may have on us, we believe that any liability resulting from the resolution of any of these matters, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our financial position, results of operations or liquidity.
We have historically incurred additional insurance premium related to a cost-sharing provision of our general liability insurance policy, and we cannot be certain that we will not incur additional costs until either existing claims become further developed or until the limitation periods expire for each respective policy year. Any such additional premiums should not have a material adverse effect on our financial position, results of operations or liquidity.
Item 4.
Item 4.
Submission of Matters to a Vote of Security Holders.
None.
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
At February 15, 2010, we had 77,618,974 shares of common stock outstanding, of which 2,396,344 shares were non-vested restricted stock subject to forfeiture restrictions. The common shares outstanding at February 15, 2010 were held by 79 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, 2009 or February 15, 2010.
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 each of the calendar quarters in 2008 and 2009:
The year-end closing sales price of our common stock was $8.15 on December 31, 2008, the last trading day of 2008 and $13.00 on December 31, 2009, the last trading day of 2009.
Issuer Purchases of Equity Securities:
We made no repurchases of our common stock during the years ended December 31, 2008 or 2007. In accordance with the provisions of the 2008 Incentive Award Plan, holders of unvested restricted stock were given the option to either remit to us the required withholding taxes associated with the vesting of restricted stock, or to authorize us to repurchase shares equivalent to the cost of the withholding tax and to remit the withholding taxes on behalf of the holder. Pursuant to this provision, we repurchased the following shares during the quarter ended December 31, 2009:
Equity Compensation Plans:
The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information as set forth in Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” contained herein.
Dividends:
We have paid no dividends on our outstanding $0.01 par value common stock for the years ended December 31, 2009, 2008 or 2007. We currently do not intend to pay dividends in the foreseeable future, but rather plan to reinvest such funds in our business. Furthermore, our credit facility and the indenture governing our senior notes contain covenants which restrict us from paying future dividends on our common stock.
Performance Graph:
The information in this section of the Annual Report pertaining to our performance relative to our peers is being furnished but not filed with the SEC, and as such, the information is neither subject to Regulation 14A or 14C or to the liabilities of Section 18 of the Exchange Act of 1934.
The following chart presents a comparative analysis of the stock performance of our common stock (“CPX”) relative to an industry index, the Philadelphia Oil Service Sector Index (“OSX”), and a broader market index, Standard & Poor’s 500 Index (“S&P”). This analysis assumes a $100 investment in the underlying common stock of CPX, OSX and S&P on April 21, 2006, the date of our initial public offering, through December 31, 2009. 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 44 MONTH CUMULATIVE TOTAL RETURN*
Among Complete Production Services, Inc, The S & P 500 Index
And The PHLX Oil Service Sector Index
*
$100 invested on 4/21/06 in stock & 3/31/06 in index-including reinvestment of dividends. Fiscal year ending December 31.
Copyright ©
2010 S&P, a division of The McGraw-Hill Companies, Inc. All rights reserved.
Item 6.
Item 6.
Selected Financial Data.
The following table presents selected historical consolidated financial and operating data for the periods shown. The selected consolidated financial data as of December 31, 2005, 2006, 2007, 2008 and 2009 and for each of the years then ended have been derived from our audited consolidated financial statements for those dates and periods, adjusted for discontinued operations, as indicated. The following information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes included in this Annual Report.
(1)
We paid a dividend of $2.62 per share to our stockholders as of September 12, 2005 in conjunction with the Combination. Our current debt obligations restrict us from paying dividends on our common stock, and we have not paid any other dividends in the past five fiscal years.
(2)
In June 2009, we discovered accounting errors within one of our operations located in the Rocky Mountain region, which occurred in prior years and impacted our reported operating results for the years ended
December 31, 2006, 2007 and 2008. The majority of the errors were due to a flawed revenue accrual process and ineffective controls over inventory within this operation. We evaluated the impact that these errors had on our financial statements and determined that these errors would not have been material to our financial statements from a quantitative or qualitative perspective for those periods. However, the amount of the adjustment required to correct these errors was deemed to be material to the results for 2009. We corrected these errors as of June 30, 2009 and made the required adjustments to our reported results for the comparative periods in the applicable subsequent public filings. In addition, we have adjusted our previously published balance sheet at December 31, 2008, decreasing beginning retained earnings by $8,405. As applicable, we revised the presentation of the selected data above for the years ended December 31, 2006, 2007 and 2008. We have labeled our balance sheet, statement of operations and statement of cash flows as “Revised” where applicable.
(3)
Service and product expenses is the aggregate of service expenses and product expenses.
(4)
For the year ended December 31, 2009, we recorded a fixed asset impairment in our drilling services segment of $36,158 and an intangible asset impairment in our completion and production services segment totaling $2,488. We also recorded a goodwill impairment charge of $97,643 associated with several of our reportable units at December 31, 2009. We recorded an impairment loss of $272,006 associated with goodwill for various reporting units as of December 31, 2008. For the year ended December 31, 2007, we recorded an impairment loss of $13,094 associated with our Canadian reporting unit. For a further discussion, see “Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included within this Annual Report. This discussion contains forward-looking statements based on our current expectations, assumptions, estimates and projections about us and the oil and gas industry. See “Forward-Looking Statement” contained in Item 1. “Business.” These forward-looking statements involve risks and uncertainties that may be outside of our control and could cause actual results to differ materially from those in the forward-looking statements. For examples of those risks and uncertainties, see the cautionary statements contained in Item 1A. “Risk Factors.” Factors that could cause or contribute to such differences include, but are not limited to: market prices for oil and gas, the level of oil and gas drilling, economic and competitive conditions, capital expenditures, regulatory changes and other uncertainties. In light of these risks, uncertainties and assumptions, the forward-looking events discussed below may not occur. Unless otherwise required by law, we undertake no obligation to publicly update any forward-looking statements, even if new information becomes available or other events occur in the future.
The words “believe,” “may,” “will,” “estimate,” “continue,” “anticipate,” “intend,” “plan,” “expect” and similar expressions are intended to identify forward-looking statements. All statements other than statements of current or historical fact contained in this Annual Report are forward-looking statements.
Overview
We are a leading provider of specialized services and products focused on helping oil and gas companies develop hydrocarbon reserves, reduce operating costs and enhance production. We focus on basins within North America that we believe have attractive long-term potential for growth, and we deliver targeted, value-added services and products required by our customers within each specific basin. We believe our range of services and products positions us to meet the many needs of our customers at the wellsite, from drilling and completion through production and eventual abandonment. We manage our operations from regional field service facilities located throughout the U.S. Rocky Mountain region, Texas, Oklahoma, Louisiana, Arkansas, Pennsylvania, western Canada, Mexico and Southeast Asia.
We operate in three business segments:
Completion and Production Services. Through our completion and production services segment, we establish, maintain and enhance the flow of oil and gas throughout the life of a well. This segment is divided into the following primary service lines:
•
Intervention Services. Well intervention requires the use of specialized equipment to perform an array of wellbore services. Our fleet of intervention service equipment includes coiled tubing units, pressure pumping units, nitrogen units, well service rigs, snubbing units and a variety of support equipment. Our intervention services provide customers with innovative solutions to increase production of oil and gas.
•
Downhole and Wellsite Services. Our downhole and wellsite services include electric-line, slickline, production optimization, production testing, rental and fishing services.
•
Fluid Handling. We provide a variety of services to help our customers obtain, move, store and dispose of fluids that are involved in the development and production of their reservoirs. Through our fleet of specialized trucks, frac tanks and other assets, we provide fluid transportation, heating, pumping and disposal services for our customers.
Drilling Services. Through our drilling services segment, we provide services and equipment that initiate or stimulate oil and gas production by providing land drilling and specialized rig logistics services. Our drilling rigs operate primarily in and around the Barnett Shale region of north Texas.
Product Sales. We provide oilfield service equipment and refurbishment of used equipment through our Southeast Asian business, and we provide repair work and fabrication services for our customers at a business located in Gainesville, Texas.
Substantially all service and rental revenue we earn is based upon a charge for a period of time (an hour, a day, a week) for the actual period of time the service or rental is provided to our customer or on a fixed per-stage-completed fee. Product sales are recorded when the actual sale occurs and title or ownership passes to the customer.
Our customers include large multi-national and independent oil and gas producers, as well as smaller independent producers and the major land-based drilling contractors in North America (see “Customers” in Item 1 of this Annual Report on Form 10-K). The primary factors influencing demand for our services and products is the level of drilling and workover activity of our customers and the complexity of such activity, which in turn, depends on current and anticipated future oil and gas prices, production depletion rates and the resultant levels of cash flows generated and allocated by our customers to their drilling and workover budgets. As a result, demand for our services and products is cyclical, substantially depends on activity levels in the North American oil and gas industry and is highly sensitive to current and expected oil and natural gas prices. The following tables summarize average North American drilling and well service rig activity, as measured by Baker Hughes Incorporated (“BHI”) and the Cameron International Corporation/Guiberson/AESC Service Rig Count for “Active Rigs,” respectively, and historical commodity prices as provided by Bloomberg:
AVERAGE RIG COUNTS
Source: BHI (www.BakerHughes.com)
Source: Cameron International Corporation/Guiberson/AESC Well Service Rig Count for “Active Rigs.”
Average service rig counts for active rigs for December 2009 was 2,110, according to the Cameron International Corporation/Guiberson/AESC Well Service Rig Count for “Active Rigs.”
AVERAGE OIL AND GAS PRICES
Source: Bloomberg NYMEX prices.
The closing spot price of a barrel of WTI Cushing oil at December 31, 2009 was $79.36 and the closing spot price for Henry Hub natural gas ($/mcf) was $5.82. At February 15, 2010, the closing spot price of a barrel of WTI Cushing oil was $74.13 and the closing spot price for Henry Hub natural gas was $5.47.
We consider the drilling and well service rig counts to be an indication of spending by our customers in the oil and gas industry for exploration and development of new and existing hydrocarbon reserves. These spending levels are a primary driver of our business, and we believe that our customers tend to invest more in these activities when oil and gas prices are at higher levels or are increasing. The utilization of our assets and the performance of our business can be impacted by these and other external and internal factors. See Item 1A. “Risk Factors.”
We generally charge for our services either on a dayrate or per-stage-completed basis. Depending on the specific service, charges may include one or more of these components: (1) a set-up charge, (2) an hourly service rate based on equipment and labor, (3) a stage-completed charge, (4) an equipment rental charge, (5) a consumables charge, and (6) a mileage and fuel charge. We generally determine the rates charged through a competitive process on a job-by-job basis. Typically, work is performed on a “call out” basis, whereby the customer requests services on a job-specific basis, but does not guarantee work levels beyond the specific job bid. For contract drilling services, fees are charged based on standard dayrates or, to a lesser extent, as negotiated by footage contracts. Product sales generated through our Southeast Asian business are typically based on a pre-determined price book.
Outlook
Since our initial public offering, in April 2006, our growth strategy has been focused on internal growth in the basins in which we currently operate, as we sought to maximize our equipment utilization, add additional like-kind equipment and expand service and product offerings. In addition, we have sought new basins in which to replicate this approach and augmented our internal growth with strategic acquisitions. In late 2008, we noticed a decline in drilling and exploration expenditures by our customers following the significant decline in oil and gas commodity prices. Accordingly, in 2009 we decreased our level of investment relative to recent years, and implemented cost-saving measures throughout 2009, while remaining responsive to our customers’ needs for quality services.
•
Internal Capital Investment. Our internal expansion activities have generally consisted of adding equipment and qualified personnel in locations where we have established a presence. We have grown our operations in many of these locations by expanding services to current customers, attracting new customers and hiring local personnel with local basin-level expertise and leadership recognition. Depending on customer demand, we will consider adding equipment to further increase the capacity of services currently
being provided and/or add equipment to expand the services we provide. We invested $665.2 million in equipment additions over the three-year period ended December 31, 2009, which included $548.9 million for the completion and production services segment, $101.2 million for the drilling services segment, $10.8 million for the product sales segment and $4.3 million related to general corporate operations. For the year ended December 31, 2009, we invested only $38.5 million in capital expenditures.
•
External Growth. We use strategic acquisitions as an integral part of our growth strategy. We consider acquisitions that will add to our service offerings in a current operating area or that will expand our geographical footprint into a targeted basin. We have completed several acquisitions in recent years. These acquisitions affect our operating performance period to period. Accordingly, comparisons of revenue and operating results are not necessarily comparable and should not be relied upon as indications of future performance. We invested an aggregate of $230.6 million in acquisitions over the three-year period ended December 31, 2009. Of this amount, we invested an aggregate of $180.2 million to acquire 4 businesses during 2008 and $49.7 million to acquire 7 businesses during 2007. We did not complete any business acquisitions during the year ended December 31, 2009 primarily due to poor market conditions. See “- Significant Acquisitions.”
Natural gas prices have declined from historical highs in 2008 and rotary rig counts have also declined significantly. The recent change in activity levels are likely the result of a number of macro-economic factors, such as an excess supply of natural gas, lower demand for oil and gas, market expectations of weather conditions and the utilization of heating fuels, the cyclical nature of the oil and gas industry and other general market conditions for the U.S. economy, including the current global economic recession and the recent financial crisis, which contributed to significant reductions in available capital and liquidity from banks and other providers of credit. We experienced a significant decline in utilization of our assets starting in late 2008 which continued throughout most of 2009. Although activity began to recover at the end of 2009, we anticipate that lower commodity prices and activity levels relative to 2008, will continue to adversely impact our near-term results. Due to challenging market conditions, we recorded non-cash impairment charges of $97.6 million and $272.0 million at December 31, 2009 and 2008, respectively, related to the write-down of goodwill for various of our reporting units. In 2007, we recorded a non-cash goodwill impairment charge of $13.1 million for our Canadian reporting unit. In addition, we recorded a $36.2 million impairment charge related to our drilling assets and a $2.5 million charge related to other intangible assets during the year ended December 31, 2009. Although we cannot determine the depth or duration of the decline in activity in the oil and gas industry, we believe the overall long-term outlook for North American oilfield activity and our business remains favorable, especially in the basins in which we operate.
Our business continues to be impacted by seasonality and inclement weather, including the effects of the normal second quarter Canadian “break-up,” as well as the impact of Gulf of Mexico tropical weather systems.
We, and many of our competitors, have invested in new equipment, some of which requires long lead-times to manufacture. As more of this equipment is available to be placed into service and if oilfield activity declines, there will be additional excess capacity in the industry, which may further negatively impact our utilization rates and pricing for certain service offerings. In addition, as new equipment enters the market, we must compete for employees to crew the equipment, which puts inflationary pressure on labor costs. Our equipment fleet is relatively new, as we have made significant investments in new equipment over the past few years. We continue to monitor our equipment utilization and poll our customers to assess demand levels. As equipment enters the marketplace or competition for existing customers increases, we believe our customers will rely upon service providers with local knowledge and a proven ability to effectively execute complex services on location,, which we believe we have and which constitutes fundamental aspects of our growth strategy.
Significant Transactions
During 2008, we acquired substantially all the assets or all of the equity interests in four oilfield service companies, for $180.2 million in cash, resulting in goodwill of approximately $71.2 million. Several of these acquisitions were subject to final working capital adjustments.
•
On February 29, 2008, we acquired substantially all of the assets of KR Fishing & Rental, Inc. for $9.5 million in cash, resulting in goodwill of $6.4 million. KR Fishing & Rental, Inc. is a provider of fishing,
rental and foam unit services in the Piceance Basin and the Raton Basin, and is located in Rangely, Colorado. We believe this acquisition complements our completion and production services business in the Rocky Mountain region.
•
On April 15, 2008, we acquired all the outstanding common stock of Frac Source Services, Inc., a provider of pressure pumping services to customers in the Barnett Shale of north Texas, for $62.4 million in cash, net of cash acquired, which includes a working capital adjustment of $1.6 million and recorded goodwill of $15.4 million. Upon closing this transaction, we entered into a contract with one of our major customers to provide pressure pumping services in the Barnett Shale utilizing three frac fleets under a contract with a term that extends up to three years from the date each fleet is placed into service. We spent an additional $20.0 million in 2008 on capital equipment related to these contracted frac fleets. Thus, our total investment in this operation was approximately $82.4 million. We believe this acquisition expands our pressure pumping business in north Texas and that the related contract provides a stable revenue stream from which to expand our pressure pumping business outside of this region.
•
On October 3, 2008, we acquired all of the membership interests of TSWS Well Services, LLC, a limited liability corporation which held substantially all of the well servicing and heavy haul assets of TSWS, Inc., a company based in Magnolia, Arkansas, which provides well servicing and heavy haul services to customers in northern Louisiana, east Texas and southern Arkansas. As consideration, we paid $57.2 million in cash and prepaid an additional $1.0 million related to an employee retention bonus pool. We also recorded goodwill totaling $21.9 million. We believe this acquisition extends our geographic reach into the Haynesville Shale area.
•
On October 4, 2008, we acquired substantially all of the assets of Appalachian Wells Services, Inc. and its wholly-owned subsidiary, each of which is based in Shelocta, Pennsylvania. This business provides pressure pumping, e-line and coiled tubing services in the Appalachian region, and includes a service area which extends through portions of Pennsylvania, West Virginia, Ohio and New York. As consideration for the purchase, we paid $50.1 million in cash and issued 588,292 unregistered shares of our common stock, valued at $15.04 per share. We invested an additional $6.5 million to complete a frac fleet at this location and have an option to purchase real property for approximately $0.6 million. In addition, we have entered into an agreement under which we may be required to pay up to an additional $5.0 million in cash consideration during the earn-out period which extends through 2010, based upon the results of operations of various service lines acquired. We recorded goodwill of approximately $27.5 million associated with this acquisition, however, this goodwill was deemed impaired in 2009 and expensed as of December 31, 2009. This acquisition created a platform for future growth for our pressure pumping and other completion and production service lines in the Marcellus Shale.
In addition, we completed several other smaller acquisitions in 2007 which have 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. Results of operations related to each of the acquired companies have been included in our combined operations as of the date of acquisition.
In May 2008, our Board of Directors authorized and committed to a plan to sell certain operations in the Barnett Shale region of north Texas, consisting primarily of our supply store business, as well as certain non-strategic drilling logistics assets and other completion and production services assets. On May 19, 2008, we sold these operations to Select Energy Services, L.L.C., a company owned by a former officer of one of our subsidiaries, for which we received proceeds of $50.2 million in cash and assets with a fair market value of $8.0 million. The carrying value of the net assets sold was approximately $51.4 million, excluding $11.1 million of allocated goodwill associated with the combination that formed Complete Production Services, Inc. in September 2005. We recorded a loss on the sale of this disposal group totaling approximately $6.9 million, which included $2.6 million related to income taxes. In accordance with the sales agreement, we sublet office space to Select Energy Services, L.L.C. and provided certain administrative services for an initial term of one year, at an agreed-upon rate.
In March 2009, our Canadian subsidiary exchanged certain non-monetary assets with a net book value of $9.3 million related to our production testing business for certain e-line assets of a competitor. We recorded a non-cash loss on the transaction of $4.9 million, which represented the difference between the carrying value and the fair market value of the assets surrendered. We believe the e-line assets will generate incremental future cash flows compared to the production testing assets exchanged.
Market Environment
We operate in a highly competitive industry. Our competition includes many large and small oilfield service companies. As such, we price our services and products to remain competitive in the markets in which we operate, adjusting our rates to reflect current market conditions as necessary. We examine the rate of utilization of our equipment as one measure of our ability to compete in the current market environment.
Critical Accounting Policies and Estimates
The preparation of our consolidated financial statements in conformity with Generally Accepted Accounting Principles (“GAAP”) requires the use of estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, and provide a basis for making judgments about the carrying value of assets and liabilities that are not readily available through open market quotes. Estimates and assumptions are reviewed periodically, and actual results may differ from those estimates under different assumptions or conditions. We must use our judgment related to uncertainties in order to make these estimates and assumptions.
In the selection of our critical accounting policies, the objective is to properly reflect our financial position and results of operations for each reporting period in a consistent manner that can be understood by the reader of our financial statements. Our accounting policies and procedures are explained in note 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.
Revenue Recognition
We recognize service revenue as services are performed and when realized or earned. Revenue is deemed to be realized or earned when we determine that the following criteria are met: (1) persuasive evidence of an arrangement exists; (2) delivery has occurred or services have been rendered; (3) the fee is fixed or determinable; and (4) collectibility is reasonably assured. These services are generally provided over a relatively short period of time pursuant to short-term contracts at pre-determined dayrate fees, or on a day-to-day basis. Revenue and costs related to drilling contracts are recognized as work progresses. Progress is measured as revenue is recognized based upon dayrate charges. For certain contracts, we may receive lump-sum payments from our customers related to the mobilization of rigs and other drilling equipment. Under these arrangements, we defer revenues and the related cost of services and recognize them over the term of the drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Revenues associated with product sales are recorded when product title is transferred to the customer.
Under current GAAP, revenue is to be recognized when it is realized or realizable and earned. The SEC’s rules and regulations provide additional guidance for revenue recognition under specific circumstances, including bill and hold transactions. There is a risk that our results of operations could be misstated if we do not record revenue in the proper accounting period.
The nature of our business has been such that we generally bill for services over a relatively short period of time and record revenues as products are sold. We did not record material adjustments resulting from revenue recognition issues for the years ended December 31, 2009, 2008 and 2007.
Impairment of Long-Lived Assets
Based on guidance from the Financial Accounting Standards Board (“FASB”) regarding accounting for the impairment or disposal of long-lived assets, we evaluate potential impairment of long-lived assets and intangibles, excluding goodwill and other intangible assets without defined service lives, when indicators of impairment are present. If such indicators are present, we project the fair value of the assets by estimating the undiscounted future cash in-flows to be derived from the long-lived assets over their remaining estimated useful lives, as well as any salvage value. Then, we compare this fair value estimate to the carrying value of the assets and determine whether the assets are deemed to be impaired. For goodwill and other intangible assets without defined service lives, we perform an annual impairment test, whereby we estimate the fair value of the asset by discounting future cash flows at a projected cost of capital rate. If the fair value estimate is less than the carrying value of the asset, an additional test is required whereby we apply a purchase price analysis similar to a purchase price allocation for a business combination. If impairment is still indicated, we would record an impairment loss in the current reporting period for the amount by which the carrying value of the intangible asset exceeds its projected fair value.
Our industry is highly cyclical and the estimate of future cash flows requires the use of assumptions and our judgment. Periods of prolonged down cycles in the industry could have a significant impact on the carrying value of these assets and may result in impairment charges. If our estimates do not approximate actual performance or if the rates we used to discount cash flows vary significantly from actual discount rates, we could overstate our assets and an impairment loss may not be timely identified.
We tested goodwill for impairment for each of the years ended December 31, 2009, 2008 and 2007. Management prepared a discounted cash flow analysis to determine the fair market value of the reportable units as of the annual testing date. Projected cash flows were based on certain management assumptions related to expected growth, capital investment and terminal value, discounted at a market-participant weighted average cost of capital, refined to reflect our current and anticipated capital structure. Based on this analysis, management determined that goodwill was impaired in 2009, 2008 and 2007. In accordance with the FASB’s guidance for goodwill, management performed a step-two analysis to calculate the amount by which the carrying value of the reporting units exceeded the projected fair market value of such units as of the annual testing date. As a result of this testing in 2007, management recorded an impairment charge which reduced goodwill in Canada by $13.4 million. This annual testing was performed in 2008 and yielded another impairment for this Canadian subsidiary as of the test date. However, due to a decline in the overall U.S. debt and equity markets and concerns over the availability of credit, we determined that a triggering event had occurred during the fourth quarter of 2008. Therefore, we performed our impairment calculations again as of December 31, 2008, incorporating our most recent assumptions of future earnings and cash flows. Based on this testing, we determined that the goodwill associated with most of our reporting units had been impaired. We recorded an impairment charge of $272.0 million at December 31, 2008. In calculating this impairment charge, management made assumptions about future earnings by reportable unit, which may differ from actual future earnings for these operations. In 2009, management performed additional analysis and determined that further write-downs were necessary. We recorded a goodwill impairment charge of $97.6 million associated with several of our reportable units at December 31, 2009. In addition, pursuant to an undiscounted cash flow analysis, we recorded a fixed asset impairment in our drilling services segment of $36.2 million and an intangible asset impairment in our completion and production services segment totaling $2.5 million. See “Property, Plant and Equipment.” A significant decline in expected future cash flow, a further erosion of market conditions or a lower-than-expected recovery of the oil and gas industry activity levels in future years, could result in an additional impairment charge.
Stock Options and Other Stock-Based Compensation
We have issued stock-based compensation to certain employees, officers and directors in the form of stock options and restricted stock. In accordance with U.S. GAAP, we account for grants made prior to September 30, 2005, the date of our initial filing with the SEC, using the minimum value method, whereby no compensation
expense is recognized for stock-based compensation grants that have an exercise price equal to the fair value of the stock on the date of grant. For grants of stock-based compensation between October 1, 2005 and December 31, 2005, we utilized the modified prospective transition method to record expense associated with these options, whereby we did not record compensation expense associated with these grants during the period October 1, 2005 through December 31, 2005 but provided pro forma disclosure of this expense, and, then began recognizing compensation expense related to these grants over the remaining vesting period after December 31, 2005 based upon a calculated fair value. These grants were fully vested as of December 31, 2009. For grants of stock-based compensation on or after January 1, 2006, we recognize expense associated with new awards of stock-based compensation, as determined using a Black-Scholes pricing model over the expected term of the award. In addition, we record compensation expense associated with restricted stock which has been granted to certain of our directors, officers and employees. In accordance with current U.S. GAAP, we calculate compensation expense on the date of grant (number of options granted multiplied by the fair value of our common stock on the date of grant) and recognize this expense, adjusted for forfeitures, ratably over the applicable vesting period.
U.S. GAAP permits the use of various models to determine the fair value of stock options and the variables used for the model are highly subjective. For purposes of determining compensation expense associated with stock options granted after January 1, 2006, we are required to determine the fair value of the stock options by applying a pricing model which includes assumptions for expected term, discount rate, stock volatility, expected forfeitures and a dividend rate. The use of different assumptions or a different model may have a material impact on our financial disclosures.
For the years ended December 31, 2009, 2008 and 2007, we applied a Black-Scholes model with similar assumptions for expected term (based on a probability analysis and ranging from 2.2 to 5.1 years), risk free rate (based upon published rates for U.S. Treasury notes), zero dividend rate and stock volatility, which we determined based on our historical common stock volatility for grants after June 2008 and estimated based on the historical volatility rates of several peer companies prior to that time. In addition, we estimated a forfeiture rate based upon our historical experience. We have recorded compensation expense associated with stock option and restricted stock grants totaling $12.2 million, $12.4 million and $7.6 million for the years ended December 31, 2009, 2008 and 2007, respectively.
Allowance for Bad Debts and Inventory Obsolescence
We record trade accounts receivable at billed amounts, less an allowance for bad debts. Inventory is recorded at cost, less an allowance for obsolescence. To estimate these allowances, management reviews the underlying details of these assets as well as known trends in the marketplace, and applies historical factors as a basis for recording these allowances. If market conditions are less favorable than those projected by management, or if our historical experience is materially different from future experience, additional allowances may be required.
There is a risk that management may not detect uncollectible accounts or unsalvageable inventory in the correct accounting period.
Bad debt expense has been less than 1% of sales for the years ended December 31, 2009, 2008 and 2007. If bad debt expense had increased by 1% of sales for the years ended December 31, 2009, 2008 and 2007, net income would have declined by $7.8 million, $11.9 million and $9.7 million, respectively. Our obsolescence and other inventory reserves were approximately 2%, 2% and 7% of our inventory balances at December 31, 2009, 2008 and 2007, respectively. A 1% increase in inventory reserves, from 2% to 3%, at December 31, 2009 would have decreased net income by $0.7 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. During September 2009, we evaluated the fair market value of assets in our contract drilling business with the assistance of a third-party appraiser and determined that the carrying value of certain of these drilling rigs exceeded the fair market value estimates. We projected the undiscounted cash flows associated with these rigs, including an estimate of salvage value, and compared these expected future cash flows to the carrying amount of the rigs. If the undiscounted cash flows exceeded the carrying amount, no further testing was performed and the rig was deemed to not be impaired. If the undiscounted cash flows did not exceed the carrying value, we estimated the fair market value of the equipment based on management estimates and general market data obtained by the third-party appraiser using the sales comparison market approach, which included the analysis of recent sales and offering prices of similar equipment to arrive at an indication of the most probable selling price for the equipment. The result of this analysis was a calculated fixed asset impairment of $36.2 million, which was recorded as an impairment loss in September 30, 2009. This impairment charge was allocated entirely to the drilling services business segment. This impairment was deemed necessary due to an overall decline in oil and gas exploration and production activity in late 2008 which extended throughout 2009, as well as management’s expectation of future operating results for this business segment. There were no significant impairment charges related to our long-term assets during the years ended December 31, 2008 and 2007. Depreciation and amortization expense for the years ended December 31, 2009 and 2008 represented 19% and 17% of the average depreciable asset base for the respective years. An increase in depreciation relative to the depreciable base of 1%, from 19% to 20%, would have reduced net income by approximately $7.9 million for the year ended December 31, 2009.
Self Insurance
On January 1, 2007, we began a self-insurance program to pay claims associated with health care benefits provided to certain of our employees in the United States. Pursuant to this program, we have purchased a stop-loss insurance policy from an insurance company. Our accounting policy for this self-insurance program is to accrue expense based upon the number of employees enrolled in the plan at pre-determined rates. As claims are processed and paid, we compare our claims history to our expected claims in order to estimate incurred but not reported claims. If our estimate of claims incurred but not reported exceeds our current accrual, we record additional expense during the current period. There is a risk that we may not estimate our incurred but not reported claims correctly or that our stop-loss provision may not be adequate to insure us against losses in the future. At December 31, 2009, we accrued $4.1 million pursuant to this self-insurance program. A 10% increase in this self-insurance accrual would reduce our net income for the year ended December 31, 2009 by $0.3 million.
Deferred Income Taxes
Our income tax expense includes income taxes related to the United States, Canada and other foreign countries, including local, state and provincial income taxes. We account for tax ramifications pursuant to U.S. GAAP for income taxes and record deferred income tax assets and liabilities based upon temporary differences between the carrying amount and tax basis of our assets and liabilities and measure tax expense using enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect of a change in tax rates is recognized in income in the period of the change. Furthermore, we record a valuation allowance for any net deferred income tax assets which we believe are likely to not be used through future operations. As of December 31, 2009, 2008 and 2007, 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, 2009, we did not provide deferred U.S. income taxes on approximately $21.2 million of undistributed earnings of our foreign subsidiaries in which we intend to indefinitely reinvest. Upon distribution of these earnings in the form of dividends or otherwise, we may be subject to U.S. income taxes and foreign withholding taxes. On January 1, 2007, we adopted the FASB interpretation that provides guidance to account for uncertain tax positions. During 2008, we performed an evaluation of our tax positions and determined that this interpretation did not have a material impact on our financial position, results of operations and cash flows. We have evaluated our tax positions at December 31, 2009 and believe these positions are deemed appropriate for all significant matters.
There is a risk that estimates related to the use of loss carry forwards and the realizability of deferred tax accounts may be incorrect, and that the result could materially impact our financial position and results of operations. In addition, future changes in tax laws or GAAP requirements could result in additional valuation allowances or the recognition of additional tax liabilities.
Historically, we have utilized net operating loss carry forwards to partially offset current tax expense, and we have recorded a valuation allowance to the extent we expect that our deferred tax assets will not be utilized through future operations. Deferred income tax assets totaled $33.0 million at December 31, 2009, against which we recorded a valuation allowance of $0.3 million, leaving a net deferred tax asset of $32.7 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 the FASB guidance on accounting for the impairment or disposal of long-lived assets. U.S. GAAP requires that we classify the assets and liabilities of a disposal group as held for sale if the following criteria are met: (1) management, with appropriate authority, commits to a plan to sell a disposal group; (2) the asset is available for immediate sale in its current condition; (3) an active program to locate a buyer and other actions to complete the sale have been initiated; (4) the sale is probable; (5) the disposal group is being actively marketed for sale at a reasonable price; and (6) actions required to complete the plan of sale indicate it is unlikely that significant changes to the plan of sale will occur or that the plan will be withdrawn. Once deemed held for sale, we no longer depreciate the assets of the disposal group. Upon sale, we calculate the gain or loss associated with the disposition by comparing the carrying value of the assets less direct costs of the sale with the proceeds received. In conjunction with the sale, we settle inter-company balances between us and the disposal group and allocate interest expense to the disposal group for the period the assets were held for sale. In the statement of operations, we present discontinued operations, net of tax effect, as a separate caption below net income from continuing operations.
Prior Period Adjustments
In June 2009, we discovered accounting errors within one of our operations located in the Rocky Mountain region, which occurred in prior years and impacted our reported operating results for the years ended December 31, 2006, 2007 and 2008. The majority of the errors were due to a flawed revenue accrual process and ineffective controls over inventory within this operation. We evaluated the impact that these errors had on our financial statements and determined that these errors would not have been material to our financial statements from a quantitative or qualitative perspective for those periods. However, the amount of the adjustment required to correct these errors was deemed to be material to the results for 2009. We corrected these errors as of June 30, 2009 and made the required adjustments to our reported results for the comparative periods in the applicable subsequent public filings. In addition, we have adjusted our previously published balance sheet at December 31, 2008, decreasing beginning retained earnings by $8,405. As applicable, we revised the presentation of the selected data above for the years ended December 31, 2006, 2007 and 2008. We have labeled the following tables “Revised” where applicable.
Results of Operations for the Years Ended December 31, 2009 and
The following tables set forth our results of continuing operations, including amounts expressed as a percentage of total revenue, for the periods indicated (in thousands, except percentages).
“Corporate” includes amounts related to corporate personnel costs, other general expenses and stock-based compensation charges.
“Adjusted EBITDA” consists of net income (loss) from continuing operations before net interest expense, taxes, depreciation and amortization, non-controlling interest and impairment loss. Adjusted EBITDA is a non-GAAP measure of performance. We use Adjusted EBITDA as the primary internal management measure for evaluating performance and allocating additional resources. The following table reconciles Adjusted EBITDA for the years ended December 31, 2009 and 2008 to the most comparable U.S. GAAP measure, operating income (loss). The calculation of Adjusted EBITDA is different from the calculation of “EBITDA,” as defined and used in our credit facilities. For a discussion of the calculation of “EBITDA” as defined under our existing credit facilities, as recently amended, see Note 7, Long-term debt.
Reconciliation of Adjusted 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, 2009 Compared to the Year ended December 31, 2008
Revenue
Revenue from continuing operations for the year ended December 31, 2009 decreased by $778.5 million, or 42%, to $1,056.4 million from $1,834.9 million for the year ended December 31, 2008. This decrease by segment was as follows:
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Completion and Production Services. Segment revenue decreased $644.1 million, or 42%, primarily due to an overall decline in investment by our customers in oil and gas exploration and development activities resulting from lower oil and gas commodity prices and concerns over the availability of capital for such investment. We experienced lower utilization and pricing for each of our service offerings on a year-over-year basis, except for our coiled tubing business in Mexico which provided a positive contribution to 2009 results. In the fourth quarter of 2009, we experienced an increase in revenues and margins compared to the third quarter of 2009 as market conditions showed signs of improvement.
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Drilling Services. Segment revenue decreased $119.4 million, or 51%, for the year, primarily due to the overall decline in oilfield service activities throughout the year compared to 2008. Lower utilization rates and pricing pressure impacted our rig logistics and drilling businesses, however revenues were up slightly in the fourth quarter of 2009 compared to the third quarter of 2009 as we experienced a slight increase in customer activity.
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Product Sales. Segment revenue decreased $15.0 million, or 25%, for the year, primarily due to a decline in our Southeast Asian business resulting from a change in the sales mix and the timing of product sales and equipment refurbishment, which tends to be project-specific. Partially offsetting this decrease were the consistent revenues earned at our fabrication business in north Texas year-over-year, which included a work-over rig project completed in the first quarter of 2009 and sales of low margin equipment to third-parties.
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 decreased $411.1 million, or 36%, to $725.4 million for the year ended December 31, 2009 from $1,136.5 million for the year ended December 31, 2008. The decline in service and product expenses was primarily due to significantly lower activity levels and cost-saving measures we began implementing in late 2008, including headcount reductions, payroll concessions and reduced product and service costs from outside vendors. The following table summarizes service and product expenses as a percentage of revenues for the years ended December 31, 2009 and 2008:
Service and Product Expenses as a Percentage of Revenue
Service and product expenses as a percentage of revenue increased to 69% for the year ended December 31, 2009 compared to 62% for the year ended December 31, 2008. Margins by business segment were impacted primarily by pricing and utilization.
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Completion and Production Services. Service and product expenses as a percentage of revenue for this business segment increased when comparing the year ended December 31, 2009 to the same period in 2008.
The overall decline in activity levels in the oil and gas industry, which began in late 2008 and continued throughout most of the year in 2009, resulted in lower utilization of our equipment and services, and pricing pressure from competitors. Partially defraying the impact of this overall decline in activity levels were cost-saving measures we began implementing in late 2008.
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Drilling Services. The increase in service and product expenses as a percentage of revenue for this business segment was primarily due to lower utilization of our equipment due to significantly reduced activity levels by our customers, and lower pricing on a year-over-year basis, partially offset by cost-saving measures.
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Product Sales. The increase in service and product expenses as a percentage of revenue for the products segments was primarily due to the mix of products sold for the relative periods, as the 2008 results included several higher margin projects associated with our Southeast Asian operations when compared to the year ended December 31, 2009. Additionally, on a year-over-year basis, a larger proportion of the revenues and related costs for the product sales segment for the year ended December 31, 2009 were provided by our repair and fabrication facility in north Texas at lower margins relative to our Southeast Asian business, including the sale of a large inventory item.
Selling, General and Administrative Expenses
Selling, general and administrative expenses include salaries and other related expenses for our selling, administrative, finance, information technology and human resource functions. Selling, general and administrative expenses decreased $16.8 million, or 8%, for the year ended December 31, 2009 to $181.4 million from $198.2 million during the year ended December 31, 2008. Several cost saving measures were implemented during 2009 including headcount reductions, other payroll concessions and lower outside service costs. These expense reductions were offset by: (1) the loss on the exchange of certain non-monetary assets in Canada during the first quarter of 2009 which totaled $4.9 million; (2) higher bad debt expense, particularly in our drilling services segment and (3) higher losses from the disposal of fixed assets. Excluding the impact of the non-monetary asset exchange in Canada, as a percentage of revenues, selling, general and administrative expense was 17% and 11% for the years ended December 31, 2009 and 2008, respectively.
Depreciation and Amortization
Depreciation and amortization expense increased $19.5 million, or 11%, to $200.7 million for the year ended December 31, 2009 from $181.2 million for the year ended December 31, 2008. The increase in depreciation and amortization expense was the result of the following: (1) depreciation of equipment placed into service throughout 2008, as well as additional equipment purchased in 2009; (2) depreciation and amortization expense related to assets associated with businesses acquired in 2008, some of which did not contribute depreciation expense for the full year ended December 31, 2008 due to the timing of the acquisitions; and (3) an increase in amortization expense associated with intangible assets acquired in business combinations in 2008. As a percentage of revenue, depreciation and amortization expense increased to 19% from 10% for the years ended December 31, 2009 and 2008, respectively. We expect depreciation and amortization expense as a percentage of revenue to continue to remain higher than in recent periods due to the significant investment in capital expenditures made throughout the last three years and the overall decline in activity levels that began in late 2008.
Fixed asset and other intangible impairment loss
For the year ended December 31, 2009, we recorded a fixed asset and other intangible impairment loss of $38.6 million. We recorded a charge of $36.2 million related to our contract drilling business in the third quarter of 2009 after determining that the carrying value of certain of these drilling rigs exceeded the undiscounted cash flows associated with these assets and the fair market value estimates for these assets. In the fourth quarter of 2009, we recorded an impairment of intangible assets of $2.5 million related to our completion and production business. We recorded no such expense in 2008.
Goodwill impairment Loss
We recorded a goodwill impairment loss of $97.6 million for the year ended December 31, 2009 compared to $272.0 million recorded in 2008. These write-downs of goodwill in both 2008 and 2009 were associated with several of our reporting units and were based upon a discounted cash flow analysis of expected future earnings associated with these businesses. Our analysis of future cash flows was impacted significantly by the overall decline in oilfield activity in late 2008 which continued throughout 2009.
Interest Expense
Interest expense was $56.9 million and $59.7 million for the years ended December 31, 2009 and 2008, respectively. This 5% decrease in interest expense was attributable primarily to a decrease in the average amount of debt outstanding during the year ended December 31, 2009 and lower interest rates in 2009 compared to 2008 on our outstanding borrowings under revolving credit facilities, which were fully repaid as of June 30, 2009. The weighted-average interest rate of borrowings outstanding at December 31, 2009 and 2008 was approximately 8.0% and 7.0%, respectively.
Taxes
Tax expense (benefit) is comprised of current income taxes and deferred income taxes. The current and deferred taxes added together provide an indication of an effective rate of income tax.
We recorded a tax benefit of $63.1 million for the year ended December 31, 2009 at an effective rate of approximately 25.8%. The lower effective tax rate in 2009 was due to the impairment of goodwill with limited tax basis. Our tax rate for the year ended December 31, 2008 was impacted significantly by a $272.0 million impairment of goodwill which had a limited tax basis, as the majority of the goodwill arose through stock purchase transactions with little or no tax basis. Excluding the impact of the goodwill impairment charges, our effective tax rates for the years ended December 31, 2009 and 2008 would have been 33.9% and 35.5%
Results of Operations for the Years Ended December 31, 2008 and
The following tables set forth our results of continuing operations, including amounts expressed as a percentage of total revenue, for the periods indicated (in thousands, except percentages).
“Corporate” includes amounts related to corporate personnel costs, other general expenses and stock-based compensation charges.
“Adjusted EBITDA” consists of net income (loss) from continuing operations before net interest expense, taxes, depreciation and amortization, non-controlling interest and impairment loss. Adjusted EBITDA is a non-GAAP measure of performance. We use Adjusted EBITDA as the primary internal management measure for evaluating performance and allocating additional resources. The following table reconciles Adjusted EBITDA for the years ended December 31, 2008 and 2007 to the most comparable U.S. GAAP measure, operating income (loss). The calculation of Adjusted EBITDA is different from the calculation of “EBITDA,” as defined and used in our credit facilities. For a discussion of the calculation of “EBITDA” as defined under our existing credit facilities, as recently amended, see Note 7, Long-term debt.
Reconciliation of Adjusted 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, 2008 Compared to the Year ended December 31, 2007
Revenue
Revenue from continuing operations for the year ended December 31, 2008 increased by $343.7 million, or 23%, to $1,834.9 million from $1,491.3 million for the year ended December 31, 2007. This increase by segment was as follows:
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Completion and Production Services. Segment revenue increased $303.6 million, or 25%, primarily due to revenues earned as a result of additional capital investment in our pressure pumping, coiled tubing, well servicing, rental and fluid handling businesses in 2007 and 2008. We experienced favorable results for our pressure pumping, fluid handling, well service and U.S. and Mexican coiled tubing businesses when comparing 2008 to 2007. Revenues for our pressure pumping business increased due to: (1) the successful integration of a business acquired in April 2008, and (2) the expansion of services into the Bakken Shale area of North Dakota. During 2007 and 2008, we completed a series of small acquisitions which provided incremental revenues for 2008 compared to 2007 due to the timing of those acquisitions. Revenue increases were partially offset by a general decline in oilfield activity which began during the fourth quarter of 2008 and pricing pressures in certain service offerings during the latter half of 2007 and throughout 2008.
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Drilling Services. Segment revenue increased $21.8 million, or 10%, for the year, primarily due to higher utilization rates and additional capital invested in our contract drilling business in 2007 and 2008. In early 2008, we experienced lower pricing for our drilling services and lower utilization rates in our rig logistics operations primarily due to an increase in equipment placed into service by our competitors. However, utilization improved during the second and third quarters of 2008, before declining in the fourth quarter due to a general decline in oilfield activity by our customers.
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Product Sales. Segment revenue increased $18.2 million, or 45%, for the year, primarily due to the sales mix and the timing of product sales and equipment refurbishment for our Southeast Asian business, which tends to be project-specific. We also had a larger volume of third-party sales at our repair and fabrication shop in north Texas during 2008 as compared to 2007.
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 $260.9 million, or 30%, to $1,136.5 million for the year ended December 31, 2008 from $875.6 million for the year ended December 31, 2007. The following table summarizes service and product expenses as a percentage of revenues for the years ended December 31, 2008 and 2007:
Service and Product Expenses as a Percentage of Revenue
Service and product expenses as a percentage of revenue increased to 62% for the year ended December 31, 2008 compared to 58% for the year ended December 31, 2007. Margins by business segment were impacted by acquisitions, pricing and utilization.
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Completion and Production Services. The increase in service and product expenses as a percentage of revenue for this business segment reflects pricing pressure for many of our service lines throughout 2008, resulting in less favorable operating margins on a year-over-year basis. We incurred higher labor and fuel costs during 2008, although fuel costs began to decline in the fourth quarter of 2008, and we incurred higher sand and cement costs in our pressure pumping business. Start-up costs associated with mobilizing a frac fleet in the Bakken Shale area of North Dakota also impacted our operating margins. Cost increases were partially offset by the mix of services provided in 2008 compared to 2007, a full-year’s benefit of capital invested throughout 2007, additional equipment placed into service during 2008 and several acquisitions. In late 2008, we experienced lower utilization rates and an increase in pricing pressure in several service lines due to a general decline in oilfield activity, which may stem from lower commodity prices and concerns over the broader U.S. economy and the availability of credit for investment by our customers.
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Drilling Services. The increase in service and product expenses as a percentage of revenue for this business segment represented a decline in margin during 2008 compared to 2007 due to: (1) lower pricing for our contract drilling and drilling logistics businesses on a year-over-year basis; (2) higher operating costs associated primarily with labor and fuel; and (3) lower utilization of our equipment due primarily to more market competition.
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Product Sales. The increase in service and product expenses as a percentage of revenue for the products segments was primarily due to the mix of products sold, specifically the timing of equipment sales and refurbishment associated with our Southeast Asian operations which tend to be project-specific and can fluctuate between periods depending upon the nature of the projects in process, and third-party repair and fabrication work performed at our shop in north Texas.
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 $18.7 million, or 10%, for the year ended December 31, 2008 to $198.2 million from
$179.5 million during the year ended December 31, 2007. These expense increases included: (1) costs associated with businesses acquired in 2008, including additional employee headcount, property rental expense and insurance expense; (2) costs associated with 2007 acquisitions, which provided a full-year of selling, general and administrative expense for 2008; (3) incremental costs of approximately $5.0 million related to stock-based compensation in 2008 compared to the prior year; and (4) costs associated with the retirement of an executive officer during the fourth quarter of 2008 and other severance costs. As a percentage of revenues, selling, general and administrative expense declined to 11% for the year ended December 31, 2008 as compared to 12% for the year ended December 31, 2007.
Depreciation and Amortization
Depreciation and amortization expense increased $49.8 million, or 38%, to $181.2 million for the year ended December 31, 2008 from $131.4 million for the year ended December 31, 2007. The increase in depreciation and amortization expense was the result of equipment placed into service in 2008, a portion of which was purchased in 2007. Capital expenditures for equipment in 2008 totaled $253.8 million. In addition, we recorded depreciation and amortization expense related to businesses acquired in 2007 and 2008, as well as assets purchased and placed into service throughout 2007, which contributed a full year of depreciation expense in 2008 compared to a partial year of depreciation expense in 2007. In addition, we incurred incremental amortization expense associated with intangible assets related to businesses acquired in 2008, particularly customer relationship intangibles which totaled $14.0 million. As a percentage of revenue, depreciation and amortization expense increased to 10% for the year ended December 31, 2008 as compared to 9% for the year ended December 31, 2007.
Impairment Loss
We recorded an impairment loss of $272.0 million related to the write-down of goodwill associated with several of our reporting units based upon a discounted cash flow analysis of expected future earnings associated with these businesses. This analysis was impacted significantly by the overall decline in oilfield activity in late 2008 and the expected slowdown in activities in the short-term, due in part to concerns of excess supply of commodities, a general decline in the U.S. economy and concerns over the availability of credit for our customers to continue investment in drilling and exploration activities in the short-term. We recorded an impairment charge of $13.1 million for the year ended December 31, 2007 related to our Canadian operations.
Interest Expense
Interest expense was $59.7 million and $61.3 million for the years ended December 31, 2008 and 2007, respectively. The decrease in interest expense was attributable primarily to a decline in the average borrowing rate in 2008 for variable rate borrowings, primarily our revolving credit facilities in the U.S. and Canada. This decline in the average borrowing rate was partially offset by an increase in the average debt balance outstanding throughout 2008 as compared to 2007. These borrowings were used primarily for business acquisitions and equipment purchases during 2008. The weighted-average interest rate of borrowings outstanding at December 31, 2008 and 2007 was approximately 7.0% and 7.7%, respectively.
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.
Our tax rate for the year ended December 31, 2008 was impacted significantly by a $272.0 million impairment of goodwill which had a limited tax basis, as the majority of the goodwill arose through stock purchase transactions with little or no tax basis. We received no tax benefit from the $13.1 million impairment of goodwill recorded at December 31, 2007. Excluding the impact of the goodwill impairment charges, our effective tax rates for the years ended December 31, 2008 and 2007 would have been 35.5% and 34.8%, respectively. The difference in the tax rates was attributable to the impact of the domestic production activities deduction and the effect of changes in earnings in the various tax jurisdictions in which we operate.
Non-Controlling Interest
Prior to December 31, 2007, an unrelated third party owned a 50% interest in Premier Integrated Technologies, Inc. (“Premier”), a company that we acquired on January 1, 2005, and have consolidated in our accounts since the date of acquisition. This amount represents the minority owner’s share of Premier’s earnings for the applicable periods. On December 31, 2007, we acquired the remaining 50% interest in this company.
Liquidity and Capital Resources
The recent and unprecedented disruption in the credit markets has had a significant adverse impact on the availability of credit from a number of financial institutions. We are not currently a party to any interest rate swaps, currency hedges or derivative contracts of any type and have no exposure to commercial paper or auction rate securities markets. We will continue to closely monitor our liquidity and the overall health of the credit markets. However, we cannot predict with any certainty the impact that any further disruption in the credit environment would have on us. We had cash and cash equivalents at December 31, 2009 and 2008 of $77.4 million and $18.5 million, respectively.
Our primary liquidity needs are to fund capital expenditures and general working capital. In addition, we have historically obtained capital to fund strategic business acquisitions. Our primary sources of funds have been cash flow from operations, proceeds from borrowings under bank credit facilities, a private placement of debt that was subsequently exchanged for publicly registered debt and the issuance of equity securities in our initial public offering.
We anticipate that we will rely on cash generated from operations, borrowings under our amended revolving credit facility, future debt offerings and/or future public equity offerings to satisfy our liquidity needs. We believe that funds from these sources, or funds received from our newly amended credit facility, will be sufficient to meet both our short-term working capital requirements and our long-term capital requirements. If our plans or assumptions change, or are inaccurate, or if we make further acquisitions, we may have to raise additional capital. Our ability to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance, and more broadly, on the availability of equity and debt financing, which will be affected by prevailing economic conditions in our industry, and general financial, business and other factors, some of which are beyond our control. In addition, new debt obtained could include service requirements based on higher interest paid and shorter maturities and could 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.
On October 13, 2009, we completed an amendment to our existing revolving credit facilities (the “Third Amendment”) which modified the structure of the credit facility to an asset-based facility subject to borrowing base restrictions. This amendment provided us with less restrictive financial debt covenants and reduced borrowing capacity under the facility. We believe the amended revolving credit facility will allow us to better manage our cash flow needs, provide greater certainty of access to funds in the future and allow us to use our asset base for future financing needs.
The following table summarizes cash flows by type for the periods indicated (in thousands):
Net cash provided by operating activities decreased $65.2 million for the year ended December 31, 2009 compared to the year ended December 31, 2008, and increased $12.0 million for the year ended December 31, 2008 compared to the year ended December 31, 2007. The decrease in operating cash flows for the year ended December 31, 2009 compared to the year ended December 31, 2008 was primarily due to lower sales in 2009 resulting from the general slowdown of activity in the oil and gas industry which started in the fourth quarter of
2008, offset by an increase in cash receipts from collections of outstanding accounts receivable, due to lower receivable balances from the decline in revenues.
Net cash used in investing activities decreased $356.0 million for the year ended December 31, 2009 compared to the prior year, and increased $35.1 million for the year ended December 31, 2008 compared to the year ended December 31, 2007. Of this decrease, $215.3 million was due to a reduction in the funds used to invest in capital equipment, which was $38.5 million for the year ended December 31, 2009 compared to $253.8 million for the year ended December 31, 2008. We decreased our overall capital expenditures in 2009 in response to the decline in commodity prices and lower activity levels. In addition, we invested $180.2 million in business acquisitions in 2008, with no corresponding business acquisitions in 2009, and we received $50.2 million as proceeds from the sale of a discontinued operation in May 2008. For the year ended December 31, 2007, we invested $372.9 million in capital equipment and $50.4 million in business acquisitions.
Net cash used for financing activities was $208.0 million for the year ended December 31, 2009 compared to cash provided by financing activities of $28.0 million and $66.6 million for the years ended December 31, 2008 and 2007, respectively. We repaid long-term borrowings under our debt facilities totaling $200.6 million and only borrowed $3.2 million during 2009. The primary source of these funds in 2009 was cash flow from operations. For the year ended December 31, 2008, we borrowed $350.1 million and repaid $329.3 million, a net borrowing of $20.8 million under our debt facilities. The source of funds for this net repayment in 2008 was cash flow from operations and funds received from the sale of a discontinued operation in 2008. Borrowings were used to fund capital expenditures, business acquisitions and general corporate needs. The source of cash for the year ended December 31, 2007 was borrowings under debt facilities to fund investment in equipment and acquisitions. In 2009, we focused on eliminating obligations under our credit facility and building cash. Our long-term debt balances, including current maturities, were $650.2 million and $847.6 million as of December 31, 2009 and 2008, respectively.
We spent significantly less than we have in recent years for investment in capital expenditures and acquisitions, during the year ended December 31, 2009. We anticipate our capital expenditures will increase in 2010 and we will continue to evaluate acquisitions of complementary companies. We believe that our operating cash flows and borrowing capacity will be sufficient to fund our operations for the next 12 months.
Dividends
We did not pay dividends on our $0.01 par value common stock during the years ended December 31, 2009, 2008 and 2007. 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 contains restrictive debt covenants which preclude us from paying future dividends on our common stock.
Description of Our Indebtedness
Senior Notes.
On December 6, 2006, we issued 8.0% senior notes with a face value of $650.0 million through a private placement of debt. These notes mature in 10 years, on December 15, 2016, and require semi-annual interest payments, paid in arrears and calculated based on an annual rate of 8.0%, on June 15 and December 15, of each year, which commenced on June 15, 2007. There was no discount or premium associated with the issuance of these notes. The senior notes are guaranteed by all of our current domestic subsidiaries. The senior notes have covenants which, among other things: (1) limit the amount of additional indebtedness we can incur; (2) limit restricted payments such as a dividend; (3) limit our ability to incur liens or encumbrances; (4) limit our ability to purchase, transfer or dispose of significant assets; (5) limit our ability to purchase or redeem stock or subordinated debt; (6) limit our ability to enter into transactions with affiliates; (7) limit our ability to merge with or into other companies or transfer all or substantially all of our assets; and (8) limit our ability to enter into sale and leaseback transactions. We have the option to redeem all or part of these notes on or after December 15, 2011. Additionally, we may redeem some or all of the notes prior to December 15, 2011 at a price equal to 100% of the principal amount of the notes plus a make-whole premium.
Pursuant to a registration rights agreement with the holders of our 8.0% senior notes, on June 1, 2007, we filed a registration statement on Form S-4 with the SEC which enabled these holders to exchange their notes for publicly registered notes with substantially identical terms. These holders exchanged 100% of the notes for publicly traded notes on July 25, 2007. On August 28, 2007, we entered into a supplement to the indenture governing the 8.0% senior notes, whereby additional domestic subsidiaries became guarantors under the indenture. Effective April 1, 2009, we entered into a second supplement to this indenture whereby additional domestic subsidiaries became guarantors under the indenture.
We issued subordinated seller notes totaling $3,450 in 2004 related to certain business acquisitions. These notes bore interest at 6% and matured in March 2009. We repaid the outstanding principal associated with these note agreements totaling $3,450 upon maturity.
Credit Facility.
On December 5, 2008, we entered into a senior secured credit facility (the “Credit Agreement”) with Wells Fargo Bank, National Association, as U.S. Administrative Agent, HSBC Bank Canada, as Canadian Administrative Agent, and certain other financial institutions. On October 13, 2009, we entered into the Third Amendment (the Credit Agreement, after giving effect to the Third Amendment, the “Amended Credit Agreement”) and modified the structure of our existing credit facility to an asset-based facility subject to borrowing base restrictions. In connection with the Third Amendment, Wells Fargo Capital Finance, LLC (formerly known as Wells Fargo Foothill, LLC) replaced Wells Fargo Bank, National Association, as U.S. Administrative Agent and also serves as U.S. Issuing Lender and U.S. Swingline Lender under the Amended Credit Agreement. The Amended Credit Agreement provides for a U.S. revolving credit facility of up to $225.0 million that matures in December 2011 and a Canadian revolving credit facility of up to $15.0 million (with Integrated Production Services Ltd., one of our wholly-owned subsidiaries, as the borrower thereof (“Canadian Borrower”)) that matures in December 2011. The Amended Credit Agreement includes a provision for a “commitment increase”, as defined therein, which permits us to effect up to two separate increases in the aggregate commitments under the Amended Credit Agreement by designating one or more existing lenders or other banks or financial institutions, subject to the bank’s sole discretion as to participation, to provide additional aggregate financing up to $75.0 million, with each committed increase equal to at least $25.0 million in the U.S., or $5.0 million in Canada, and in accordance with other provisions as stipulated in the Amended Credit Agreement. Certain portions of the credit facilities are available to be borrowed in U.S. dollars, Canadian dollars and other currencies approved by the lenders.
Our U.S. borrowing base is limited to: (1) 85% of U.S. eligible billed accounts receivable, less dilution, if any, plus (2) the lesser of 55% of the amount of U.S. eligible unbilled accounts receivable or $10.0 million, plus (3) the lesser of the “equipment reserve amount” and 80% times the most recently determined “net liquidation percentage”, as defined in the Amended Credit Agreement, times the value of our and the U.S. subsidiary guarantors’ equipment, provided that at no time shall the amount determined under this clause exceed 50% of the U.S. borrowing base, minus (4) the aggregate sum of reserves established by the U.S. Administrative Agent, if any. The “equipment reserve amount” means $50.0 million upon the effective date of the Third Amendment, less $0.6 million for each subsequent month, not to be reduced below zero in the aggregate.
The Canadian borrowing based is limited to: (1) 80% of Canadian eligible billed accounts receivable, plus (2) if the Canadian Borrower has requested credit for equipment under the Canadian borrowing base, the lesser of (a) $15.0 million, and (b) 80% times the most recently determined “net liquidation percentage”, as defined in the Amended Credit Agreement, times the value (calculated on a basis consistent with our historical accounting practices) of our and the US subsidiary guarantors’ equipment, minus (3) the aggregate amount of reserves established by our Canadian Administrative Agent, if any.
Subject to certain limitations set forth in the Amended Credit Agreement, we have the ability to elect how interest under the Amended Credit Agreement will be computed. Interest under the Amended Credit Agreement may be determined by reference to (1) the London Inter-bank Offered Rate, or LIBOR, plus an applicable margin between 3.75% and 4.25% per annum (with the applicable margin depending upon our “excess availability amount”, as defined in the Amended Credit Agreement) or (2) the “Base Rate” (which means the higher of the Prime Rate, Federal Funds Rate plus 0.50%, or the 3-month LIBOR plus 1.00% and 3.50%), plus the applicable margin, as described above. For
the period from the effective date of the Third Amendment until the six month anniversary of the effective date of the Third Amendment, interest will be computed as described above with an applicable margin rate of 4.00%. If an event of default exists or continues under the Amended Credit Agreement, advances will bear interest as described above with an applicable margin rate of 4.25% plus 2.00%. Additionally, if an event of default exists under the Amended Credit Agreement, as defined therein, the lenders could accelerate the maturity of the obligations outstanding thereunder and exercise other rights and remedies. Interest is payable monthly.
Under the Amended Credit Agreement, we are permitted to prepay our borrowings and we have the right to terminate, in whole or in part, the unused portion of the U.S. commitments in $1.0 million increments upon written notice to the U.S. Administrative Agent. If all of the U.S. facility is terminated, the Canadian facility must also be terminated.
All of the obligations under the U.S. portion of the Amended Credit Agreement are secured by first priority liens on substantially all of our assets and the assets of our U.S. subsidiaries as well as a pledge of approximately 66% of the stock of our first-tier foreign subsidiaries. Additionally, all of the obligations under the U.S. portion of the Amended Credit Agreement are guaranteed by substantially all of our U.S. subsidiaries. The obligations under the Canadian portion of the Amended Credit Agreement are secured by first priority liens on substantially all of our assets and the assets of our subsidiaries (other than our Mexican subsidiary). Additionally, all of the obligations under the Canadian portion of the Amended Credit Agreement are guaranteed by us as well as certain of our subsidiaries.
The Amended Credit Agreement also contains various covenants that limit our and our subsidiaries’ ability to: (1) grant certain liens; (2) incur additional indebtedness; (3) make certain loans and investments; (4) make capital expenditures; (5) make distributions; (6) make acquisitions; (7) enter into hedging transactions; (8) merge or consolidate; or (9) engage in certain asset dispositions. The Amended Credit Agreement contains one financial maintenance covenant which requires us and our subsidiaries, on a consolidated basis, to maintain a “fixed charge coverage ratio”, as defined in the Amended Credit Agreement, of not less than 1.10 to 1.00. This covenant is only tested if our “excess availability amount”, as defined under the Amended Credit Agreement, plus certain qualified cash and cash equivalents (collectively “Liquidity”) is less than $50.0 million for a period of 5 consecutive days and continues only until such time as our Liquidity has been greater than or equal to $50.0 million for a period of 90 consecutive days or greater than or equal to $75.0 million for a period of 45 consecutive days.
Our fixed charge coverage ratio covenant is calculated, for fiscal quarters ending after September 30, 2009, as the ratio of “EBITDA” calculated for the four fiscal quarter period ended after September 30, 2009 minus capital expenditures made with cash (to the extent not already incurred in a prior period) or incurred during such four quarter period, compared to “fixed charges”, calculated for the four quarters then ended. “EBITDA” is defined in the Amended Credit Agreement as consolidated net income for the period plus, to the extent deducted in determining our consolidated net income, interest expense, taxes, depreciation, amortization and other non-cash charges for such period, provided that EBITDA shall be subject to pro forma adjustments for acquisitions and non-ordinary course asset sales assuming that such transactions occurred on the first day of the determination period, which adjustments shall be made in accordance with the guidelines for pro forma presentations set forth by the Securities and Exchange Commission. “Fixed charges”, as defined in the Amended Credit Agreement, include interest expense, among other things, reduced by the amortization of transaction fees associated with the Third Amendment.
We were in compliance with the fixed charge coverage ratio covenant in the Amended Credit Agreement as of December 31, 2009. However, there can be no assurance as to our future compliance in light of highly uncertain industry conditions. See “Risk Factors - Risks Related to Our Business and Our Industry” and “Risk Factors - Risks Related to Our Indebtedness, including Our Senior Notes.”
We will incur unused commitment fees under the Amended Credit Agreement ranging from 0.50% to 1.00% based on the average daily balance of amounts outstanding. The unused commitment fees were calculated at 1.00% as of December 31, 2009.
To date, we have incurred fees and expenses associated with the execution and effectiveness of the Third Amendment totaling approximately $2,911. These fees and expenses are included in our consolidated balance sheet
as a long-term asset, deferred financing fees, at December 31, 2009 and will be amortized to interest expense over the remaining term of the facility.
There were no revolving borrowings outstanding under our U.S. or Canadian revolving credit facilities as of December 31, 2009. The weighted average interest rate for our revolving credit facilities during the twelve months ended December 31, 2009 was 1.87%. There were letters of credit outstanding under the U.S. revolving portion of the facility totaling $54.6 million, which reduced the available borrowing capacity as of December 31, 2009. We incurred fees calculated at 1.25% of the total amount outstanding under letter of credit arrangements through October 12, 2009. Under the Amended Credit Agreement, effective October 13, 2009, we incurred fees related to our letters of credit, calculated using a 360-day provision, at 4.1% per annum. The net excess availability under our borrowing base calculations for the U.S. and Canadian revolving facilities at December 31, 2009 was $79.5 million and $5.1 million, respectively.
Outstanding Debt and Operating Lease Commitments
The following table summarizes our known contractual obligations as of December 31, 2009 (in thousands):
(1)
Purchase obligations were pursuant to non-cancelable equipment purchase orders outstanding as of December 31, 2009. We have no significant purchase orders which extend beyond one year.
(2)
Other long-term obligations include amounts for loans relating to equipment purchases which mature at various dates through September 2010.
We have entered into agreements to purchase certain equipment for use in our business, which are included as purchase obligations in the table above to the extent that these obligations represent firm non-cancelable commitments. The manufacture of this equipment requires lead-time and we generally are committed to accept this equipment at the time of delivery, unless arrangements have been made to cancel delivery in accordance with the purchase agreement terms. We spent $38.5 million for equipment purchases and other capital expenditures during the year ended December 31, 2009.
We expect to continue to acquire complementary companies and evaluate potential acquisition targets. We may use cash from operations, proceeds from future debt or equity offerings and borrowings under our amended revolving credit facility for this purpose.
Off-Balance Sheet Arrangements
We have entered into operating lease arrangements for our light vehicle fleet, certain of our specialized equipment and for our office and field operating locations in the normal course of business. The terms of the facility leases range from monthly to five years. The terms of the light vehicle leases range from three to four years. The terms of the specialized equipment leases range from two to six years. Annual payments pursuant to these leases are included above in the table under “- Outstanding Debt and Operating Lease Commitments.”
Recent Accounting Pronouncements and Authoritative Literature
In December 2007, the FASB issued additional guidance regarding business combinations that replaced the initial statement in its entirety. The guidance now additionally requires that all assets and liabilities and non-controlling interests of an acquired business be measured at their fair value, with limited exceptions, including the recognition of acquisition-related costs and anticipated restructuring costs separate from the acquired net assets. The statement also provides guidance for recognizing pre-acquisition contingencies and states that an acquirer must recognize assets and liabilities assumed arising from contractual contingencies as of the acquisition date, measured at acquisition-date fair values, but must recognize all other contractual contingencies as of the acquisition date, measured at their acquisition-date fair values only if it is more likely than not that these contingencies meet the definition of an asset or liability. Furthermore, this statement provides guidance for measuring goodwill and recording a bargain purchase, defined as a business combination in which total acquisition-date fair value of the identifiable net assets acquired exceeds the fair value of the consideration transferred plus any non-controlling interest in the acquiree, and it requires that the acquirer recognize that excess in earnings as a gain attributable to the acquirer. In April 2009, the FASB issued a further update regarding accounting for assets and liabilities assumed in a business combination that arises from contingencies which amends the previous guidance to require contingent assets acquired and liabilities assumed in a business combination to be recognized at fair value on the acquisition date if fair value can be reasonably estimated during the measurement period. If fair value cannot be reasonably estimated during the measurement period, the contingent asset or liability would be recognized in accordance with U.S. GAAP to account for contingencies and reasonable estimation of the amount of loss, if any. Further, this update eliminated the specific subsequent accounting guidance for contingent assets and liabilities, without significantly revising the original guidance. However, contingent consideration arrangements of an acquiree assumed by the acquirer in a business combination would still be initially and subsequently measured at fair value. We adopted this additional guidance regarding business combinations on January 1, 2009 with no impact on our financial position, results of operations and cash flows.
In December 2007, the FASB issued guidance which established accounting and reporting standards for non-controlling interests, formerly referred to as minority interests. This guidance requires separate presentation of the non-controlling interest as a component of equity on the balance sheet, and that net income be presented prior to adjustment for the non-controlling interests’ portion of earnings with the portion of net income attributable to the parent company and the non-controlling interest both presented on the face of the statement of operations. We determined that this guidance had no impact on our financial statements for the years ended December 31, 2009 and 2008, and no material impact for the year ended December 31, 2007. Therefore, no presentation changes have been made to the consolidated financial statements relating to non-controlling interest.
In September 2008, the FASB issued guidance regarding the reporting of discontinued operations which clarified the definition of a discontinued operation as either: (1) a component of an entity which has been disposed of or classified as held for sale which meets the criteria of an operating segment, or (2) as a business which meets the criteria to be classified as held for sale on acquisition. This proposed guidance further modifies certain disclosure requirements. We are currently evaluating the effect this proposed guidance may have on our financial position, results of operations and cash flows.
In May 2009, the FASB issued a standard regarding subsequent events that provides guidance as when an entity should recognize events or transactions occurring after a balance sheet date in its financial statements and the necessary disclosures related to these events. Specifically, the entity should recognize subsequent events that provide evidence about conditions that existed at the balance sheet date, including significant estimates used to prepare financial statements. An entity must disclose the date through which subsequent events have been evaluated and whether that date is the date the financial statements were issued or the date the financial statements were available to be issued. We adopted this new accounting standard effective June 30, 2009 and have applied its provisions prospectively.
In August 2009, the FASB further updated the fair value measurement guidance to clarify how an entity should measure liabilities at fair value. The update reaffirms fair value is based on an orderly transaction between market participants, even though liabilities are infrequently transferred due to contractual or other legal restrictions. However, identical liabilities traded in the active market should be used when available. When quoted prices are not available, the quoted price of the identical liability traded as an asset, quoted prices for similar liabilities or similar liabilities traded as an asset, or another valuation approach should be used. This update also clarifies that restrictions
preventing the transfer of a liability should not be considered as a separate input or adjustment in the measurement of fair value. We adopted the provisions of this update for fair value measurements of liabilities effective October 1, 2009, with no material impact on our financial position, results of operations and cash flows.
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
The demand, pricing and terms for oil and gas services provided by us are largely dependent upon the level of activity for the U.S. and Canadian gas industry. Industry conditions are influenced by numerous factors over which we have no control, including, but not limited to: the supply of and demand for oil and gas; the level of prices, and expectations about future prices, of oil and gas; the cost of exploring for, developing, producing and delivering oil and gas; the expected rates of declining current production; the discovery rates of new oil and gas reserves; available pipeline and other transportation capacity; weather conditions; domestic and worldwide economic conditions; political instability in oil-producing countries; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of oil and gas producers to raise equity capital and debt financing; and merger and divestiture activity among oil and gas producers.
The level of activity in the U.S. and Canadian oil and gas exploration and production industry is volatile. No assurance can be given that our expectations of trends in oil and gas production activities will reflect actual future activity levels or that demand for our services will be consistent with the general activity level of the industry. Any prolonged substantial reduction in oil and gas prices would likely affect oil and gas exploration and development efforts and therefore affect demand for our services. A material decline in oil and gas prices or U.S. and Canadian activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flows.
For the years ended December 31, 2009 and 2008, approximately 5% of our revenues from continuing operations and 4% and 3% of our total assets, respectively, were denominated in Canadian dollars, our functional currency in Canada. As a result, a material decrease in the value of the Canadian dollar relative to the U.S. dollar may negatively impact our revenues, cash flows and net income. Each one percentage point change in the value of the Canadian dollar would have impacted our revenues for the year ended December 31, 2009 by approximately $0.6 million, or $0.4 million net of tax. We do not currently use hedges or forward contracts to offset this risk.
Our Mexican operation uses the U.S. dollar as its functional currency, and as a result, all transactions and translation gains and losses are recorded currently in the financial statements. The balance sheet amounts are translated into U.S. dollars at the exchange rate at the end of the month and the income statement amounts are translated at the average exchange rate for the month. We estimate that a hypothetical one percentage point change in the value of the Mexican peso relative to the U.S. dollar would have impacted our revenues for the year ended December 31, 2009 by approximately $0.6 million, or $0.4 million, net of tax. Currently, we conduct a portion of our business in Mexico in the local currency, the Mexican peso.
Item 8.
Item 8.
Financial Statements and Supplementary Data.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and
Stockholders of Complete Production Services, Inc.:
We have audited the accompanying consolidated balance sheets of Complete Production Services, Inc. and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Complete Production Services, Inc. as of December 31, 2009 and 2008, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Complete Production Services, Inc. and its subsidiaries’ internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 19, 2010, expressed an unqualified opinion that Complete Production Services, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting.
/s/ Grant Thornton LLP
Houston, Texas
February 19, 2010
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and
Stockholders of Complete Production Services, Inc.:
We have audited Complete Production Services, Inc’s. internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Complete Production Services, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Complete Production Services, Inc.’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Complete Production Services, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Complete Production Services, Inc. and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2009, and our report dated February 19, 2010 expressed an unqualified opinion on those consolidated financial statements.
/s/ Grant Thornton LLP
Houston, Texas
February 19, 2010
COMPLETE PRODUCTION SERVICES, INC.
Consolidated Balance Sheets
December 31, 2009 and 2008
See accompanying notes to consolidated financial statements.
COMPLETE PRODUCTION SERVICES, INC.
Consolidated Statements of Operations
Years Ended December 31, 2009, 2008 and 2007
See accompanying notes to consolidated financial statements.
COMPLETE PRODUCTION SERVICES, INC.
Consolidated Statements of Comprehensive Income (Loss)
Years Ended December 31, 2009, 2008 and 2007
See accompanying notes to consolidated financial statements.
COMPLETE PRODUCTION SERVICES, INC.
Consolidated Statement of Stockholders’ Equity
Years Ended December 31, 2009, 2008 and 2007
See accompanying notes to consolidated financial statements.
COMPLETE PRODUCTION SERVICES, INC.
Consolidated Statements of Cash Flows
Years Ended December 31, 2009, 2008 and 2007
See accompanying notes to consolidated financial statements.
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements
(In thousands, except share and per share data)
1.
General:
(a) Nature of operations:
Complete Production Services, Inc. is a provider of specialized services and products focused on developing hydrocarbon reserves, reducing operating costs and enhancing production for oil and gas companies. Complete Production Services, Inc. focuses its operations on basins within North America and manages its operations from regional field service facilities located throughout the U.S. Rocky Mountain region, Texas, Oklahoma, Louisiana, Arkansas, Pennsylvania, western Canada, Mexico and Southeast Asia.
References to “Complete”, the “Company”, “we”, “our” and similar phrases are used throughout these financial statements and relate collectively to Complete Production Services, Inc. and its consolidated affiliates.
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. See Note 12, Stockholders’ Equity.
(b) Basis of presentation:
Our consolidated financial statements are expressed in U.S. dollars and have been prepared by us in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). In preparing financial statements, we make informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, we review our estimates, including those related to impairment of long-lived assets and goodwill, contingencies and income taxes. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.
These audited consolidated financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary for a fair statement of the financial position of Complete as of December 31, 2009 and 2008 and the statements of operations, the statements of comprehensive income, the statements of stockholders’ equity and the statements of cash flows for each of the three years in the period ended December 31, 2009. We believe that these financial statements contain all adjustments necessary so that they are not misleading. Certain reclassifications have been made in order to present results on a comparable basis with amounts for 2009, including a reclassification of certain payroll benefits and related burdens.
In May 2008, our Board of Directors authorized and committed to a plan to sell certain operations in the Barnett Shale region of north Texas, consisting primarily of our supply store business, as well as certain non-strategic drilling logistics assets and other completion and production services assets. On May 19, 2008, we sold these operations to a company owned by a former officer of one of our subsidiaries, for which we received proceeds of $50,150 and assets with a fair market value of $7,987. Accordingly, we have revised our financial statements for all periods presented to classify the related results of operations of this disposal group as discontinued operations. See Note 14, Discontinued Operations.
We performed an evaluation of subsequent events as of February 19, 2010, the date of issuance of these financial statements.
(b) Prior period adjustments:
In June 2009, we discovered accounting errors within one of our operations located in the Rocky Mountain region, which occurred in prior years and would have impacted our reported operating results for the years ended December 31, 2006, 2007 and 2008. The majority of the errors were due to a flawed revenue accrual process and ineffective controls over inventory within this operation. We evaluated the impact that these errors would have had
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
on our financial statements and determined that these errors would not have been material to our financial statements from a quantitative or qualitative perspective for those periods. However, the amount of the adjustment required to correct these errors was deemed to be material to the results for 2009. We corrected these errors as of June 30, 2009 and have made the required adjustments to our reported results for the years ended December 31, 2006, 2007 and 2008. In addition, we adjusted our balance sheets at December 31, 2007 and 2008, decreasing beginning retained earnings by $3,704 and $4,113, respectively. We have recorded a prior period adjustment of $588 related to our December 31, 2006 retained earnings on the accompanying statement of stockholders’ equity. We have labeled our balance sheet, statement of operations, statement of stockholders’ equity and statement of cash flows as “Revised” where applicable.
The following tables summarize the impact of these accounting errors on our previously published financial statements by caption for each of the comparable periods presented in this Annual Report on Form 10-K (in thousands, except per share data):
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
2.
Significant accounting policies:
(a) Basis of preparation:
Our consolidated financial statements include the accounts of the legal entities discussed above and their wholly owned subsidiaries. All material inter-company balances and transactions have been eliminated in consolidation.
(b) Foreign currency translation:
Assets and liabilities of foreign subsidiaries, whose functional currencies are the local currency, are translated from their respective functional currencies to U.S. dollars at the balance sheet date exchange rates. Income and expense items are translated at the average rates of exchange prevailing during the year. Foreign exchange gains and losses resulting from translation of account balances are included in income or loss in the year in which they occur. The adjustment resulting from translating the financial statements of such foreign subsidiaries into U.S. dollars is reflected as a separate component of stockholders’ equity.
(c) Revenue recognition:
We recognize service revenue when it is realized and earned. We consider revenue to be realized and earned when the services have been provided to the customer, the product has been delivered, the sales price is fixed or determinable and collectibility is reasonably assured. Generally, services are provided over a relatively short time.
Revenue and costs on drilling contracts are recognized as work progresses. Progress is measured and revenues recognized based upon agreed day-rate charges. For certain contracts, we may receive additional lump-sum payments for the mobilization of rigs and other drilling equipment. Consistent with the drilling contract day-rate revenues and charges, revenues and related direct costs incurred for the mobilization are deferred and recognized over the term of the related 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.
We recognize revenue under service contracts as services are performed. We had no significant unearned revenues associated with long-term service contracts as of December 31, 2009 and 2008.
(d) Cash and cash equivalents:
Short-term investments with maturities of less than three months are considered to be cash equivalents and are recorded at cost, which approximates fair market value. For purposes of the consolidated statements of cash flows, we consider all investments in highly liquid debt instruments with original maturities of three months or less to be cash equivalents. We invest excess cash in overnight investments which are accounted for as cash. At December 31, 2009, our cash and cash equivalents exceeded what is federally insured.
(e) Trade accounts receivable:
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses incurred in our existing accounts receivable. We determine the allowance based on historical write-off experience, account aging and our assumptions about the oil and gas industry economic cycle. We review our allowance for doubtful accounts monthly. Past due balances over 90 days and over a specified amount are reviewed individually for collectibility. All other balances are reviewed on a pooled basis. Account balances are charged off against the allowance after all appropriate means of collection have been exhausted and the potential for recovery is considered remote. Considering our customer base, we do not believe that we have any significant concentrations of credit risk other than our concentration in the oil and gas industry. We have no significant off balance-sheet credit exposure related to our customers.
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Notes to Consolidated Financial Statements - (Continued)
(f) Inventory:
Inventory, which consists of finished goods and materials and supplies held for resale, is carried at the lower of cost and market. Market is defined as net realizable value for finished goods and as replacement cost for manufacturing parts and materials. Cost is determined on a first-in, first-out basis for refurbished parts and an average cost basis for all other inventories and includes the cost of raw materials and labor for finished goods. We record a reserve for excess and obsolete inventory based upon specific identification of items based on periodic reviews of inventory on hand.
(g) Property, plant and equipment:
Property, plant and equipment are carried at cost less accumulated depreciation. Major betterments are capitalized. Repairs and maintenance that do not extend the useful life of equipment are expensed.
Depreciation is provided over the estimated useful life of each asset as follows:
(h) Intangible assets:
Intangible assets, consisting of acquired customer relationships, service marks, non-compete agreements, acquired patents and technology, are carried at cost less accumulated amortization, which is calculated on a straight-line basis over a period of 2 to 10 years depending on the asset’s estimated useful life. The weighted average amortization period for these intangible assets was approximately 4 years as of December 31, 2009.
(i) Impairment of long-lived assets:
In accordance with the Financial Accounting Standards Board’s (“FASB”) guidance on accounting for long-lived assets, including property, plant and equipment and purchased intangibles subject to amortization, we review these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. When assets are determined to be held for sale, they are separately presented in the appropriate asset and liability sections of the balance sheet and reported at the lower of the carrying amount or fair value less cost to sell, and are no longer depreciated. We recorded a fixed asset and other intangibles impairment loss of $38,646 for the year ended December 31, 2009. See Note 6, “Property, plant and equipment.”
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Notes to Consolidated Financial Statements - (Continued)
(j)
Asset retirement obligations:
Asset retirement obligation are recorded at fair value as a liability in the period in which a legal obligation is incurred associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development, and/or normal use of the assets in accordance with U.S. GAAP. Furthermore, a corresponding asset would be recorded and depreciated over the contractual term of the underlying asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation would be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. There were no significant retirement obligations recorded at December 31, 2009 and 2008.
(k)
Deferred financing costs:
Deferred financing costs associated with long-term debt under our revolving credit facilities and senior notes are carried at cost and are expensed over the term of the applicable long-term debt facility or the term of the notes.
(l)
Goodwill:
Goodwill represents the excess of costs over the fair value of the assets and liabilities of businesses acquired. U.S. GAAP requires an impairment test at least annually or more frequently if indicators of impairment are present, whereby we estimate the fair value of the asset by discounting future cash flows at a projected cost of capital rate. If the fair value estimate is less than the carrying value of the asset, an additional test is required whereby we apply a purchase price analysis consistent with the standard pertaining to business combinations. 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 implied fair value. We recorded a goodwill impairment loss for the years ended December 31, 2009, 2008 and 2007. See (t) “Fair Value Measurements” and Note 15, “Segment Information.”
(m)
Deferred income taxes:
We follow the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are determined based upon temporary differences between the carrying amount and tax basis of our assets and liabilities and measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect on deferred tax assets and liabilities of a change in the tax rates is recognized in income in the period in which the change occurs. We record a valuation reserve when we believe that it is more likely than not that any deferred tax asset created will not be realized.
In assessing the realizability of deferred income tax assets, management considers whether it is more likely than not that some portion or all of the deferred income tax assets will not be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.
(n)
Financial instruments:
The financial instruments recognized in the balance sheet consist of cash and cash equivalents, trade accounts receivable, revolving credit facilities, accounts payable and accrued liabilities, long-term debt and senior notes. The fair value of our financial instruments approximate their carrying amounts due to their current maturities or market rates of interest, except the senior notes which were issued in December 2006 with a fixed 8% coupon rate. At December 31, 2009 and 2008, the fair value of these notes was $641,875 and $409,500, respectively, based on the published closing prices for the applicable day.
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Notes to Consolidated Financial Statements - (Continued)
(o)
Per share amounts:
In accordance with U.S. GAAP, we use the treasury stock method to calculate the dilutive effect of stock options, stock warrants and non-vested restricted stock on our earnings per share calculations. This method requires that we compare the presumed proceeds from the exercise of options and other dilutive instruments, including the expected tax benefit to us, to the exercise price of the instrument, and assume that we used the net proceeds to purchase shares of our common stock at the average price during the period. These assumed shares are then included in the calculation of the diluted weighted average shares outstanding for the period, if such instruments are not deemed to be anti-dilutive.
(p)
Stock-based compensation:
We have stock-based compensation plans for our employees, officers and directors to acquire common stock. For grants of stock options prior to January 1, 2006, no compensation expense was recorded if stock options were issued at fair value on the date of grant. Accordingly, we did not recognize compensation expense associated with these stock option grants. Subsequent to January 1, 2006, we measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award, with limited exceptions, by using an option pricing model to determine fair value. We applied the modified-prospective transition method to account for grants of stock options between September 30, 2005, the date of our initial filing with the Securities and Exchange Commission, and December 31, 2005. For stock options granted on or after January 1, 2006, we use the prospective transition method to account for these grants and record compensation expense. See Note 12, Stockholders’ Equity.
(q)
Research and development:
Research and development costs are charged to income as period costs when incurred.
(r)
Contingencies:
Liabilities for loss contingencies, including environmental remediation costs not within the scope of FASB guidance provided with regard to asset retirement obligations and which arise from claims, assessments, litigation, fines, and penalties and other sources, are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated.
(s)
Measurement uncertainty:
Our consolidated financial statements are prepared in accordance with U.S. GAAP. The preparation of the consolidated financial statements in accordance with U.S. GAAP necessarily requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We evaluate our estimates including those related to bad debts, inventory obsolescence, property plant and equipment useful lives, goodwill, intangible assets, income taxes, contingencies and litigation on an ongoing basis. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances. Under different assumptions or conditions, the actual results could differ, possibly materially, from those previously estimated. Many of the conditions impacting these assumptions are estimates outside of our control.
(t)
Fair Value Measurement:
We evaluate fair value measurements in accordance with U.S. GAAP, which requires us to base our estimates on assumptions market participants would use to price an asset or liability, and to establish a hierarchy that prioritizes the information used to determine fair value, whereby quoted market prices in active markets are given
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Notes to Consolidated Financial Statements - (Continued)
highest priority with lowest priority given to data provided by the reporting entity based on unobservable facts. U.S. GAAP requires disclosure of significant fair value measurements by level within the prescribed hierarchy.
We generally apply fair value valuation techniques on a non-recurring basis associated with: (1) valuing assets and liabilities acquired in connection with business combinations and other transactions; (2) valuing potential impairment loss related to long-lived assets; and (3) valuing potential impairment loss related to goodwill and indefinite-lived intangible assets. We generally do not hold trading securities, and we were not party to significant derivative contract arrangements during the years ended December 31, 2009 and 2008.
Business combinations and other transactions:
We acquired several businesses during 2008. To determine the fair value of the assets acquired, primarily fixed assets, we obtained assistance from an independent appraiser to compare the value of the assets to comparable assets in the market to determine the fair value as of the date of the acquisition. Furthermore, we applied an income method approach to value identifiable intangible assets associated with these acquisitions including customer relationships, trade names and non-compete agreements. For working capital items, including receivables, payables and inventory, carrying value was deemed to approximate fair value. During 2009, we did not complete any business combination transactions; however, we did acquire certain property, plant and equipment at a subsidiary in Canada through a non-monetary exchange of assets, as further described in Note 6, Property, plant and equipment. We determined that this transaction had economic substance and that the assets received should be recorded at the fair value of the assets surrendered in the exchange. To determine the fair value of these assets, management obtained assistance from a third-party appraiser and used the orderly-liquidation value of the assets surrendered as an estimate of fair value. This transaction resulted in a loss of $4,868 for the year ended December 31, 2009.
Long-lived assets:
In September 2009, we evaluated the fair market value of assets in our contract drilling business with the assistance of a third-party appraiser and determined that the carrying value of certain of these drilling rigs exceeded the fair market value estimates. We projected the undiscounted cash flows associated with these rigs, including an estimate of salvage value, and compared these expected future cash flows to the carrying amount of the rigs. If the undiscounted cash flows exceeded the carrying amount, no further testing was performed and the rig was deemed to not be impaired. If the undiscounted cash flows did not exceed the carrying value, we estimated the fair market value of the equipment based on management estimates and general market data obtained by the third-party appraiser using the sales comparison market approach, which included the analysis of recent sales and offering prices of similar equipment to arrive at an indication of the most probable selling price for the equipment. The result of this analysis was a calculated fixed asset impairment of $36,158, which was recorded as an impairment loss in the accompanying statement of operations for the year ended December 31, 2009. This impairment charge was allocated entirely to the Drilling Services business segment. This impairment was deemed necessary due to an overall decline in oil and gas exploration and production activity in late 2008 which has extended throughout 2009, as well as management’s expectation of future operating results for this business segment for the foreseeable future. We continue to evaluate the remaining useful lives of our drilling rigs, and have considered our depreciation methodology and these estimates of useful lives in our projected future cash flows associated with these assets.
In addition, we evaluated certain long-term intangible assets with definite lives in accordance with U.S. GAAP as of December 31, 2009. Based on our review, we believe that impairment was indicated at one of our businesses due to lower-than-expected results, revised expected future cash flows for the business and changes in local management. Therefore, with the assistance of a third-party appraiser, we determined that certain non-compete agreements and customer relationship intangibles were impaired at December 31, 2009. We have recorded an impairment charge related to these intangible assets totaling $2,488 in the accompanying statement of operations at December 31, 2009.
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
Goodwill:
We evaluated our goodwill and indefinite-lived intangible assets in accordance with the recoverability tests prescribed by U.S. GAAP as of our annual testing date in 2009 and determined that goodwill associated with three of our reporting units was impaired as of the testing date. For the year ended December 31, 2008, we performed this test at the annual testing date and impairment of goodwill was indicated for most of our reporting units. We performed the test again at December 31, 2008, due to a triggering event which occurred in late 2008 which was the general decline in the overall U.S. debt and equity markets during the fourth quarter of 2008 and continued throughout 2009. Previously, we recorded an impairment loss for the year ended December 31, 2007 related to our Canadian operations.
In performing the two-step goodwill impairment test, we compared the fair value of each of our reportable units to its carrying value. We estimated the fair value of our reportable units by considering both the income approach and market approach. Under the market approach, the fair value of the reportable unit is based on market multiple and recent transaction values of peer companies. Under the income approach, the fair value of the reportable unit is based on the present value of estimated future cash flows using the discounted cash flow method. The discounted cash flow method is dependent on a number of unobservable inputs including projections of the amounts and timing of future revenues and cash flows, assumed discount rates and other assumptions. Based upon this testing, we determined that goodwill associated several of our reporting units within our completion and production services business segments were impaired, which triggered step two. For step two, we calculated the implied fair value of goodwill and compared it to the carrying amount of that goodwill, by examining the fair value of the tangible and intangible property of these reportable units. The inputs for this model were largely unobservable estimates from management based on historical performance. We retained the assistance of a third-party appraiser to collect market data for a sample of assets from each of these reporting units to assess the market value of the property, plant and equipment of these reportable units, and the results were extrapolated to the asset population. Thus, the primary source for our assessment of value was based on management’s estimates and projections. The result of this analysis was a calculated goodwill impairment of $97,643 which is recorded in the accompanying statement of operations at December 31, 2009. This impairment charge of $97,643 was allocated to the completion and production services business segment in 2009. These impairments were deemed necessary due to an overall decline in oil and gas exploration and production activity throughout 2009. We intend to continue to hold our investment in these reportable units for the foreseeable future.
The following tabular presentation is presented for quantitative presentation of our significant fair value measurements for the year ended December 31, 2009:
For the year ended December 31, 2008, goodwill with a carrying amount of $613,876 was written down to its implied fair value of $341,592, resulting in an impairment charge of $272,284, of which $272,006 was recorded as an impairment loss and $277 was recorded as a charge to cumulative translation adjustment in the accompanying balance sheet as of December 31, 2008. For the year ended December 31, 2007, we recorded an impairment charge
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Notes to Consolidated Financial Statements - (Continued)
of $13,360, of which $13,094 was recorded as an impairment loss and $266 was recorded as a charge to cumulative translation adjustment.
(u) Investment in Unconsolidated Subsidiaries
We constructed a salt water disposal well for a customer during 2009 at a cost of $1,497. In exchange for this service, we received a non-controlling interest in the company that owns and operates the well. In accordance with U.S. GAAP, we account for our interest in this company as an equity investment in an unconsolidated subsidiary, whereby we have recorded our initial investment as a long-term asset in the accompanying balance sheet at December 31, 2009, and record our portion of earnings or losses associated with this well as equity in earnings of unconsolidated subsidiaries, a component of income or expense in the current period. We have evaluated this ownership interest and determined that it does not constitute a variable interest entity, as that term is defined in current U.S. GAAP guidance. This well did not begin operating until late 2009, and we did not record any significant earnings or loss associated with these operations during the year ended December 31, 2009.
3.
Business combinations:
We did not acquire any businesses during the year ended December 31, 2009. However, we did execute several business acquisitions in recent years and expect to complete more transactions in the future, depending on the circumstances and the availability of financing.
(a) Acquisitions During the Year Ended December 31, 2008:
During the year ended December 31, 2008, we acquired substantially all the assets or all of the equity interests in four oilfield service companies, for $180,154 in cash, resulting in goodwill of $71,209. Several of these acquisitions were subject to final working capital adjustments.
(i) On February 29, 2008, we acquired substantially all of the assets of KR Fishing & Rental, Inc. (“KR Fishing & Rental”) for $9,464 in cash, resulting in goodwill of $6,411. KR Fishing & Rental, Inc. is a provider of fishing, rental and foam unit services in the Piceance Basin and the Raton Basin, and is located in Rangely, Colorado. We believe this acquisition complements our completion and production services business in the Rocky Mountain region.
(ii) On April 15, 2008, we acquired all the outstanding common stock of Frac Source Services, Inc. (“Frac Source”), a provider of pressure pumping services to customers in the Barnett Shale of north Texas, for $62,359 million in cash, net of cash acquired, which includes a working capital adjustment of $1,600 and recorded goodwill of $15,431. Upon closing this transaction, we entered into a contract with one of our major customers to provide pressure pumping services in the Barnett Shale utilizing three frac fleets under a contract with a term that extends up to three years from the date each fleet is placed into service. We spent an additional $20,000 in 2008 on capital equipment related to these contracted frac fleets. Thus, our total investment in this operation was approximately $82,400. We believe this acquisition expands our pressure pumping business in north Texas and that the related contract provides a stable revenue stream from which to expand our pressure pumping business outside of this region.
(iii) On October 3, 2008, we acquired all of the membership interests of TSWS Well Services, LLC (“TSWS”), a limited liability corporation which held substantially all of the well servicing and heavy haul assets of TSWS, Inc., a company based in Magnolia, Arkansas, which provides well servicing and heavy haul services to customers in northern Louisiana, east Texas and southern Arkansas. As consideration, we paid $57,163 in cash and prepaid an additional $1,000 related to an employee retention bonus pool. We also recorded goodwill totaling $21,911. The purchase price allocation associated with this acquisition has not yet been completed. We believe this acquisition extends our geographic reach into the Haynesville Shale area.
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Notes to Consolidated Financial Statements - (Continued)
(iv) On October 4, 2008, we acquired substantially all of the assets of Appalachian Well Services, Inc. and its wholly-owned subsidiary (“AWS”), each of which is based in Shelocta, Pennsylvania. This business provides pressure pumping, e-line and coiled tubing services in the Appalachian region, and includes a service area which extends through portions of Pennsylvania, West Virginia, Ohio and New York. As consideration for the purchase, we paid $50,168 in cash and issued 588,292 unregistered shares of our common stock, valued at $15.04 per share. We expect to invest an additional $6,500 to complete a frac fleet at this location and have an option to purchase real property for approximately $600. In addition, we have entered into an agreement under which we may be required to pay up to an additional $5,000 in cash consideration during the earn-out period which extends through 2010, based upon the results of operations of various service lines acquired. We recorded goodwill of approximately $27,456 associated with this acquisition, however, this goodwill was deemed impaired in 2009 and expensed as of December 31, 2009. We believe this acquisition creates a platform for future growth for our pressure pumping and other completion and production service lines in the Marcellus Shale.
We accounted for these acquisitions using the purchase method of accounting, whereby the purchase price was allocated to the fair value of net assets acquired, including intangibles and property, plant and equipment at depreciated replacement costs, with the excess recorded as goodwill. Results for each of these acquisitions were included in our accounts and results of operations since the date of acquisition, and goodwill associated with these acquisitions was allocated entirely to the completion and production services business segment. The following table summarizes our purchase price allocations for these acquisitions as of December 31, 2008:
The purchase price of each of the businesses that we acquire is negotiated as an arm’s length transaction with the seller. We generally evaluate acquisition targets based on an earnings multiple approach, whereby we consider precedent transactions which we have undertaken and those of others in our industry.
In accordance with the FASB guidance on fair value measurements, we determined the fair value of assets and liabilities acquired through these business acquisitions as of the acquisition date by retaining third-party consultants to perform valuation techniques related to identifiable intangible assets and to evaluate property, plant and equipment acquired based upon, at minimum, the replacement cost of the assets. Working capital items were deemed to be acquired at fair market value. Of the total intangible assets acquired, $14,010 related to customer relationship intangibles determined by applying an income approach over the expected term, allowing for customer attribution at an assumed rate. We considered these factors when determining the goodwill impairment recorded at December 31, 2008. Of the businesses acquired in 2008, an insignificant portion of the goodwill associated with the acquisitions of TSWS and AWS was deemed impaired at December 31, 2008. As of December 31, 2009, the
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Notes to Consolidated Financial Statements - (Continued)
remaining goodwill associated with AWS, and other intangibles totaling $2,488, were deemed impaired and expensed.
(b) Acquisitions During the Year Ended December 31, 2007:
During the year ended December 31, 2007, we acquired substantially all the assets or all of the equity interests in six oilfield service businesses, and the remaining 50% interest in our Canadian joint venture, for $49,691 in cash, resulting in goodwill of $19,391. Several of these acquisitions were subject to final working capital adjustments. These acquisitions in 2007 were as follows:
(v) On January 4, 2007, we acquired substantially all of the assets of a company located in LaSalle, Colorado, which provides frac tank rental and fresh water hauling services to customers in the Wattenburg Field of the DJ Basin, which supplements our fluid handling and rental business in the Rocky Mountain region.
(vi) On February 28, 2007, we acquired substantially all of the assets of a company located in Greeley, Colorado, which provides fluid handling and fresh frac water heating services to customers in the Wattenburg Field of the DJ Basin, which also supplements our fluid handling business in the Rocky Mountain region.
(vii) On April 1, 2007, we acquired substantially all of the assets of a company located in Borger, Texas, which provides fluid handling and disposal services to customers in the Texas panhandle. We believe this acquisition complements certain operations that we acquired in 2006 within the Texas panhandle area and broadens our ability to provide fluid handling and disposal services throughout the Mid-continent region.
(viii) On June 8, 2007, we acquired all the membership interests in a business located in Rangely, Colorado, which provides rig workover and roustabout services to customers in the Rangely Weber Sand Unit and northern Piceance Basin area. This acquisition expands our geographic reach in the northern Piceance Basin, expands our workover rig capabilities and provides a beneficial customer relationship.
(ix) On October 18, 2007, we acquired all of the outstanding common stock of a company located in Kilgore, Texas, which provides remedial cement and acid services used in pressure pumping operations to customers throughout the east Texas region. This acquisition supplements our pressure pumping business and expands our presence in east Texas.
(x) On November 30, 2007, we acquired substantially all of the assets of a company located in Greeley, Colorado, which is an e-line service provider to customers in the Wattenberg Field of the DJ Basin. This acquisition supplements our completion and production services business in the Rocky Mountain region.
(xi) On December 31, 2007, we acquired the remaining 50% interest in our joint venture in Canada for approximately $1,600. This transaction resulted in a decrease in goodwill of $595, as the amount paid was less than the minority interest liability related to this operation just prior to the acquisition. This company provides optimization services in the Canadian market.
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Notes to Consolidated Financial Statements - (Continued)
We accounted for these acquisitions using the purchase method of accounting, whereby the purchase price was allocated to the fair value of net assets acquired, including intangibles and property, plant and equipment at depreciated replacement costs, with the excess recorded as goodwill. Results for each of these acquisitions were included in our accounts and results of operations since the date of acquisition, and goodwill associated with these acquisitions was allocated entirely to the completion and production services business segment. We do not deem these acquisitions to be significant to our consolidated operations for the year ended December 31, 2007. The following table summarizes our purchase price allocations for these acquisitions as of December 31, 2007:
(c) Pro Forma Results
We calculated the pro forma impact of the businesses we acquired on our operating results for the year ended December 31, 2008. The following pro forma results give effect to each of these acquisitions, assuming that each occurred on January 1, 2008.
We derived the pro forma results of these acquisitions based upon historical financial information obtained from the sellers and certain management assumptions. In addition, we assumed debt service costs related to these acquisitions based upon the actual cash investments, calculated at a rate of 7% per annum, less an assumed tax benefit calculated at our statutory rate of 35%. Each of these acquisitions related to our continuing operations, and, thus, had no pro forma impact on discontinued operations presented on the accompanying statement of operations for the year ended December 31, 2008.
The following pro forma results do not purport to be indicative of the results that would have been obtained had the transactions described above been completed on the indicated dates or that may be obtained in the future.
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Notes to Consolidated Financial Statements - (Continued)
4.
Accounts receivable:
(a)
See Note 19, Related Party Transactions.
The following table summarizes the change in our allowance for doubtful accounts for the years ended December 31, 2009, 2008 and 2007:
5.
Inventory:
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Notes to Consolidated Financial Statements - (Continued)
6.
Property, plant and equipment:
Construction in progress at December 31, 2009 and 2008 primarily included progress payments to vendors for equipment to be delivered in future periods and component parts to be used in final assembly of operating equipment, which in all cases were not yet placed into service at the time. For the years ended December 31, 2009 and 2008, we recorded capitalized interest of $878 and $4,458, respectively, related to assets that we are constructing for internal use and amounts paid to vendors under progress payments for assets that are being constructed on our behalf.
Effective March 1, 2009, our Canadian subsidiary transferred certain property, plant and equipment used in our production testing business to Enseco, a competitor, in exchange for certain electric line (e-line) equipment. This exchange was determined to have commercial substance for us and therefore we recorded the new assets acquired at the fair market value of the assets surrendered which had a carrying value of $9,284. We incurred costs to sell totaling approximately $71. We determined the fair value of the assets with the assistance of a third-party appraiser, assuming an orderly liquidation methodology, to be $4,487, resulting in a loss on the exchange of $4,868. Of the total value assigned to the new assets, $4,209 was included in property, plant and equipment and $279 was included in inventory in the accompanying balance sheet as of December 31, 2009. The fair market value of the assets received was determined to be $5,497, using the same methodology applied to the assets surrendered. We believe that these e-line assets will generate cash flows in excess of the cash flows that would have been received from the production testing assets due to relatively higher demand from our customers for e-line services.
Effective March 31, 2009, we entered into a sale-leaseback transaction with Agua Dulce, LLC, through which we sold a facility and approximately 50 acres of real property located near Rock Springs, Wyoming for $3,827. The sales price approximated the net book value of the facility, which is currently under construction, and the land, resulting in an insignificant gain on the transaction which has been included as a component of selling, general and administrative expense in the accompanying statement of operations for the year ended December 31, 2009. In
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
addition, the buyer agreed to fund the completion of the construction of the facility. Effective April 1, 2009, we became party to the lease agreement which requires monthly operating lease payments for a term of 10 years, with an option to extend the lease term for an additional 10 years. The rental rate adjusts for construction draws to date divided ratably over the remaining lease term. The lease term began on April 1, 2009 and the first monthly rental was $35. We will also incur additional lease costs related to certain operating costs, taxes and insurance for the facility over the term of the lease.
Effective July 30, 2009, we entered into a sale-leaseback agreement with Enterprise Leasing Company of Houston to sell over 550 light-vehicles with a net book value of approximately $10,362 as of July 30, 2009. During the third quarter of 2009, we received proceeds from the sale which totaled $10,551. In August 2009, pursuant to this lease agreement, we began making monthly rental payments of approximately $306. The lease terms range from 24 to 36 months.
7.
Intangible assets:
We recorded amortization expense associated with intangible assets of continuing operations totaling $7,769, $5,248 and $2,918 for the years ended December 31, 2009, 2008 and 2007, respectively. We expect to record amortization expense associated with these intangible assets for the next five years approximating: 2010 - $6,525; 2011 - $4,051; 2012 - $2,073; 2013 - $570 and 2014 - $24.
8.
Deferred financing costs:
We incurred deferred financing costs during 2006 related to the issuance of our senior notes in December 2006 totaling $13,414 and $718 associated with the amendment of our existing term loan and revolving credit facility. In October 2009, we amended our senior secured credit facility and incurred additional financing costs of $2,911 in the fourth quarter of 2009. In October 2009, due to the decrease in borrowing capacity after giving effect to the amendment, we expensed $528 of unamortized fees related to our prior revolving credit facilities.
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
9.
Taxes:
Tax expense (benefit) from continuing operations consisted of:
We operate in several tax jurisdictions. A reconciliation of the U.S. federal income tax rate of 35% for the years ended December 31, 2009, 2008 and 2007 to our effective income tax rate follows:
Non-deductible expenses for the years ended December 31, 2009 and 2008 relate primarily to impaired goodwill with limited tax basis.
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Notes to Consolidated Financial Statements - (Continued)
The net deferred income tax liability from continuing operations was comprised of the tax effect of the following temporary differences:
The net deferred income tax liability consisted of:
Net operating loss carryforwards are included in the determination of our deferred tax asset at December 31, 2009. We will need to generate future taxable income of approximately $6,450 in order to fully utilize our net operating loss carryforwards. We have sufficient deferred tax liabilities to generate taxable income to offset the deferred tax assets.
We had U.S. loss carryforwards of $3,592 at December 31, 2009 and $2,535 of U.S. loss carryforwards at December 31, 2008. We have a $2,930 foreign non-capital loss carryforward at December 31, 2009, compared to $2,930 at December 31, 2008.
No deferred income taxes were provided on $21,241 of undistributed earnings of foreign subsidiaries as of December 31, 2009, as we intend to indefinitely reinvest these funds. 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. It is not practical, however, to estimate the amount of taxes that may be payable on the eventual distribution of these earnings after consideration of available foreign tax credits.
We adopted the FASB interpretation on accounting for uncertainty in income taxes as of January 1, 2007. This guidance clarifies the accounting for uncertain tax positions that may have been taken by an entity. Specifically, it prescribes a more-likely-than-not recognition threshold to measure a tax position taken or expected to be taken in a tax return through a two-step process: (1) determining whether it is more likely than not that a tax position will be sustained upon examination by taxing authorities, after all appeals, based upon the technical merits of the position; and (2) measuring to determine the amount of benefit/expense to recognize in the financial statements, assuming taxing authorities have all relevant information concerning the issue. The tax position is measured at the largest amount of benefit/expense that is greater than 50 percent likely of being realized upon ultimate settlement. This
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
pronouncement also specifies how to present a liability for unrecognized tax benefits in a classified balance sheet, but does not change the classification requirements for deferred taxes. Under this guidance, if a tax position previously failed the more-likely-than-not recognition threshold, it should be recognized in the first subsequent financial reporting period in which the threshold is met. Similarly, a position that no longer meets this recognition threshold should no longer be recognized in the first financial reporting period in which the threshold is no longer met.
The FASB issued additional guidance on how an entity is to determine whether a tax position has effectively settled for purposes of recognizing previously unrecognized tax benefits. Specifically, this guidance states that an entity would recognize a benefit when a tax position is effectively settled using the following criteria: (1) the taxing authority has completed its examination including all appeals and administrative reviews; (2) the entity does not plan to appeal or litigate any aspect of the tax position; and (3) it is remote that the taxing authority would examine or reexamine any aspect of the tax position, assuming the taxing authority has full knowledge of all relevant information relative to making their assessment on the position.
We performed an examination of our tax positions and calculated the cumulative amount of our estimated exposure by evaluating each issue to determine whether the impact exceeded the 50 percent threshold of being realized upon ultimate settlement with the taxing authorities. Based upon this examination, we determined that the aggregate exposure did not have a material impact on our financial statements during the years ended December 31, 2009 and 2008. Therefore, we have not recorded an adjustment to our financial statements related to this interpretation. We will continue to evaluate our tax positions, and recognize any future impact as a charge to income in the applicable period in accordance with the standard. Our tax filings for tax years 2006 to 2008 remain open for examination by taxing authorities. We do not anticipate any significant changes in our uncertain tax positions during the next twelve months.
Our accounting policy related to income tax penalties and interest assessments is to accrue for these costs and record a charge to selling, general and administrative expense for tax penalties and a charge to interest expense for interest assessments during the period that we take an uncertain tax position through resolution with the taxing authorities or the expiration of the applicable statute of limitations. We did not record any significant amounts related to penalties and interest during the years ended December 31, 2009, 2008 and 2007.
10.
Notes payable:
We entered into a note arrangement to finance our annual insurance premiums for the policy term beginning December 1, 2007 and extending through April 30, 2009. As of December 31, 2007, we recorded a note payable totaling $15,354 and an offsetting prepaid asset which included a broker’s fee. At December 31, 2008, this note balance totaled $1,353 and was classified as a current liability. We paid this note in full during the first quarter of 2009. Effective May 1, 2009, we renewed our insurance policies and entered into a similar financing arrangement through April 2010. We recorded a note payable of $7,960, and have made payments toward this note of $6,892, resulting in a note payable balance of $1,069 at December 31, 2009. In addition, we renewed our workers’ compensation, general liability and auto insurance policies through our insurance broker. We have recorded a prepaid asset of approximately $2,435 associated with these policies and are making monthly premium payments. Our primary insurance policies extend through April 30, 2010.
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
11.
Long-term debt:
The following table summarizes long-term debt as of December 31, 2009 and 2008:
(a)
On December 6, 2008, we entered into a senior secured facility (the “Credit Agreement”) with Wells Fargo Bank, National Association, as U.S. Administrative Agent, HSBC Bank Canada, as Canadian Administrative Agent, and certain other financial institutions. On October 13, 2009, we entered into the Third Amendment (the Credit Agreement after giving effect to the Third Amendment, the “Amended Credit Agreement”) and modified the structure of our existing credit facility to an asset-based facility subject to borrowing base restrictions. In connection with the Third Amendment, Wells Fargo Capital Finance, LLC (formerly known as Wells Fargo Foothill, LLC) replaced Wells Fargo Bank, National Association, as U.S. Administrative Agent and also serves as U.S. Issuing Lender and U.S. Swingline Lender under the Amended Credit Agreement. The Amended Credit Agreement provides for a U.S. revolving credit facility of up to $225,000 that matures in December 2011 and a Canadian revolving credit facility of up to $15,000 (with Integrated Production Services Ltd., one of our wholly-owned subsidiaries, as the borrower thereof (“Canadian Borrower”)) that matures in December 2011. The Amended Credit Agreement includes a provision for a “commitment increase”, as defined therein, which permitted us to effect up to two separate increases in the aggregate commitments under the Amended Credit Agreement by designating one or more existing lenders or other banks or financial institutions, subject to the bank’s sole discretion as to participation, to provide additional aggregate financing up to $75,000, with each committed increase equal to at least $25,000 in the U.S., or $5,000 in Canada, and in accordance with other provisions as stipulated in the Amended Credit Agreement. Certain portions of the credit facilities are available to be borrowed in U.S. dollars, Canadian dollars and other currencies approved by the lenders.
Our U.S. borrowing base is limited to: (1) 85% of U.S. eligible billed accounts receivable, less dilution, if any, plus (2) the lesser of 55% of the amount of U.S. eligible unbilled accounts receivable or $10,000, plus (3) the lesser of the “equipment reserve amount” and 80% times the most recently determined “net liquidation percentage”, as defined in the Amended Credit Agreement, times the value of our and the U.S. subsidiary guarantors’ equipment, provided that at no time shall the amount determined under this clause exceed 50% of the U.S. borrowing base, minus (4) the aggregate sum of reserves established by the U.S. Administrative Agent, if any. The “equipment reserve amount” means $50,000 upon the effective date of the Third Amendment, less $595 for each subsequent month, not to be reduced below zero in the aggregate.
The Canadian borrowing based is limited to: (1) 80% of Canadian eligible billed accounts receivable, plus (2) if the Canadian Borrower has requested credit for equipment under the Canadian borrowing base, the lesser of (a) $15,000, and (b) 80% times the most recently determined “net liquidation percentage”, as defined in the Amended Credit Agreement, times the value (calculated on a basis consistent with our historical accounting practices) of our and the US subsidiary guarantors’ equipment, minus (3) the aggregate amount of reserves established by our Canadian Administrative Agent, if any.
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
Subject to certain limitations set forth in the Amended Credit Agreement, we have the ability to elect how interest under the Amended Credit Agreement will be computed. Interest under the Amended Credit Agreement may be determined by reference to (1) the London Inter-bank Offered Rate, or LIBOR, plus an applicable margin between 3.75% and 4.25% per annum (with the applicable margin depending upon our “excess availability amount”, as defined in the Amended Credit Agreement) or (2) the “Base Rate” (which means the higher of the Prime Rate, Federal Funds Rate plus 0.50%, or the 3-month LIBOR plus 1.00% and 3.50%), plus the applicable margin, as described above. For the period from the effective date of the Third Amendment until the six month anniversary of the effective date of the Third Amendment, interest will be computed as described above with an applicable margin rate of 4.00%. If an event of default exists or continues under the Amended Credit Agreement, advances will bear interest as described above with an applicable margin rate of 4.25% plus 2.00%. Additionally, if an event of default exists under the Amended Credit Agreement, as defined therein, the lenders could accelerate the maturity of the obligations outstanding thereunder and exercise other rights and remedies. Interest is payable monthly.
Under the Amended Credit Agreement, we are permitted to prepay our borrowings and we have the right to terminate, in whole or in part, the unused portion of the U.S commitments in $1,000 increments upon written notice to the U.S. Administrative Agent. If all of the U.S. facility is terminated, the Canadian facility must also be terminated.
All of the obligations under the U.S. portion of the Amended Credit Agreement are secured by first priority liens on substantially all of our assets and the assets of our U.S. subsidiaries as well as a pledge of approximately 66% of the stock of our first-tier foreign subsidiaries. Additionally, all of the obligations under the U.S. portion of the Amended Credit Agreement are guaranteed by substantially all of our U.S. subsidiaries. The obligations under the Canadian portion of the Amended Credit Agreement are secured by first priority liens on substantially all of our assets and the assets of our subsidiaries (other than our Mexican subsidiary). Additionally, all of the obligations under the Canadian portion of the Amended Credit Agreement are guaranteed by us as well as certain of our subsidiaries.
The Amended Credit Agreement also contains various covenants that limit our and our subsidiaries’ ability to: (1) grant certain liens; (2) incur additional indebtedness; (3) make certain loans and investments; (4) make capital expenditures; (5) make distributions; (6) make acquisitions; (7) enter into hedging transactions; (8) merge or consolidate; or (9) engage in certain asset dispositions. The Amended Credit Agreement contains one financial maintenance covenant which requires us and our subsidiaries, on a consolidated basis, to maintain a “fixed charge coverage ratio”, as defined in the Amended Credit Agreement, of not less than 1.10 to 1.00. This covenant is only tested if our “excess availability amount”, as defined under the Amended Credit Agreement, plus certain qualified cash and cash equivalents (collectively “Liquidity”) is less than $50,000 for a period of 5 consecutive days and continues only until such time as our Liquidity has been greater than or equal to $50,000 for a period of 90 consecutive days or greater than or equal to $75,000 for a period of 45 consecutive days.
Our fixed charge coverage ratio covenant is calculated, for fiscal quarters ending after September 30, 2009, as the ratio of “EBITDA” calculated for the four fiscal quarter period ended after September 30, 2009 minus capital expenditures made with cash (to the extent not already incurred in a prior period) or incurred during such four quarter period, compared to “fixed charges”, calculated for the four quarters then ended. “EBITDA” is defined in the Amended Credit Agreement as consolidated net income for the period plus, to the extent deducted in determining our consolidated net income, interest expense, taxes, depreciation, amortization and other non-cash charges for such period, provided that EBITDA shall be subject to pro forma adjustments for acquisitions and non-ordinary course asset sales assuming that such transactions occurred on the first day of the determination period, which adjustments shall be made in accordance with the guidelines for pro forma presentations set forth by the Securities and Exchange Commission. “Fixed charges”, as defined in the Amended Credit Agreement, include interest expense, among other things, reduced by the amortization of transaction fees associated with the Third Amendment.
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
We were in compliance with the fixed charge coverage ratio covenant in the Amended Credit Agreement as of December 31, 2009.
We will incur unused commitment fees under the Amended Credit Agreement ranging from 0.50% to 1.00% based on the average daily balance of amounts outstanding. The unused commitment fees were calculated at 1.00% as of December 31, 2009.
To date, we have incurred fees and expenses associated with the execution and effectiveness of the Third Amendment totaling $2,911. These fees and expenses are included in our consolidated balance sheet as a long-term asset, deferred financing fees, at December 31, 2009, and will be amortized to interest expense over the remaining term of the facility.
There were no revolving borrowings outstanding under our U.S. or Canadian revolving credit facilities as of December 31, 2009. The weighted average interest rate for our revolving credit facilities during the twelve months ended December 31, 2009 was 1.87%. There were letters of credit outstanding under the U.S. revolving portion of the facility totaling $54,649, which reduced the available borrowing capacity as of December 31, 2009. We incurred fees calculated at 1.25% of the total amount outstanding under letter of credit arrangements through October 12, 2009. Under the Amended Credit Agreement, effective October 13, 2009, we incurred fees related to letters of credit, calculated using a 360-day provision, at 4.1% per annum. The net excess availability under our borrowing base calculations for the U.S. and Canadian revolving facilities at December 31, 2009 was $79,522 and $5,079, respectively.
(b)
On December 6, 2006, we issued 8.0% senior notes with a face value of $650,000 through a private placement of debt. These notes mature in 10 years, on December 15, 2016, and require semi-annual interest payments, paid in arrears and calculated based on an annual rate of 8.0%, on June 15 and December 15, of each year, which commenced on June 15, 2007. There was no discount or premium associated with the issuance of these notes. The senior notes are guaranteed by all of our current domestic subsidiaries. The senior notes have covenants which, among other things: (1) limit the amount of additional indebtedness we can incur; (2) limit restricted payments such as a dividend; (3) limit our ability to incur liens or encumbrances; (4) limit our ability to purchase, transfer or dispose of significant assets; (5) limit our ability to purchase or redeem stock or subordinated debt; (6) limit our ability to enter into transactions with affiliates; (7) limit our ability to merge with or into other companies or transfer all or substantially all of our assets; and (8) limit our ability to enter into sale and leaseback transactions. We have the option to redeem all or part of these notes on or after December 15, 2011. Additionally, we may redeem some or all of the notes prior to December 15, 2011 at a price equal to 100% of the principal amount of the notes plus a make-whole premium.
Pursuant to a registration rights agreement with the holders of our 8.0% senior notes, on June 1, 2007, we filed a registration statement on Form S-4 with the SEC which enabled these holders to exchange their notes for publicly registered notes with substantially identical terms. These holders exchanged 100% of the notes for publicly traded notes on July 25, 2007. On August 28, 2007, we entered into a supplement to the indenture governing the 8.0% senior notes, whereby additional domestic subsidiaries became guarantors under the indenture. Effective April 1, 2009, we entered into a second supplement to this indenture whereby additional domestic subsidiaries became guarantors under the indenture.
(c)
We issued subordinated seller notes totaling $3,450 in 2004 related to certain business acquisitions. These notes bore interest at 6% and matured in March 2009. We repaid the outstanding principal associated with these note agreements totaling $3,450 upon maturity.
At December 31, 2009, principal maturities under our capital leases and other debt obligations for the next five years were: 2010 - $266; 2011 - $192; 2012 - $0; 2013 - $0 and 2014 - $0. Our senior notes mature in 2016, at a face value of $650,000.
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
12.
Stockholders’ equity:
(a) Authorized Share Capital:
On September 12, 2005, our authorized share capital was increased to 200,000,000 shares of common stock from 24,000,000 shares of common stock with par value of $0.01 per share and to 5,000,000 shares of preferred stock from 1,000 shares of preferred stock with a par value of $0.01 per share.
(b) Initial Public Offering:
On April 26, 2006, we sold 13,000,000 shares of our common stock, $.01 par value per share, in our initial public offering. These shares were offered to the public at $24.00 per share, and we recorded proceeds of approximately $292,500 after underwriter fees of $19,500. In addition, we incurred transaction costs of $3,865 associated with the issuance that were netted against the proceeds of the offering. Our stock began trading on the New York Stock Exchange on April 21, 2006.
(b) Stock-based Compensation:
We maintain option plans under which we grant stock-based compensation to employees, officers and directors to purchase our common stock. The exercise price of each option is based on the fair value of the individual company’s stock at the date of grant. Options may be exercised over a five or ten-year period and generally a third of the options vest on each of the first three anniversaries from the grant date. Upon exercise of stock options, we issue our common stock.
In November 2006, we assumed the stock option plan of Pumpco, which included 145,000 outstanding employee stock options at an exercise price of $5.00 per share. The exercise price of these stock options was $5.00 per share, which was below market price at the date of grant pursuant to the agreed-upon conversion rate negotiated as part of the acquisition. These options vest ratably over a three-year term. Upon exercise of these Pumpco stock options, we issue shares of our common stock.
(i) Employee Stock Options Granted Prior to September 30, 2005:
We continue to account for stock-based compensation for grants made prior to September 30, 2005, the date of our initial filing with the Securities and Exchange Commission, using the intrinsic value method prescribed by U.S. GAAP, 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.
(ii) Employee Stock Options Granted Between October 1, 2005 and December 31, 2005:
For grants of stock-based compensation between October 1, 2005 and December 31, 2005, we have utilized the modified prospective transition method to record expense associated with these stock-based compensation instruments. Under this transition method, beginning January 1, 2006, we began to recognize expense related to these option grants over the applicable vesting period, with expense calculated by applying a Black-Scholes pricing model with the following assumptions: risk-free rate of 4.23% to 4.47%; expected term of 4.5 years and no dividend rate. The weighted average fair value of these option grants was $2.05 per share.
For the years ended December 31, 2008 and 2007, the compensation expense recognized related to these stock options was $270 and $307, respectively, which reduced net income by $174 and $200, respectively. There was no impact on basic and diluted earnings per share from continuing operations as reported for the years ended December 31, 2008 and 2007 attributable to the compensation expense recognized related to these stock options. These awards were 100% vested at December 31, 2008.
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Notes to Consolidated Financial Statements - (Continued)
(iii) Employee Stock Options Granted On or After January 1, 2006:
For grants of stock-based compensation on or after January 1, 2006, we apply the prospective transition method under prescribed by U.S. GAAP, whereby we recognize expense associated with new awards of stock-based compensation ratably, as determined using a Black-Scholes pricing model, over the expected term of the award.
During the years ended December 31, 2009 and 2008, the Compensation Committee of our Board of Directors authorized and issued to our officers and employees 875,300 and 368,596 employee stock options, respectively and 1,301,008 and 605,176 non-vested restricted shares, respectively. Stock option grants in 2009 had an exercise price which ranged from $6.41 to $6.78 per share. Stock option grants in 2008 had an exercise price which ranged from $8.16 to $34.19 per share. The exercise price represented the fair market value of the shares on the date of grant. These stock option grants vest ratably over a three-year term. Additionally, the directors received grants of stock-based compensation during 2009 and 2008, which included 40,000 stock options granted in each of these years which vest ratably over a three-year period. Furthermore, the directors received 109,608 shares of non-vested restricted stock which vests 100% on January 30, 2010. In 2008, the directors received 13,456 shares of non-vested restricted stock that vested 100% on May 22, 2009. The 2007 grant of 17,144 shares of non-vested restricted stock vested 100% on May 24, 2008. The fair value of this stock-based compensation was determined by applying a Black-Scholes option pricing model based on the following assumptions:
The weighted average fair values of 2009, 2008 and 2007 stock option grants were $1.82, $4.62 and $6.14, respectively.
We completed our initial public offering in April 2006. Prior to the second quarter of 2008, we did not have sufficient historical market data in order to determine the volatility of our common stock. In accordance with U.S. GAAP, we analyzed the market data of peer companies and calculated an average volatility factor based upon changes in the closing price of these companies’ common stock for a three-year period. This volatility factor was then applied as a variable to determine the fair value of our stock options granted prior to the second quarter of 2008. For stock options granted during or after the second quarter of 2008, we calculated an average volatility factor for our common stock for the period from April 21, 2006 through the respective quarter end. These volatility calculations were used to compute the calculation of the fair market value of stock option grants made subsequent to June 30, 2008.
We projected a rate of stock option forfeitures based upon historical experience and management assumptions related to the expected term of the options. After adjusting for these forfeitures, we expect to recognize expense totaling $16,903 related to our stock option grants made after January 1, 2006. For the years ended December 31, 2009, 2008 and 2007, we have recognized expense related to these stock option grants totaling $3,943, $5,166 and $4,118, respectively, which represents a reduction of net income before taxes and minority interest. The impact on net income was a reduction of $2,926, $3,332 and $2,677, respectively. The unrecognized compensation costs related to the non-vested portion of these awards was $2,080 as of December 31, 2009 and will be recognized over the applicable remaining vesting periods.
The non-vested restricted shares were granted at fair value on the date of grant. If the restricted non-vested shares are not forfeited, we will recognize compensation expense related to our 2009, 2008 and 2007 grants to officers and employees totaling $7,634, $14,025 and $1,600, respectively, over the three-year vesting period, our
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
grants to directors in 2009, 2008 and 2007 totaling $703, $402 and $450, respectively, over a twelve-month vesting period.
The following tables provide a roll forward of stock options from December 31, 2006 to December 31, 2009 and a summary of stock options outstanding by exercise price range at December 31, 2009:
The total intrinsic value of stock options exercised during the years ended December 31, 2009 and 2008 was $568 and $24,063, respectively. The total intrinsic value of all in-the-money vested outstanding stock options at December 31, 2009 was $5,177. Assuming all stock options outstanding at December 31, 2009 were vested, the total intrinsic value of all in-the-money outstanding stock options would have been $10,975.
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
(d)
Incentive Award Plan:
In March 2008, upon the recommendation of the Compensation Committee and subject to approval by stockholders, our Board of Directors approved the Complete Production Services, Inc. 2008 Incentive Award Plan, which was intended to succeed the prior stock option plan, the Amended and Restated 2001 Stock Incentive Plan, pursuant to which, 2,500,000 shares of common stock were authorized for future issuance to our directors, officers and employees in conjunction with stock-based compensation arrangements. On May 22, 2008, stockholders owning more than a majority of the shares of our common stock adopted the 2008 Stock Incentive Plan. We subsequently filed a registration statement on Form S-8 and made grants to our directors, officers and employees. In March 2009, upon the recommendation of the Compensation Committee and as approved by our stockholders owning more than a majority of the shares of our common stock on May 24, 2009, we amended the 2008 Incentive Award Plan to increase the number of shares authorized for future issuance to up to 6,400,000 shares. As amended, the aggregate number of shares of common stock available for issuance under the 2008 Incentive Award Plan will be reduced by (i) 1.3 shares for each share of common stock delivered in settlement of any full value award, and (ii) 1.0 shares for each share of common stock delivered in settlement of any option, stock appreciation right or any other award that is not a full value award. If all of the shares authorized by the amendment to the 2008 Incentive Award Plan were granted as full value awards, then there would be 4,900,000 shares granted as full value awards and no shares available for issuance as awards that were not full value awards. For purposes of the 2008 Incentive Award Plan, full value awards mean any award other than (i) an option, (ii) a stock appreciation right or (iii) any other award for which the holder pays the intrinsic value existing as of the date of grant (whether directly or by forgoing a right to receive a payment from us or any subsidiary of ours). We subsequently filed a registration statement on Form S-8 and made grants to our directors, officers and employees under the 2008 Incentive Award Plan, as amended. The 2008 Stock Incentive Plan provides that forfeitures under the Amended and Restated 2001 Stock Incentive Plan will become available for issuance under the 2008 Incentive Award Plan.
(f)
Non-vested Restricted Stock:
We present the amortization of non-vested restricted stock as an increase in additional paid-in capital. At December 31, 2009 and 2008, amounts not yet recognized related to non-vested stock totaled $9,727 and $10,080, respectively, which represented the unamortized expense associated with awards of non-vested stock granted to employees, officers and directors under our compensation plans, including $9,293 and $1,248 related to grants made in 2008 and 2007, respectively. Compensation expense associated with these grants of non-vested stock is determined as the fair value of the shares on the date of grant, and recognized ratably over the applicable vesting periods. We recognized compensation expense associated with non-vested restricted stock totaling $8,222, $6,934 and $3,142 for the years ended December 31, 2009, 2008 and 2007, respectively.
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Notes to Consolidated Financial Statements - (Continued)
The following table summarizes the change in non-vested restricted stock from December 31, 2006 to December 31, 2009:
(g) Common Shares Issued for Acquisitions:
On October 4, 2008, we issued 588,292 unregistered shares of our $0.01 par value common stock as a portion of the purchase consideration for Appalachian Well Service, Inc. and its wholly owned subsidiary. See Note 3, Business Combinations. In connection with this issuance, we recorded common stock and additional paid-in capital totaling $8,854, an issuance price of $15.04 per share, based on an average of the closing and opening price of our common stock on the business day proceeding and following the acquisition date. The number of shares issued was calculated based upon the agreed-upon purchase price negotiated with the seller.
(h) Treasury shares:
In accordance with the provisions of the 2008 Incentive Award Plan, holders of unvested restricted stock were given the option to either remit to us the required withholding taxes associated with the vesting of restricted stock, or to authorize us to repurchase shares equivalent to the cost of the withholding tax and to remit the withholding taxes on behalf of the holder. Pursuant to this provision, we repurchased the following shares during the year ended December 31, 2009:
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
These shares were included as treasury stock at cost in the accompanying balance sheet as of December 31, 2009. We expect to purchase additional shares in the future pursuant to this plan provision.
13.
Earnings per share:
We compute basic earnings per share by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per common and potential common share includes the weighted average of additional shares associated with the incremental effect of dilutive employee stock options and non-vested restricted stock, as determined using the treasury stock method prescribed by the FASB guidance on earnings per share. The following table reconciles basic and diluted weighted average shares used in the computation of earnings per share for the years ended December 31, 2009, 2008 and 2007:
For each of the years ended December 31, 2009 and 2008, we incurred a net loss and thus all potential common shares were deemed to be anti-dilutive. We excluded the impact of anti-dilutive potential common shares from the calculation of diluted weighted average shares for the years ended December 31, 2009, 2008 and 2007. If these potential common shares were included, the impact would have been a decrease in weighted average shares outstanding of 2,474,169, 1,245,148 shares and 231,233 shares, respectively, for the years ended December 31, 2009, 2008 and 2007.
14.
Discontinued operations:
In May 2008, our Board of Directors authorized and committed to a plan to sell certain business assets located primarily in north Texas which included our product supply stores, certain drilling logistics assets and other completion and production services assets. Although this sale did not represent a material disposition of assets relative to our total assets, the disposal group did represent a significant portion of the assets and operations which were attributable to our product sales business segment for the periods presented, and therefore, was accounted for as a disposal group that is held for sale. We revised our financial statements, in accordance with U.S. GAAP and removed the results of operations of the disposal group from net income from continuing operations, and presented these separately as income from discontinued operations, net of tax, for the accompanying statements of operations for the years ended December 31, 2008 and 2007. We ceased depreciating the assets of this disposal group in May 2008 and adjusted the net assets to the lower of carrying value or fair value less selling costs, which resulted in a pre-tax charge of approximately $200. In addition, we allocated $11,109 of goodwill associated with the original formation of Complete Production Services, Inc. to this business, and impaired this goodwill as of the date of the transaction. Thus, this amount has been included in the calculation of the loss on the sale of this disposal group.
On May 19, 2008, we completed the sale of the disposal group for $50,150 in cash and we received assets with a fair market value of $7,987. In addition, we retained the receivables and payables associated with the operating results of these entities as of the date of the sale. The carrying value of the related net assets was approximately $51,353 on May 19, 2008, excluding allocated goodwill of $11,109. We recorded a loss of $6,935 associated with the sale of this disposal group, which represents the excess of the carrying value of the assets less selling costs over the sales price and a charge of approximately $2,610 related to income tax on the transaction. The income tax on the
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
disposal was primarily attributable to the $11,109 of allocated goodwill which was non-deductible for tax purposes and resulted in a taxable gain on the disposal. We sold this disposal group to Select Energy Services, L.L.C., an oilfield service company located in Gainesville, Texas which is owned by a former officer of one of our subsidiaries. Pursuant to the agreement, we sublet office space to Select Energy Services, L.L.C., and provided certain administrative functions for a period of one year at an agreed-upon rate for services per hour. Proceeds from the sale of this disposal group were used to repay outstanding borrowings under our U.S. revolving credit facility and for other general corporate purposes.
The following table summarizes operating results for this disposal group for the periods indicated:
15.
Segment information:
We report segment information based on how our management organizes the operating segments to make operational decisions and to assess financial performance. We evaluate performance and allocate resources based on net income (loss) from continuing operations before net interest expense, taxes, depreciation and amortization, minority interest and impairment loss (“Adjusted EBITDA”). The calculation of Adjusted EBITDA should not be viewed as a substitute for calculations under U.S. GAAP, in particular net income. Adjusted EBITDA calculated by us may not be comparable to the EBITDA calculation of another company or to the calculation of EBITDA under our credit facilities (see Note 11 for a description of the calculation of EBITDA under our existing credit facility, as amended). See also the table below for a reconciliation of Adjusted EBITDA to operating income (loss) by segment.
We have three reportable operating segments: completion and production services (“C&PS”), drilling services and product sales. The accounting policies of our reporting segments are the same as those used to prepare our consolidated financial statements as of December 31, 2009, 2008, and 2007. Inter-segment transactions are accounted for on a cost recovery basis.
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
Inter-segment sales in 2009, 2008 and 2007 were largely due to service work performed and drilling rigs assembled by a subsidiary in the product sales business segment that sold such services and rigs to a subsidiary in the drilling services business segment as well as other subsidiaries primarily in the completion and production services business segment.
We do not allocate net interest expense, tax expense or minority interest to the operating segments. The write-off of deferred financing fees of $528 for the year ended December 31, 2009 reduced Adjusted EBITDA, as defined,
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
for the Corporate and Other segment. The following table reconciles operating income (loss) as reported above to net income from continuing operations for each of the years ended December 31, 2009, 2008 and 2007.
The following table summarizes the changes in the carrying amount of goodwill for continuing operations by segment for the three-year period ended December 31, 2009:
(a)
We test goodwill for impairment annually, or more often if indicators of impairment exist. For the year ended December 31, 2007 we determined that goodwill associated with our Canadian reportable unit was deemed to be impaired as of the test date, resulting in an impairment charge of $13,360. For the year ending December 31, 2008, we determined that goodwill associated with our Canadian reportable unit was further impaired as of the test date. However, during the fourth quarter of 2008, we believed that the decline in the U.S. debt and equity markets, as well as the credit market, constituted a triggering event. As such, we performed the prescribed impairment testing at December 31, 2008 and noted impairment which impacted several of our reportable units. Therefore, we recorded an impairment charge of $272,006 for the year ended December 31, 2008. For
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
the year ending December 31, 2009, we determined that goodwill associated with several of our reportable units was further impaired and recorded an impairment charge of $97,643. See Note 2, Significant Accounting Policies - Fair Value Measurements.
(b)
The contingency adjustment includes a reclassification of $3,485 from goodwill to identifiable intangible assets, primarily non-compete agreements and customer relationships, which were identified upon acquisition but for which the fair value was recently determined based upon estimates calculated by a third-party appraiser. Of this amount, $2,017 related to the acquisition of Pumpco Services, Inc. in November 2006. In addition, we recorded an adjustment to reduce goodwill related to the acquisition of Pumpco Services, Inc. totaling $3,136 associated with certain federal income tax liabilities recorded at the acquisition date that were deemed to be unnecessary based upon the 2006 federal tax return prepared in 2007. Partially offsetting these reductions to goodwill were additional charges associated with final working capital adjustments for several 2006 and 2007 acquisitions.
(c)
See Note 14 - Discontinued operations.
Geographic information (d):
(d)
The segment operating results provided above represent amounts for continuing operations as presented on the accompanying statements of operations. Long-lived assets presented above represent amounts associated with all operations as of the periods then ended as indicated. Revenues from external customers are assigned to geographic region based upon the domicile of the subsidiary providing the services or products to the customers.
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
For the year ended December 31, 2009, we had two customers who represented 9.9% and 9.7% of our revenue. We did not have revenues from any single customer which amounted to 10% or more of our total annual revenue for the years ended December 31, 2008 and 2007.
16.
Legal matters and contingencies:
In the normal course of our business, we are a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including warranty and product liability claims and occasional claims by individuals alleging exposure to hazardous materials, on the job injuries and fatalities as a result of our products or operations. Many of the claims filed against us relate to motor vehicle accidents which can result in the loss of life or serious bodily injury. Some of these claims relate to matters occurring prior to our acquisition of businesses. In certain cases, we are entitled to indemnification from the sellers of such businesses.
Although we cannot know or predict with certainty the outcome of any claim or proceeding or the effect such outcomes may have on us, we believe that any liability resulting from the resolution of any of these matters, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our financial position, results of operations or liquidity.
We have historically incurred additional insurance premium related to a cost-sharing provision of our general liability insurance policy, and we cannot be certain that we will not incur additional costs until either existing claims become further developed or until the limitation periods expire for each respective policy year. Any such additional premiums should not have a material adverse effect on our financial position, results of operations or liquidity. We incurred no additional premium related to this cost-sharing provision of our general liability policy in 2009 or 2008, but paid approximately $1,400 of additional premium for the year ended December 31, 2007.
17.
Financial instruments:
(a) Interest rate risk:
We manage our exposure to interest rate risks through a combination of fixed and floating rate borrowings. At December 31, 2009, almost 100% of our debt relates to the senior notes issued in December 2006 with a fixed interest rate of 8%.
(b) Foreign currency rate risk:
We are exposed to foreign currency fluctuations in relation to our foreign operations. Approximately 5% of our revenues from continuing operations were derived from operations conducted in Canadian dollars for the years ended December 31, 2009 and 2008. For our Canadian operations, we recorded a net loss from continuing operations before taxes and non-controlling interest of $11,069 and $26,412 for the years ended December 31, 2009 and 2008, respectively. Total assets denominated in Canadian dollars at December 31, 2009 and 2008 were $59,343 and $66,355, respectively.
(c) Credit risk:
A significant portion of our trade accounts receivable are from companies in the oil and gas industry, and as such, we are exposed to normal industry credit risks. We evaluate the credit-worthiness of our major new and existing customers’ financial condition and generally do not require collateral.
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
18.
Commitments and contingences:
We have non-cancelable operating lease commitments for equipment and office space. These commitments for the next five years were as follows at December 31, 2009:
We expensed operating lease payments totaling $25,477, $22,750 and $22,446 for the years ended December 31, 2009, 2008 and 2007, respectively.
19.
Related party transactions:
We believe all transactions with related parties have terms and conditions no less favorable to us than transactions with unaffiliated parties.
We have entered into lease agreements for properties owned by certain of our employees and former officers. The leases expire at different times through December 2016. Total lease expense pursuant to these leases was $2,749, $2,828 and $2,991 for the years ended December 31, 2009, 2008 and 2007, respectively.
In connection with the Complete Energy Services, Inc. (“CES”) acquisition of Hamm Co. in 2004, CES entered into a certain Strategic Customer Relationship Agreement with Continental Resources, Inc. (“CRI”). By virtue of the Combination, through a subsidiary, we are now party to such agreement. The agreement provides CRI the option to engage a limited amount of our assets into a long-term contract at market rates. Mr. Hamm is a majority owner of CRI and serves as a member of our board of directors.
We provided services to companies that were majority-owned by certain of our directors during 2009 which totaled $40,623, of which $40,343 was sold to CRI, and $280 was sold to other companies. In 2008, these sales totaled $61,194, of which $60,634 was sold to CRI, and $560 was sold to other companies and in 2007, these sales totaled $52,027, of which $51,340 was sold to CRI, and $687 was sold to other companies. We also purchased services from companies that are majority-owned by certain of our directors which totaled $1,423 in 2009, of which $1,191 was purchased from CRI and $232 was purchased from other companies. These purchases for 2008 totaled $2,866, of which $2,750 was purchased from CRI and $116 was purchased from other companies and in 2007, these purchases totaled $1,260, of which $1,211 was purchased from CRI and $49 was purchased from other companies. At December 31, 2009 and 2008, our trade receivables included amounts from CRI of $5,957 and $10,542, respectively, and our trade payables included amounts due to CRI of $181 at December 31, 2008.
We provided services to companies majority-owned by certain of our officers, or current or former officers of our subsidiaries, for the years ended December 31, 2009, 2008 and 2007. In 2009, these sales totaled $3,552, of which $2,433 was sold to HEP Oil (“HEP”), $9 was sold to Peak Oilfield and $1,110 was sold to other companies. For 2008, these sales totaled $11,256, of which $3,348 was sold to HEP, $1,660 was sold to Cimarron, $3,513 was sold to Peak Oilfield and $2,735 was sold to other companies. For 2007, these sales totaled $4,914, of which $2,974 was sold to HEP, $39 was sold to Cimarron, $1,527 was sold to Peak Oilfield and $374 was sold to other companies. HEP, Cimarron and Peak Oilfield are owned by a former officer of one of our subsidiaries who resigned his position in late 2006 but continued to provide consulting services through early 2007. We also purchased services from companies majority-owned by certain officers, or current or former officers of our subsidiaries. For 2009, these purchases totaled $36,838, of which $13,920 was purchases from Ortowski Construction primarily related to the
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
manufacture of pressure pumping units, $12,005 was purchased from Texas Specialty Sands, LLC primarily for the purchase of sand used for pressure pumping activities, $3,302 was purchased from Resource Transport, $2,642 was purchased from ProFuel, $24 was purchased from Select Energy Services LLC and affiliates and $4,945 was purchased from other companies. For 2008, these purchases totaled $60,546, of which $25,344 was purchased from Ortowski Construction, $7,910 was purchased from Texas Specialty Sands, LLC, $4,809 was purchased from Resource Transport, $5,601 was purchased from ProFuel, $16,595 was purchased from Select Energy Services LLC and affiliates and $287 was purchased from other companies. Ortowski Construction, Texas Specialty Sands, LLC, Resource Transport and Pro Fuel are owned by a current employee who is an officer of one of our subsidiaries. Select Energy Services LLC is owned by a former officer of one of our subsidiaries who purchased a disposal group from us during May 2008. Of the total purchases from Select Energy Services, LLC, $11,098 was purchased from the businesses sold as part of this disposal group for the period May 19, 2008 through December 31, 2008. For 2007, these purchases from related companies totaled $70,550, of which $64,503 was purchased from Ortowski Construction, $70 was purchased from HEP and $5,977 was purchased from other companies. At December 31, 2009 and 2008, our trade receivables included amounts from HEP of $270 and $384, respectively. Our trade payables and accrued expenses at December 31, 2008 included amounts payable to Ortowski construction of $175. Amounts payable at December 31, 2008 to Texas Specialty Sand, LLC, Resource Transport, and ProFuel totaled $581, $199 and $187, respectively. There were no amounts payable to HEP or Cimarron at December 31, 2009 and 2008.
One of our Mexican subsidiaries, Servicios Petrotec de S.A. de C.V., has purchased services from entities in which certain of our current and former employees have ownership interests. We purchased fluid transportation, industrial cleaning, pumping equipment and safety equipment, totaling $1,262, $1,485 and $857 for the years ended December 31, 2009, 2008 and 2007, respectively.
We provided services totaling $1,012, $1,697 and $2,068 for the years ended December 31, 2009, 2008 and 2007, respectively, to Laramie Energy LLC and Laramie Energy II (collectively “Laramie”), companies for which one of our directors serves as an officer. At December 31, 2009 and 2008, our trade receivables included amounts due from Laramie totaling $326 and $383, respectively.
For the years ended December 31, 2009, 2008 and 2007, we provided services totaling $3,613, $9,468 and $11,016, respectively, and purchased services totaling $8,784, $14,108 and $13,757, respectively, from companies, or their affiliates, that formerly employed our current officers or for customers on whose board of directors or management team certain of our current directors serve.
We entered into subordinated note agreements with certain employees, including current officers of subsidiaries, whereby we are obligated to pay an aggregate principal amount of $8,450 pursuant to promissory notes issued in conjunction with 2005 and 2004 business acquisitions. Of this amount, $5,000 was repaid in May 2006 and the remaining notes matured in 2009. See Note 11, Long-term Debt.
Premier Integrated Technologies Ltd. (“PIT”), an affiliate of IPS, purchased $2,427, $1,493 and $2,290 of machining services from a company controlled by employees of PIT during the years ended December 31, 2009, 2008 and 2007, respectively.
On May 19, 2008, we sold certain business assets located primarily in north Texas which included our product supply stores, certain drilling logistics assets and other completion and production services assets to Select Energy Services, L.L.C., an oilfield service company located in Gainesville, Texas which is partially owned by Mr. Schmitz who resigned as an officer of one of our subsidiaries in late 2006. The proceeds from the sale totaled $50,150 in cash and we received assets with a fair market value of $7,987. We recorded a loss of $6,935 associated with the sale of
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
this disposal group, and we will provide certain administrative functions for a period of one year at an agreed-upon rate. For the period May 20, 2008 through December 31, 2008, we sold services totaling $1,509 and purchased products and services totaling $11,098 from these former subsidiaries. See Note 14, Discontinued operations. At December 31, 2009, our trade receivables and payables included amounts related to these disposed businesses which totaled $21 and $295, respectively.
20.
Retirement plans:
Effective January 1, 2009, we adopted and established (and subsequently amended and restated for compliance and other issues) the Complete Production Services, Inc. Deferred Compensation Plan, whereby eligible participants, including members of senior management, non-employee directors and certain highly-compensated individuals, could defer up to 90% of their compensation and up to 90% of the employees’ annual incentive bonus, or 100% of director compensation for services rendered, into various investment options pre-tax. For amounts deferred, we will match the contribution dollar-for-dollar up to four percent of compensation minus $3.3, and we may make other discretionary contributions pursuant to resolutions of this plan’s administrative committee. Participants immediately vest in amounts deferred as well as any matching or discretionary contributions we make. Participants bear the risk of loss associated with investment gains or losses. We intend that this plan will meet all the requirements necessary to be a nonqualified, unfunded, unsecured plan of deferred compensation within the meaning of Sections 201(2), 301(a)(3) and 401(a)(1) of the Employee Retirement Income Security Act of 1974, as amended. For the year ended December 31, 2009, we expensed $14 of matching contributions associated with this deferred compensation plan.
In response to current market conditions, we amended our 401(k) plan and deferred compensation plan effective May 1, 2009 to suspend matching contributions to such plans until further notice.
We expensed $2,231, $6,101 and $5,216 related to our various defined contribution plans for the years ended December 31, 2009, 2008 and 2007, respectively.
We provide a seniority premium benefit to substantially all of our Mexican employees, through a subsidiary, in accordance with Mexican law. The benefit consists of a one-time payment equivalent to 12-days wages for each year of service (calculated at the employee’s current wage rate but not exceeding twice the minimum wage), payable upon voluntary termination after fifteen years of service, involuntary termination or death. In addition, we provide statutory mandated severance benefits to substantially all Mexican employees, which includes a one-time payment of three months wages, plus 20-days wages for each year of service, payable upon involuntary termination without cause and charged to income as incurred. We accrued $1,604 and $1,591 at December 31, 2009 and 2008, respectively, related to our liability under this benefit arrangement in Mexico.
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
21.
Unaudited selected quarterly data:
The following table presents selected quarterly financial data for the years ended December 31, 2009 and 2008 (unaudited, in thousands, except per share amounts):
(a)
Quarterly earnings per share amounts were calculated based upon the weighted average number of shares outstanding for the applicable quarter. Therefore the sum of the quarterly earnings per share results may not agree to earnings per share for the year in the accompanying Statements of Operations, as the annual results were calculated based upon the weighted average number of shares outstanding for the year.
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
22.
Guarantor and non-guarantor condensed consolidating financial statements:
The following tables present the financial data required by SEC Regulation S-X Rule 3-10(f) related to condensed consolidating financial statements, and includes the following: (1) condensed consolidating balance sheets for the years ended December 31, 2009 and 2008; (2) condensed consolidating statements of operations for the years ended December 31, 2009, 2008 and 2007; and (3) condensed consolidating statements of cash flows for the years ended December 31, 2009, 2008 and 2007.
Condensed Consolidating Balance Sheet
December 31, 2009
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
Condensed Consolidating Balance Sheet (Revised)
December 31, 2008
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
Condensed Consolidated Statement of Operations
Year Ended December 31, 2009
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
Condensed Consolidated Statement of Operations (Revised)
Year Ended December 31, 2008
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
Condensed Consolidated Statement of Operations
Year Ended December 31, 2007 (Revised)
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2009
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
Condensed Consolidated Statement of Cash Flows (Revised)
Year Ended December 31, 2008
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2007 (Revised)
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
23.
Recent accounting pronouncements and authoritative literature:
In December 2007, the FASB issued additional guidance regarding business combinations that replaced the initial statement in its entirety. The guidance now additionally requires that all assets and liabilities and non-controlling interests of an acquired business be measured at their fair value, with limited exceptions, including the recognition of acquisition-related costs and anticipated restructuring costs separate from the acquired net assets. The statement also provides guidance for recognizing pre-acquisition contingencies and states that an acquirer must recognize assets and liabilities assumed arising from contractual contingencies as of the acquisition date, measured at acquisition-date fair values, but must recognize all other contractual contingencies as of the acquisition date, measured at their acquisition-date fair values only if it is more likely than not that these contingencies meet the definition of an asset or liability. Furthermore, this statement provides guidance for measuring goodwill and recording a bargain purchase, defined as a business combination in which total acquisition-date fair value of the identifiable net assets acquired exceeds the fair value of the consideration transferred plus any non-controlling interest in the acquiree, and it requires that the acquirer recognize that excess in earnings as a gain attributable to the acquirer. In April 2009, the FASB issued a further update regarding accounting for assets and liabilities assumed in a business combination that arises from contingencies which amends the previous guidance to require contingent assets acquired and liabilities assumed in a business combination to be recognized at fair value on the acquisition date if fair value can be reasonably estimated during the measurement period. If fair value cannot be reasonably estimated during the measurement period, the contingent asset or liability would be recognized in accordance with U.S. GAAP to account for contingencies and reasonable estimation of the amount of loss, if any. Further, this update eliminated the specific subsequent accounting guidance for contingent assets and liabilities, without significantly revising the original guidance. However, contingent consideration arrangements of an acquiree assumed by the acquirer in a business combination would still be initially and subsequently measured at fair value. We adopted this additional guidance regarding business combinations on January 1, 2009 with no impact on our financial position, results of operations and cash flows.
In December 2007, the FASB issued guidance which established accounting and reporting standards for non-controlling interests, formerly referred to as minority interests. This guidance requires separate presentation of the non-controlling interest as a component of equity on the balance sheet, and that net income be presented prior to adjustment for the non-controlling interests’ portion of earnings with the portion of net income attributable to the parent company and the non-controlling interest both presented on the face of the statement of operations. We determined that this guidance had no impact on our financial statements for the years ended December 31, 2009 and 2008, and no material impact for the year ended December 31, 2007. Therefore, no presentation changes have been made to the consolidated financial statements relating to non-controlling interest.
In September 2008, the FASB issued guidance regarding the reporting of discontinued operations which clarified the definition of a discontinued operation as either: (1) a component of an entity which has been disposed of or classified as held for sale which meets the criteria of an operating segment, or (2) as a business which meets the criteria to be classified as held for sale on acquisition. This proposed guidance further modifies certain disclosure requirements. We are currently evaluating the effect this proposed guidance may have on our financial position, results of operations and cash flows.
In May 2009, the FASB issued a standard regarding subsequent events that provides guidance as when an entity should recognize events or transactions occurring after a balance sheet date in its financial statements and the necessary disclosures related to these events. Specifically, the entity should recognize subsequent events that provide evidence about conditions that existed at the balance sheet date, including significant estimates used to prepare financial statements. An entity must disclose the date through which subsequent events have been evaluated and whether that date is the date the financial statements were issued or the date the financial statements were available to be issued. We adopted this new accounting standard effective June 30, 2009 and have applied its provisions prospectively.
In August 2009, the FASB further updated the fair value measurement guidance to clarify how an entity should measure liabilities at fair value. The update reaffirms fair value is based on an orderly transaction between market
COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements - (Continued)
participants, even though liabilities are infrequently transferred due to contractual or other legal restrictions. However, identical liabilities traded in the active market should be used when available. When quoted prices are not available, the quoted price of the identical liability traded as an asset, quoted prices for similar liabilities or similar liabilities traded as an asset, or another valuation approach should be used. This update also clarifies that restrictions preventing the transfer of a liability should not be considered as a separate input or adjustment in the measurement of fair value. We adopted the provisions of this update for fair value measurements of liabilities effective October 1, 2009, with no material impact on our financial position, results of operations and cash flows.
24.
Subsequent events:
On January 31, 2010, the Compensation Committee of our Board of Directors approved the annual grant of stock options and non-vested restricted stock to certain employees, officers and directors. Pursuant to this authorization, we issued 794,112 shares of non-vested restricted stock at a grant price of $12.53. We expect to recognize compensation expense associated with this grant of non-vested restricted stock totaling $9,950 ratably over the three-year vesting period. In addition, we granted 516,300 stock options to purchase shares of our common stock at an exercise price of $12.53. These stock options vest ratably over a three-year period. We will recognize compensation expense associated with these stock option grants over the vesting period.
Pursuant to our 2008 Incentive Award Plan, holders of unvested restricted stock have the option to authorize us to repurchase shares equivalent to the cost of the withholding tax associated with the vesting of restricted stock and to remit the withholding taxes on behalf of the holder. Pursuant to this provision, we purchased 109,360 shares of our common stock on January 31, 2010 for $1,370, or $12.53 per share. These shares were included in treasury stock at cost.
Item 9.
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A.
Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), management has evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K.
Disclosure controls and procedures refer to controls and other procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the rules and forms of the Securities and Exchange Commission. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding our required disclosure. In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management was required to apply its judgment in evaluating and implementing possible controls and procedures.
Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2009, the end of the period covered by this Annual Report on Form 10-K, our disclosure controls and procedures were effective at a reasonable assurance level to ensure that information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported as and when required.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a - 15(f) and 15d - 15(f) under the Exchange Act). Our internal control over financial reporting is a process designed by management, under the supervision of the Chief Executive Officer and Chief Financial Officer, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America, and includes those policies and procedures that:
(i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets;
(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States, and that our receipts and expenditures are being made only in accordance with authorizations of management and our directors; and
(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our consolidated financial statements.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improver override. Because of its inherent limitations, there is a risk that internal control over financial reporting may not prevent or detect, on a timely basis, material misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies and procedures may deteriorate. Accordingly, even effective internal control over financial reporting can only provide reasonable assurance of achieving their control objectives.
Our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009. In making this assessment, management used the criteria set forth by the committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework.
Based on our evaluation under the framework in Internal Control - Integrated Framework, our management concluded that, as of December 31, 2009, our internal control over financial reporting was effective.
Grant Thornton LLP, the independent registered accounting firm who audited the consolidated financial statements included in this Annual Report, has issued a report on our internal control over financial reporting dated February 19, 2010, also included in this Annual Report and expressed an unqualified opinion on the effectiveness of our internal control over financial reporting as of December 31, 2009.
Changes in Internal Control over Financial Reporting
As of December 31, 2009, there were no changes in our system of internal control over financial reporting (as defined in Rules 13a - 15(f) and 15d - 15(f) under the Exchange Act) that occurred during the last fiscal quarter then ended that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
/s/ Joseph C. Winkler
Joseph C. Winkler
Chairman and Chief Executive Officer
February 19, 2010
/s/ Jose A. Bayardo
Jose A. Bayardo
Vice President and Chief Financial Officer
February 19, 2010
Item 9B.
Item 9B.
Other Information.
None.
PART III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance.
The information to be included in the sections entitled, “Election of Directors” and “Executive Officers,” respectively, in the Definitive Proxy Statement of the Annual Meeting of Stockholders to be filed by us with the Securities and Exchange Commission no later than 120 days after December 31, 2009 (the “2010 Proxy Statement”) is incorporated herein by reference.
The information to be included in the section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” in the 2010 Proxy Statement is incorporated herein by reference.
The information to be included in the section entitled “Corporate Governance” in the 2010 Proxy Statement is incorporated herein by reference.
We have filed, as exhibits to this Annual Report on Form 10-K, the certifications of our Principal Executive Officer and Principal Financial Officer required pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Item 11.
Item 11.
Executive Compensation.
The information to be included in the sections entitled “Executive Compensation” and “Directors’ Compensation” in the 2010 Proxy Statement is incorporated herein by reference.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information to be included in the section entitled “Security Ownership of Certain Beneficial Owners and Management” in the 2010 Proxy Statement is incorporated herein by reference.
Item 13.
Item 13.
Certain Relationships and Related Transactions, and Director Independence.
The information to be included in the sections entitled “Certain Relationships and Related Transactions” and “Board Independence” in the 2010 Proxy Statement is incorporated herein by reference.
Item 14.
Item 14.
Principal Accounting Fees and Services.
The information to be included in the section entitled “Independent Registered Public Accountants” in the 2010 Proxy Statement is incorporated herein by reference.
PART IV
Item 15.
Item 15.
Exhibits, Financial Statement Schedules.
(a) List the following documents filed as a part of the report:
(b) Exhibits
The following exhibits are incorporated by reference into the filing indicated or are filed herewith.
*
Management employment agreements, compensatory arrangements or option plans
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized
COMPLETE PRODUCTION SERVICES, INC.
By:
/s/ JOSEPH C. WINKLER
Name: Joseph C. Winkler
Title:
Chief Executive Officer
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Joseph C. Winkler and Jose A. Bayardo, and each of them severally, his true and lawful attorney or attorneys-in-fact and agents, with full power to act with or without the others and with full power of substitution and re-substitution, to execute in his name, place and stead, in any and all capacities, any or all amendments to this Annual Report on Form 10-K, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents and each of them, full power and authority to do and perform in the name of on behalf of the undersigned, in any and all capacities, each and every act and thing necessary or desirable to be done in and about the premises, to all intents and purposes and as fully as they might or could do in person, hereby ratifying, approving and confirming all that said attorneys-in-fact and agents or their substitutes may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
EXHIBIT INDEX
*
Management employment agreements, compensatory arrangements or option plans