Item 1.
Business
Our Company
We are a Delaware corporation formed in 2005 to serve as the parent holding company for an oilfield services business operating under the Superior Well Services name since 1997. In August 2005, we completed our initial public offering of 6,460,000 shares of common stock at a price of $13.00 per share.
We provide a wide range of wellsite solutions to oil and natural gas companies, primarily technical pumping services and down-hole surveying services. We focus on offering technologically advanced equipment and services at competitive prices, which we believe allows us to successfully compete against both major oilfield services companies and smaller, independent service providers.
We identify and pursue markets where we can capitalize on our competitive advantages to establish a significant market presence. Since 1997, our operations have expanded from two service centers in the Appalachian region to 13 service centers providing coverage across 37 states, including our four newest service centers in Utah, Louisiana, Arkansas and Michigan that we opened in 2005. Our customer base has grown from 89 customers in 1999 to over 600 customers today. The majority of our customers are regional, independent oil and natural gas companies. We serve these customers in key markets in many of the active domestic oil and natural gas producing regions, including the Appalachian, Mid-Continent, Rocky Mountain and Southeast regions.
Our Business Strategy
We intend to grow our revenue and profitability by pursuing the following business strategies:
Expand Our Operations and Market Presence. Our growth strategy is to expand on operations by leveraging our solid relationships with existing customers. We intend to continue to establish new service centers as our customers invite us into existing markets and expand their operations into new markets. We further intend to selectively pursue acquisitions of other oilfield services providers that complement our existing operations or allow us to enter new markets. We also expand our operations by hiring qualified personnel in new markets where we can capitalize on our competitive strengths.
Emphasize Our High Value, Single Source Approach. We create value for our customers by developing and offering technologically advanced fluids, equipment and technical pumping and down-hole surveying services comparable to major oilfield services providers, but typically at lower prices than those offered by our larger competitors. We believe our ability to provide multiple services also creates an advantage over our smaller independent competitors by providing customers with a single source for a wide range of oilfield services.
Pursue Customers Requiring Advanced Fluid Technology for Higher Pressure Stimulation. We plan to pursue additional customers whose stimulation services projects require advanced fluid technology at relatively high pressures (8,000 to 10,000 psi). We typically realize increased revenue and higher margins from these high-pressure projects. We currently serve these types of customers in Mississippi and Oklahoma and plan to pursue similar customers in our higher growth markets in East Texas, northern Louisiana and the Rocky Mountain region through our new service centers in Utah and Louisiana.
Maintain Our Streamlined Management Structure. Our management structure is designed to give our field level managers responsibility for the sales and marketing of our equipment and services and our central management team responsibility for strategic and logistical decisions. Our field level managers have significant local knowledge of our numerous operating areas and have developed strong relationships with our customers at the field level. We intend to maintain this streamlined management structure because the majority of our customers’ purchasing decisions are typically made at the field level and are often influenced by the strength of existing relationships. We also believe this structure allows us to be more responsive to
customer needs than our larger competitors, which typically have a more layered and complex management structure.
Emphasize Highly Responsive Customer Service. Our emphasis on highly responsive customer service has been an integral part of our growth and success. We locate our service centers near our customers to allow us to handle short lead-time projects. In addition, our experienced employees have the technological expertise to understand our customers’ needs and provide specialized equipment and services packages. We plan to continue to leverage our reputation for highly responsive customer service both to attract new customers and enhance the solid and long-standing relationships we have with our existing customers.
Our Services and Products
Technical Pumping Services
We offer three types of technical pumping services - stimulation, nitrogen and cementing - which accounted for 55.3%, 13.4% and 21.8% of our revenue for the year ended December 31, 2005 and 52.4%, 16.7% and 20.5% of our revenue for the year ended December 31, 2004, respectively. As of December 31, 2005, we owned a fleet of 345 commercial vehicles through which we provided our technical pumping services.
Stimulation Services. Our fluid-based stimulation services include fracturing and acidizing, which are designed to improve the flow of oil and natural gas from producing zones. Fracturing services are performed to enhance the production of oil and natural gas from formations with low permeability, which restricts the natural flow of the formation. The fracturing process consists of pumping a fluid gel into a cased well at sufficient pressure to fracture the formation. A proppant, typically sand, which is suspended in the gel is pumped into the fracture to prop it open. The size of a fracturing job is generally expressed in terms of pounds of proppant. The main pieces of equipment used in the fracturing process are the blender, which blends the proppant into the fracturing fluid, and the pumping unit, which is capable of pumping significant volumes at high pressures. Our fracturing pump units are capable of pumping slurries at pressures of up to 10,000 pounds per square inch, or psi, at rates of up to 100 barrels per minute.
Acidizing services are performed to enhance the flow rate of oil and natural gas from wells with reduced flow caused by limestone and other materials that block the formation. Acidizing entails pumping large volumes of specially formulated acids into a carbonate formation to dissolve barriers and enlarge crevices in the formation, thereby eliminating obstacles to the flow of oil and natural gas. We own and operate a fleet of mobile acid transport and pumping units to provide acidizing services.
Our fluid technology expertise and specialized equipment has enabled us to provide stimulation services with relatively high pressures (8,000 to 10,000 psi) that many of our smaller independent competitors currently do not offer. For these higher pressure projects, we typically arrange with third-party, independent laboratories to optimize and verify our fluid composition as part of our pre-job approval process. We currently have 18 stimulation crews of approximately six to 20 employees each and a fleet of 242 vehicles, including 98 high-tech, customized pump trucks, blenders and frac vans for use in our fluid-based stimulation services. We provide basic stimulation services from ten different service centers: Black Lick, Pennsylvania; Bradford, Pennsylvania; Kimball, West Virginia; Columbia, Mississippi; Cleveland, Oklahoma; Vernal, Utah; Cottondale, Alabama; Gaylord, Michigan; Van Buren, Arkansas; and Bossier City, Louisiana.
Nitrogen Services. In addition to our fluid-based stimulation services, we also use nitrogen, an inert gas, to stimulate wellbores. Our foam-based nitrogen stimulation services accounted for substantially all of our total nitrogen services revenue in 2005. Our customers use foam-based nitrogen stimulation when the use of fluid-based fracturing or acidizing could result in damage to oil and natural gas producing zones or in low pressure zones where such fluid-based treatment would not be effective. Liquid nitrogen is transported to the jobsite in truck mounted insulated storage vessels. The liquid nitrogen is then pumped under pressure via a high pressure pump into a heat exchanger, which converts the liquid to a gas at the desired discharge temperature. In addition, we use nitrogen to foam cement slurries and to purge and test pipelines, boilers and pressure vessels.
We currently have six nitrogen crews of approximately three to four employees each and a fleet of 19 nitrogen pump trucks and 14 nitrogen transport vehicles. We provide nitrogen services from our Mercer, Pennsylvania, Cleveland, Oklahoma, Gaylord Michigan, Kimball, West Virginia and Cottondale, Alabama service centers.
Cementing Services. Our cementing services consist of blending high-grade cement and water with various solid and liquid additives to create a cement slurry. The additives and the properties of the slurry are designed to ensure the proper pump time, compression strength and fluid loss control and vary depending on the well depth, down-hole temperatures and pressures and formation characteristics. We have developed a series of proprietary slurry blends. Our field engineers develop job design recommendations to achieve desired porosity and bonding characteristics. We contract with independent, third party regional laboratories to provide testing services to evaluate our slurry properties, which vary with cement supplier and local water properties.
Once blended, this cement slurry is pumped through the well casing into the void between the casing and the bore hole. There are a number of specific applications for cementing services. The principal application is the cementing behind the casing pipe and the wellbore during the drilling and completion phase of a well. This is known as primary cementing. Primary cementing is performed to (i) isolate fluids between the casing and productive formations and other formations that would damage the productivity of hydrocarbon producing zones or damage the quality of freshwater aquifers, (ii) seal the casing from corrosive formation fluids and (iii) provide structural support for the casing string. Cementing services are also used when recompleting wells from one producing zone to another and when plugging and abandoning wells.
As a complement to our cementing services, we also sell casing attachments such as baffle plates, centralizers, float shoes, guide shoes, formation packer shoes, rubber plugs and wooden plugs. After installation of the tubulars being cemented, casing attachments are used to achieve the correct placement of cement slurries in the wellbore. Accordingly, our casing attachments are complementary to, and often bundled with, our cementing services as customers prefer the convenience and efficiencies of sourcing from a single provider. Sales of casing attachments accounted for approximately 1% of our total revenue in 2005.
We currently have 31 cementing crews of approximately three to four employees each and a fleet of 70 cement trucks. We provide cementing services from nine different service centers: Black Lick, Pennsylvania; Bradford, Pennsylvania; Kimball, West Virginia; Cleveland, Oklahoma; Columbia, Mississippi; Cottondale, Alabama; Gaylord, Michigan; Van Buren, Arkansas; and Bossier City, Louisiana.
Down-Hole Surveying Services
We offer two types of down-hole surveying services - logging and perforating. As of December 31, 2005, we owned a fleet of 41 logging and perforating trucks and cranes through which we provided our down-hole surveying services.
We supply wireline logging services primarily to open-hole markets and perforating services to cased-hole markets. Open-hole operations are performed in oil and natural gas wells that are newly drilled. Cased-holes operations are in oil and natural gas wells that have been drilled and cased and are either ready to produce or already producing. These services require skilled operators and typically last for several hours. We purchase our wireline equipment, down-hole tools and data gathering systems from third-parties. Our vendor relationships allow us to concentrate on our operations and limit our costs for research and development.
Logging Services. Our logging services involve the gathering of down-hole information to identify various characteristics of the down-hole rock formations, casing cement bond and mechanical integrity. We lower specialized tools into a wellbore from a truck on an armored electro-mechanical cable, or wireline. These tools communicate across the cable with a truck mounted acquisition unit at the surface that contains considerable instrumentation and computer equipment. The specialized, down-hole tools transmit data to the surface computer, which charts and records down-hole information, that details various characteristics about the formation or zone to be produced, such as rock type, porosity, permeability and the presence of hydrocarbons. We currently have 11 logging crews of approximately two to three employees each and
14 logging trucks and cranes. We provide logging services from four different service centers: Wooster, Ohio; Bradford, Pennsylvania; Black Lick, Pennsylvania; and Hominy, Oklahoma.
Perforating Services. We provide perforating services as the initial step of stimulation by lowering specialized tools and perforating guns into a wellbore by wireline. The specialized tools transmit data to our surface computer to verify the integrity of the cement and position the perforating gun, which fires shaped explosive charges to penetrate the producing zone. Perforating creates a short path between the oil or natural gas reservoir and the wellbore that enables the production of hydrocarbons. In addition, we perform workover services aimed at improving the production rate of existing oil and natural gas wells and by perforating new hydrocarbon bearing zones in a well once a deeper zone or formation has been depleted. We currently have 13 perforating crews of approximately two to four employees each and 27 perforating trucks and cranes. We provide perforating services from five different service centers: Wooster, Ohio; Mercer, Pennsylvania; Black Lick, Pennsylvania; Kimball, West Virginia; and Hominy, Oklahoma.
Competition
Our competition includes small and mid-size independent contractors as well as major oilfield services companies with international operations. We compete with Halliburton Company, Schlumberger Limited, BJ Services Company, RPC, Inc., Weatherford International Ltd., Key Energy Services, Inc. and a number of smaller independent competitors for our technical pumping services. We compete with Schlumberger Limited, Halliburton Company, Precision Drilling Corp., Baker Hughes Incorporated and a number of smaller independent competitors for our down-hole surveying services. We believe that the principal competitive factors in the market areas that we serve are price, product and service quality, availability of crews and equipment and technical proficiency.
Customers and Markets
We serve numerous major and independent oil and natural gas companies that are active in our core areas of operations.
The majority of our customers are regional, independent oil and natural gas companies. The following table shows the growth and increasing geographic diversity of our revenue through December 31, 2005:
We commenced operations in the Rocky Mountain region in the first quarter of 2005 by establishing a service center in Vernal, Utah. During the second quarter of 2005, we opened operations in the Appalachian and the Southeast regions by establishing service centers in Gaylord, Michigan and Bossier City, Louisiana, respectively. In the fourth quarter of 2005, we opened operations another Mid-Continent service center located in Van Buren, Arkansas.
During 2005, we provided services to over 600 customers, with our top five customers comprising approximately 40.5% of our total revenue. The following table shows information regarding our top five customers in 2005:
We believe our relationship with these significant customers is good.
Suppliers
We purchase the materials used in our technical pumping services, such as fracturing sand, cement, nitrogen and fracturing and cementing chemicals from various third party and related-party suppliers. Raw materials essential to our business are normally readily available. Where we rely on a single supplier for materials essential to our business, we believe that we will be able to make satisfactory alternative arrangements in the event of interruption of supply. The following table provides key information regarding several of our major materials suppliers:
We purchase the equipment used in our technical pumping services, such as pumpers, blenders, engines and chassis, from various third party suppliers, as shown in the table below:
Other than with respect to nitrogen supplies, we do not have long-term contracts with our suppliers.
Operating Risks and Insurance
Our operations are subject to hazards inherent in the oil and natural gas industry, including accidents, blowouts, explosions, craterings, fires and oil spills and hazardous materials spills. These conditions can cause:
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personal injury or loss of life;
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damage to or destruction of property, equipment, the environment and wildlife; and
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suspension of operations.
In addition, claims for loss of oil and natural 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 us 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 from time to time have suffered accidents in the past and anticipate that we could 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 relationship 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.
We maintain insurance coverage of types and amounts that we believe to be customary in the industry, but we are not fully insured against all risks, either because insurance is not available or because of the high premium costs. We do maintain employer’s liability, pollution, cargo, umbrella, comprehensive commercial general liability, workers’ compensation and limited physical damage insurance. There can be no assurance, however, that any insurance obtained by us will be adequate to cover any losses or liabilities, or that this insurance will 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 materially adverse effect on us.
Safety Program
In the well services industry, an important competitive factor in establishing and maintaining long-term customer relationships is having an experienced and skilled work force. In recent years, many of our larger customers have placed an emphasis not only on pricing, but also on safety records and quality management systems of contractors. We believe that these factors will gain further importance in the future. We have directed substantial resources toward employee safety and quality management training programs, as well as our employee review process. While our efforts in these areas are not unique, many competitors, particularly small contractors, have not undertaken similar or as extensive training programs for their employees.
Environmental Regulation
Our business is subject to stringent and comprehensive federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. Federal and state governmental agencies issue regulations to implement and enforce these laws, which are often difficult and costly to comply with. Failure to comply with these laws and regulations often carries substantial administrative, civil and criminal penalties and may result in the issuance of injunctions limiting or prohibiting our operations. Some laws and regulations relating to protection of the environment may, in some circumstances, impose joint and several, strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of that person. Strict adherence with these regulatory requirements increases our cost of doing business and consequently affects our profitability. We believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a materially adverse effect upon our capital expenditures, earnings or our competitive position.
The Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose strict liability, without regard to fault or the legality of the original conduct on certain classes of persons that are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current owner and operator of the disposal site or sites where the release occurred and companies that transport or disposed or arranged for the
transportation or disposal of the hazardous substances that have been released at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment from properties currently or even previously owned or operated by us as well as from offsite properties where our wastes have been disposed, for damages to natural resources and for the costs of some health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.
The Resource Conservation and Recovery Act, referred to as RCRA, generally does not regulate most wastes generated by the exploration and production of oil and natural gas because that act specifically excludes drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of oil and natural gas from regulation as hazardous waste. However, these wastes may be regulated by the U.S. Environmental Protection Agency, referred to as the EPA, or state environmental agencies as non-hazardous waste. Moreover, in the ordinary course of our operations, industrial wastes such as paint wastes, waste solvents, and laboratory wastes as well as certain wastes generated in the course of providing well services may be regulated as hazardous waste under RCRA or hazardous substances under CERCLA. We currently own or lease, and have in the past owned or leased, a number of properties that for many years have been used for services in support of oil and natural gas exploration and production activities. We have utilized operating and disposal practices that were standard in the industry at the time, but hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, we may own or lease properties that in the past were operated by third parties whose operations were not under our control. Those properties and the hydrocarbons or wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination. We believe that we are in substantial compliance with the requirements of CERCLA and RCRA.
Our operations are subject to the federal Clean Water Act and analogous state laws, which impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States except in accordance with issued permits. Under the Clean Water Act, the EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits or seek coverage under a general permit. Some of our properties may require permits for discharges of storm water runoff and, as part of our overall evaluation of our current operations, we are, as may be necessary, applying for stormwater discharge permit coverage and updating stormwater discharge management practices at some of our facilities. We believe that we will be able to obtain, or be included under, these permits, where necessary, and make minor modifications to existing facilities and operations that would not have a material effect on us.
The federal Clean Water Act and the federal Oil Pollution Act of 1990, which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States, require some owners or operators of facilities that store or otherwise handle oil to prepare and implement spill prevention, control, countermeasure and response plans relating to the possible discharge of oil into surface waters. We believe we are in substantial compliance with these regulations.
Our down-hole surveying operations use densitometers containing sealed, low-grade radioactive sources such as Cesium-137 that aid in determining the density of down-hole cement slurries, waters, and sands as well as help evaluate the porosity of specified subsurface formations. Our activities involving the use of densitometers are regulated by the U.S. Nuclear Regulatory Commission and specified agencies of applicable agreement states that work cooperatively in implementing the federal regulations. In addition, our down-hole surveying services involve the use of explosive charges that are regulated by the U.S. Department of Justice, Bureau of Alcohol, Tobacco, Firearms, and Explosives. Standards implemented by these regulatory agencies require us to obtain licenses or other approvals for the use of such densitometers as well as explosive charges. We have obtained these licenses and approvals when necessary and believe that we are in substantial compliance with these federal requirements.
We maintain insurance against some risks associated with underground contamination that may occur as a result of well services activities. However, this insurance is limited to activities at the wellsite and may not continue to be available or may not be available at premium levels that justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.
We are also subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.
Employees
As of December 31, 2005, we employed 646 people, with approximately 75% employed on an hourly basis. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements, and we consider our relations with our employees to be satisfactory.
Item 1A
Item 1A - Risk Factors
Risks Related to Our Business and Our Industry
Our business depends on domestic spending by the oil and natural gas industry, and this spending and our business 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, develop and produce oil and natural gas in the United States. Industry conditions are influenced by numerous factors over which we have no control, such as:
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the supply of and demand for oil and natural gas and related products;
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domestic and worldwide economic conditions;
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political instability in oil producing countries;
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price of foreign imports of oil and natural gas, including liquefied natural gas;
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substantial lead times on our capital expenditures;
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weather conditions;
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technical advances affecting energy consumption;
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the price and availability of alternative fuels; and
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merger and divestiture activity among oil and natural gas producers.
The volatility of the oil and natural gas industry and the consequent impact on exploration and production activity could adversely impact the level of drilling and workover activity by some of our customers. This reduction may cause a decline in the demand for our services or adversely affect the price of our services. In addition, reduced discovery rates of new oil and natural gas reserves in our market areas may have a negative long-term impact on our business, even in an environment of stronger oil and natural gas prices, to the extent existing production is not replaced and the number of producing wells for us to service declines. We cannot predict the future level of demand for our services, future crude oil and natural gas commodity prices or future conditions of the well services industry.
A decline in or substantial volatility of crude oil and natural gas commodity prices could adversely affect the demand for our services.
The demand for our services is substantially influenced by current and anticipated crude oil and natural gas commodity prices and the related level of drilling activity and general production spending in the areas in which we have operations. Volatility or weakness in crude oil and natural gas commodity prices (or the perception that crude oil and natural gas commodity prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower production spending for existing wells. This, in turn, could result in lower demand for our services as the products and services we provide are, to a substantial extent, deferrable in the event oil and natural gas companies reduce capital expenditures. As a result, we may experience lower utilization of, and may be forced to lower our rates for, our equipment and services. A decline in crude oil and natural gas commodity prices or a reduction in drilling or production activities could materially adversely affect the demand for our services and our results of operations.
Historical prices for crude oil and natural gas have been extremely volatile and are expected to continue to be volatile. For example, since 1999, oil prices have ranged from as low as approximately $10 per barrel to over $60 per barrel. Producers may reduce expenditures in reaction to declining crude oil and natural gas commodity prices. This has in the past and may in the future adversely affect our business. A prolonged low level of activity in the oil and natural gas industry will adversely affect the demand for our products and services and our financial condition and results of operations.
We may incur substantial indebtedness or issue additional equity securities to finance future acquisitions, which may reduce our profitability and result in significant dilution to our stockholders. We may not be able to effectively integrate the businesses we do acquire, which may result in unforeseen operational difficulties and diminished financial performance.
Our business strategy has included, and will continue to include, growth through the acquisitions of other businesses. We may not be able to continue to identify attractive acquisition opportunities or successfully acquire identified targets on terms favorable to us. Competition for acquisition opportunities may escalate, increasing our cost of making further acquisitions or causing us to refrain from making additional acquisitions. We may be required to incur substantial indebtedness to finance future acquisitions and also may issue equity securities in connection with such acquisitions. Such additional debt service requirements may impose a significant burden on our results of operations and financial condition. The issuance of additional equity securities could result in significant dilution to our stockholders. In addition, we may not be successful in integrating our current or future acquisitions into our existing operations, which may result in unforeseen operational difficulties or diminished financial performance, or require a disproportionate amount of our management’s attention.
If we do not manage the potential difficulties associated with rapid expansion successfully, our operating results could be adversely affected.
We have grown rapidly over the last several years through internal growth and acquisitions of other businesses and assets. We believe our future success depends in part on our ability to manage the rapid growth we have experienced and the demands from increased responsibility on our management personnel. The following factors could present difficulties to us:
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lack of sufficient experienced management personnel;
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increased administrative burden; and
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increased logistical problems common to large, expansive operations.
If we do not manage these potential difficulties successfully, our operating results could be adversely affected. In addition, we may have difficulties managing the increased costs associated with our growth, which could adversely affect our operating margins. The historical financial information incorporated herein is not necessarily indicative of the results that we would have achieved had we operated under a fully integrated corporate structure or the results that we may realize in the future.
In order to execute our growth strategy, we may require additional capital in the future, which may not be available to us.
Our business is capital intensive with long lead times required to fabricate the equipment. To the extent we do not generate sufficient cash from operations, we may need to raise additional funds through public or private debt or equity financings to execute our growth strategy. Adequate sources of capital funding may not be available when needed or may not be available on favorable terms. If we raise additional funds by issuing equity securities, dilution to the holdings of existing stockholders may result. If funding is insufficient at any time in the future, we may be unable to fund maintenance requirements, acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could harm our business.
We depend on a relatively small number of customers for a substantial portion of our revenue. The inability of one or more of our customers to meet their obligations or the loss of our business with Atlas America, Inc. or GeoMet Operating Company, in particular, may adversely affect our financial results.
We derive a significant amount of our revenue from a relatively small number of independent oil and natural gas companies. In 2005 and 2004, eight companies accounted for 51% and 55% of our revenue, respectively. Our inability to continue to provide services to these key customers, if not offset by additional sales to our customers, could adversely affect our financial condition and results of operations. Moreover, the revenue we derived from our contracts with Atlas America, Inc. and Chesapeake Energy Corp., constituted approximately 17.6% and 8.6%, respectively of our total revenue for the year ended December 31, 2005. These companies may not provide the same level of our revenue in the future for a variety of reasons including, their lack of funding, a strategic shift on their part in moving to different geographic areas in which we do not operate or our failure to meet their performance criteria. The loss of all or a significant part of this revenue would adversely affect our financial condition and results of operations.
This concentration of customers may impact our overall exposure to credit risk in that customers may be similarly affected by changes in economic and industry condition. We do not generally require collateral in support of our trade receivables.
The loss of or interruption in operations of one or more of our key suppliers could have a material adverse effect on our operations.
Our reliance on outside suppliers for some of the key materials and equipment we use in providing our services involves risks, including limited control over the price, timely delivery and quality of such materials or equipment.
With the exception of our contract with our largest supplier of nitrogen, we have no written contracts with our suppliers to ensure the continued supply of materials. Historically, we have placed capital expenditure orders with our suppliers for periods of less than one year. Any required changes in our suppliers could cause material delays in our operations and increase our costs. In addition, our suppliers may not be able to meet our future demands as to volume, quality or timeliness. Our inability to obtain timely delivery of key materials or equipment of acceptable quality or any significant increases in prices of materials or equipment could result in material operational delays, increase our operating costs, limit our ability to service our customers’ wells or materially and adversely affect our business and operating results.
Competition within the oilfield services industry may adversely affect our ability to market our services.
The oilfield services industry is highly competitive and fragmented and includes several large companies that compete in many of the markets we serve, as well as numerous small companies that compete with us on a local basis. Our larger competitors’ greater resources could allow them to better withstand industry downturns, compete more effectively on the basis of technology and geographic scope and retain skilled personnel. We believe the principal competitive factors in the market areas we serve are price, product and service quality, availability of crews and equipment and technical proficiency. Our operations may be adversely affected if our current competitors or new market entrants introduce new products or services with better features, performance, prices or other characteristics than our products and services or expand into
service areas where we operate. Competitive pressures or other factors also may result in significant price competition, particularly during industry downturns, which could have a material adverse effect on our results of operations and financial condition. In addition, competition among oilfield services and equipment providers is affected by each provider’s reputation for safety and quality.
We may not be able to keep pace with the continual and rapid technological developments that characterize the market for our services, and our failure to do so may result in our loss of market share.
The market for our services is characterized by continual and rapid technological developments that have resulted in, and will likely continue to result in, substantial improvements in equipment functions and performance. As a result, our future success and profitability will be dependent in part upon our ability to:
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improve our existing services and related equipment;
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address the increasingly sophisticated needs of our customers; and
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anticipate changes in technology and industry standards and respond to technological developments on a timely basis.
If we are not successful in acquiring new equipment or upgrading our existing equipment on a timely and cost-effective basis in response to technological developments or changes in standards in our industry, we could lose market share. In addition, current competitors or new market entrants may develop new technologies, services or standards that could render some of our services or equipment obsolete, which could have a material adverse effect on our operations.
Our industry has recently experienced shortages in the availability of qualified field personnel. Any difficulty we experience replacing or adding qualified field personnel could adversely affect our business.
We may not be able to find enough skilled labor to meet our employment needs, which could limit our growth. There is currently a reduced pool of qualified workers in our industry due to increased activity in the oilfield services and commercial trucking sectors. Therefore, we may have problems finding enough skilled and unskilled laborers in the future if the demand for our services increases. In that event, it is possible that we will have to raise wage rates to attract and train workers from other fields in order to retain or expand our current work force. If we are not able to increase our service rates sufficiently to compensate for wage rate increases, our operating results may be adversely affected.
Other factors may also limit our ability to find enough workers to meet our employment needs. Our services are performed by licensed commercial truck drivers and equipment operators who must perform physically demanding work. As a result of our industry volatility and the demanding nature of the work, workers may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive with ours. We believe that our success is dependent upon our ability to continue to employ, train and retain skilled technical personnel. Our inability to accomplish this task generally could have a material adverse effect on our operations.
The loss of key members of our management or the failure to attract and motivate key personnel could have an adverse effect on our business, financial condition and results of operations.
We depend to a large extent on the services of some of our executive officers and directors. The loss of the services of David E. Wallace, our Chief Executive Officer, Jacob B. Linaberger, our President, Rhys R. Reese, an Executive Vice President and our Chief Operating Officer, and other key personnel, or the failure to attract and motivate key personnel, could have an adverse effect on our business, financial condition and results of operations. We have entered into employment agreements with Messrs. Wallace, Reese and Linaberger that contain non-compete agreements. Notwithstanding these agreements, we may not be able to retain our executive officers and may not be able to enforce all of the provisions in the employment agreements. We do not maintain key person life insurance on the lives of any of our executive officers or directors. The death or disability of any of our executive officers or directors may adversely affect our operations.
Our operations are subject to inherent risks, some of which are beyond our control, and these risks may not be fully covered under our insurance policies. The occurrence of a significant event that is not covered by insurance could have a material adverse effect on our financial condition and results of operations.
Our operations are subject to hazards inherent in the oil and natural gas industry, such as, but not limited to, accidents, blowouts, explosions, craterings, fires, oil spills and hazardous materials spills. These conditions can cause:
•
personal injury or loss of life;
•
damage to or destruction of property, equipment, the environment and wildlife; and
•
suspension of operations.
The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our financial condition and results of operations. In addition, claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a wellsite location where our equipment and services are being used may result in us being named as a defendant in lawsuits asserting large claims. The frequency and severity of such incidents affect our operating costs, insurability and relationships with customers, employees and regulators. Any increase in the frequency or severity of such incidents could affect our ability to obtain projects from oil and natural gas companies.
We do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. In addition, we are subject to various self-retentions and deductibles under our insurance policies. The occurrence of an event not fully insured against, or the failure of an insurer to meet its insurance obligations, could result in substantial losses. We also may not be able to maintain adequate insurance in the future at rates we consider reasonable, and insurance may not be available to cover any or all of these risks, or, even if available, that it will be adequate or that insurance premiums or other costs will not rise significantly in the future, so as to make such insurance cost prohibitive. In addition, our insurance is subject to coverage limits and some policies exclude coverage for damages resulting from environmental contamination. See “Business - Operating Risks and Insurance”.
We are subject to federal, state and local regulation regarding issues of health, safety and protection of the environment. Under these regulations, we may become liable for penalties, damages or costs of remediation. Any changes in laws and government regulations could increase our costs of doing business.
Our operations are subject to federal, state and local laws and regulations relating to protection of natural resources and the environment, health and safety, waste management, and transportation of waste and other substances. Liability under these laws and regulations could result in cancellation of well operations, fines and penalties, expenditures for remediation, and liability for property damages and personal injuries. Sanctions for noncompliance with applicable environmental laws and regulations also may include assessment of administrative, civil and criminal penalties, revocation of permits and issuance of corrective action orders. In addition, the oil and natural gas operations of our customers and therefore our operations, particularly in the Rocky Mountain region, are limited by lease stipulations designed to protect various wildlife.
Our down-hole surveying operations use densitometers containing sealed, low-grade radioactive sources such as Cesium-137 that aid in determining the density of down-hole cement slurries, waters, and sands as well as help evaluate the porosity of specified subsurface formations. Our activities involving the use of densitometers are regulated by the U.S. Nuclear Regulatory Commission and specified agencies of applicable agreement states that work cooperatively in implementing the federal regulations. In addition, our down-hole surveying operations involve the use of explosive charges that are regulated by the U.S. Department of Justice, Bureau of Alcohol, Tobacco, Firearms, and Explosives. Standards implemented by these regulatory agencies require us to obtain licenses or other approvals for the use of such densitometers as well as explosive charges.
Laws protecting the environment generally have become more stringent over time and are expected to continue to do so, which could lead to material increases in costs for future environmental compliance and remediation. The modification or interpretation of existing laws or regulations, or the adoption of new laws or regulations, could curtail exploratory or developmental drilling for oil and natural gas and could limit our well services opportunities. Some environmental laws and regulations may impose strict liability, which means that in some situations we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or due to the conduct of, or conditions caused by, prior operators or other third parties. Clean-up costs and other damages arising as a result of environmental laws and regulations, and costs associated with changes in such laws and regulations could be substantial and could have a material adverse effect on our financial condition. Please read “Business - Environmental Regulation” for more information on the environmental laws and government regulations that are applicable to us.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common stock.
Effective internal controls are necessary for us to provide reliable financial reports and effectively prevent fraud and to operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. Our efforts to develop and maintain our 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 develop or maintain effective controls, or difficulties encountered in their implementation or other effective improvement of our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock.
We are a holding company, with no revenue generating operations of our own. Any restrictions on our subsidiaries’ ability to make distributions to us would materially impact our financial condition or our ability to service our obligations.
We are a holding company with no business operations, sources of income, indebtedness or assets of our own other than our ownership interests in our subsidiaries. Because all our operations are conducted by our subsidiaries, our cash flow and our ability to repay our debt is dependent upon cash dividends and distributions or other transfers from our subsidiaries. Payment of dividends, distributions, loans or advances by our subsidiaries to us will be subject to restrictions imposed by the current and future debt instruments of our subsidiaries.
Our subsidiaries are separate and distinct legal entities. Any right that we will have to receive any assets of or distributions from any of our subsidiaries upon the bankruptcy, dissolution, liquidation or reorganization of any such subsidiary, or to realize proceeds from the sale of their assets, will be junior to the claims of that subsidiary’s creditors, including trade creditors and holders of debt issued by that subsidiary.
Our indebtedness could restrict our operations and make us more vulnerable to adverse economic conditions.
As of December 31, 2005, our total debt on a combined basis was $1.4 million. Our total debt could increase, as we have a total borrowing capacity of $20 million under our credit facilities, of which $20 million was available as of December 31, 2005. Our revolving credit facility requires us to maintain certain financial ratios and satisfy certain financial conditions and limits our ability to take various actions, such as incurring additional indebtedness, purchasing assets and merging or consolidating with other entities.
Our overall level of indebtedness could have important consequences. For example, it could:
•
impair our ability to make investments and obtain additional financing for working capital, capital expenditures, acquisitions or other general corporate purposes;
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limit our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make principal and interest payments on our indebtedness;
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limit our ability to borrow funds that may be necessary to operate or expand our business;
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put us at a competitive disadvantage to competitors that have less debt;
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increase our vulnerability to interest rate increases; and
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hinder our ability to adjust to rapidly changing economic and industry conditions.
Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Description of Our Indebtedness” for a discussion of our credit facilities.
Unionization efforts could increase our costs or limit our flexibility.
Presently, none of our employees work under collective bargaining agreements. Unionization efforts have been made from time to time within our industry, to varying degrees of success. Any such unionization could increase our costs or limit our flexibility.
Severe weather could have a material adverse impact on our business.
Our business could be materially and adversely affected by severe weather. Repercussions of severe weather conditions may include:
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curtailment of services;
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weather-related damage to equipment resulting in suspension of operations;
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weather-related damage to our facilities;
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inability to deliver materials to jobsites in accordance with contract schedules; and
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loss of productivity.
In addition, oil and natural gas operations of potential customers located in the Appalachian, Mid-Continent and Rocky Mountain regions of the United States can be adversely affected by seasonal weather conditions, primarily in the spring. Many municipalities impose weight restrictions on the paved roads that lead to our jobsites due to the muddy conditions caused by spring thaws. This can limit our access to these jobsites and our ability to service wells in these areas. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs in those regions.
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflict involving the United States may adversely affect the U.S. and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur or escalate, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenue. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to customer’s operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
Item 2.
Item 2.
Properties
Our principal executive offices are located at 1380 Rt. 286 East, Suite #121, Indiana, Pennsylvania 15701. We purchased the building that houses our principal executive offices in April 2005. We currently conduct our business from 13 service centers, two of which we own and eleven of which we lease. Each office typically includes a yard, administrative office and maintenance facility. Our 13 service centers are located in Bradford, Black Lick and Mercer, Pennsylvania; Wooster, Ohio; Columbia, Mississippi; Kimball, West Virginia; Cottondale, Alabama; Vernal, Utah; Hominy and Cleveland, Oklahoma; Bossier City, Louisiana; Van Buren, Arkansas; and Gaylord, Michigan. We believe that our leased and owned properties are adequate for our current needs.
The following table sets forth the location of each service center lease, the expiration date of each lease, whether each lease is renewable at our sole option and whether we have an option to purchase the leased property:
(1)
The lease is month-to-month.
Item 3.
Item 3.
Legal Proceedings
We are named as a defendant, from time to time, in litigation relating to our normal business operations. Our management is not aware of any significant pending litigation that would have a material adverse effect on our financial position or results of operations.
Item 4.
Item 4.
Submission of Matters to a Vote of Security Holders
None
PART II
Item 5.
Item 5.
Market for the Registrant’s Common Equity and Related Stockholder Matters
Market Information for Common Stock
Our common stock is traded on the Nasdaq National Market under the symbol “SWSI.” The following table sets forth, for the quarterly periods indicated, the high and low sales prices for our common stock as reported on the Nasdaq National Market during 2005. Shares of our common stock were not publicly traded prior to July 29, 2005.
As of February 14, 2006, there were over 29 holders of the common stock.
(1)
Covers the period from July 29, 2005 through September 30, 2005.
Dividend Policy
We have not declared or paid any dividends on our common stock, and we do not currently anticipate paying any dividends on our common stock in the foreseeable future. Instead, we currently intend to retain all future earnings to fund the development and growth of our business. Any future determination relating to our dividend policy will be at the discretion of our board of directors and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table sets forth certain information with respect to our equity compensation plans as of December 31, 2005:
EQUITY COMPENSATION PLAN INFORMATION
(1)
Excludes securities to be issued upon the exercise of outstanding options, warrants and rights.
(2)
Includes options and restricted stock awards granted under the 2005 Stock Incentive Plan which is further described in footnote 10 to our audited financial statements.
Purchases of Equity Securities By the Issuer and Affiliated Purchases
We have not purchased any of our securities during the last fiscal quarter.
Item 6.
Item 6.
Selected Financial Data
The selected consolidated financial information contained below is derived from our Consolidated Financial Statements and should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our audited consolidated financial statements.
(1)
Historically, we were not subject to federal or state income taxes due to the partnership structure. Pro forma income tax expense (unaudited) has been computed at statutory rates to reflect the pro forma effect on net income for periods prior to our holding company restructuring.
(2)
Share and per share data have been retroactively restated to reflect our holding company restructuring in connection with our initial public offering in August 2005. For the calculations of earnings per share for the years ended December 31, 2001 through 2004, all shares are assumed to have been issued at the beginning of the period resulting in 19,376,667 average shares outstanding.
(3)
We define EBITDA as earnings (net income) before interest expense, income tax expense and depreciation and amortization This term, as we define it, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. EBITDA should not be considered in isolation or as a substitute for operating income, net income, cash flows provided by operating, investing and financing activities or other income or cash flow statement data prepared in accordance with GAAP. Our management uses EBITDA:
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as a measure of operating performance because it assists us in comparing our performance on a consistent basis, since it removes the impact of our capital structure and asset base from our operating results;
•
as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations;
•
to assess compliance with financial ratios and covenants included in credit facilities;
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in communications with lenders concerning our financial performance; and
•
to evaluate the viability of potential acquisitions and overall rates of return.
The following table presents a reconciliation of EBITDA with our net income for each of the periods indicated:
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 the consolidated financial statements and notes thereto included elsewhere in this report. This discussion contains forward-looking statement that reflect management’s current views with respect to future events and financial performance. Our actual results may differ materially form those anticipated in these forward-looking statements or as a result of certain factors such as those set forth below under “Forward-Looking Statements.”
Overview
We are a Delaware corporation formed in 2005 to serve as the parent holding company for an oilfield services business operating under the Superior Well Services name since 1997 in many of the major oil and natural gas producing regions in the Appalachian, Mid-Continent, Rocky Mountain and Southeast regions of the United States. In August 2005, we completed our initial public offering of 6,460,000 shares of common stock at a price of $13.00 per share. We provide a wide range of wellsite solutions to oil and natural gas companies, primarily technical pumping services and down-hole surveying services. We focus on offering technologically advanced equipment and services at competitive prices, which we believe allows us to successfully compete against both major oilfield services companies and smaller, independent service providers.
We derive our revenue from two primary categories of services - technical pumping services and down-hole surveying services. Substantially all of our customers are domestic oil and natural gas exploration and production companies that typically require both types of services in their operations. Our operating revenue from these operations, and their relative percentages of our total revenue, consisted of the following (dollars in thousands):
The following is a brief description of our services:
Technical Pumping Services
We offer three types of technical pumping services - stimulation, nitrogen and
cementing - which accounted for 55.3%, 13.4% and 21.8% of our revenue for the year ended December 31, 2005 and 52.4%, 16.7% and 20.5% of our revenue for the year ended December 31, 2004, respectively. Our fluid-based stimulation services include fracturing and acidizing, which are designed to improve the flow of oil and natural gas from producing zones. In addition to our fluid-based stimulation services, we also use nitrogen to stimulate wellbores. Our foam-based nitrogen stimulation services accounted for substantially all of our total nitrogen services revenue in 2005. Our cementing services consist of blending high-grade cement and water with various additives to create a cement slurry that is pumped through the well casing into the void between the casing and the bore hole. Once the slurry hardens, the cement isolates fluids and gases, which protects the casing from corrosion, holds the well casing in place and controls the well.
Down-Hole Surveying Services
We offer two types of down-hole surveying services - logging and perforating - which collectively accounted for approximately 9.5% and 10.4% of our revenues for years ended December 31, 2005 and 2004. Our logging services involve the gathering of down-hole information through the use of specialized tools that are lowered into a wellbore from a truck. An armored electro-mechanical cable, or wireline, is used to transmit
data to our surface computer that records various characteristics about the formation or zone to be produced. We provide perforating services as the initial step of stimulation by lowering specialized tools and perforating guns into a wellbore by wireline. The specialized tools transmit data to our surface computer to verify the integrity of the cement and position the perforating gun, which flres shaped explosive charges to penetrate the producing zone to create a short path between the oil or natural gas reservoir and the production tubing to enable the production of hydrocarbons. In addition, we also perform workover services aimed at improving the production rate of existing oil and natural gas wells, including perforating new hydrocarbon bearing zones in a well once a deeper zone or formation has been depleted.
How We Generate Our Revenue
The majority of our customers are regional, independent oil and natural gas companies. The primary factor influencing demand for our services by those customers is their level of drilling activity, which, in turn, depends primarily on current and anticipated future crude oil and natural gas commodity prices and production depletion rates.
We generate revenue from our technical pumping services and down-hole surveying services by charging our customers a set-up charge plus an hourly rate based on the type of equipment used. The set-up charges and hourly rates are determined by a competitive bid process and depend upon the type of service to be performed, the equipment and personnel required for the particular job and the market conditions in the region in which the service is performed. Each job is given a base time allotment of six hours. We generally charge an increased hourly rate for each hour worked beyond the initial six hour base time allotment. We also charge customers for the materials, such as stimulation fluids, cement and nitrogen, that we use in each job. Material charges include the cost of the materials plus a markup and are based on the actual quantity of materials used.
How We Evaluate Our Operations
Our management uses a variety of financial and operational measurements to analyze the performance of our services. These measurements include the following: (1) operating income per operating region; (2) material and labor expenses as a percentage of revenue; (3) selling, general and administrative expenses as a percentage of revenue; and (4) EBITDA.
Operating Income per Operating Region.
We currently service customers in five operating regions through our 13 service centers. Our Appalachian region service centers are located in Bradford, Black Lick and Mercer, Pennsylvania, Wooster, Ohio, Kimball, West Virginia and Gaylord, Michigan. Our Southeast region service centers are located in Cottondale, Alabama, Columbia, Mississippi and Bossier City, Louisiana. Our Mid-Continent region service centers are located in Hominy, Oklahoma, Cleveland, Oklahoma and Van Buren, Arkansas. Our Rocky Mountain region service center is located in Vernal, Utah.
The operating income generated in each of our operating regions is an important part of our operational analysis. We monitor operating income separately for each of our operating regions and analyze trends to determine our relative performance in each region. Our analysis enables us to more efficiently allocate our equipment and field personnel among our various operating regions and determine if we need to increase our marketing efforts in a particular region. By comparing our operating income on an operating region basis, we can quickly identify market increases or decreases in the diverse geographic areas in which we operate. It has been our experience that when we establish a new service center in a particular operating region, it may take from 12 to 24 months before that service center has a positive impact on the operating income that we generate in the relevant region.
Material and Labor Expenses as a Percentage of Revenue.
Material and labor expenses are composed primarily of cost of materials, maintenance, fuel and the wages of our field personnel. The cost of these expenses as a percentage of revenue has historically remained relatively stable for our established service centers.
Our material costs primarily include the cost of inventory consumed while performing our stimulation, nitrogen and cementing services. Increases in our material and fuel costs are frequently passed on to our customers. However, due to the timing of our marketing and bidding cycles, there is generally a delay of several weeks or months from the time that we incur an actual price increase until the time that we can pass on that increase to our customers.
Our labor costs consist primarily of wages for our field personnel. As a result of recent shortages of qualified supervision personnel and equipment operators, due to increased activity in the oilfield services and commercial trucking sectors, it is possible that we will have to raise wage rates to attract and train workers from other fields in order to maintain or expand our current work force. We believe we will be able to continue to increase service rates to our customers to compensate for wage rate increases.
Selling, General and Administrative Expenses as a Percentage of Revenue.
Our selling, general and administrative expenses, or SG&A expenses, include fees for management services and administrative, marketing and maintenance employee compensation and related benefits, office and lease expenses, insurance costs and professional fees, as well as other costs and expenses not directly related to field operations. Our management continually evaluates the level of our general and administrative expenses in relation to our revenue because these expenses have a direct impact on our profitability. Our selling, general and administrative expenses have increased as a result of our becoming a public company. For a discussion of the increase in costs associated with our public company status, please read “- Items Impacting Comparability of Our Financial Results - Public Company Expenses”.
EBITDA.
We define EBITDA as net income before interest expense, income tax expense and depreciation and amortization expense. Our management uses EBITDA:
•
as a measure of operating performance because it assists us in comparing our performance on a consistent basis, since it removes the impact of our capital structure and asset base from our operating results;
•
as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations;
•
to assess compliance with financial ratios and covenants included in credit facilities;
•
in communications with lenders concerning our financial performance; and
•
to evaluate the viability of potential acquisitions and overall rates of return.
How We Manage Our Operations
Our management team uses a variety of tools to manage our operations. These tools include monitoring: (1) service crew performance; (2) equipment maintenance performance; (3) inventory turnover rates; (4) customer satisfaction; and (5) safety performance.
Service Crew Performance.
We monitor our revenue on a per service crew basis to determine the relative performance of each of our crews. We also measure our activity levels by the total number of jobs completed by each of our crews as well as by each of the trucks in our fleet. We evaluate our crew and fleet utilization levels on a monthly basis, with full utilization deemed to be approximately 24 jobs per month for each of our service crews and approximately
30 jobs per month for each of our trucks. By monitoring the relative performance of each of our service crews, we can more efficiently allocate our personnel and equipment to maximize our overall crew utilization.
Equipment Maintenance Performance.
Preventative maintenance on our equipment is an important factor in our profitability. If our equipment is not maintained properly, our repair costs may increase and, during levels of high activity, our ability to operate efficiently could be significantly diminished due to having trucks and other equipment out of service. Our maintenance crews perform monthly inspections and preventative maintenance on each of our trucks and other mechanical equipment. Our management monitors the performance of our maintenance crews at each of our service centers by monitoring the level of maintenance expenses as a percentage of revenue. A rising level of maintenance expenses as a percentage of revenue at a particular service center can be an early indication that our preventative maintenance schedule is not being followed. In this situation, management can take corrective measures, such as adding additional maintenance personnel to a particular service center to help reduce maintenance expenses as well as ensure that maintenance issues do not interfere with operations.
Inventory Turnover Rates.
The cost of our material inventory represents a significant portion of our cost of revenue from our technical pumping services. As a result, maintaining an optimum level of inventory at each of our service centers is an important factor in managing our operations and the failure to do so can have a material impact on our profitability. The optimum inventory level at any given service center is primarily a function of the level of activity at that service center. Our management continually monitors the inventory turnover rates at each of our service centers and adjusts the frequency of inventory orders as appropriate in order to maintain the optimum level of inventory in light of the activity level at each service center. Because some items of inventory, particularly frac sand, generally have a long lead time from order to delivery, it is important for our management to identify in advance any trends or events with respect to activity levels that may impact future inventory turnover rates.
Customer Satisfaction.
Upon completion of each job, we encourage our customers to complete a “pride in performance survey” that gauges their satisfaction level. The customer evaluates the performance of our service crew under various criteria and comments on their overall satisfaction level. Survey results give our management valuable information from which to identify performance issues and trends. Our management also uses the results of these surveys to evaluate our position relative to our competitors in the various markets in which we operate.
Safety Performance.
Maintaining a strong safety record is a critical component of our operational success. Many of our larger customers have safety history standards we must satisfy before we can perform services for them. We maintain an online safety database that our customers can access to review our historical safety record. Our management also uses this safety database to identify negative trends in operational incidents so that appropriate measures can be taken to maintain a positive safety history.
Our Industry
We provide products and services primarily to domestic onshore oil and natural gas exploration and production companies for use in the drilling and production of oil and natural gas. The main factor influencing demand for well services in our industry is the level of drilling activity by oil and natural gas companies, which, in turn, depends largely on current and anticipated future crude oil and natural gas prices and production depletion rates. Current market indicators suggest an increasing demand for oil and natural gas coupled with a flat or declining production curve, which we believe should result in the continuation of historically high crude oil and natural gas commodity prices. For example, the Energy Information Agency of the U.S. Department of Energy, or EIA, forecasts that U.S. oil and natural gas consumption will increase at an average annual rate
of 1.1% through 2025. Conversely, the EIA estimates that U.S. oil production will decline at an average annual rate of 0.4% and natural gas production will increase at an average annual rate of 0.7%.
We anticipate that oil and natural gas exploration and production companies will continue to respond to sustained increases in demand by expanding their exploration and drilling activities and increasing capital spending. In recent years, much of this expansion has focused on natural gas. According to Baker Hughes rig count data, the average total rig count in the United States increased 50.7% from 918 in 2000 to 1383 in 2005, while the average natural gas rig count increased 64.7% from 720 in 2000 to 1,186 in 2005. While the number of rigs drilling for natural gas has increased by more than 300% since 1996, natural gas production has only increased by approximately 1% over the same period of time. This is largely a function of increasing decline rates for natural gas wells in the United States. We believe that a continued increase in U.S. drilling and workover activity will be required for the natural gas industry to help meet the expected increased demand for natural gas in the United States.
Our Growth Strategy
Our growth strategy contemplates engaging in organic expansion opportunities and, to a lesser extent, complementary acquisitions of other oilfield services businesses. Our organic expansion activities generally consist of establishing service centers in new locations, including purchasing related equipment and hiring experienced local personnel. Historically, many of our customers have asked us to expand our operations into new regions that they enter. Once we establish a new service center, we seek to expand our operations by attracting new customers and hiring additional local personnel.
Our revenues from each operating region, and their relative percentage of our total revenue, consisted of the following (dollars in thousands):
We also pursue selected acquisitions of complementary businesses both in existing operating regions and in new geographic areas in which we do not currently operate. In analyzing a particular acquisition, we consider the operational, financial and strategic benefits of the transaction. Our analysis includes the location of the business, strategic fit of the business in relation to our business strategy, expertise required to manage the business, capital required to integrate and maintain the business, the strength of the customer relationships associated with the business and the competitive environment of the area where the business is located. From a financial perspective, we analyze the rate of return the business will generate under various scenarios, the comparative market parameters applicable to the business and the cash flow capabilities of the business.
To successfully execute our growth strategy, we will require access to capital on competitive terms to the extent that we do not generate sufficient cash from operations. We intend to finance future acquisitions primarily by using capacity available under our bank credit facility and equity or debt offerings or a combination of both. For a more detailed discussion of our capital resources, please read “- Liquidity and Capital Resources”.
Our Results of Operations
Our results of operations are derived primarily by three interrelated variables: (1) market price for the services we provide; (2) drilling activities of our customers; and (3) cost of materials and labor. To a large extent, the pricing environment for our services will dictate our level of profitability. Our pricing is also
dependent upon the prices and market demand for oil and natural gas, which affect the level of demand for, and the pricing of, our services and fluctuates with changes in market and economic condition and other factors. To a lesser extent, seasonality can affect our operations in the Appalachian region and certain parts of the Mid-Continent and Rocky Mountain regions, which may be subject to a brief period of diminished activity during spring thaw due to road restrictions. As our operations have expanded in recent years into new operating regions in warmer climates, this brief period of diminished activity no longer has a significant impact on our overall results of operations.
Our results of operations from our two primary categories of services consisted of the following (amounts in thousands):
Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
Revenue.
Revenue was $131.7 million for the year ended December 31, 2005 compared to $76.0 million for the year ended December 31, 2004, an increase of 73.2%. Increased activity levels and pricing improvement led to the increases in 2005. Revenue by operating region increased in 2005 by $23.3 million, $13.2 million, $14.6 million and $4.6 million in the Appalachian, Southeast, Mid-Continent and Rocky Mountain operating regions, respectively. Approximately $28.7 million was attributable to new service centers. New service center revenue by operating region increased in 2005 by $1.8 million, $7.7 million, $14.5 million and $4.7 million in the Appalachian, Southeast, Mid-Continent and Rocky Mountain operating regions, respectively. New service centers include: Gaylord, MI (Appalachian), Bossier City, LA (Southeast), Columbia, MS (Southeast), Cleveland, OK (Mid-Continent), Van Buren, Arkansas (Mid-Continent) and Vernal, UT (Rocky Mountain). Existing service center revenue by operating region increased in 2005 by $21.4 million, $5.3 million and $0.3 million in the Appalachian, Southeast and Mid-Continent operating regions, respectively.
Revenue from our technical pumping services increased by approximately 74.9% to $119.2 million for the year ended December 31, 2005 from $68.2 million for the year ended December 31, 2004. Approximately $27.1 million was attributable to new service centers. New service center revenue by operating region increased in 2005 by $1.8 million, $7.6 million, $12.9 million and $4.7 million in the Appalachian, Southeast, Mid-Continent and Rocky Mountain operating regions, respectively. Existing service center revenue by operating region increased in 2005 by $18.5 million, $5.3 million and $0.2 million in the Appalachian, Southeast and Mid-Continent operating regions, respectively.
Revenue from our down-hole surveying services increased approximately 58.9% to $12.5 million for the year ended December 31, 2005 from $7.9 million for the year ended December 31, 2004. Revenue by operating region increased in 2005 by $2.9 million and $1.6 million in the Appalachian and Mid-Continent
operating regions, respectively. The Mid-Continent operating region increase was from new service centers and the Appalachian operating increase was from existing service centers.
Cost of Revenue.
Cost of revenue increased 65.8% to $90.3 million for the year ended December 31, 2005 compared to $54.4 million for the year ended December 31, 2004. Approximately $20.3 million was attributable to new service centers. New service center cost of revenue by operating region increased in 2005 by $1.8 million, $4.8 million, $10.3 million and $3.4 million in the Appalachian, Southeast, Mid-Continent and Rocky Mountain operating regions, respectively. As a percentage of revenue, cost of revenue decreased to 68.5% for the year ended December 31, 2005 from 71.6% for the year ended December 31, 2004. This percentage decrease was primarily due to a 3.1% drop in labor expenses as a percentage of revenues in 2005 versus 2004. Labor expenses as a percentage of revenues decreased from 20.4% in 2004 to 17.2% in 2005. Aggregate labor expenses increased $7.2 million to $22.7 million in 2005 due to revenue growth.
Selling, General and Administrative Expenses.
SG&A expenses were $17.8 million for the year ended December 31, 2005 compared to $11.3 million for the year ended December 31, 2004, an increase of 57.1%. We hired additional personnel during 2005 to manage the growth in our operations. As a result of this growth, 2005 expenses for labor, office, transportation, rent and depreciation increased $3.5 million, $0.5 million, $0.4 million, $0.3 million and $0.4 million, respectively. SG&A expense increases related to the new service centers amounted to $1.6 million, $0.3 million, $0.2 million, $0.2 million and $0.4 million for labor, office, transportation, rent and depreciation, respectively. Additionally, legal and professional and franchise tax expenses increased $0.6 million and $0.2 million, respectively. The legal and professional and franchise tax expense increases were associated with going public during 2005. As a percentage of revenue, the portion of labor expenses included in SG&A expenses decreased slightly from 10.1% in 2004 to 8.4% in 2005.
Operating Income.
Operating income was $23.7 million for the year ended December 31, 2005 compared to $10.3 million for the year ended December 31, 2004, an increase of 130.8%. The primary reason for this increase was the increase in drilling activity by our customers in our existing locations, coupled with the establishment and expansion of our operations in new and existing service centers. This increase in operating income was partially offset by the increases in our cost of revenue and SG&A expenses as described above. New service center operating income by operating region increased (decreased) in 2005 by $(0.7) million, $1.2 million, $1.0 million and $0.7 million in the Appalachian, Southeast, Mid-Continent and Rocky Mountain operating regions, respectively. It has been our experience that when we establish a new service center in a particular operating region, it may take from 12 to 24 months before that service center has a positive impact on the operating income that we generate in the relevant region. EBITDA increased $17.4 million in 2005 to $32.6 million. For a definition of EBITDA, a reconciliation of EBITDA to net income and a discussion of EBITDA as a performance measure, please see “Non-GAAP Accounting Measures.” Net income decreased $0.3 million to $9.5 million in 2005 due to a non-cash adjustment of $8.6 million to deferred tax expense to establish deferred tax liabilities that existed at the date of reorganization. Prior to the reorganization, the Partnerships were not subject to federal or state corporate income taxes. Additionally, the statement of operations reflects federal and state income taxes for the five months of operations that occurred after the reorganization.
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Revenue.
Revenue was $76.0 million for the year ended December 31, 2004 compared to $51.5 million for the year ended December 31, 2003, an increase of 47.8%. Increased activity levels and pricing improvement led to the increases in 2004. Approximately $14.7 million of this increase was attributable to an increase in the drilling
activity of our customers in our Appalachian, Southeast and Mid-Continent operating regions. Approximately $4.3 million of this increase was attributable to our establishment of a Southeast region service center located in Columbia, Mississippi, and approximately $4.1 million was attributable to our establishment of an additional Mid-Continent region service center located in Cleveland, Oklahoma. The remaining $1.4 million was attributable to increased activity at our other Mid-Continent region service center located in Hominy, Oklahoma. Revenue by operating region increased in 2004 by $8.6 million, $10.4 million and $5.4 million in the Appalachian, Southeast and Mid-Continent operating regions, respectively.
Revenue from our technical pumping services increased by approximately 47.7% to $68.2 million for the year ended December 31, 2004 from $46.2 million for the year ended December 31, 2003. Approximately $13.6 million of this increase was attributable to an increase in the drilling activity of our existing and new customers in our Appalachian, Southeast and Mid-Continent operating regions. Approximately $4.3 million of this increase was attributable to our establishment of our service center in Columbia, Mississippi, and the remaining $4.1 million was attributable to the establishment of our Cleveland, Oklahoma service center.
Revenue from our down-hole surveying services increased approximately 48.6% to $7.9 million for the year ended December 31, 2004 from $5.3 million for the year ended December 31, 2003. Approximately $1.4 million of this increase was attributable to an expansion of our existing operations at our Hominy service center with the remainder of the increase due to an increase in the drilling activity of our existing and new customers in our Appalachian, Southeast and Mid-Continent operating regions.
Cost of Revenue.
Cost of revenue increased 53.0% to $54.4 million for the year ended December 31, 2004 compared to $35.6 million for the year ended December 31, 2003. As a percentage of revenue, cost of revenue increased to 71.6% for the year ended December 31, 2004 from 69.1% for the year ended December 31, 2003. Approximately $7.5 million of this increase was attributable to an increase in the drilling activity of our customers in our Appalachian, Southeast and Mid-Continent operating regions. Approximately $3.9 million of our increase in cost of revenue was attributable to the establishment of our Southeast region service center in Columbia, Mississippi. Approximately $5.0 million of this increase was attributable to our establishment of an additional Mid-Continent region service center in Cleveland, Oklahoma. The remaining $1.6 million was attributable to increased costs as a result of increased activity at our Hominy, Oklahoma service center. This increase was partially offset by a reduction in costs for nitrogen in West Virginia and Alabama due to market competition. The cost of nitrogen declined 5.0%, and our nitrogen costs as a percentage of revenue declined from 5.1% in 2003 to 4.3% in 2004. In addition, our transportation costs increased by approximately $0.5 million due to a general shortage of railroad cars, requiring us to take delivery of frac sand by truck. Furthermore, the costs of stimulation and cementing supplies increased in 2004 and could not immediately be passed on to customers due to our preexisting pricing commitments. Price adjustments to offset these cost increases were implemented in January 2005. As a percentage of revenue, the portion of labor expenses included as a cost of revenue decreased slightly from 21.9% in 2003 to 20.4% in 2004.
Selling, General and Administrative Expenses.
SG&A expenses were $11.3 million for the year ended December 31, 2004 compared to $7.6 million for the year ended December 31, 2003, an increase of 49.1%. We hired additional personnel during 2004 to manage the growth in our operations. As a result of this growth, 2004 labor expenses increased $2.7 million. Another $0.9 million was attributable to the establishment of our Cleveland, Oklahoma service center. The remainder was attributable to additional expenses as a result of establishment of our Southeast region service center located in Columbia, Mississippi. As a percentage of revenue, the portion of labor expenses included in SG&A expenses increased slightly from 9.6% in 2003 to 10.1% in 2004.
Operating Income.
Operating income was $10.3 million for the year ended December 31, 2004 compared to $8.3 million for the year ended December 31, 2003, an increase of 24.0%. The primary reason for this increase was the
increase in drilling activity by our customers in our existing locations, coupled with the establishment and expansion of our operations in Mississippi and Oklahoma. This increase in operating income was partially offset by the increases in our cost of revenue and SG&A expenses as described above. Operating income in the Appalachian and Southeast operating regions increased $0.4 million and $3.4 million, respectively, and operating income in the Mid-Continent operating region decreased $0.7 million. EBITDA increased $3.4 million in 2004 to $15.2 million. For a definition of EBITDA, a reconciliation of EBITDA to net income and a discussion of EBITDA as a performance measure, please see “Non-GAAP Accounting Measures.” Net income increased $1.6 million to $9.8 million in 2004.
Items Impacting Comparability of Our Financial Results
Our historical results of operations for the periods presented may not be comparable to our results of operations in the future for the reasons discussed below.
Changes in Our Legal Structure.
Prior to our initial public offering in August 2005, our operations were conducted by two separate operating partnerships under common control, Superior Well Services, Ltd. and Bradford Resources, Ltd. Pursuant to a contribution agreement among Superior Well, Inc. and the former partners of these two operating partnerships, the operations of these two partnerships were combined under a holding company structure immediately prior to the closing of our initial public offering. Superior Well Services, Inc. serves as the parent holding company for this structure. Following the closing of the contribution agreement and our initial public offering as discussed in Note 1 to the financial statements, we began to report our results of operations and financial condition as a corporation on a consolidated basis, rather than as two operating partnerships on a combined basis.
Historically, we did not incur income taxes because our operations were conducted by two separate operating partnerships that were not subject to income tax. The historical combined financial statements of Superior Well Services, Ltd. and Bradford Resources, Ltd., however, include a pro forma adjustment for income taxes calculated at the statutory rate resulting in a pro forma net income adjusted for income taxes. Historically, partnership capital distributions were made to the former partners of our operating partnerships to fund the tax obligations resulting from the partners being taxed on their proportionate share of the partnerships’ taxable income. As a consequence of our change in structure, we recognized deferred tax assets and liabilities to reflect net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial and tax reporting purposes. As of December 31, 2005, the net deferred tax liability was approximately $9.3 million, resulting primarily from accelerated depreciation. Following our initial public offering, we incur income taxes under our new holding company structure, and our consolidated financial statements reflect the actual impact of income taxes.
Public Company Expenses.
Our general and administrative expenses have increased as a result of becoming a public company following our initial public offering. We currently anticipate that our total annual general and administrative expenses will increase by approximately $1.5 - 2.0 million. This increase will be due to the cost of tax return preparations, accounting support services, Sarbanes-Oxley compliance expenses, filing annual and quarterly reports with the SEC, investor relations, directors’ fees, directors’ and officers’ insurance and registrar and transfer agent fees. Our consolidated financial statements will reflect the impact of these increased expenses and affect the comparability of our financial statements with periods prior to the completion of our initial public offering.
Liquidity and Capital Resources
Prior to the completion of our initial public offering, cash generated from operations, borrowings under our existing credit facilities and funds from partner contributions were our primary sources of liquidity. Following completion of our initial public offering, we rely on cash generated from operations, future public
equity and debt offerings and borrowings under our new revolving credit facility to satisfy our liquidity needs. 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 financial, business and other factors, some of which are beyond our control. At December 31, 2005, the Company had $10.8 million of cash and cash equivalents and $20.0 million of availability under a revolving credit loan which can be used for planned capital expenditures and to make acquisitions.
Financial Condition and Cash Flows
Financial Condition.
The Company’s working capital increased $25.0 million at December 31, 2005 compared to December 31, 2004, primarily due to increases in cash, accounts receivable and inventory of $9.2 million, $12.1 million and $1.9 million. Cash increased due to proceeds from the initial public offering and the growth in accounts receivable and inventory was due to higher revenue activity discussed above in “- Our Results of Operations.” Offsetting the rise in current assets were increases in accounts payable and accrued liabilities of $3.5 million and $1.0 million, respectively. These increases were due to higher revenue activity levels. Additionally, capital expenditures amounted to $40.8 million for the year ended December 31, 2005. The capital expenditures were financed through funds generated by the initial public offering, as well as $14.5 million of short term borrowings and $12.2 million of long term debt that were subsequently repaid using proceeds generated by the initial public offering.
Cash flows from operations.
The Company’s cash flow from operations increased $5.0 million for the year ended December 31, 2005 compared to December 31, 2004, primarily due to higher income before income taxes that was partially offset by increases in working capital. Working capital increased due to growth in accounts receivable from higher revenues. Other significant components of the growth in 2005 cash flow from operations included increases in deferred income taxes and depreciation and amortization of $9.3 million and $8.7 million, respectively. The increase in deferred income taxes reflects a non-cash adjustment of $8.6 million to establish deferred tax liabilities that existed at the date of reorganization. These increases were partially offset by a $25.0 million increase in working capital.
Cash flows used in investing activities.
Net cash used in investing activities increased from $19.4 million for the year ended December 31, 2004 to $41.0 million for the year ended December 31, 2005. The increase was due to higher amounts of capital expenditures to purchase and upgrade pumping and down-hole surveying equipment. During the third and fourth quarters of 2005, the Company began placing orders for new capital equipment to be utilized in 2006. Certain vendors required deposits when the equipment build orders were placed.
Cash flows from financing activities.
Net cash provided by financing activities increased $25.5 million to $32.3 million for the year ended December 31, 2005, primarily due to net proceeds from our initial public offering that was partially offset by debt repayments and distributions to the former partners of our operating subsidiaries intended to fund their 2005 tax obligations. The significant increase in cash flows from financing activities included $61.8 million in net proceeds from the initial public offering and $10.5 million from credit facility borrowings used to fund capital expansion. These increases were partially offset by repayments of $12.2 million and $14.5 million of long-term debt and notes payable, respectively. Additionally, the Company paid $13.7 million in distributions to the former partners of our operating subsidiaries to fund tax obligations in 2005 that were a result of pre-reorganization activities.
Capital Requirements
The oilfield services business is capital-intensive, requiring significant investment to expand and upgrade operations. Our capital requirements have consisted primarily of, and we anticipate will continue to be:
•
expansion capital expenditures, such as those to acquire additional equipment and other assets to grow our business; and
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maintenance or upgrade capital expenditures, which are capital expenditures made to extend the useful life of partially or fully depreciated assets or to upgrade the operational capabilities of existing assets.
We continually monitor new advances in pumping equipment and down-hole technology and commit capital funds to upgrade and purchase additional equipment to meet our customers’ needs. For the year ended December 31, 2005, we made capital expenditures of approximately $40.8 million to purchase and upgrade our pumping and down-hole surveying equipment. This equipment allows us to deploy additional service crews. The 2005 capital expenditure amounts include approximately $8.8 million of spending for new capital equipment to be delivered in 2006. Our preliminary 2006 capital expenditure budget is estimated at $53.0 million. We also plan to continue to focus on expanding our ability to provide stimulation services for high-pressure wells, with approximately 45-50% of our planned 2006 capital expenditures budgeted for high-pressure pumping equipment.
Given our objective of growth through organic expansions and selective acquisitions, we anticipate that we will continue to invest significant amounts of capital to acquire businesses and assets. We actively consider a variety of businesses and assets for potential acquisitions, although currently we have no agreements or understandings with respect to any acquisition. For a discussion of the primary factors we consider in deciding whether to pursue a particular acquisition, please read “- Our Growth Strategy”. Management believes that cash flows from operations, combined with cash and cash equivalents and the revolving credit loan provide the Company with sufficient capital resources and liquidity to manage its routine operations and fund capital expenditures that are presently projected.
The following table summarizes the Company’s contractual cash obligations as of December 31, 2005 (in thousands):
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements as of December 31, 2005.
Description of Our Indebtedness
We used the proceeds from our initial public offering to repay all amounts outstanding under our credit facilities and terms note payable. In October 2005, we entered into a revolving credit loan with its existing lending institution. The new agreement provides for a $20.0 million revolving credit facility and matures in October 2008. Interest on the revolving credit facility will be at LIBOR plus a spread of 1.00% to 1.25%, based upon certain financial ratios. The loan is secured by our accounts receivable, inventory and equipment. At December 31, 2005, we had no borrowings under our revolving credit loan and $20.0 million of available capacity.
We have $1.4 million of other indebtedness, collateralized by specific buildings and equipment.
Recent Accounting Pronouncements
In January 2003, the Financial Accounting Standards Board, or the FASB, issued FASB Interpretation (FIN) No. 46, Consolidation of Variable Interest Entities. An entity is subject to the consolidation rules of FIN 46 and is referred to as a variable interest entity if the entity’s equity investors lack the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its operations without additional financial support. In December 2003, the FASB issued modifications to FIN 46, referred to as FIN 46R, resulting in multiple effective dates based on the nature as well as the creation date of a variable interest entity. The adoption of FIN 46 and FIN 46R in 2004 had no impact on our consolidated financial statements.
In December 2004, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 123R, Share-Based Payment. The standard amends SFAS No. 123, Accounting for Stock Based Compensation, and concludes that services received from employees in exchange for stock-based compensation results in a cost to the employer that must be recognized in the financial statements. The cost of such awards should be measured at fair value at the date of grant. SFAS 123R provides public companies with a choice of transition methods to implement the standard. In April 2005, the SEC adopted a rule permitting registrants to delay the expensing of options pursuant to SFAS 123R until the first annual period beginning after June 15, 2005. Accordingly, we expect to implement the provisions of SFAS 123R in our financial statements, effective January 1, 2006. At December 31, 2005, Superior did not have any stock-based compensation arrangements, although awards have been made in 2006.
Critical Accounting Policies
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting standards have developed. Accounting standards generally do not involve a selection among alternatives, but involve the implementation and interpretation of existing standards, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable standards on or before their adoption, and we believe the proper implementation and consistent application of the accounting standards are critical. For further details on our accounting policies, please read Note 2 of the Notes to Consolidated Financial Statements in Part II, Item 8 of this report.
These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the balance sheet date and the amounts of revenue and expenses recognized during the reporting period. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable under the circumstances. However, actual results could differ from such estimates. The following is a discussion of our critical accounting estimates.
Revenue Recognition
We recognize revenue when the services are performed, collection of the relevant receivables is reasonably assured, evidence of the arrangement exists and the price is determinable. Substantially all of our services performed for our customers are completed within one day.
We grant credit to all qualified customers. Losses arising from uncollectible accounts have been negligible. Management maintains close, regular contact with customers and regularly reviews accounts receivable for credit risks resulting from changes in the financial condition of our customers. We record provisions for bad debt expense when management believes that a related receivable is not recoverable based on customer payment activity and other factors that could affect collection. Judgment is involved in performing these evaluations, since the results are based on estimated future events. Such items include the financial stability of our customers, timing of anticipated payments, as well as the overall condition of the oil and gas industry. Historically, our bad debt expense has not been significant, but if there is a prolonged downturn in the oil and gas industry, our bad debt expense could materially change. Additionally, changing circumstances could cause us to increase our allowance for doubtful accounts.
Property, Plant and Equipment
Our property, plant and equipment are carried at cost and are depreciated using the straight-line and accelerated methods over their estimated useful lives. The estimated useful lives range from 15 to 30 years for buildings and improvements and range from five to ten years for equipment and vehicles. The estimated useful lives may be adversely impacted by technological advances, unusual wear or by accidents during usage. Management routinely monitors the condition of equipment. Historically, management has not changed the estimated useful lives of our property, plant and equipment and presently does not anticipate any significant changes to those estimates. Repairs and maintenance costs, which do not extend the useful lives of the asset, are expensed in the period incurred.
Impairment of Long-Lived Assets
In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we evaluate our long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management’s estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is recalculated when related events or circumstances change.
When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset or asset group. Our estimate of cash flows is based on assumptions regarding the future estimated cash flows, which in most cases is derived from our performance of services. The amount of future business is dependent in part on crude oil and natural gas prices. Projections of our future cash flows are inherently subjective and contingent upon a number of variable factors, including but not limited to:
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changes in general economic conditions in regions in which our services are located;
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the price of crude oil and natural gas;
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our ability to negotiate favorable sales arrangements; and
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our competition from other service providers.
We currently have not recorded any impairment of an asset. Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.
Intangible Assets
Our intangible assets are customer relationships related to an asset acquisition in the third quarter of 2003. The gross amount of $1,425,000 is being amortized at $285,000 per year over an estimated period of five years.
Contingent Liabilities
We record an expenses for legal, environmental and other contingent matters when a loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by governmental regulators and the courts. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information. Although we continue to
monitor all contingencies closely, particularly our outstanding litigation, we currently have no material accruals for contingent liabilities.
Insurance Expenses
We self-insure employee health insurance plan costs. The estimated costs of claims under this self-insurance program are accrued as the claims are incurred (although actual settlement of the claims may not be made until future periods) and may subsequently be revised based on developments relating to such claims. The self-insurance accrual is estimated based upon our historical experience, as well as any known unpaid claims activity. Judgment is required to determine the appropriate accrual levels for claims incurred but not yet received and paid. The accrual estimates are based primarily upon recent historical experience adjusted for employee headcount changes. Historically, the lag time between the occurrence of an insurance claim and the related payment has been approximately two months and the differences between estimates and actuals have not been material. The estimates could be affected by actual claims being significantly different.
We maintain an insurance policy that covers claims in excess of $75,000 per employee with a maximum out-of-pocket claim liability of $3.1 million. Aggregate claims exceeding the $3.1 million policy limit are paid by the insurer.
Forward-Looking Statements and Risk Factors
Certain information contained in this Annual Report on Form 10-K (including, without limitation, statements contained in Part I, Item 1. “Business”, Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Part II, Item 9A. “Controls and Procedures”), as well as other written and oral statements made or incorporated by reference from time to time by us and our representatives in other reports, filings with the United States Securities and Exchange Commission (the “SEC”), press releases, conferences, or otherwise, may be deemed to be forward-looking statements within the meaning of Section 2lE of the Securities Exchange Act of 1934 (“the Exchange Act”). This information includes, without limitation, statements concerning:
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a decrease in domestic spending by the oil and natural gas exploration and production industry;
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a decline in or substantial volatility of crude oil and natural gas commodity prices;
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the loss of one or more significant customers;
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the loss of or interruption in operations of one or more key suppliers;
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the incurrence of significant costs and liabilities in the future resulting from our failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment; and
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other financial, operational and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings.
Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. When used in this report, the words “anticipate,” “believe,” “estimate,” “expect,” “may,” and similar expressions, as they relate to the Company and our management, identify forward-looking statements. The actual results of future events described in such forward-looking statements could differ materially from the results described in the forward-looking statements due to the risks and uncertainties set forth below and elsewhere within this Annual Report on Form 10-K.
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
Quantitative and Qualitative Disclosures about Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risk to which we are exposed is the risk related to interest rate fluctuations. To a lesser extent, we are also exposed to risks related to increases in the prices of fuel and raw materials consumed in performing our services. We do not engage in commodity price hedging activities.
Interest Rate Risk. We are exposed to changes in interest rates as a result of our new credit facility established in October 2005, which has a variable interest rate based upon, at our option, LIBOR or the prime lending rate. The impact of a 1% increase in interest rates on our outstanding debt as December 31, 2005 would result in interest expense, and a corresponding decrease in net income, of less than $0.1 million annually.
Concentration of Credit Risk. Substantially all of our customers are engaged in the oil and natural gas industry. This concentration of customers may impact overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions. Two customers individually accounted for 22% and 11% and 18% and 9% of our revenue for the years ended December 31, 2004 and 2005, respectively. At December 31, 2005, one customer accounted for 15% and eight customers accounted for 46% of Superior’s accounts receivable.
Commodity Price Risk. Our fuel and material purchases expose us to commodity price risk. In addition to purchasing diesel fuel for our truck fleet, we also purchase various raw materials that we hold as inventory to be consumed in performing our services. Our material costs primarily include the cost of inventory consumed while performing our stimulation, nitrogen and cementing services such as frac sand, cement and nitrogen. Our fuel costs consist primarily of diesel fuel used by our various trucks and other motorized equipment. The prices for fuel and the raw materials in our inventory are volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages. Although we are generally able to pass along price increases to our customers, due to pricing commitments and the timing of our marketing and bidding cycles there is generally a delay of several weeks or months from the time that we incur a price increase until the time that we can pass it along to our customers.
Item 8.
Item 8.
Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Superior Wells Services, Inc.
We have audited the accompanying consolidated balance sheets of Superior Wells Services, Inc. (Superior) as of December 31, 2005 and 2004, and the related statements of income, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2005. In addition, our audit included the financial statement schedule included in the index at Item 15 (b). These consolidated financial statements and financial statement schedule are the responsibility of Superior’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. Superior is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of Superior’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Superior as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ Schneider Downs & Co., Inc.
Pittsburgh, Pennsylvania
March 6, 2006
SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
The accompanying notes are an integral part of these consolidated financial statements.
SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL AND STOCKHOLDERS’ EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements
SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
Organization
Superior Well Services, Inc. (“Superior”) was formed as a Delaware corporation on March 2, 2005 for the purpose of serving as the parent holding company for Superior GP, L.L.C. (“Superior GP”), Superior Well Services, Ltd. (“Superior Well”) and Bradford Resources, Ltd. (“Bradford”). In May 2005, Superior and the partners of Superior Well and Bradford entered into a contribution agreement that resulted in the partners of Superior Well and Bradford contributing their respective partnership interests to Superior in exchange for shares of common stock of Superior (the “Contribution Agreement”). Superior Well and Bradford are Pennsylvania limited partnerships that became wholly owned subsidiaries of Superior in connection with its initial public common stock offering.
In August 2005, Superior completed its initial public offering of 6,460,000 shares of its common stock, which included 1,186,807 shares sold by selling stockholders and 840,000 shares sold by Superior to cover the exercise by the underwriters of an option to purchase additional shares to cover over-allotments. Proceeds to Superior, net of the underwriting discount and offering expenses, were approximately $61.8 million.
Superior Well provides a wide range of well services to oil and gas companies, primarily technical pumping and down-hole surveying services, in many of the major oil and natural gas producing regions of the United States.
Bradford owns oil and gas well services equipment and provides, through leasing arrangements, substantially all of Superior Well’s equipment needs. All of Bradford’s revenues are derived from Superior Well and have been eliminated in the amounts presented.
2.
Summary of Significant Accounting Policies
Basis of Presentation
The consolidated financial statements are prepared in accordance with generally accepted accounting principles accepted in the United States of America (GAAP). These financial statements reflect all adjustments that, in our opinion, are necessary to fairly present our financial position and results of operations. Significant intercompany accounts and transactions have been eliminated in consolidation.
At December 31, 2005, the accompanying consolidated financial statements include the accounts of Superior and its wholly-owned subsidiaries Superior Well, Bradford and Superior GP. Superior Well and Bradford (“Partnerships”), prior to the effective date of the Contribution Agreement, were entities under common control arising from common direct or indirect ownership of each. The transfer of the Partnerships assets and liabilities to Superior (see Note 1) represented a reorganization of entities under common control and was accounted for at historical cost. Prior to the reorganization, the Partnerships were not subject to federal and state corporate income taxes. The statements of income reflect federal and state income taxes for the five months of operations following the reorganization. Additionally, Superior recorded a non-cash adjustment of $8.6 million to record the deferred tax asset and liabilities arising from the differences in the financial statement and tax bases of assets and liabilities that existed at that time. The $8.6 million non-cash adjustment is included in the deferred income tax provision for the year ended December 31, 2005.
Estimates and Assumptions
Superior uses certain estimates and assumptions that affect reported amounts and disclosures. These estimates are based on judgments, probabilities and assumptions that are believed to be reasonable but inherently uncertain and unpredictable. Assumptions may be incomplete or inaccurate, and unanticipated events and circumstances may occur. Superior is subject to risks and uncertainties that may cause actual results to differ from estimated amounts.
Cash and Cash Equivalents
All cash and cash equivalents are stated at cost, which approximates market. Superior considers all highly liquid investments purchased with a maturity of three months or less to be cash equivalents. Superior maintains cash at various financial institutions that may exceed federally insured amounts.
Trade Accounts Receivable
Accounts receivable are carried at the amount owed by customers. Superior grants credit to all qualified customers, which are mainly independent and major oil and gas companies. Management periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of its customers. Once an account is deemed not to be collectible, the remaining balance is charged to the reserve account. During 2003, 2004 and 2005, Superior recorded bad debt expense of $79,300, $5,300 and $144,200, respectively.
Property, Plant and Equipment
Superior’s property, plant and equipment are stated at cost less accumulated depreciation. The costs are depreciated using the straight-line and accelerated methods over their estimated useful lives. The estimated useful lives range from 15 to 30 years for building and improvements and range from 5 to 10 years for equipment and vehicles. Depreciation expense, excluding intangible amortization, amounted to $3,370,000, $4,772,000 and $8,413,000 in 2003, 2004 and 2005, respectively.
Repairs and maintenance costs that do not extend the useful lives of the asset are expensed in the period incurred. Gain or loss resulting from the retirement or other disposition of assets is included in income.
Superior reviews long-lived assets for impairment whenever there is evidence that the carrying value of such assets may not be recoverable. The review consists of comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. An impairment loss would be recognized when estimated future cash flows expected to result from the use of the asset and their eventual dispositions are less than the asset’s carrying value. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions.
Revenue Recognition
Superior’s revenue is comprised principally of service revenue. Product sales represent approximately 1% of total revenues. Services and products are generally sold based on fixed or determinable pricing agreements with the customer and generally do not include rights of return. Service revenue is recognized when the services are provided and collectibility is reasonably assured. Substantially all of Superior’s services performed for customers are completed at the customer’s site within one day. Superior recognizes revenue from product sales when the products are delivered to the customer and collectibility is reasonably assured. Products are delivered and used by our customers in connection with the performance of our cementing services. Product sale prices are determined by published price lists provided to our customers.
Inventories
Inventories, which consist principally of materials consumed in Superior’s services provided to customers, are stated at the lower of cost or market using the specific identification method.
Insurance Expense
Superior self-insures employee health insurance plan costs. The annual policy limitation is $75,000 of claims per employee with a maximum out-of-pocket exposure of $3.1 million. Aggregate claims exceeding the $3.1 million policy limit are paid by the insurer. The estimated costs of claims under this self-insurance program are accrued as the claims are incurred (although actual settlement of the claims may not be made until future periods) and may subsequently be revised based on developments relating to such claims.
Income Taxes
Superior accounts for income taxes in accordance with the provisions of SFAS No. 109, Accounting for Income Taxes. This statement requires a company to recognize deferred tax liabilities and assets for the expected future tax consequences of events that have been recognized in Superior’s financial statements or tax returns. Using this method, deferred tax liabilities and assets were determined based on the difference between the financial carrying amounts and tax bases of assets and liabilities using enacted tax rates. Prior to becoming wholly-owned subsidiaries of Superior, the Partnerships were not taxable entities for federal or state income tax purposes and, accordingly, were not subject to federal or state corporate income taxes. For the years ended December 31, 2003 and 2004, pro forma income tax expense (unaudited) has been computed at statutory rates to provide the reader of the financial statements with a pro forma net income (unaudited) consistent with the entity structure change referenced in Note 1.
Interest Rate Risk Management
Prior to repayment of its variable rate bank debt, Superior used an interest rate swap agreement to manage the risk that future cash flows associated with interest payments on its variable rate debt may be adversely affected by volatility in market rates. Superior settled the interest rate swap agreement and recorded a $20,000 gain on settlement which is reflected in other income. The interest rate swap had a notional principal amount of $3 million and a fixed rate of 3.28%. The fair market value of the interest rate swap was $1,700 as of December 31, 2004. The unrealized gain on the interest rate swap included in accumulated other comprehensive income was $58,000 at December 31, 2004.
Fair Value of Financial Instruments
Superior’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable and notes payable. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value due to the short-term nature of such instruments. The carrying value of notes payable and long-term debt approximates fair value, since the interest rates are market-based and are generally adjusted periodically.
Additionally, interest rate swaps are recorded at fair value in accordance with Statement of Financial Accounting Standards (SFAS) No. 133.
Superior’s financial instruments are not held for trading purposes.
Intangible Assets
Superior’s intangible assets are customer relationships related to a 2003 acquisition. The gross amount of $1,425,000 is being amortized at $285,000 per year.
Concentration of Credit Risk
Substantially all of Superior’s customers are engaged in the oil and gas industry. This concentration of customers may impact overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions. Two customers individually accounted for 21% and 13% and 22% and 11% of Superior’s revenue for the years ended December 31, 2003 and 2004. One customer accounted for 18% of Superior’s revenue for the year ended December 31, 2005. Eight customers accounted for 63%, 55% and 51% of Superior’s revenue for the years ended December 31, 2003, 2004 and 2005, respectively. At December 31, 2005, one customer accounted for 15% and eight customers accounted for 46% of Superior’s accounts receivable.
Weighted average shares outstanding
The weighted average shares outstanding for the computation of basic and diluted earnings per share has been computed taking into account the 14,103,474 shares issued to former partners in connection with the reorganization described in Note 2, effective immediately prior to the initial public offering, the
5,273,193 shares issued by Superior in the initial public offering, which included 840,000 shares sold by Superior to cover the underwriters’ over-allotment option, each from the respective date of issuance. This resulted in 19,317,436 average shares outstanding for the year ended December 31, 2005. For the pro-forma calculations of earnings per share for the years ended December 31, 2003 and 2004, all shares are assumed to have been issued at the beginning of the period resulting in 19,376,667 average shares outstanding.
Reclassification
Certain prior amounts have been reclassified to conform with 2005 presentation. We have regrouped certain repair and vehicle expenses associated with our shop operations, uniform cleaning expenses and maintenance expenses from “Selling, general and administrative expenses” into “Cost of revenue” in order to better segregate the expense items between those more closely related to serving our customers versus those expenses, which in nature are not directly related to servicing customers. The reclassifications had no impact on operating income for any of the periods presented.
Recently Issued Guidance
In January 2003, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 46 (“FIN 46”), Consolidation of Variable Interest Entities. FIN 46 clarifies the application of Accounting Research Bulletin No. 51, Consolidated Financial Statements, to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. In December 2003, the FASB issued FIN 46(R), which revised certain provisions in the original interpretation and permitted multiple effective dates based upon the nature and formation date of the variable interest entity. Adoption of the provisions of FIN 46 did not have a material impact on Superior’s financial position or results of operations.
In December 2004, the FASB issued SFAS 123R (Share-Based Payment). The standard amends SFAS 123 (Accounting for Stock-Based Compensation) and concludes that services received from employees in exchange for stock-based compensation results in a cost to the employer that must be recognized in the financial statements. The cost of such awards should be measured at fair value at the date of grant. In April 2005, the SEC adopted a rule permitting registrants to delay the expensing of options pursuant to SFAS 123R until the first annual period beginning after June 15, 2005. Accordingly, the provisions of FAS 123R will be applicable to share-based compensation in the future, effective no later than January 1, 2006. Prior to January 2006, Superior did not have any stock-based compensation arrangements. On January 20, 2006, the Company awarded 299,000 restricted shares of common stock to non-employee directors and key employees (See Note 11).
3.
Notes Receivable - Limited Partners
Superior Well sold limited partnership interests, amounting to 40% ownership, to three individuals during the year ended December 31, 2000. Capital contributions made to Superior Well for these limited partnership interests aggregated $200,000, of which $87,000 was received in cash and $113,000 was received through issuance of notes receivable. The notes receivable were due in monthly installments totaling $1,338, including interest at 7.5%, through January 2010. The notes were repaid prior to the initial public offering. The amount outstanding as of December 31, 2004 was $68,000.
4.
Debt
In October 2005, Superior entered into a revolving credit loan with its existing lending institution. The new agreement provides for a $20 million revolving credit facility and matures in October 2008. Interest on the revolving credit facility will be at LIBOR plus a spread of 1% to 1.25%, based upon certain financial ratios. The loan is secured by Superior’s accounts receivable, inventory and equipment. The revolving credit loan requires the Company to maintain a maximum debt to EBITDA ratio and a minimum amount of adjusted net tangible net worth, as defined under the credit agreement. At December 31, 2005, Superior had no borrowings
under the revolving credit loan, $20 million of borrowing availability and was in compliance with its financial covenants.
Bradford had a $12.0 million mortgage note payable maturing in January 2010 that was repaid and terminated in August 2005. Interest on the mortgage note payable was at LIBOR plus 1.2%. During 2004 and 2005, the weighted average interest rates on the outstanding borrowings were 2.5% and 4.1%, respectively.
Bradford had a $9.5 million note payable maturing January 2011 that was repaid and terminated in August 2005. Obligations under the agreement were guaranteed by Superior Well and the former limited partners of Bradford. Interest on the note payable was at LIBOR plus 1%. During 2005, the weighted average interest rates on the outstanding borrowings was 3.9%.
Long-term debt at December 31, 2004 and 2005 consisted of the following (amounts in thousands):
Principal payments required under our long-term debt obligations during the next five years and thereafter are as follows: 2006-$179,000, 2007-$139,000, 2008-$139,000, 2009-139,000, 2010-$121,000 and thereafter $720,000.
5.
Note Payable
Superior Well had a $9.5 million revolving credit agreement (“Note Payable”) that was repaid in August 2005. The Note Payable was terminated in October 2005. Interest on the Note Payable was at London InterBank Offered Rate (LIBOR) plus 1%. During 2004 and 2005, the weighted average interest rates on the outstanding borrowings were 2.1% and 3.9%, respectively.
6.
Income taxes
Superior accounts for income taxes and the related accounts under the liability method. Deferred taxes and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted rates expected to be in effect during the year in which the basis differences reverse.
As indicated in Note 2, the conveyance of the Partnerships to Superior represented a reorganization of entities under common control. Prior to becoming wholly-owned subsidiaries of Superior, the Partnerships were not taxable entities for federal or state income tax purposes and, accordingly, were not subject to federal or state corporate income taxes. At the date of reorganization, Superior recorded a non-cash adjustment of $8.6 million to record the deferred tax asset and liabilities arising from the differences in the financial statement and tax bases of assets and liabilities that existed at that time. Substantially all of the balance at reorganization is attributable to depreciation differences in property, plant at equipment. The adjustment resulted from the change in tax status from non-taxable entities to an entity which is subject to taxation.
The provision for income taxes is comprised of (amounts in thousands):
Significant components of Superior’s deferred tax assets and liabilities are as follows (amounts in thousands):
A reconciliation of income tax expense using the statutory U.S. income tax rate compared with actual income tax expense is as follows (amounts in thousands):
7.
401(k) Plan
Superior Well has a defined contribution profit sharing/401(k) retirement plan (“the Plan”) covering substantially all employees. Employees are eligible to participate after six months of service. Under terms of the Plan, employees are entitled to contribute up to 15% of their compensation, within limitations prescribed by the Internal Revenue Code. Superior Well makes matching contributions of 25% of employee deferrals up to 12% of their compensation and may elect to make discretionary contributions to the Plan, all subject to vesting ratably over a five-year period. Discretionary contributions made to the Plan were approximately $356,000, $571,000 and $810,000 in 2003, 2004 and 2005, respectively.
8.
Related-Party Transactions
Superior Well provides technical pumping services and down-hole surveying services to a customer owned by certain shareholders and directors of Superior. The total amounts of services provided to this affiliated party were approximately $3,906,000, $4,248,000 and $5,588,000 in 2003, 2004 and 2005, respectively. The accounts receivable outstanding from the affiliated party were $402,000 and $366,000 at December 31, 2004 and 2005, respectively.
Superior Well also regularly purchases, in the ordinary course of business, materials from vendors owned by certain shareholders and directors of Superior. The total amounts paid to these affiliated parties were approximately $1,329,000, $1,623,000 and $2,141,000 in 2003, 2004 and 2005, respectively. Superior Well had accounts payable to these affiliates of $159,000 and $173,000 at December 31, 2004 and 2005, respectively.
Prior to Superior’s initial public offering in August 2005, administrative and management services were provided to Superior Well by affiliates that were owned by certain partners of Superior Well. The total amounts paid to these affiliated entities were approximately $979,000, $1,298,000 and $594,000 in 2003, 2004 and 2005, respectively. Following Superior’s initial public offering, Superior Well no longer requires these administrative and management services.
In February 2006, the Company discovered it had paid $305,000 in state income taxes in November 2005 with respect to the operations of Superior Well that related to periods prior to the time the Company acquired Superior Well from the partners of Superior Well in August 2005. These former partners included, among others, certain executive officers and directors of the Company. After review, the Audit Committee of the Company’s Board of Directors determined that the contribution agreement under which the Company acquired Superior Wells from these former partners did not provide for the payment by the Company of such state tax payments that were incorrectly made by the Company. All of the former partners of Superior Well have since reimbursed the Company for the full amount of their respective portions of those state tax payments.
9.
Commitments and Contingencies
Minimum annual rental payments, principally for non-cancelable real estate and vehicle leases with terms in excess of one year, in effect at December 31, 2005, were as follows: 2006-$1,305,000; 2007-$1,111,000; 2008-$934,000; 2009-$527,000 and 2010-$153,000.
Total rental expense charged to operations was approximately $662,000, $697,000 and $968,000 in 2003, 2004 and 2005, respectively.
Superior had commitments of approximately $34.2 million for capital expenditures as of December 31, 2005.
Superior is involved in various legal actions and claims arising in the ordinary course of business. Management is of the opinion that the outcome of these lawsuits will not have a material adverse effect on the financial position, results of the operations or liquidity of Superior.
10.
Stock Incentive Plan
In July 2005, Superior adopted a stock incentive plan for its employees. The 2005 Stock Incentive Plan permits the grant of non-qualified stock options, incentive stock options, stock appreciation rights, restricted stock awards, phantom stock awards, performance awards, bonus stock awards or any combination of the foregoing to employees, directors and consultants. A maximum of 2,700,000 shares of common stock may be delivered pursuant to awards under the 2005 Stock Incentive Plan. The Compensation Committee of the Board of Directors, which is composed entirely of independent directors, will determine all awards made pursuant to the 2005 Stock Incentive Plan. At December 31, 2005, no awards had been made under the 2005 Stock Incentive Plan.
11.
Subsequent event
On January 20, 2006, each of the non-employee directors of Superior Well Services, Inc. (the “Company”) were granted an award of 10,000 restricted shares of common stock in consideration of the unique obligations associated with being a director of a newly public company. The total non-employee director awards amounted to 50,000 shares. The award is subject to a service requirement that requires the director to continuously serve as a member of the Board of Directors of the Company from the date of grant through the number of years following the date of grant as set forth in the following schedule. The forfeiture restrictions lapse with respect to a percentage of the aggregate number of restricted shares in accordance with the following schedule:
On January 20, 2006, certain officers and key employees of the Company were awarded 249,000 restricted shares of common stock. The officer awards amounted to 67,000 shares. The award is subject to a service requirement that requires the individual to continuously serve as an employee of the Company from the date of grant through the number of years following the date of grant as set forth in the schedule above. The forfeiture restrictions lapse with respect to a percentage of the aggregate number of restricted shares in accordance with the schedule provided above.
The Company’s common stock closed at a market price of $28.56 per share on January 20, 2006. The market value of the award was approximately $8.5 million, before the impact of income taxes. The Company plans to recognize the expense in connection with the restricted share awards ratably over the five year vesting period.
12.
Quarterly Financial Information (Unaudited)
Quarterly financial information for the years ended December 31, 2005 and 2004 is presented below:
(1)
All quarters reflect reclassification of certain repair and vehicle expenses associated with our shop operations, uniform cleaning expenses and maintenance expenses from “Selling, general and administrative expenses” into “Cost of revenue” in order to better segregate the expense items between those more closely related to serving our customers versus those expenses, which in nature are not directly related to servicing customers. The reclassifications had no impact on operating income for any of the periods presented.
(2)
Share and per share data have been retroactively restated to reflect our holding company restructuring. For the calculations of earnings per share for 2004 and the first and second quarters of 2005, all shares are assumed to have been issued at the beginning of the period resulting in 19,376,667 average shares outstanding.
Item 9.
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None
Item 9A.
Item 9A.
Controls and Procedures
As required by SEC Rule 13a-15(b), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation 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 report. Our principal executive officer and principal financial officer have concluded that our current disclosure controls and procedures are effective to timely alert them to material information regarding the Company that is required to be included in our periodic reports filed with the SEC, and that our disclosure controls and procedures are effective to provide reasonable assurance that our financial statements are fairly presented in conformity with generally accepted accounting principles.
During the three months ended December 31, 2005, we have made no change in our internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
PART III
Item 10.
Item 10.
Directors and Executive Officers of the Registrant
Information regarding our directors and executive officers will be set forth in the proxy statement for the 2006 Annual Meeting of Shareholders under the heading “Election of Directors.” Information regarding compliance by our officers, directors and control persons with Section 16(a) of the Securities Exchange Act of 1934 will be set forth in our proxy statement for the 2005 Annual Meeting of Shareholders under the heading “Other Matters-Compliance with Section 16(a) of the Exchange Act.”
Item 11.
Item 11.
Executive Compensation
Information regarding executive compensation will be set forth in our proxy statement for the 2006 Annual Meeting of Shareholders.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management
Information regarding security ownership of certain beneficial owners and management and related stockholder matters will be set forth in our proxy statement for the 2006 Annual Meeting of Stockholders.
Item 13.
Item 13.
Certain Relationships and Related Transactions
Information regarding certain relationships and related transactions will be set forth in our proxy statement for the 2006 Annual Meeting of Shareholders.
Item 14.
Item 14.
Principal Accounting Fees and Services
Information regarding principal accounting fees and services will be set forth in our proxy statement for the 2006 Annual Meeting of Shareholders.
PART IV
Item 15.
Item 15.
Exhibits and Financial Statement Schedules.
(a) Financial Statements
The following financial statements are included in Part II, Item 8:
(b) Financial Statement Schedules
All other schedules are omitted because they are not applicable, are not required or the information is included in the financial statements or notes thereto.
(c) Exhibits
*
Management contract or compensatory plan or arrangement.
**
Filed herewith.
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, on the 7th day of March, 2006.
SUPERIOR WELL SERVICES, INC.
By:
/s/ Thomas W. Stoelk
Thomas W. Stoelk
Vice President and Chief Financial Officer
(principal financial officer)
Each person whose signature appears below hereby constitutes and appoints David E. Wallace and Thomas W. Stoelk, and each of them, his true and lawful attorney-in-fact and agent, with full powers of substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report of Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission granting to said attorneys-in-fact, and each of them, full power and authority to perform any other act on behalf of the undersigned required to be done in connection therewith.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the persons on behalf of the registrant in the capacities and on the dates indicated.
Schedule II.
Valuation and Qualifying Accounts