UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form l0-K

 

 

Commission File No. 000-51435

 

SUPERIOR WELL SERVICES, INC.

(Exact name of registrant as specified in its charter)

 

 

1380 Rt. 286 East, Suite #121

Indiana, Pennsylvania 15701

(Address of principal executive offices)

(Zip Code)

 

 

(Registrant’s telephone number, including area code) (724) 465-8904

 

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

 

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

None

 

 

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

 

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

 

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

 

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

 

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

 

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

 

 

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

 

As of June 30, 2009, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $101,875,930 based on the closing sale price as reported on The NASDAQ Global Select Market on June 30, 2009 which is the last business day of the registrant’s most recently completed second quarter.

 

As of March 3, 2010, there were outstanding 30,906,573 shares of the registrant’s common stock, par value $.01, which is the only class of common or voting stock of the registrant.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the registrant’s definitive proxy statement for its 2010 annual meeting of stockholders are incorporated by reference in Part III of this Form 10-K.

 

 

SUPERIOR WELL SERVICES, INC.
ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

 

 

 

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. 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 opportunities in markets where we believe 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 28 service centers providing coverage across 38 states. Our customer base has grown from 89 customers in 1999 to over 1,200 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, Southeast and Southwest regions of the United States. Historically, our expansion strategy has been to establish new service centers as our customers expand their operations into new markets. Once we establish a service center in a new market, we seek to expand our operations at that service center by attracting new customers and experienced local personnel.

 

Since our inception, we have also completed several selective acquisitions including (i) our February 2007 acquisition of the operating assets of ELI Wireline Services, Inc., which expanded our operations in the Mid-Continent region, (ii) our November 2007 acquisition of the operating assets and personnel of Madison Wireline Services, Inc., which expanded our operations in North Dakota, (iii) our July 2008 acquisition of the operating assets of Nuex Wireline, Inc., which expanded our operations in the Rocky Mountain region, and (iv) our November 2008 acquisition of the pressure pumping, fluid logistics and completion, production and rental tools business lines from Diamondback Energy Holdings, LLC (“Diamondback”), which operate in the Anadarko, Arkoma, and Permian Basins, as well as in the Barnett Shale, the Woodford Shale, West Texas, Southern Louisiana and the Texas Gulf Coast. Today, we operate through our 28 service centers located in Pennsylvania, Alabama, Arkansas, Colorado, Kansas, Louisiana, Michigan, Mississippi, North Dakota, Oklahoma, Texas, Utah, Virginia, West Virginia and Wyoming.

 

Our Services and Products

 

Our services are conducted through two principal business segments which are technical services and fluid logistics. Each business segment includes service lines that contain similarities among customers, financial performance and management, as well as the economic and business conditions impacting their activity levels. Technical services include technical pumping services, completion, production and rental tool services and down-hole surveying services. Fluid logistics services include those services related to the transportation, storage and disposal of fluids that are used in the drilling, development and production of hydrocarbons. See Note 10 “Business segment information” to our consolidated financial statements in Part II, Item 8 of this report for additional financial information for our two principal business segments.

 

Technical Services

 

Technical Pumping Services  

 

We offer three types of technical pumping services — stimulation, nitrogen and cementing, which accounted for 65.7%, 6.4%, and 13.2% of our revenue for the year ended December 31, 2009, 64.2%, 6.7%, and 18.0% of our revenue for the year ended December 31, 2008 and 54.3%, 12.0% and 20.6% of our revenue for the year ended December 31, 2007, respectively. As of December 31, 2009, we owned a fleet of 1,614 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, is suspended in the gel to form a slurry and pumped into the fracture to prop it open. The size of a fracturing job is generally expressed in terms of pounds of proppant. The primary equipment used in the fracturing process include the blender, which blends the proppant into the fracturing fluid, and the pumping unit, which pumps significant volumes of slurry at high pressures. Our fracturing pump units are capable of pumping slurries at pressures of up to 13,000 psi and at rates of up to 130 barrels per minute.

 

Acidizing services 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 enables us to provide stimulation services with relatively high pressures (8,000 to 13,000 psi) that many of our smaller independent competitors currently do not offer. For these higher pressure projects, we typically contract with independent third-party regional laboratories to test our fluid composition as part of our pre-job optimization and approval process. As of December 31, 2009, we had 22 stimulation and acidizing crews of approximately three to 30 employees each and a fleet of 1,176 vehicles that includes high-tech, customized pump trucks, blenders and frac vans for use in our fluid-based stimulation services. We provide basic stimulation and acidizing services from 17 different service centers: Black Lick, Pennsylvania; Bradford, Pennsylvania; Mercer, Pennsylvania; Norton, Virginia; Kimball, West Virginia; Jane Lew, West Virginia; Columbia, Mississippi; Marlow, Oklahoma; Vernal, Utah; Cottondale, Alabama; Gaylord, Michigan; Van Buren, Arkansas; Midland, Texas; Cresson, Texas; Brighton, Colorado; Williston, North Dakota 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 2009. 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 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.

 

As of December 31, 2009, we had six nitrogen crews of approximately two to eight employees each and a fleet of 62 nitrogen pump trucks and 46 nitrogen transport vehicles. We provide nitrogen services from our Mercer, Pennsylvania; Gaylord, Michigan; Kimball, West Virginia; Jane Lew, West Virginia; Norton, Virginia, Van Buren, Arkansas and Cottondale, Alabama service centers. During 2009 we also provided nitrogen services from a service center in Farmington, New Mexico that ceased operations in January 2010.

 

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 (1) 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, (2) seal the casing from corrosive formation fluids and (3) 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. 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 have consistently accounted for less than 1% of our total revenue.

 

As of December 31, 2009, we had 37 cementing crews of approximately three to six employees each and a fleet of 330 cement trucks. We provide cementing services from 15 different service centers: Black Lick, Pennsylvania; Bradford, Pennsylvania; Mercer, Pennsylvania; Kimball, West Virginia; Jane Lew, West Virginia; Clinton, Oklahoma; Columbia, Mississippi; Cottondale, Alabama; Gaylord, Michigan; Van Buren, Arkansas; Vernal, Utah; Cresson, Texas; Norton, Virginia; Williston, North Dakota and Bossier City, Louisiana.

 

Completion, Production and Rental Tool Services  

 

Our completion, production and rental tool services include completion and production services as well as plugging and abandonment, gravel pack, storm valves, roustabout services and sale and rental of tools and equipment. We provide completion, production and rental tool services from five different service centers: Broussard, Louisiana; Victoria, Texas; Bossier City, Louisiana; Columbia, Mississippi and Elk City, Oklahoma.

 

Completion and Production Services.  Completion and production services were added in connection with our Diamondback asset acquisition in November 2008 and accounted for 3.6% and 0.4% of our revenues for the years ended December 31, 2009 and 2008, respectively. Our completion and production services include specialty services, many of which are performed after drilling is completed. Consequently, these services occur later in the lifecycle while a well is being completed or during the production stage. As newly drilled oil and natural gas wells are prepared for production, our completion services include selectively testing producing zones of the wells before and after stimulation. This service is called “flow back” testing and assists producers in determining potential production and production equipment needs. As of December 31, 2009, we owned nine flow back tanks.

 

Plugging and Abandonment Services.  We provide plugging and abandonment services when a well has reached the end of its productive life. We use workover rigs, cementing equipment and other equipment in the process of permanently closing oil and natural gas wells no longer capable of producing in economic quantities.

 

Roustabout Services.  We provide roustabout services on well sites, ranging from constructing production sites, repairing production equipment, laying production flow lines, disassembly of tank batteries, transporting equipment and other ancillary services. These services are used during completion, production and abandonment phases of a well’s lifecycle and are generally more labor intensive than equipment intensive.

 

Sale and Rental of Tools and Equipment.  We sell expendable equipment that is used during the cementing process and in the completion of wells including plugs, tubing anchors, retainers and other accessories. We also rent electric generators and lighting equipment and a comprehensive line of reusable tools and equipment that are used in the completion and production phases. The most frequently used equipment includes packers and plugs, which are used to seal the wellbore to isolate certain zones for completion and re-completion procedures.

 

Down-Hole Surveying Services  

 

We offer two types of down-hole surveying services — logging and perforating, which accounted for 5.8% and 9.4% of our revenue for the years ended December 31, 2009 and 2008, respectively. As of December 31, 2009, we owned a fleet of 118 logging and perforating trucks and cranes through which we provide 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-hole 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.

 

Logging Services.  Our logging services involve the gathering of down-hole information to identify various geological and mechanical characteristics of the wellbore. 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 data acquisition unit at the surface that contains instruments and computer equipment. The specialized, down-hole tools transmit data to the surface computer, which charts and records information about the formation or zone to be produced, such as rock type, porosity, permeability and the presence of hydrocarbons. As of December 31, 2009, we had nine logging crews of approximately two to three employees each and 31 logging trucks. We provide logging services from five different service centers: Buckhannon, West Virginia; Kimball, West Virginia; Black Lick, Pennsylvania; Hays, Kansas and Williston, North Dakota.

 

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 a 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. As of December 31, 2009, we had 21 perforating crews of approximately two to four employees each and 87 perforating trucks and cranes. We provide perforating services from 12 different service centers: Mercer, Pennsylvania; Black Lick, Pennsylvania; Bradford, Pennsylvania; Buckhannon, West Virginia; Kimball, West Virginia; Gaylord, Michigan; Cottondale, Alabama; Hominy, Oklahoma; Hays, Kansas; Williston, North Dakota; Brighton, Colorado and Midland, Texas.

 

Fluid Logistics Services

 

Fluid logistics services were added in connection with our Diamondback asset acquisition in November 2008 and accounted for 5.3% and 1.2% of revenues for the years ended December 31, 2009 and 2008, respectively. Oil and natural gas operations use and produce significant quantities of fluids. We provide a variety of services to assist our customers to obtain, transport, store and dispose of fluids that are involved in the drilling, development and production of hydrocarbons. As of December 31, 2009, we owned or leased over 100 fluid hauling transports and trucks, which are used to transport various fluids in the lifecycle of an oil or natural gas well. As of December 31, 2009, we also owned approximately 400 frac tanks that we rent to producers for use in fracturing and stimulation operations and for other fluid storage needs. We use our fleet of fluid hauling trucks to fill and empty the frac tanks and we deliver and remove these tanks from our customers’ well sites. As of December 31, 2009, we owned and operated six underground water disposal wells in Texas and Oklahoma. The disposal wells are an important component of fluid logistic operations as they provide an efficient solution for the disposal of waste waters. We provide fluid logistics services from three different services centers: Countyline, Oklahoma; Sweetwater, Oklahoma and Tolar, Texas.

 

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, Weatherford International Ltd., Baker Hughes Incorporated and a number of smaller independent competitors for our down-hole surveying services. Our major competitors for our fluid logistics and our completion, production and rental tool services include Complete Production Services, Inc., Key Energy Services, Inc., Basic Energy Services, Inc. and a significant number of smaller independent competitors. We believe that the principal competitive factors in the market areas that we serve are price, product and service quality, safety record, availability of crews and equipment and technical proficiency.

Customers and Markets

 

The majority of our customers are regional, independent oil and natural gas companies. The following table shows the geographic diversity of our revenue for the periods indicated (amounts in thousands):

 

 

 

 

During 2009, we provided services to over 1,200 customers, with our top five customers comprising approximately 42.9% of our total revenue. The following table shows information regarding our top five customers in 2009:

 

 

 

We believe our relationships with these significant customers are 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:

 

 

We have a take-or-pay contract with Preferred Rocks USS, Inc. to purchase fracturing sand through December 2015. We amended this contract in January of 2010. The minimum purchases under the take-or-pay contract as amended are estimated at $14.2 million in 2010, 2011, 2012, 2013, 2014 and 2015, respectively.

 

Operating Risks and Insurance

 

Our operations are subject to hazards inherent in the oil and natural gas industry, including accidents, blowouts, explosions, craterings, fires, oil spills and hazardous materials spills. These conditions can cause:

 

 

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 will experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability, and our

relationship with customers, employees and regulatory agencies. Any significant increase in the frequency or severity of these incidents, or the general level of compensatory payments, 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. The insurance coverage that we maintain includes employer’s liability, pollution, cargo, umbrella, comprehensive commercial general liability, workers’ compensation and limited physical damage insurance. We cannot assure you, 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 that are acceptable to us. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on our financial condition and results of operations.

 

Safety Program

 

In the oilfield 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 and regulations governing 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 implement and enforce these laws and regulations, 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 imposition of remedial obligations or the issuance of injunctions limiting or prohibiting some or all our operations.

 

Some laws and regulations relating to protection of the environment may impose strict and, in some circumstances, joint and several liability for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of that person. Strict adherence with these laws and regulations 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 but we can provide no assurance that this trend will continue. Moreover, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect upon our capital expenditures, earnings or competitive position.

 

The following is a summary of the more significant existing environmental laws to which our business operations are subject and with which compliance may have a material adverse effect on our capital expenditures, earnings or competitive position.

 

The Comprehensive Environmental Response, Compensation and Liability Act, as amended, 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, for damages to natural resources and for the costs of certain 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 released into the environment. While we generate materials in the course of our operations that may be regulated as hazardous substances, we have not received any currently pending notification that we may be potentially responsible for cleanup costs under CERCLA.

 

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 solid 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 petroleum hydrocarbons and 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 petroleum hydrocarbons and wastes have been taken for recycling or 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 petroleum 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.

 

Our operations are subject to the federal Water Pollution Control Act, as amended, referred to as the 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. These laws also regulate the discharge of stormwater in process areas. Pursuant to these laws and regulations, we are required to obtain and maintain approvals or permits for the discharge of wastewater and stormwater and develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans” in connection with on-site storage of greater than threshold quantities of oil. We believe that our operations are in substantial compliance with applicable Clean Water Act and analogous state requirements, including those relating to wastewater and stormwater discharges and SPCC plans.

 

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

adverse effect on natural gas production activities in shale formations, which in turn could have an adverse effect on the hydraulic fracturing services that we render for our exploration and production customers.

 

The Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources in the United States, including bulk cement facilities. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. We believe we are in substantial compliance with the Clean Air Act, including applicable permitting and control technology requirements.

 

In response to studies suggesting that emissions of certain gases commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere and other climatic changes, President Obama has expressed support for, and Congress is actively considering legislation to restrict or regulate emissions of greenhouse gases by establishing an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases. In addition, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Also, the EPA has determined that greenhouse gases present an endangerment to public health and the environment and, consequently, has proposed regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and could trigger permit review for greenhouse gas emissions from certain stationary sources, as well as adopted regulations requiring the reporting of greenhouse gas emissions from specified large greenhouse gas sources in the United States. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such new federal, regional, or state restrictions on emissions of carbon dioxide or other greenhouse gases that may be imposed in areas in which we conduct business could result in increased compliance or operating costs or additional operating restrictions, any of which could have a material adverse effect on our business or demand for the services we provide to oil and gas producers.

 

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 (“NRC”) and certain states under agreement with the NRC 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.

 

The federal Endangered Species Act (the “ESA”) and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. While some of our facilities may be located in, or otherwise serve, areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas. For example, the U.S. Fish and Wildlife Service (“USFW”) is currently evaluating whether the Sage Grouse, a ground-dwelling bird that inhabits portions of the Rocky Mountain region including Wyoming, where we provides our services to oil and natural gas exploration and production operators, requires protection as an endangered species under the ESA. The USFW is expected to render a determination on protection of the Sage Grouse in 2010. An Endangered Species Act designation could result in broad conservation measures restricting or even prohibiting oil or natural gas exploration and production activities in affected areas. Any curtailment in exploration and production activities by operators for whom we conduct services could have an adverse effect on our financial condition or results of operations. Moreover, the federal Bureau of Land Management and the State of Wyoming are pursuing separate strategies to maintain and enhance Sage Grouse habitat, which could have an adverse effect on oil and natural gas production and related support services in affected areas.

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 material adverse effect on our financial condition and results of 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, 2009, we employed 1,407 people, with approximately 70% 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.

 

Available Information

 

We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains a website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents that we file with the SEC at http://www.sec.gov.

 

Our website address is www.swsi.com. We make available, free of charge through the Investor Relations portion of this website, annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the 1934 Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Reports of beneficial ownership filed pursuant to Section 16(a) of the 1934 Act are also available on our website. Information contained on our website is not part of this report.

 

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.

 

Demand for our products and services is particularly sensitive to the level of exploration, development and production activity of, and the corresponding capital spending by, oil and natural gas companies. 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:

 

 

The volatility of the oil and natural gas industry and the resulting 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, and we are uncertain whether these factors will have a negative impact on our results of operations in 2010 as compared to 2009.

 

Many of our customers’ activity levels and spending for our products and services may continue to be impacted by the sustained decline in oil and natural gas prices and the continued weakness in the credit and capital markets.

 

The demand for our services is substantially influenced by global economic conditions, current and anticipated 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. During 2009, growth in global economic activity slowed substantially compared to the prior year. At the present time, it appears that the rate at which the global economy has slowed has become more stable. However, additional slowing of global economic growth, and in particular in the United States and China, will likely continue to reduce demand for oil and natural gas, increase spare productive capacity and result in lower prices and adversely impact the demand for our services.

 

During 2009, oil and natural gas prices were volatile and substantially lower than the prior year. On March 4, 2010, the price of oil on the New York Mercantile Exchange was $80.87 per barrel and the price of natural gas was $4.76 per mcf compared to a 52-week high of $145.29 and $13.58 in 2008, respectively. These lower oil and natural gas prices have impacted our customers’ activity levels and spending for our products and services. While current energy prices are important contributors to positive cash flow for our customers, expectations about future prices and price volatility are generally more important for determining future spending levels. Our customers also take into account the volatility of energy prices and other risk factors by requiring higher returns for individual projects if

there is higher perceived risk. These factors have, and could continue to have a material and adverse effect on our customers’ activity levels, which would continue to have a material adverse effect on our results of operations.

 

In addition, many of our customers finance their exploration and development activities through cash flow from operations, the incurrence of debt or the issuance of equity. Global financial markets and economic conditions have been, and continue to be, weak and volatile, which has caused a continuation of the substantial deterioration in the credit and capital markets. These conditions have made, and will likely continue to make, it difficult for our customers to obtain funding for their capital needs from the credit and capital markets. The combination of a reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve based credit facilities and the lack of availability of debt or equity financing may result in a continued reduction in our customers’ spending for our products and services. A continued reduction in spending would have a material adverse effect on our operations.

 

Our ability to obtain funding for our capital projects may be limited due to continued weakness in the credit and capital markets.

 

Our ability to fund planned capital expenditures and to make acquisitions will depend on the availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. Equity and debt financing from the capital markets may not be available on acceptable terms, which will limit our growth and reduce our expansion capital expenditures. Accordingly, our capital expenditures budget for 2010 is $24 million, which is $2.1 million less than our capital expenditures in 2009.

 

As of December 31, 2009, we had $163.7 million of indebtedness comprising $82.7 million outstanding under our credit facility, $80.0 million of second lien notes due in 2013 and $1.0 million of mortgage and other notes payable. At December 31, 2009, availability under our credit facility was $10.0 million. Because of the downturn in the financial markets since the third quarter of 2008, including the issues surrounding the solvency of many institutional lenders and the failure of several banks, we may be unable to utilize the full borrowing capacity under our credit facility if any of the committed lenders is unable or unwilling to fund their respective portion of any funding request we make under our credit facility and the other lenders are not willing to provide additional funding to make up the portion of the credit facility commitments that the defaulting lender has refused to fund. Due to these factors, we cannot be certain that funding for our capital needs will be available from the credit markets if needed and to the extent required, on acceptable terms.

 

If funding for capital expenditures is not available when needed, or is available only on unfavorable terms, we may be unable to implement our long-term growth strategy, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

 

We may incur substantial indebtedness or issue additional equity securities to execute our long-term growth strategy, which may reduce our profitability and result in significant dilution to our stockholders.

 

Our long-term business strategy has included, and will continue to include, growth through the acquisitions of assets and businesses. To the extent we do not generate sufficient cash from operations, we may need to incur substantial indebtedness to finance future acquisitions and capital expenditures and also may issue equity securities to finance such acquisitions and capital expenditures. For example, we funded our acquisition of the Diamondback assets through the issuance of preferred stock and second lien notes and additional borrowing under our credit facility. Our business is capital intensive, with long lead times required to fabricate our equipment. If available sources of capital are 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 adversely affect our financial condition and results of operations. Any 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. Furthermore, competition for acquisition opportunities may escalate, increasing our cost of making further acquisitions or causing us to refrain from making additional acquisitions. We also must meet certain financial covenants in order to borrow money under our

credit facility to fund capital expenditures, and we may be unable to meet such covenants. Turmoil in the credit markets over the past year and the potential impact on liquidity of major financial institutions may have an adverse effect on our ability to fund our business strategy through borrowings, under either existing or newly created instruments in the public or private markets on terms we believe to be reasonable.

 

Our current and future indebtedness, including indebtedness associated with the Diamondback acquisition, could restrict our operations and make us more vulnerable to adverse economic conditions.

 

Following the Diamondback acquisition, we have significantly higher levels of debt and interest expense than we had immediately prior to the acquisition. As of December 31, 2009, we had approximately $163.7 million of indebtedness outstanding. Our total debt could increase, as we have available borrowing capacity of $10.0 million under our credit facility as of December 31, 2009 and we could issue additional notes or other indebtedness in the future.

 

A substantially increased level of combined indebtedness may have an adverse effect on our future operations, including:

 

 

Our credit facility and the terms of the indenture under which we issued our second lien notes in November 2008 also require 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.

 

Recent changes to our credit facility may hinder or prevent us from meeting our future capital needs.

 

We recently entered into an amendment to the credit agreement evidencing our credit facility that has reduced the total commitment under our credit facility to $100 million effective as of January 1, 2010, which amount will be further reduced by (i) an additional $25.0 million upon our receipt of a federal income tax refund of $20 million or more and (ii) by an additional $25.0 million upon the sale of all or substantially all of the assets of our fluid logistics services business. This reduction may hinder or prevent us from meeting our future liquidity needs. We cannot be certain that alternative funding will be available on acceptable terms. If available borrowings under our credit facility are insufficient to meet our liquidity needs and alternative funding is not available as needed, or is available only on more expensive or otherwise unfavorable terms, we may be unable to fund operating cash flow shortfalls, fund planned capital expenditures, make acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our business and financial condition.

 

The amount we are able to borrow under our credit facility is determined based on the value of our accounts receivable and property, plant and equipment. As part of the recent amendments to the credit agreement evidencing our credit facility, we revised the definition of “borrowing base” to consist solely of 80% of eligible accounts receivable if the total commitment under our credit facility is reduced to $50 million. Our borrowing base is subject to redetermination by lenders holding at least 51% of our outstanding borrowings on five days’ written notice.

Should there be a deficiency in the amount of our borrowing base in comparison to the outstanding debt under our credit facility, such deficiency would result in an event of default which would, absent a waiver or amendment, require repayment of outstanding indebtedness and accrued interest under the credit agreement within three business days. In addition, an event of default under the credit agreement would result in an event of default under the indenture governing our second lien notes, which could require repayment of the outstanding principal and interest on such notes. If we were unable to make those repayments, these defaults would have a material adverse effect on our business and financial condition.

 

If we fail to generate sufficient consolidated EBITDA during 2010 to comply with our debt covenants, we could be in default under the credit agreement evidencing our credit facility and the indenture governing our second lien notes.

 

The credit agreement evidencing our credit facility and the indenture governing our second lien notes contain a covenant that requires us to maintain a minimum quarterly consolidated EBITDA of $(2.5) million, $0, $0, $0 and $10 million for the fourth quarter of 2009, and the first, second, third and fourth quarters of 2010, respectively. As of December 31, 2009, we were in compliance with this covenant.

 

Demand for the majority of our services is dependent on the level of oil and gas expenditures made by our customers, which makes our operations sensitive to the current lower demand for energy and lower prices for oil and natural gas. As a result of the reduced demand for oilfield services in the markets that we serve, it may be difficult for us to generate enough consolidated EBITDA in future quarters to comply with the covenant described above. Any failure to be in compliance with any material provision or covenant of our credit agreement could result in a default which would, absent a waiver or amendment, require immediate repayment of outstanding indebtedness under our credit facility. Additionally, any event of default under our credit agreement would result in an event of default under the indenture governing our second lien notes, which could also require repayment of the outstanding principal and interest on such notes and could have a material adverse effect on our business and financial condition.

 

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 facility.

 

If we do not successfully manage the potential difficulties associated with our long-term growth strategy, our operating results could be adversely affected.

 

We have grown rapidly over the last several years through internal growth, including the establishment of new service centers, 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 among others, could present difficulties to us:

 

 

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 and profitability.

 

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. Additionally, discounts at new service centers are typically higher than at established service centers. For example, the opening of our service centers in Oklahoma, Colorado, Wyoming and New Mexico in 2007 was materially delayed due to late equipment deliveries, facility procurement delays and holdups in obtaining regulatory permits. These delays caused these service centers to open much later in 2007 than originally planned

and resulted in lower 2007 revenue for the new service centers in Oklahoma and New Mexico and no revenue contribution for the new service centers in Colorado and Wyoming. As a result, our net income and earnings per share in 2007 were materially lower than anticipated. We may continue to experience material negative impacts on our earnings due to our long-term expansion program and the delay in new service centers becoming profitable.

 

Our long-term business strategy also includes growth through the acquisitions of assets and other businesses. Acquisitions and business expansions involve numerous risks, including difficulties with the assimilation of the assets and operations of the acquired business, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the business associated with them and new geographic areas and the diversion of management’s attention from other business concerns. Further, unexpected costs and challenges may arise whenever businesses with different operations of management are combined. We may not be successful in integrating our acquisitions into our existing operations or in identifying all potential risks and liabilities associated with those acquisitions, which may result in unforeseen operational difficulties or diminished financial performance or require a disproportionate amount of our management’s attention. Even if we are successful in integrating our acquisitions into our existing operations, we may not derive the benefits, such as operational or administrative synergies, that we expected from such acquisitions, which may result in the commitment of our capital resources without the expected returns on such capital.

 

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 Chesapeake Energy Corp. or Atlas America, Inc., in particular, may adversely affect our financial results.

 

Although we have expanded our customer base, we derive a significant amount of our revenue from a relatively small number of independent oil and natural gas companies. In 2008 and 2009, eight companies accounted for 44% and 51% of our revenue, respectively. Our inability to continue to provide services to these key customers, if not offset by additional sales to other customers, could adversely affect our financial condition and results of operations. Moreover, the revenue we derived from our two largest customers, Chesapeake Energy Corp. and Atlas America, Inc., constituted approximately 21% and 11%, respectively, of our total revenue for the year ended December 31, 2009. 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 also impact our overall exposure to credit risk in that customers may be similarly affected by changes in economic and industry condition. Our customers are largely independent oil and natural gas producers, who are adversely affected by declines in the price of oil and natural gas. We do not generally require collateral in support of our trade receivables. A sustained decrease in prices, coupled with the continued weakness in the credit and capital markets, could have a material adverse effect on the results of operations of our customers and could further increase our credit risk.

 

The sustained decline in oil and natural gas prices and continued weakness in the credit and capital markets may expose us to credit risk from customers and counterparties.

 

We regularly review the financial performance of our customers. However, we do not generally require collateral in support of trade receivables, and the limited number of customers on which we depend for a substantial portion of our revenue exposes us to concentration of credit risk in that customers may be adversely affected by changes in economic and industry conditions. Our customers are largely independent oil and natural gas producers who are adversely affected by declines in the credit and capital markets and the price of oil and natural gas. Additional slowing of global economic conditions and further decreases in demand for oil and natural gas resulting in lower prices may adversely impact the financial viability of and increase the credit risk associated with our customers. Customer insolvencies in the oil and natural gas industry resulting from the recent economic downturn or lower oil and natural gas prices, or the financial failure of a large customer or distributor, an important supplier, or a group thereof, could require us to assume greater credit risk and could limit our ability to collect receivables. Although we intend to expand our customer base in an attempt to mitigate the concentration of credit risk, our inability to collect receivables could have an adverse impact on our operating results and financial condition.

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, safety record, 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.

 

Our industry is prone to overcapacity, which results in increased competition and lower prices for our services.

 

Because crude oil and natural gas prices and drilling activity were at historically high levels during 2007 and 2008, oilfield service companies acquired additional equipment to meet their customers’ increasing demand for services. This has resulted in an increased competitive environment and a significant increase in capacity among us and our competitors in certain of our operating regions. For example, this increased capacity resulted in significant downward pricing pressure and increased discounts for our services in certain of our operating regions, which adversely affected our financial condition and results of operations in 2009. Additionally, prices for crude oil and natural gas and utilization rates for drilling rigs declined significantly in the fourth quarter of 2008 and in 2009. A sustained decline in these prices could result in a lower number of wells that are commercially viable for the oil and natural gas producers that we service. A reduction in the number of wells that require service could also increase overcapacity in our industry. To the extent that overcapacity persists in 2010, we will continue to experience significant downward pricing pressure and lower demand for our services, which will continue to adversely affect our financial condition and results of operations.

 

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. As a result of the shale play expansion, we require substantially higher volumes of raw materials and equipment than we have historically needed. Our suppliers may not be able to satisfy this increased demand on schedule or at favorable prices and we may become more vulnerable to supply disruptions.

 

With the exception of our contracts with our largest suppliers of nitrogen and fracturing sand, we have no contracts with our suppliers to ensure the continued supply of materials. Historically, we have placed 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.

 

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:

 

 

 

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 experienced shortages in the availability of qualified field personnel. Any difficulty we experience adding or replacing 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 has recently been a reduced pool of qualified workers in our industry, particularly in the Rocky Mountain region, due to increased activity in the oilfield services and commercial trucking sectors. A reduction in the number of qualified workers now or in the future may make it difficult to find enough skilled and unskilled laborers if the demand for our services increases, including in particular demand related to our completion, production and rental tool services. 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 financial condition and results of operations 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 do so would have a material adverse effect on our financial condition and results of operations.

 

Our customers’ activity levels and demand for our services may be impacted by future legislation that may eliminate certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development.

 

President Obama’s Proposed Fiscal Year 2010 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to the oil and gas exploration and development activities conducted by our customers, and any such change could materially and adversely affect our customers’ activity levels and spending for our products and services which would have a material adverse effect on our financial condition and results of 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 also 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:

 

 

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.

 

We are subject to federal, state and local laws and regulations regarding issues of health, safety and protection of the environment. Under these laws and regulations, we may become liable for penalties arising from non-compliance, property and natural resource damages or costs of performing remediation. Any changes in these laws and 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, expenditures for compliance and remediation, and liability for property damages and personal injuries. Sanctions for noncompliance with applicable environmental laws and regulations 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 NRC and certain states under agreement with the NRC 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.

 

Among the assets that we acquired from Diamondback were six injection well disposal systems in North Texas and southern Oklahoma. We dispose of fluids, including saltwater, into the disposal wells, which poses some risk of liability, including leakage from the wells to surface and subsurface soils, surface water or groundwater. We also handle, transport and store these fluids. The handling, transportation, storage and disposal of these fluids are regulated by a number of laws, including the Resource Conservation and Recovery Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Clean Water Act; the Safe Drinking Water Act; and other federal and state laws and regulations. We also acquired assets that necessitate the handling of petroleum products, and failure to properly handle, store, transport or dispose of these materials in accordance with applicable environmental laws and regulations could expose us to liability for administrative, civil and criminal penalties, cleanup costs and liability associated with releases of such materials, damages to natural resources, and actions enjoining some or all of our operations.

 

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 joint and several, 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.

 

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for our services.

 

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Accordingly, the EPA has proposed regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and could trigger permit review for greenhouse gas emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. ACESA would require a 17% reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances authorizing emissions of greenhouse gases into the atmosphere. These reductions would be expected to cause the cost of allowances to escalate significantly over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and the Obama Administration has indicated its support for legislation to reduce greenhouse gas emissions through an emission allowance system. At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations or those of exploration and production operators for whom we perform oil and natural gas-related services could require us to

incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for our oil and natural gas support services. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations.

 

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect our support services.

 

Congress is currently considering two companions bills for the “Fracturing Responsibility and Awareness of Chemicals Act,” or “FRAC Act.” The bills would repeal an exemption in the federal Safe Drinking Water Act (“SWDA”) for the underground injection of hydraulic fracturing fluids near drinking water sources. Hydraulic fracturing is an important and commonly used process for the completion of natural gas, and to a lesser extent, oil wells in shale formations, and involves the pressurized injection of water, sand and chemicals into rock formations to stimulate natural gas production. Sponsors of the FRAC Act have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. If enacted, the FRAC Act could result in additional regulatory burdens such as permitting, construction, financial assurance, monitoring, recordkeeping, and plugging and abandonment requirements. The FRAC Act also proposes requiring the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities, who would then make such information publicly available. The availability of this information could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, various state and local governments are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. The adoption of the FRAC Act or any other federal or state laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete natural gas wells in shale formations, increase our costs of compliance, and adversely affect the hydraulic fracturing services that we render for our exploration and production customers.

 

The Subcommittee on Energy and Environment the of the U.S. House of Representatives (the “House Subcommittee”) is currently examining the practice of hydraulic fracturing in the United States and is gathering information on its potential impacts on human health and the environment. On February 18, 2010, we, along with seven other oilfield service companies that perform hydraulic fracturing in the United States, received a letter from the House Subcommittee requesting the voluntary production of various categories of data and other information relating to hydraulic fracturing activities between 2005 and 2009. There have been no allegations made against us related to our hydraulic fracturing activities, and we have notified the House Subcommittee that we intend to cooperate in providing the requested information.

 

Our internal control over financial reporting may be or become insufficient to allow us to accurately report our financial results or prevent fraud, which could cause our financial statements to become materially misleading and adversely affect the trading price of our common stock.

 

We are required under Section 404 of the Sarbanes-Oxley Act of 2002 to furnish a report by our management on the design and operating effectiveness of our internal control over financial reporting. In connection with our Section 404 compliance efforts, we continue to identify remedial measures to improve or strengthen our internal control over financial reporting. If these measures are insufficient to address any future issues, or if material weaknesses or significant deficiencies in our internal control over financial reporting are discovered in the future, we may fail to meet our financial reporting obligations. If we fail to meet these obligations, our financial statements could become materially misleading, which could adversely affect 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 and 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.

 

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, with 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:

 

 

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.

 

 

None.

 

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 28 service centers, five of which we own and 23 of which we lease. Each office typically includes a yard, administrative office and maintenance facility. Our Appalachian region service centers are located in Bradford, Black Lick and Mercer, Pennsylvania; Kimball, Buckhannon and Jane Lew, West Virginia; Norton, Virginia and Gaylord, Michigan. Our Southeast region service centers are located in Cottondale, Alabama; Columbia, Mississippi; and Bossier City and Broussard, Louisiana. Our Mid-Continent region service centers are located in Hominy, Clinton, Marlow, Countyline, Sweetwater, and Elk City, Oklahoma; Van Buren, Arkansas; and Hays, Kansas. Our Rocky Mountain region service centers are located in Vernal, Utah; Rock Springs, Wyoming; Williston, North Dakota; and Brighton, Colorado. Our Southwest region service centers are located in Cresson, Tolar, Midland and Victoria, Texas. Our fluid logistics services business segment provides services out of our service centers in Countyline and Sweetwater, Oklahoma and Tolar, Texas. All other service centers are dedicated to our technical services business segment. 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 or sales office 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:

 

 

 

 

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, results of operations or cash flows.

 

 

 

Market Information for Common Stock

 

Our common stock is traded on The NASDAQ Stock Market LLC under the symbol “SWSI.” As of March 3, 2010, there were 30,906,573 shares outstanding, held by approximately 239 holders of record. 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 Global Select Market during 2008 and 2009.

 

 

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. Additionally, the terms of our Series A 4% convertible preferred stock provide that no dividends may be paid on any shares of our common stock unless and until all accumulated and unpaid dividends on outstanding shares of our Series A 4% convertible preferred stock have been declared and paid in full. As of February 28, 2010, all dividends that had accumulated on our Series A 4% convertible preferred stock through December 31, 2009 had been paid in full. 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.

 

Purchases of Equity Securities By the Issuer and Affiliated Purchases

 

During the quarter ended December 31, 2009, we purchased 366 shares of common stock that were surrendered by employees to pay tax withholding upon the vesting of restricted stock awards. These repurchases were not part of a publicly announced program to repurchase shares of our common stock.

 

The selected consolidated financial information contained below is derived from our Consolidated Financial Statements and should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our audited consolidated financial statements included in Item 8 of this Annual Report on form 10K.

 

 

 

 

 

 

		Year Ended December 31,
		2005				2006				2007				2008				2009
Reconciliation of Adjusted EBITDA to Net Income (Loss):
Net income (loss)		$	9,467			$	31,923			$	37,755			$	38,812			$	(79,615	)
Income tax expense (benefit)			13,826				20,791				24,570				27,362				(47,291	)
Interest expense			566				478				282				2,834				13,762
Stock compensation expense			—				1,740				1,961				2,522				2,941
Goodwill and intangible impairment			—				—				—				—				33,479
Depreciation, amortization and accretion			8,698				14,453				25,277				41,806				72,418
Adjusted EBITDA		$	32,557			$	69,385			$	89,845			$	113,336			$	(4,306	)

 

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this report. This discussion contains forward-looking statements 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 factors such as those set forth below under “Forward-Looking Statements and Risk Factors.”

 

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. We service our customers in key markets in many of the active domestic oil and natural gas producing regions in the Appalachian, Mid-Continent, Rocky Mountain, Southwest 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 and follow-on offerings of common stock in December 2006 for 3,690,000 shares at a price of $25.50 per share and in October 2009 for 6,900,000 shares at a price of $10.50 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.

 

In November 2008, we purchased the pressure pumping, fluid logistics and completion, production and rental tools business lines from Diamondback for approximately $202.0 million. The acquisition consideration consisted of $71.5 million in cash, $42.9 million of our Series A 4% Convertible Preferred Stock ($75 million liquidation preference) and $80 million in second lien notes aggregating $194.4 million plus $7.6 million of transaction costs for a total purchase price of $202.0 million. See Note 3 to our consolidated financial statements for more information. As part of the acquisition, we acquired 128,000 horsepower, 105 transports and trucks, 400 frac tanks, six water disposal wells and completion and rental tool businesses in Louisiana, Texas and Oklahoma. The assets that we purchased from Diamondback are operating in the Anadarko, Arkoma, and Permian Basins, as well as the Barnett Shale, Woodford Shale, West Texas, Southern Louisiana and Texas Gulf Coast.

 

Services Offered

 

Our services are conducted through two principal business segments, which are technical services and fluid logistics services. Each business segment includes service lines that contain similarities among customers, financial performance and management, as well as the economic and business conditions impacting their activity levels. Technical services include technical pumping services, completion, production and rental tool services and down-hole surveying services. Fluid logistics services include those services related to the transportation, storage and disposal of fluids that are used in the drilling, development and production of hydrocarbons. Substantially all of our customers are domestic oil and natural gas exploration and production companies that typically require all 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 Services

 

Technical Pumping Services

 

We offer three types of technical pumping services — stimulation, nitrogen and cementing services — which accounted for 65.7%, 6.4% and 13.2% of our revenue for the year ended December 31, 2009 and 64.2%, 6.7% and 18.0% of our revenue for the year ended December 31, 2008, 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 2008 and 2009. 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.

 

Completion, Production and Rental Tool Services

 

Completion and production services were added in connection with the Diamondback asset acquisition and accounted for 3.6% and 0.4% or our revenues for the years ended December 31, 2009 and 2008, respectively. Our completion and production services and other production related activities include specialty services, many of which are performed after drilling has been completed. Consequently, these services occur later in the lifecycle while a well is being completed or during the production stage. These specialty services include plugging and abandonment, gravel pack, storm valves, roustabout services, as well as the sale and rental of equipment. As newly drilled oil and natural gas wells are prepared for production, our completion services include selectively testing producing zones of the wells before and after stimulation.

 

Down-Hole Surveying Services

 

We offer two types of down-hole surveying services — logging and perforating — which collectively accounted for approximately 5.8% and 9.4% of our revenues for years ended December 31, 2009 and 2008, respectively. 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 fires 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. 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.

 

Fluid Logistics Services

 

Oil and natural gas operations use and produce significant quantities of fluids. We provide a variety of services to assist our customers to obtain, transport, store and dispose of fluids that are involved in the drilling, development and production of hydrocarbons. We own or lease over 100 fluid hauling transports and trucks, which are used to transport various fluids in the lifecycle of an oil or natural gas well. As of December 31, 2009, we also owned approximately 400 frac tanks that we rent to producers for use in fracturing and stimulation operations plus other fluid storage needs. We use our fleet of fluid hauling trucks to fill and empty the frac tanks and we deliver and remove these tanks from the well sites. As of December 31, 2009, we owned and operated six water disposal wells in North Texas and southern Oklahoma. The disposal wells are an important component of our fluid logistics operations as they provide an efficient solution for the disposal of waste waters. Our fluid logistics services accounted for approximately 5.3% and 1.2% of our revenues for the years ended December 31, 2009 and 2008, respectively.

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, completion, production and rental tool 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 four 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.

 

We generate revenue from our fluid logistics services by charging our customers based on volumes of fluids transported and disposed of and rental charges for use of our frac tanks. The rates for the transportation of fluids are generally determined by a competitive bid process and depend upon the type of service to be performed, the equipment and personnel and the cost of goods required for the particular job and the market conditions in the region in which the service is performed. The rates for our fluid disposal services vary depending on the type of fluid being disposed of, and the rates charged are generally driven by market conditions in the region the disposal well is located. Frac tanks are rented on a daily basis and the rates are generally driven by market conditions in the region the disposal well is located.

 

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) Adjusted EBITDA.

 

Operating Income (Loss) per Operating Region.

 

We currently service customers in five operating regions through our 28 service centers. In April 2009, we ceased operations at our service centers in Wooster, Ohio and Cleveland, Oklahoma due to significant activity declines in those areas. In October 2009, we ceased operations at our service centers in Clinton and Coalgate Oklahoma; Trinidad, Colorado; Alvarado, Texas and Artesia, New Mexico due to significant activity declines in those areas. In 2010 we ceased operations at our service center in Farmington, New Mexico due to significant activity declines in this area. Our Appalachian region service centers are located in Bradford, Black Lick and Mercer, Pennsylvania; Kimball, Buckhannon and Jane Lew, West Virginia; Norton, Virginia; and Gaylord, Michigan. Our Southeast region service centers are located in Cottondale, Alabama; Columbia, Mississippi; and Bossier City and Broussard, Louisiana. Our Mid-Continent region service centers are located in Hominy, Clinton, Marlow, Countyline, Sweetwater, and Elk City, Oklahoma; Hays, Kansas; and Van Buren, Arkansas. Our Rocky Mountain region service centers are located in Vernal, Utah; Rock Springs, Wyoming; Williston, North Dakota; and Brighton, Colorado. Our Southwest region service centers are located in Cresson, Tolar, Midland and Victoria, Texas.

 

The operating income (loss) generated in each of our operating regions is an important part of our operational analysis. We monitor operating income (loss) 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 (loss) 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 (loss) that we generate in the relevant region.

Material, Maintenance, Fuel and Labor Expenses as a Percentage of Revenue.

 

A significant portion of the cost of revenues is comprised of the cost of materials, maintenance, fuel and the wages of our field personnel. Although, the cost of these expenses as a percentage of revenue has historically remained relatively stable for our established service centers, the industry has experienced an unprecedented decline in drilling activity during 2009 compared to the prior year. This rapid and deep reduction in drilling activity has resulted in heavy pricing pressure and severe margin contraction in all our service offerings. As a result, our ability to pass on cost increases to customers has been limited and material, maintenance, fuel and labor expenses as a percentage of revenue has increased significantly in 2009.

 

Our material costs primarily include the cost of inventory consumed while performing our stimulation, nitrogen and cementing services. We try to pass on to our customers the increases in our material and fuel costs. 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. In the current competitive environment, it is very difficult to pass on these increases to our customers.

 

Our labor costs consist primarily of wages for our field personnel. If we experience a shortage of qualified supervision personnel and equipment operators in certain areas in which we operate, 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 try to pass on higher wage expenses through an increase in our service rates. In the current competitive environment, it is very difficult to pass on these increases to our customers.

 

Selling, General and Administrative Expenses as a Percentage of Revenue.

 

Our selling, general and administrative expenses, or SG&A expenses, include 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 aggregate selling, general and administrative expenses have increased as a result of the growth in operations.

 

Adjusted EBITDA

 

We define Adjusted EBITDA as net income (loss) before interest expense, income tax expense, non-cash stock compensation expense, non-cash goodwill and intangible impairment, depreciation, amortization and accretion expense. We believe Adjusted EBITDA is useful to an equity investor in evaluating our operating performance because:

 

 

Our management uses Adjusted EBITDA:

 

 

Adjusted EBITDA is not a measure of financial performance under GAAP and should not be considered in isolation or as an alternative to cash flow from operating activities or as an alternative to net income (loss) as indicators of operating performance or any other measures of performance derived in accordance with GAAP. Other companies in our industry may calculate Adjusted EBITDA differently than we do and Adjusted EBITDA may not be comparable with similarly titled measures reported by other companies. See Item 6 “Selected Financial Data” for a reconciliation of Adjusted EBITDA to net income (loss).

 

How We Manage Our Operations

 

Our management team uses a variety of tools to manage our operations. These tools include monitoring: (1) service crew utilization and performance; (2) equipment maintenance performance; (3) customer satisfaction; and (4) 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. 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.

 

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 and Recent Developments

 

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. Long-term

forecast for energy demand suggests an increasing demand for oil and natural gas, which when coupled with flat or declining production curves, we believe should result over the long-term in the continuation of historically high crude oil and natural gas commodity prices.

 

The current economic recession and credit environment has lowered demand for energy resulting in significantly lower prices for crude oil and natural gas. North American drilling activity declined rapidly in the first six months of 2009 with the U.S. rig count dropping 58% over this period. This decrease in activity, coupled with increased price competition, has led to higher sales discounts across our operating regions that have negatively impacted our operating margins.

 

The extent and duration of this downturn is uncertain. We have responded to this downturn by implementing cost control measures including:

 

 

While it is challenging to predict the movements and extent of this downturn, we have witnessed a slow and steady increase in the drilling rig counts beginning in the third quarter of 2009, we continue to experience heavy pricing pressure in all of our service offerings. We believe these pressures will continue until drilling activity materially increases and the current imbalance of excess capacity is reabsorbed.

 

Our Business Outlook

 

The current economic environment has lowered demand for energy and resulted in significantly lower prices for crude oil and natural gas in 2009 as compared to 2008. Demand for the majority of our services is dependent on the level of oil and gas expenditures made by our customers in the exploration and production industry. These expenditures are sensitive to the oil and gas prices our customers receive for their production, the industry’s view of future oil and gas prices and the ability of our customers to access the financial and credit markets. Since the last half of 2008, the financial and credit markets have weakened substantially and demand for crude oil and natural gas has declined. As a result, crude oil and natural gas prices fell sharply, which caused a decline in the demand for our services as customers have reduced their exploration and production expenditures.

 

The price of crude oil and natural gas has improved from pricing levels experienced during the fourth quarter of 2008 and the first half of 2009, and this improvement has begun to be reflected in increased drilling activity. As of March 5, 2010 the 12-month strip for crude oil (West Texas Intermediate) and natural gas (Henry Hub) was $82.20 and $5.16, respectively. At current commodity prices, we expect that the current levels of drilling activity can be maintained in the near term. We believe that natural gas storage levels at the end of the 2010 winter withdrawal season will be a significant determining factor as to whether drilling activity increases or decreases from existing levels. If economic conditions continue to worsen and commodity prices decline further, the demand for our services could continue to decrease as customers make further reductions in their oil and gas expenditures. The extent and duration of the economic downturn and financial market deterioration is uncertain at this time, but we will continue to focus on labor cost efficiencies and monitor discretionary spending to respond to prevailing levels of activity. However, we believe our ability to service more technically complex plays, our participation in many of the most active drilling plays in the United States, as well as our regional strength in the Appalachian region will generally help us to maintain a strong and competitive position.

Historical market conditions are reflected in the table below:

 

 

 

 

Our Long-term Growth Strategy

 

Given the current market conditions it is unlikely that we will experience significant growth in the near term. However, our long-term 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, such as our recent acquisition of the Diamondback assets, 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 long-term 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 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. During 2009, increased capacity in each of our operating regions has resulted in significant downward pricing pressure and increased discounts in our service prices. We expect this pricing pressure to continue in these regions until the level of activity increases to absorb the excess capacity. 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 has a lesser impact on our overall results of operations.

 

Results for the year ended December 31, 2009 compared to the year ended December 31, 2008

 

Our results of operations from our primary categories of services consisted of the following for each of the years in the three-year period ended December 31, 2009:

 

Revenue

 

The following table summarizes the dollar and percentage changes for the types of oilfield service revenues for the year ended December 31, 2009 when compared to the year ended December 31, 2008 (dollars in thousands):

 

 

The following table summarizes the dollar and percentage change in our revenues from each operating region for the year ended December 31, 2009 when compared to the year ended December 31, 2008. (dollars in thousands):

 

 

Revenue was $399.5 million for year ended December 31, 2009 compared to $520.9 million for the year ended December 31, 2008, a decrease of 23.3%. This decrease was primarily due to lower demand and higher sales discounts for our services, partially offset by revenues from the Diamondback acquisition and increased activity levels at new service centers that were established within the last twelve months (“New Centers”). The operations we acquired in the Diamondback asset acquisition represented approximately $90.4 million of the change in revenue for the year ended December 31, 2009 compared to the same period in the prior year and increased activity from New Centers represented approximately $22.1 million of the change in revenue during the same period. Drilling activity levels in each of our operating regions were significantly impacted by decreased oil and natural gas exploration and development spending during the year ended December 31, 2009 compared to the same period in 2008. Demand for our services was impacted by this decline in drilling rig activity. As a result, we experienced pricing erosion in all of our service offerings during year ended December 31, 2009 compared to the same period in 2008. As a percentage of gross revenue, sales discounts increased 10.3% for the year ended December 31, 2009 compared to the same period in 2008 due to increased capacity and increased competition in our operating regions that resulted in significant downward pressure on our prices. All of our operating regions experienced substantially higher sales discounts during 2009 compared to 2008. Our stimulation, nitrogen and cementing services continue to see the greatest downward pricing pressure. During 2009, we also saw an $18.8 million reduction in 2009 net revenues resulting from the elimination of fuel surcharges that we were receiving from our customers during 2008.

Cost of Revenue

 

Cost of revenue increased 5.3% or $21.7 million for the year ended December 31, 2009 compared to the year ended December 31, 2008. The operations we acquired in the Diamondback acquisition represented approximately $107.9 million of our cost of revenue for the year ended December 31, 2009 and increased activity from New Centers represented approximately $26.1 million of our cost of revenue during the same period. As a percentage of net revenue, cost of revenue increased to 107.1% for the year ended December 31, 2009 from 78.0% for the year ended December 31, 2008 due primarily to higher sales discounts on materials, lower labor utilization due to the drop in drilling activity and higher depreciation expenses. As a percentage of net revenue, material costs, labor expense and depreciation increased for the year ended December 31, 2009 compared to the same period in 2008 by 8.9%, 6.5%, and 8.9%, respectively. Material costs as a percentage of gross revenues decreased 0.5% during the year ended December 31, 2009 when compared to the same period in 2008. However, the year-over-year increase in material costs as a percentage of net revenue was due to higher sales discounts on materials. Labor expenses as a percentage of net revenue increased 6.5% to 25.3% for the year ended December 31, 2009 compared to the same period in 2008 because of lower utilization due to rapidly declining demand for our services. Depreciation expense as a percentage of net revenue increased 8.9% for the year ended December 31, 2009 compared to the same period in 2008 due to additional assets acquired in the Diamondback acquisition were not fully utilized as a result of decrease in the demand for our services. Additionally, the substantially higher level of sales discounts during the year ended December 31, 2009 compared the year ended December 31, 2008 impacts the comparability of the year-over-year increases for materials, labor and depreciation.

 

Selling, General and Administrative Expenses (SG&A)

 

SG&A expenses, as a percentage of net revenue, increased by 4.4% to 13.2% for the year ended December 31, 2009 due to higher costs and a lower revenue base. Labor, professional services and rent expense increased $3.4 million, $0.8 million and $1.9 million, respectively, for the year ended December 31, 2009 compared to the same period in 2008. The operations we acquired in the Diamondback acquisition accounted for approximately $16.1 million of our SG&A expenses for the year ended December 31, 2009. As a percentage of net revenue, the portion of labor expenses included in SG&A expenses increased 2.5% in the year ended December 31, 2009 compared to the same period in 2008 due to additional personnel hired in connection with the Diamondback acquisition. Additionally, the higher level of sales discounts during the year ended December 31, 2009 compared to the same period in 2008 impacts the comparability of the year-over-year increase for labor expenses.

 

Goodwill and Intangible Impairment

 

In the second quarter of 2009, we recorded a non-cash charge totaling $33.2 million for impairment of the goodwill associated with our technical services and fluid logistics services business segments.

 

In the third quarter of 2009, we recorded a non-cash charge totaling $0.3 million for impairment of intangible assets associated with the closure of our Trinidad, Colorado downhole surveying service center.

 

Operating Income (Loss) and Adjusted EBITDA

 

Operating loss was $(114.4) million for the year ended December 31, 2009 compared to operating income of $69.1 million for the same period in 2008, a decrease of $183.5 million. As a percentage of revenue, operating loss decreased to (28.6%) in the year ended December 31, 2009 compared to operating income of 13.3% for the year ended December 31, 2008. New Centers and the Diamondback acquisition decreased operating income by approximately $5.2 million and $33.3 million, respectively, for the year ended December 31, 2009 compared to the same period in 2008. Adjusted EBITDA decreased $117.6 million for the year ended December 31, 2009 compared to same period in 2008 to $(4.3) million. For a definition of Adjusted EBITDA and a discussion of Adjusted EBITDA as a performance measure please see “— How We Evaluate Our Operations — Adjusted EBITDA.” For a reconciliation of Adjusted EBITDA to net income (loss), please see “— Selected Financial Data.” Net income decreased $118.4 million to a net loss of $79.6 million for the year ended December 31, 2009 compared to the same period in 2008 due to decreased activity levels and lower pricing as described above.

Results for the Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

 

Revenue

 

The following table summarizes the dollar and percentage changes for the types of oilfield service revenues for the year ended December 31, 2008 when compared to the same period in 2007 (dollars in thousands):

 

 

The following table summarizes the dollar and percentage change in our revenues from each operating region for the year ended December 31, 2008 when compared to the same period in 2007 (dollars in thousands):

 

 

Revenue was $520.9 million for the year ended December 31, 2008 compared to $350.8 million for the year ended December 31, 2007, an increase of 48.5%. All regions reflected revenue increases for the year ended December 31, 2008 when compared to the same period in 2007. The year-over-year revenue growth was driven by strong activity increases in our stimulation and cementing services. New Centers, existing centers and 2008 acquisitions comprised 52%, 33% and 15% of the revenue increase in 2008 as compared to 2007. New Centers for 2008 include: Jane Lew, West Virginia (Appalachian), Clinton, Oklahoma (Mid-Continent), Hays, Kansas (Mid-Continent), Artesia, New Mexico (Southwest), Midland, Texas (Southwest), Williston, North Dakota (Rocky Mountain), Brighton, Colorado (Rocky Mountain), and Rock Springs, Wyoming (Rocky Mountain). Our Rock Springs, Wyoming service center did not generate any 2008 revenues. Increased revenue activity levels at existing service centers were partially offset by higher sales discounts for the year ended December 31, 2008 as compared to the year ended December 31, 2007 as a result of increased capacity, greater competition in the operating regions served by these service centers and higher percentage of revenue growth being contributed from New Centers that have higher sales discounts than our established service centers. All of our operating regions experienced higher sales discounts during 2008 as compared to 2007. Our stimulation and cementing services saw the greatest downward pricing pressure in 2008. As a percentage of revenues, increases in stimulation and cementing sales discounts were in the high single digits for 2008 as compared to 2007.

Cost of Revenue

 

Cost of revenue increased 60.8% or $153.5 million for the year ended December 31, 2008 compared to the year ended December 31, 2007. The increase was due to the variable nature of many costs, including materials and fuel. As a percentage of revenue, cost of revenue increased to 78.0% for the year ended December 31, 2008 from 72.0% for year ended December 31, 2007 due to lower utilization caused by poor weather during the first quarter of 2008 in the Appalachian region and increased costs during 2008 for materials and fuel that could not be passed through to our customers through price increases because of the increasingly competitive environment. As a percentage of revenue, material costs, depreciation, and fuel costs increased for the year ended December 31, 2008 as compared to the year ended December 31, 2007 by 4.4%, 0.5% and 1.5%, respectively. Material costs as a percentage of revenue increased 4.4% for year ended December 31, 2008 compared to the year ended December 31, 2007 due to higher sand, chemical and cement costs, as well as transportation expenses incurred to deliver materials. As a percentage of revenue, depreciation expenses increased 0.5% to 7.5% for year ended December 31, 2008 compared to year ended December 31, 2007 due to the higher levels of capital expenditures made to expand our equipment fleet. Higher diesel prices increased our fuel costs as a percentage of revenue by 1.5% for year ended December 31, 2008 compared to year ended December 31, 2007. New Centers and the Diamondback acquisition accounted for approximately $74.8 million and $19.9 million of the aggregate increase in cost of revenue for the year ended December 31, 2008 compared to the year ended December 31, 2007, respectively.

 

Selling, General and Administrative Expenses

 

SG&A expenses increased 25.6% to 45.7 million for the year ended December 31, 2008 compared to $36.4 million for the year ended December 31, 2007. As a percentage of revenue, SG&A expenses decreased by 1.6% to 8.8% for the year ended December 31, 2008 from 10.4% for the year ended December 31, 2007 due to our ability to leverage certain of these fixed costs over a higher revenue base. As a result of the growth in our operations, aggregate labor expenses increased by $7.3 million to $28.4 million for the year ended December 31, 2008 compared to the year ended December 31, 2007. As a percentage of revenue, the portion of labor expenses included in SG&A expenses decreased 0.5% to 5.5% for the year ended December 31, 2008 compared to the year ended December 31, 2007. New Centers and the Diamondback asset acquisition accounted for approximately $2.2 million and $2.5 million of the increase in SG&A expense for the year ended December 31, 2008 compared to the year ended December 31, 2007, respectively. During the second half of 2007, we hired additional personnel to manage the growth in our operations and added six service centers.

 

Operating Income and Adjusted EBITDA

 

Operating income was $69.1 million for the year ended December 31, 2008 compared to $61.8 million for the year ended December 31, 2007, an increase of 11.8%. As a percentage of revenue, operating income decreased from 17.6% for the year ended December 31, 2007 to 13.3% for the year ended December 31, 2008. The primary reasons for this decrease were higher material, depreciation and fuel costs, as well as increased discounts for our services as described above. New Centers and the Diamondback asset acquisition increased operating income by approximately $11.9 million and $3.5 million for the year ended December 31, 2008 compared to the year ended December 31, 2007, respectively. Adjusted EBITDA increased $23.5 million for the year ended December 31, 2008 compared to the year ended December 31, 2007 to $113.3 million. For a definition of Adjusted EBITDA, and a reconciliation of Adjusted EBITDA to net income, please see “Selected Financial Data.” Net income increased $1.1 million to $38.8 million for the year ended December 31, 2008 compared to the year ended December 31, 2007 due to increased activity levels described above.

 

Items Impacting Comparability of Our Financial Results

 

Diamondback Acquisition

 

In November 2008, we purchased the pressure pumping, fluid logistics and completion, production and rental tool assets from Diamondback Energy Holdings, LLC. In connection with the asset purchase, we formed SWSI Fluids, LLC to acquire the fluid logistics assets. SWSI Fluids LLC is our wholly owned subsidiary.

Non-cash Compensation Expense

 

We account for equity transactions using an approach in which the fair value of an award is estimated at the date of grant and recognized as an expense over the requisite service period. Our results of operations for the years ended December 31, 2007, 2008 and 2009 include $2.0 million, $2.5 million and $2.9 million, respectively, of additional compensation expense primarily as a result of the restricted stock awards that we granted in January 2006 through 2009.

 

Liquidity and Capital Resources

 

We rely on cash generated from operations, public and private offerings of debt and equity securities and borrowings under our credit facility to satisfy our liquidity needs. Our ability to fund operating cash flow shortfalls, fund planned capital expenditures and 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, 2009, we had $25,000 of cash and cash equivalents and $10.0 million of availability under our credit facility that can be used to fund operating cash flow shortfalls and planned capital expenditures. Our ability to fund our operations and planned 2010 capital expenditures will depend on our future operating performance and collection of our $36.0 million income tax receivable. Based on our existing operating performance we believe this is adequate to meet operational and capital expenditure needs in 2010.

 

The credit agreement evidencing our credit facility and the indenture governing our second lien notes contain covenants which include minimum quarterly EBITDA amounts, senior and total debt to EBITDA ratios and an interest coverage ratio. These covenants are subject to a number of exceptions and qualifications set forth in the credit agreement that evidences our credit facility. Please see “— Description of Our Indebtedness.” In addition, the credit agreement and the indenture contain covenants that limit capital expenditures to $6.0 million per quarter, as well as restrict our ability to incur additional debt or sell assets, make certain investments, loans and acquisitions, guarantee debt, grant liens, enter into transactions with affiliates, engage in other lines of business and pay dividends and distributions. As of December 31, 2009, we were in compliance with each of these covenants.

 

Financial Condition and Cash Flows

 

Financial Condition

 

Our working capital increased $11.1 million to $98.9 million at December 31, 2009 compared to December 31, 2008, primarily due to a $34.1 million increase in an income tax receivable, which was partially offset by decreases in trade accounts receivable, accounts payable and inventories that resulted from lower revenue activities discussed above in “— Our Results of Operations.” The income tax receivable increased by $34.1 million due to operating losses generated during 2009 that will be carried back for the refund of taxes paid in earlier years. Trade accounts receivable, accounts payable and inventories decreased at December 31, 2009 compared to December 31, 2008 by $35.1 million, $16.5 million and $2.8 million, respectively. In October 2009, we completed a follow-on offering of 6,900,000 shares of our common stock that generated net proceeds of $68.5 million, which we used to reduce borrowings outstanding under our credit facility.

 

Cash Flows from Operations

 

The following table sets forth historical cash flow information for each of the years ended December 31, 2009 and 2008 (in thousands):

 

Our cash flow provided by operations decreased $46.5 million to $5.2 million for the year ended December 31, 2009 compared to the year ended December 31, 2008, primarily due to a $118.4 million decrease in net income (loss), which was partially offset by changes in various components of working capital, depreciation expense and goodwill and intangible impairment. During 2009, our operations were significantly impacted by decreased demand for our services that lowered activity levels and dramatically reduced the pricing for our services. Sales discounts increased during 2009 due to increased competition for lower overall levels of service work. Additionally, operating cash flows decreased by $34.1 million due to an increase in income tax receivable and an $11.5 million decrease in deferred income tax expense that resulted from the operating losses generated in 2009. For a detailed comparison of operating results for the year ended December 31, 2009 compared to year ended December 31, 2008, please see “Our Results of Operations” under the sub-heading “Year Ended December 31, 2009 Compared to Year Ended December 31, 2008.” Partially offsetting these decreases in cash flow from operations for the year ended December 31, 2009 compared to the year ended December 31, 2008 were higher non-cash depreciation, amortization and accretion expenses and goodwill and intangible impairment expenses of $72.4 million and $33.5 million, respectively. Concurrent with the decreases in 2009 activity levels, trade accounts receivable and accounts payable decreased by $31.8 million and $15.9 million, respectively.

 

Cash Flows Used in Investing Activities

 

Net cash used in investing activities decreased from $174.1 million for the year ended December 31, 2008 to $26.7 million for the year ended December 31, 2009. The decrease in 2009 capital expenditures relates to the decline in the demand for our services and our focus on reducing discretionary spending.

 

Cash Flows from Financing Activities

 

Net cash provided by financing activities decreased $98.6 million from $118.5 million for the year ended December 31, 2008 to $19.9 million for the year ended December 31, 2009, primarily due to lower net borrowings under our credit facility that resulted from lower levels of capital expenditures and the payment of $3.0 million in preferred stock dividends during the year ended 2009. Partially offsetting the decrease in net cash provided by financing activities for the year ended December 31, 2009 compared to the year ended December 31, 2008 was $68.5 million in net proceeds from our common stock offering completed in October 2009.

 

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:

 

 

We continually monitor new advances in pumping equipment and down-hole technology, as well as technologies that may compliment our existing businesses, and commit capital funds to upgrade and purchase additional equipment to meet our customers’ needs. Our total 2010 capital expenditure budget is approximately $24 million. For the year ended December 31, 2009, we made capital expenditures of approximately $28.1 million to purchase new and upgrade existing pumping and down-hole surveying equipment and for maintenance on our existing equipment base. We plan to continue to focus on minimizing our discretionary spending and limiting our capital expenditures given the current operating environment.

 

Historically, we have grown through organic expansions and selective acquisitions. Given the current operating conditions and marketplace, we do not anticipate that we will continue to invest significant capital to acquire businesses and assets during 2010. We plan to continue to monitor the economic environment and demand for our services and adjust our business as necessary. We have actively considered a variety of businesses and assets for potential acquisitions and 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 Long-Term Growth Strategy.” For a discussion of the capital resources and liquidity needed to fund our routine operations and capital expenditures, please read “— Liquidity and Capital Resources.”

 

Contractual Obligations

 

The following table summarizes our contractual cash obligations as of December 31, 2009 (in thousands):

 

 

This table includes estimated future interest expense related to long-term debt and capital leases. For additional discussion related to our short and long-term obligations, see Note 5 to the historical consolidated financial statements included elsewhere in this Annual Report on Form 10-K.

 

Off-Balance Sheet Arrangements

 

We had no off-balance sheet arrangements as of December 31, 2009.

 

Description of Our Indebtedness

 

On September 30, 2008, we entered into a credit agreement evidencing our credit facility with a syndicate of financial institutions that provided for a $250.0 million secured revolving credit facility that matures on March 31, 2013. During 2009, we amended the credit agreement twice to prevent potential breaches of the financial covenants contained in the credit agreement. In connection with these amendments, our credit facility was converted into a “borrowing base” facility and the financial covenants were replaced with financial covenants that provided us additional financial flexibility. Under the terms of the last amendment, the following changes were made to the credit agreement:

 

 

The borrowing base under our credit facility is subject to redeterminations by lenders holding at least 51% of the amounts outstanding under our credit facility.

 

The interest rate on borrowings under the credit agreement is set, at our option, at either LIBOR plus a spread of 4.0% or the prime lending rate plus a spread of 2.0%. The credit agreement contains financial covenants that we must meet, including the minimum quarterly EBITDA requirements referred to above, senior and total debt to EBITDA ratios and an interest coverage ratio. These covenants are subject to a number of exceptions and qualifications set forth in the amendment.

 

At December 31, 2009, we had had $82.7 million outstanding, $7.3 million in letters of credit outstanding and $10.0 million of available capacity under our credit facility. The weighted average interest rate for our credit facility was 3.6% during 2009.

In connection with the Diamondback asset purchase, we issued an aggregate principal amount of $80 million second lien notes due November 2013. In connection with the issuance of our second lien notes, we entered into an indenture with our subsidiaries as guarantors and the Wilmington Trust FSB, as trustee. Interest on our second lien notes accrues at an initial rate of 7% per annum and the rate increases by 1% per annum on each anniversary date of the indenture. Interest is payable quarterly in arrears on January 1, April 1, July 1 and October 1, commencing on January 1, 2009.

 

Our credit facility and our second lien notes are both secured by our cash, investment property, accounts receivable, inventory, intangibles and equipment. We are subject to certain limitations under the credit agreement and the indenture, including limitations on our ability to:

 

 

A violation of the covenants in the credit agreement would trigger a default that would, absent a waiver or amendment, require immediate repayment of the outstanding indebtedness under our credit facility. Additionally, an event of default under the credit agreement would result in an event of default under the indenture governing our second lien notes, which could require immediate repayment of the outstanding principal and accrued interest on our second lien notes. Given the condition of the current credit and capital markets, any sale of assets or issuance of additional securities may not be on terms acceptable to us and could be dilutive to our stockholders.

 

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 to the historical consolidated financial statements included elsewhere in this Annual Report on Form 10-K.

 

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 policies.

 

Revenue Recognition

 

Our 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, net of discount, when the services are provided and collectibility is reasonably assured. Generally our services performed for customers are completed at the customer’s site within one day. We recognize 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.

Accounts receivable are carried at the amount owed by customers. We grant credit to all qualified customers, which are mainly regional, independent oil and natural gas companies. Management periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of our customers. Once an account is deemed not to be collectible, the remaining balance is charged to the reserve account.

 

Inventories

 

Inventories are stated at the lower of cost or market. Cost primarily represents invoiced costs. We regularly review inventory quantities on hand and record provisions for excess or obsolete inventory based primarily on historical usage, estimated product demand, and technological developments.

 

Income Taxes

 

We recognize deferred tax liabilities and assets for the expected future tax consequences of events that have been recognized in our 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 estimated effective tax rates. Our accounting policies require that a valuation allowance be established when it is more likely than not that all or a portion of a deferred tax asset will not be realized. We evaluate the realizability of our deferred tax assets on quarterly basis and valuation allowances are provided as necessary. We have not recorded any valuation allowances as of December 31, 2009. Our balance sheets at December 31, 2008 and December 31, 2009 do not include any liabilities associated with uncertain tax positions, and we have no unrecognized tax benefits that if recognized would change our effective tax rate.

 

We file income tax returns in the U.S. federal jurisdiction, and various states and local jurisdictions. We are not subject to U.S. federal, state and local income tax examinations by tax authorities for years before 2005. We classify interest related to income tax expense in interest expense and penalties in general and administrative expense. Interest and penalties for the years ended December 2007, 2008 and 2009 were insignificant in each period. We are subject to U.S. federal income tax examinations and we are subject to various state and local tax examinations.

 

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, 5 to 15 years for disposal wells and equipment and 5 to 10 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

 

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:

 

 

We currently have not recorded any impairment of any tangible 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.

 

Goodwill and Other Intangible Assets

 

We do not record amortization for goodwill deemed to have an indefinite life for acquisitions completed after June 30, 2001. We perform our goodwill impairment test annually, or more frequently if an event or circumstances would give rise to an impairment indicator. These circumstances include, but are not limited to, significant adverse changes in the business climate. Our goodwill impairment test is performed at the business segment levels, technical services and fluid logistics, as they represent our reporting units. The impairment test is a two-step process. The first step compares the fair value of a reporting unit with its carrying amount, including goodwill, and uses a future cash flow analysis based on the estimates and assumptions for our long-term business forecast. If the fair value of a reporting unit exceeds its carrying amount, the reporting unit’s goodwill is deemed to be not impaired. If the fair value of a reporting unit is less than its carrying amount, the second step of the goodwill impairment test is performed to determine the impairment loss, if any. This second step compares the implied fair value of the reporting unit’s goodwill with the carrying amount of the goodwill, and if the carrying amount of the reporting unit’s goodwill is greater than the implied fair value of that goodwill, an impairment loss is recorded for the difference. Any impairment charge would reduce earnings.

 

We performed an assessment of goodwill at December 31, 2008 and the tests resulted in no indications of impairment. However, we determined a “triggering event” requiring an interim assessment had occurred at June 30, 2009 because the oil and gas services industry continued to decline and our net book value had been substantially in excess of our market capitalization during the second quarter of 2009.

 

To estimate the fair value of the business segments, we use a weighted-average approach of two commonly used valuation techniques, a discounted cash flow method and a similar transaction method. Our management assigns a weight to the results of each of these methods based on the facts and circumstances that are in existence for that testing period. During the second quarter of 2009, because of overall economic downturn, management assigned more weighting to the discounted cash flow method than the similar transaction method. Given the continued deterioration of the general economic and oil service industry conditions during 2009, management believed that similar transactions may not be as useful because the valuations may reflect distressed sales conditions. Accordingly, the similar transaction weighting was reduced to 10% during the second quarter of 2009.

 

In addition to the estimates made by management regarding the weighting of the various valuation techniques, the creation of the techniques themselves requires significant estimates and assumptions to be made by management. The discounted cash flow method, which is assigned the highest weight by management, requires assumptions about future cash flows, future growth rates and discount rates. The assumptions about future cash flows and growth rates are based on our forecasts and strategic plans, as well as the beliefs of management about future activity levels. In applying the discounted cash flow approach, the cash flow available for distribution is projected for a finite period of years. Cash flow available for distribution is defined as the amount of cash that could be distributed as a dividend without impairing our future profitability or operations. The cash flow available for distribution and the terminal value (our value at the end of the estimation period) are discounted to present value to derive an indication of value of the business enterprise. Based upon the result of our impairment testing, total impairment was indicated for the goodwill in both of our business segments. As a result, we recorded a non-cash goodwill impairment loss of $33.2 million at June 30, 2009.

During the third quarter of 2009, we recorded a non-cash charge totaling $0.3 million for the impairment of intangible assets associated with a service center ceasing operations.

 

Our intangible assets consist of $7.5 million of customer relationships and non-compete agreements that are amortized over their estimated useful lives which range from three to five years. For the years ended December 31, 2007, 2008 and 2009, we recorded amortization expense of $805,000, $1,138,000 and $2,291,000, respectively.

 

Contingent Liabilities

 

We record 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 partially 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 one to two months and the differences between estimates and actuals have not been material. The estimates could be affected by actual claims being significantly different. Presently, we maintain an insurance policy that covers claims in excess of $150,000 per employee.

 

Stock-Based Compensation

 

We account for equity-based awards using an approach in which the fair value of an award is estimated at the date of grant and recognized as an expense over the requisite service period. Compensation expense is adjusted for equity awards that do not vest because service or performance conditions are not satisfied. Our results of operations for the years ended December 31, 2007, 2008 and 2009 include $1,961,000, $2,522,000 and $2,941,000 of additional compensation expense, respectively, as a result of stock based compensation. We had no stock based compensation prior to 2006.

 

Impact of Inflation

 

Inflation can affect the costs of fuel, raw materials and equipment that we purchase for use in our business. Historically, we were generally able to pass along any cost increases to our customers, although 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 cost increase until the time we can pass it along to our customers. Most of our property and equipment was acquired in recent years, so recorded depreciation approximates depreciation based on current dollars. Management is of the opinion that inflation has not had a significant impact on our business.

 

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”). 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 us 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, under the heading “Risk Factors” and elsewhere within this Annual Report on Form 10-K:

 

 

The forward-looking statements speak only as of the date made, other than as required by law, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

 

 

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 floating rate borrowings, each of which have variable interest rates 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 of December 31, 2008 and December 31, 2009 would have resulted in an increase in interest expense and a corresponding decrease in net income, of less than $1.3 million and $1.0 million annually, respectively.

 

Concentration of Credit Risk.  Substantially all of our 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 12% and 9% in 2007, 13% and 9% in 2008 and 21% and 11% in 2009 of our revenue. Eight customers accounted for 42%, 44% and 51% of our revenue for the years ended December 31, 2007, 2008 and 2009,

respectively. At December 31, 2009, two customers accounted for 23% and 12%, and eight customers accounted for 62%, of our accounts receivable, respectively.

 

Commodity Price Risk.  Our fuel and material purchases expose us to commodity price risk. 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. Historically we were 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. Given the current economic conditions and the decline in the overall demand for certain types of our services, in most cases we are currently unable to pass these price increases on to our customers.

 

The Board of Directors and Stockholders of
Superior Well Services, Inc.:

 

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934). Our internal control over financial reporting is designed to provide reasonable assurance to management and board of directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

 

Under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, we conducted an evaluation to assess the effectiveness of our internal control over financial reporting as of December 31, 2009. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, we believe that, as of December 31, 2009, our internal control over financial reporting is effective based on those criteria. The effectiveness of our internal control over financial reporting has been audited by Schneider Downs & Co., Inc., our independent registered public accounting firm, as stated in their report, which is included herein.

 

 

Indiana, Pennsylvania

March 9, 2010

 

To the Board of Directors and Stockholders of

Superior Wells Services, Inc.

 

We have audited the accompanying consolidated balance sheets of Superior Well Services, Inc. (Superior) as of December 31, 2009 and 2008, and the related statements of operations, changes in stockholders’ equity, and cash flows for each of the years in the three year period December 31, 2009. In addition, our audit included the financial statement schedule listed in the index at Item 15(b) (Schedule II). We also have audited Superior’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Superior’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on Superior’s internal control over financial reporting based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

 

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Superior as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three year period ended December 31, 2009, 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 consolidated financial statements, as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, Superior maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

 

 

Pittsburgh, Pennsylvania

March 9, 2010

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEETS