FORM 10-K

/s/ David E. Wallace

/s/ Thomas W. Stoelk

David E. Wallace

Thomas W. Stoelk

Chief Executive Officer

Chief Financial Officer

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form l0-K


(Mark One)
þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the Fiscal Year Ended December 31, 2008
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.

Commission File No. 000-51435

SUPERIOR WELL SERVICES, INC.

(Exact name of registrant as specified in its charter)


Delaware		20-2535684
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

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:


Common Stock, $.01 par value (Title of class)		The NASDAQ Stock Market LLC (Exchange)

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 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. o

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


Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

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 December 31, 2008, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $135,887,910 based on the closing sale price as reported on the The NASDAQ Global Select Market.

As of March 4, 2009, there were outstanding 23,609,538 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 proxy statement to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934 with respect to the 2008 annual meeting of stockholders are incorporated by reference in Part III.

PART I


Item 1.	*Business*

Our Company

We are a Delaware corporation formed in 2005 to serve as the parent holding company for an oilfield services business operating under the Superior Well Services name since 1997. In August 2005, we completed our initial public offering of 6,460,000 shares of common stock at a price of $13.00 per share and in December 2006 we completed a follow-on offering of 3,690,000 shares of common stock at a price of $25.50 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.

We identify and pursue opportunities in markets where we can capitalize on our competitive advantages to establish a significant market presence. Since 1997, our operations have expanded from two service centers in the Appalachian region to 36 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 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. Today, we operate through our 36 service centers located in Pennsylvania, Alabama, Arkansas, Colorado , Kansas, Louisiana, Michigan, Mississippi, New Mexico, North Dakota, Ohio, Oklahoma, Texas, Utah, Virginia, West Virginia and Wyoming.

Our Services and Products

Superior 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, down-hole surveying and completion, production and rental tool 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.

Technical Services

Technical pumping services. Our technical pumping services include — stimulation, nitrogen and cementing, which accounted for 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, 2008, we owned a fleet of 1,628 commercial vehicles through which we provided our technical pumping services.

Stimulation Services. Our fluid-based stimulation services include fracturing and acidizing, which are designed to improve the flow of oil and natural gas from producing zones. Fracturing services are performed to enhance the production of oil and natural gas from formations with low permeability, which restricts the natural

flow of the formation. The fracturing process consists of pumping a fluid gel into a cased well at sufficient pressure to fracture the formation. A proppant, typically sand, which is suspended in the gel is pumped into the fracture to prop it open. The size of a fracturing job is generally expressed in terms of pounds of proppant. The main pieces of equipment used in the fracturing process are the blender, which blends the proppant into the fracturing fluid, and the pumping unit, which is capable of pumping significant volumes at high pressures. Our equipment includes fracturing pump units and blenders that 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 are performed to enhance the flow rate of oil and natural gas from wells with reduced flow caused by limestone and other materials that block the formation. Acidizing entails pumping large volumes of specially formulated acids into a carbonate formation to dissolve barriers and enlarge crevices in the formation, thereby eliminating obstacles to the flow of oil and natural gas. We own and operate a fleet of mobile acid transport and pumping units to provide acidizing services.

Our fluid technology expertise and specialized equipment has enabled us to provide stimulation services with relatively high pressures (8,000 to 13,000 psi) that many of our smaller independent competitors currently do not offer. For these higher pressure projects, we typically arrange with third-party, independent laboratories to optimize and verify our fluid composition as part of our pre-job approval process. As of December 31, 2008, we had 62 stimulation and acidizing crews of approximately three to thirty employees each and a fleet of 1,221 vehicles that includes high-tech, customized pump trucks, blenders and frac vans for use in our fluid-based stimulation services. In 2008, we provide basic stimulation and acidizing services from 21 different service centers: Black Lick, Pennsylvania; Bradford, Pennsylvania; Mercer, Pennsylvania; Norton, Virginia; Kimball, West Virginia; Jane Lew, West Virginia; Columbia, Mississippi; Cleveland, Oklahoma; Marlow, Oklahoma; Clinton, Oklahoma; Vernal, Utah; Cottondale, Alabama; Gaylord, Michigan; Van Buren, Arkansas; Alvarado, Texas; Midland, Texas; Cresson, Texas; Farmington, New Mexico; Artesia, New Mexico; Brighton, Colorado; 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 2008. Our customers use foam-based nitrogen stimulation when the use of fluid-based fracturing or acidizing could result in damage to oil and natural gas producing zones or in low pressure zones where such fluid-based treatment would not be effective. Liquid nitrogen is transported to the jobsite in truck mounted insulated storage vessels. The liquid nitrogen is then pumped under pressure via a high pressure pump into a heat exchanger, which converts the liquid to a gas at the desired discharge temperature. In addition, we use nitrogen to foam cement slurries and to purge and test pipelines, boilers and pressure vessels.

As of December 31, 2008, we had nine nitrogen crews of approximately two to eight employees each and a fleet of 53 nitrogen pump trucks and 40 nitrogen transport vehicles. We provide nitrogen services from our Mercer, Pennsylvania; Cleveland, Oklahoma; Gaylord, Michigan; Kimball, West Virginia; Jane Lew, West Virginia; Norton, Virginia; Farmington, New Mexico; and Cottondale, Alabama service centers.

Cementing Services. Our cementing services consist of blending high-grade cement and water with various solid and liquid additives to create a cement slurry. The additives and the properties of the slurry are designed to ensure the proper pump time, compression strength and fluid loss control and vary depending on the well depth, down-hole temperatures and pressures and formation characteristics. We have developed a series of proprietary slurry blends. Our field engineers develop job design recommendations to achieve desired porosity and bonding characteristics. We contract with independent, third party regional laboratories to provide testing services to evaluate our slurry properties, which vary with cement supplier and local water properties.

Once blended, this cement slurry is pumped through the well casing into the void between the casing and the bore hole. There are a number of specific applications for cementing services. The principal application is the cementing behind the casing pipe and the wellbore during the drilling and completion phase of a well. This is known as primary cementing. Primary cementing is performed to (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. After installation on the tubular being cemented, casing attachments are used to achieve the correct placement of cement slurries in the wellbore. Accordingly, our casing attachments are complementary to, and often bundled with, our cementing services as customers prefer the convenience and efficiencies of sourcing from a single provider. Sales of casing attachments has consistently accounted for less than 1% of our total revenue.

As of December 31, 2008, we had 81 cementing crews of approximately three to six employees each and a fleet of 314 cement trucks. We provide cementing services from 20 different service centers: Mercer, Pennsylvania; Black Lick, Pennsylvania; Bradford, Pennsylvania; Kimball, West Virginia; Jane Lew, West Virginia; Cleveland, Oklahoma; Clinton, Oklahoma; Marlow, Oklahoma; Coalgate, Oklahoma; Columbia, Mississippi; Cottondale, Alabama; Gaylord, Michigan; Van Buren, Arkansas; Vernal, Utah; Alvarado, Texas; Cresson, Texas; Norton, Virginia; Farmington, New Mexico; Artesia, New Mexico; and Bossier City, Louisiana.

Completion Services. Completion and production services were added in connection with the Diamondback asset acquisition and accounted for 0.4% or our revenues for the year ended December 31, 2008. 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 and roustabout services, as well as the sale and rental of equipment. These services require skilled personnel and various types and sizes 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. This service is called “flow back” testing and assists producers in determining potential production and production equipment needs. As of December 31, 2008, we owned nine flow back tanks.

Plugging and Abandonment. We provide plugging and abandonment services when a well has reached the end of its productive life. We use workover rigs, cementing equipment, roustabout services 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 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 9.4% and 13.1% of our revenue for the years ended December 31, 2008 and 2007, respectively. As of December 31, 2008, we owned a fleet of 116 logging and perforating trucks and cranes through which we provided our down-hole surveying services. We supply wireline logging services primarily to open-hole markets and perforating services to cased-hole markets. Open-hole operations are performed in oil and natural gas wells that are newly drilled. Cased-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. We purchase our wireline equipment, down-hole tools and data gathering systems from third-parties. Our vendor relationships allow us to concentrate on our operations and limit our costs for research and development.

Logging Services. Our logging services involve the gathering of down-hole information to identify various characteristics of the down-hole rock formations, casing cement bond and mechanical integrity. We lower specialized tools into a wellbore from a truck on an armored electro-mechanical cable, or wireline. These tools communicate across the cable with a truck mounted acquisition unit at the surface that contains considerable instrumentation and computer equipment. The specialized, down-hole tools transmit data to the surface computer,

which charts and records down-hole information, that details various characteristics about the formation or zone to be produced, such as rock type, porosity, permeability and the presence of hydrocarbons. As of December 31, 2008, we had 16 logging crews of approximately two to three employees each and 30 logging trucks. We provide logging services from 9 different service centers: Buckhannon, West Virginia; Kimball, West Virginia; Wooster, Ohio; Black Lick, Pennsylvania; Cottondale, Alabama; Enid, Oklahoma; Hays, Kansas; Williston, North Dakota and Trinidad, Colorado.

Perforating Services. We provide perforating services as the initial step of stimulation by lowering specialized tools and perforating guns into a wellbore by wireline. The specialized tools transmit data to our surface computer to verify the integrity of the cement and position the perforating gun, which fires shaped explosive charges to penetrate the producing zone. Perforating creates a short path between the oil or natural gas reservoir and the wellbore that enables the production of hydrocarbons. In addition, we perform workover services aimed at improving the production rate of existing oil and natural gas wells and by perforating new hydrocarbon bearing zones in a well once a deeper zone or formation has been depleted. As of December 31, 2008, we had 39 perforating crews of approximately two to four employees each and 86 perforating trucks and cranes. We provide perforating services from 14 different service centers: Wooster, Ohio; Mercer, Pennsylvania; Black Lick, Pennsylvania; Buckhannon, West Virginia; Kimball, West Virginia; Gaylord, Michigan; Cottondale, Alabama; Enid, Oklahoma; Hominy, Oklahoma; Hays, Kansas; Williston, North Dakota; Brighton, Colorado; Midland, Texas; and Trinidad, Colorado.

Fluid Logistics Services

Fluid logistics services were added in connection with the Diamondback asset acquisition and accounted for 1.2% of revenues for the year ended December 31, 2008. 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 approximately 45 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, 2008, we also owned approximately 600 frac tanks which are rented to producers for use in fracturing and stimulation operations and 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, 2008, we owned and operated 6 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 four different services centers: Countyline, Oklahoma; Sweetwater, Oklahoma; Coalgate, 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 locally oriented businesses. We believe that the principal competitive factors in the market areas that we serve are price, product and service quality, availability of crews and equipment and technical proficiency.

Customers and Markets

We serve numerous major and independent oil and natural gas companies that are active in our core areas of operations.

The majority of our customers are regional, independent oil and natural gas companies. The following table shows the growth and increasing geographic diversity of our revenue through December 31, 2008:


	2006(1)					2007(2)					2008(3)
			Percent of					Percent of					Percent of
Region	Revenue		Revenue			Revenue		Revenue			Revenue		Revenue

Appalachian	$	118,943		48.6	%	$	158,894		45.3	%	$	179,173		34.4	%
Southeast		58,491		23.9			66,690		19.0			92,971		17.8
Southwest		6,832		2.8			37,565		10.7			82,857		15.9
Mid-Continent		43,566		17.8			56,063		16.0			105,607		20.3
Rocky Mountain		16,794		6.9			31,558		9.0			60,281		11.6

Total	$	244,626		100	%	$	350,770		100	%	$	520,889		100	%


(1)		We expanded the Appalachian region by establishing service centers in Buckhannon, West Virginia and Norton, Virginia during the first and second quarters of 2006, respectively. We expanded the Rocky Mountain and Southwest regions in the third quarter of 2006 by establishing service centers in Farmington, New Mexico and Alvarado, Texas, respectively. Additionally, during the fourth quarter of 2006 we established our first down-hole surveying service center in the Rocky Mountain region when we acquired wireline assets in Trinidad, Colorado.

(2)		We expanded the Appalachian region by establishing a service center in Jane Lew, West Virginia during the second quarter of 2007. We expanded the Southwest region in the fourth quarter by establishing a service center in Artesia, New Mexico. We expanded the Mid-Continent region by acquiring wireline assets in Hays, Kansas during the first quarter of 2007 and establishing a service center in Clinton, Oklahoma during the third quarter of 2007. We expanded the Rocky Mountain region by acquiring wireline assets in Williston, North Dakota and establishing service centers in Brighton, Colorado and Rock Springs, Wyoming during the fourth quarter of 2007. The Brighton, Colorado service center began generating revenues in January of 2008 and the Rock Springs, Wyoming location is expected to start generating revenues during the first quarter of 2009.

(3)		In July 2008, we expanded the Rocky Mountain region by acquiring the down-hole surveying assets of Nuex that expanded our presence in Brighton, Colorado. In November 2008, we purchased the pressure pumping, fluid logistics and completion, production and rental tools business lines from Diamondback. As part of the acquisition, we acquired 128,000 horsepower, 105 transports and trucks, 400 frac tanks and six water disposal wells. 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.

During 2008, we provided services to over 1,200 customers, with our top five customers comprising approximately 35.8% of our total revenue. The following table shows information regarding our top five customers in 2008:


Customer	Length of Relationship		% of 2008 Revenue

Atlas America, Inc.(1)		10 years		13.1
Customer B(2)		5 years		8.6
Customer C(3)		1 year		5.9
Customer D(4)		7 years		4.9
Customer E(5)		7 years		3.3


(1)		We service Atlas America, Inc. from our Appalachian region service centers.

(2)		We service Customer B from our Appalachian, Mid-Continent, Southwest and Southeast region service centers.

(3)		We service Customer C from our Appalachian, Mid-Continent, Southwest and Southeast region service centers.

(4)		We service Customer D from our Appalachian, Southwest and Southeast region service centers.

(5)		We service Customer E from our Appalachian region service centers.

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:


	Length of Relationship		% of 2008 Purchases
Raw Materials	with Largest Supplier		with Largest Supplier

Fracturing and Cementing Chemicals		12 years		7.8
Fracturing Sand		12 years		7.6
Nitrogen		10 year		5.2

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:


	Length of Relationship		% of 2008 Purchases
Equipment	with Largest Supplier		with Largest Supplier

Blenders		12 years		5.2
Frac Trailers		10 years		3.3

In October 2008, we entered into a take-or-pay contract with Preferred Rocks USS, Inc. to purchase fracturing sand beginning in November 2008 through December 2015. Minimum purchases under the take-or-pay contract are estimated at $10.5 million, $12.1 million, $12.4 million, $12.8 million, $17.9 million, $18.4 million and $18.9 million in 2009, 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:


	•	personal injury or loss of life;

	•	damage to or destruction of property, equipment, the environment and wildlife; and

	•	suspension of operations.

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

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

Despite our efforts to maintain high safety standards, we from time to time have suffered accidents in the past and anticipate that we 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 materially 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, in some circumstances, impose joint and several, strict 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 materially adverse effect upon our capital expenditures, earnings or our 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 from properties currently or even previously owned or operated by us as well as from offsite properties where our wastes have been disposed, for damages to natural resources and for the costs of some health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. We have not received 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 waste. Moreover, in the ordinary course of our operations, industrial wastes such as paint wastes, waste solvents, and laboratory wastes as well as certain wastes generated in the course of providing well services may be regulated as hazardous waste under RCRA or hazardous substances under CERCLA. We currently own or lease, and have in the past owned or leased, a number of properties that for many years have been used for services in support of oil and natural gas exploration and production activities. We have utilized operating and disposal practices that were standard in the industry at the time, but hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, we may own or lease properties that in the past were operated by third parties whose operations were not under our control. Those properties and the hydrocarbons or wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination.

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.

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.

Recent scientific studies have suggested 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. In response to such studies, President Obama has expressed support for, and it is anticipated that the current session of Congress will consider legislation to restrict or regulate emissions of greenhouse gases. In addition, more than one-

third of the states, either individually or through multi-state regional initiatives, 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. Depending on the particular program, we could be required to purchase and surrender allowances for greenhouse gas emissions resulting from our operations.

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

We maintain insurance against some risks associated with underground contamination that may occur as a result of well services activities. However, this insurance is limited to activities at the wellsite and may not continue to be available or may not be available at premium levels that justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a materially adverse effect on our financial condition and 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, 2008, we employed 2,589 people, with approximately 76% 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

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.

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.


Item 1A —	*Risk Factors*

Risks Related to Our Business and Our Industry

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

Based on a number of economic indicators, it appears that growth in global economic activity has slowed substantially. At the present time, the rate at which the global economy will slow has become increasingly uncertain. A slowing of global economic growth, and in particular in the United States and China, will likely reduce demand for oil and natural gas, increase spare productive capacity and result in lower prices and adversely impact the demand for our services.

Recently, oil and natural gas prices have been extremely volatile and have declined substantially. On February 5, 2009, the price of oil on the New York Mercantile Exchange was $41.17 per barrel, declining from a 52-week high of $145.29 in 2008. Volatility in oil and natural gas prices can also impact 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. Any of these factors could materially and adversely affect our customers’ activity levels which would 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 substantial deterioration in the credit and capital markets. These conditions, along with significant write-offs in the financial services sector and the re-pricing of credit risk 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 significant reduction in our customers’ spending for our products and services. This reduction in spending could have a material adverse effect on our operations.

Our ability to obtain funding for our capital projects may be limited due to the deterioration of 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 is not currently available on acceptable terms and may not be available for some time, which will limit our

growth and reduce our expansion capital expenditures. Accordingly, our capital expenditures budget for 2009 is $20 million, which is $107.7 million less than our capital expenditures in 2008.

As of December 31, 2008, we had $208.2 million of indebtedness comprising $127.0 million outstanding under our syndicated credit facility, $80.0 million of second lien notes due 2013 and $1.2 million of mortgage and other notes payable. At December 31, 2008, availability under our syndicated credit facility was $116.7 million. Because of the recent downturn in the financial markets, including the issues surrounding the solvency of many institutional lenders and the recent failure of several banks, we may be unable to utilize the full borrowing capacity under our syndicated 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 syndicated credit facility and the other lenders are not willing to provide additional funding to make up the portion of the syndicated 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 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.

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, natural gas and oil 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 supply of and demand for oil and natural gas and related products;

	•	domestic and worldwide economic conditions;

	•	political instability in oil producing countries;

	•	price of foreign imports of oil and natural gas, including liquefied natural gas;

	•	substantial lead times on our capital expenditures;

	•	weather conditions;

	•	technical advances affecting energy consumption;

	•	the price and availability of alternative fuels; and

	•	merger and divestiture activity among oil and natural gas producers.

The volatility of the oil and natural gas industry and the consequent impact on exploration and production activity could adversely impact the level of drilling and workover activity by some of our customers. This reduction may cause a decline in the demand for our services or adversely affect the price of our services. In addition, reduced discovery rates of new oil and natural gas reserves in our market areas may have a negative long-term impact on our business, even in an environment of stronger oil and natural gas prices, to the extent existing production is not replaced and the number of producing wells for us to service declines. We cannot predict the future level of demand for our services, future natural gas and crude oil commodity prices or future conditions of the well services industry, we anticipate that the recent volatility and weakness in natural gas and oil prices will have a negative impact on our results of operations in 2009.

A decline in or substantial volatility of natural gas and crude oil commodity prices could adversely affect the demand for our services.

The demand for our services is substantially influenced by current and anticipated natural gas and crude oil commodity prices and the related level of drilling activity and general production spending in the areas in which we have operations. Volatility or weakness in natural gas and crude oil commodity prices (or the perception that natural gas and crude oil commodity prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower production spending for existing wells. This, in turn, could result in lower demand for our services as the products and services we provide are, to a substantial extent, deferrable in the event oil and natural gas companies reduce capital expenditures. As a result, we may experience lower utilization of, and may be forced to lower our rates for, our equipment and services. A decline in natural gas and crude oil commodity prices or a reduction in drilling or production activities could materially adversely affect the demand for our services and our results of operations.

Historical prices for natural gas and crude oil have been extremely volatile and are expected to continue to be volatile. For example, for the five years ended December 31, 2008, the NYMEX Henry Hub natural gas price ranged from a high of $15.38 per MMBtu to a low of $4.20 per MMBtu, while the NYMEX crude oil price ranged from a high of $145.29 per barrel to a low of $32.48 per barrel. In reaction to declining natural gas and crude oil commodity prices, producers have reduced their expenditures including Chesapeake Energy Corp and EOG Resources, Inc. who are among our significant customers. This has in the past and may in the future adversely affect our business. A prolonged low level of activity in the oil and natural gas industry will adversely affect the demand for our products and services and our financial condition and results of operations.

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

Our 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 recent acquisition of the Diamondback assets through the issuance of preferred stock and second lien notes and additional borrowing under our revolving 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 revolving credit facility to fund future acquisitions, and we may be unable to meet such covenants. Recent turmoil in the credit markets 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.

We have significantly higher levels of indebtedness following the Diamondback acquisition than we had before the acquisition.

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, 2008, after giving effect to the Diamondback acquisition and the related financing transactions, we have approximately $208.2 million of indebtedness

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


	•	limiting our ability to obtain additional financing on satisfactory terms to fund our working capital requirements, capital expenditures, acquisitions, investments, debt service requirements and other general corporate requirements;

	•	increasing our vulnerability to general economic downturns, competition and industry conditions, which could place us at a competitive disadvantage compared to our competitors that are less leveraged;

	•	increasing our exposure to rising interest rates because a portion of our borrowings are at variable interest rates;

	•	reducing the availability of our cash flow to fund our working capital requirements, capital expenditures, acquisitions, investments and other general corporate requirements because we will be required to use a substantial portion of our cash flow to service debt obligations; and

	•	limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.

If we do not successfully manage the potential difficulties associated with our 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:


	•	lack of sufficient experienced management personnel;

	•	failure to anticipate the actual cost and timing of establishing new service centers;

	•	increased administrative burden; and

	•	increased logistical problems common to large, expansive operations.

If we do not manage these potential difficulties successfully, our operating results could be adversely affected. In addition, we may have difficulties managing the increased costs associated with our growth, which could adversely affect our operating margins 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 new 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 the new 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 expansion program and the delay in new service centers becoming profitable.

Our business strategy also includes growth through the acquisitions of assets and other businesses. We may not be able to identify attractive acquisition opportunities or successfully acquire identified targets. In addition, we may not be successful in integrating our acquisitions, such as our recent acquisition of Diamondback, into our existing operations, which may result in unforeseen operational difficulties or diminished financial performance or require a disproportionate amount of our management’s attention. 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 may face difficulties in achieving the expected benefits of the Diamondback acquisition.

We may not be able to achieve fully the strategic and financial objectives we hope to achieve with our November 2008 acquisition of the pressure pumping, fluid logistics and completion, production and rental tools business lines from Diamondback. The ultimate success of the acquisition will depend on a number of factors, including our ability to compete effectively in the markets in which we operate, expand operations, maintain existing relationships with current customers and retain and attract qualified management and personnel.

As a result of the Diamondback acquisition, we offer additional services to our customers that we have not offered historically. These additional services include fluid logistics services and water transfer services. Our success with these new service offerings will depend upon, among other things, the ability of our management to successfully implement sound business strategies and avoid the legal and business risks of these new service offerings. We cannot assure you that we will be able to do this effectively, and in the process we may incur additional costs without an immediate increase in revenues. Additionally, our management’s attention may be diverted from the operation and growth of our core services offerings.

We depend on a relatively small number of customers for a substantial portion of our revenue. The inability of one or more of our customers to meet their obligations or the loss of our business with Atlas America, Inc. or Chesapeake Energy Corp., 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 2007 and 2008, eight companies accounted for 42% and 44% 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, Atlas America, Inc. and Chesapeake Energy Corp., constituted approximately 13% and 9%, respectively, of our total revenue for the year ended December 31, 2008. 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 natural gas and oil producers, who are adversely affected by the recent decrease in the prices of natural gas and oil. A sustained decrease in prices, coupled with the current 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. We do not generally require collateral in support of our trade receivables.

Competition within the oilfield services industry may adversely affect our ability to market our services.

The oilfield services industry is highly competitive and fragmented and includes several large companies that compete in many of the markets we serve, as well as numerous small companies that compete with us on a local basis. Our larger competitors’ greater resources could allow them to better withstand industry downturns, compete more effectively on the basis of technology and geographic scope and retain skilled personnel. We believe the principal competitive factors in the market areas we serve are price, product and service quality, availability of crews and equipment and technical proficiency. Our operations may be adversely affected if our current competitors or new market entrants introduce new products or services with better features, performance, prices or other characteristics than our products and services or expand into service areas where we operate. Competitive pressures or other factors also may result in significant price competition, particularly during industry downturns, which could have a material adverse effect on our results of operations and financial condition. In addition, competition among oilfield services and equipment providers is affected by each provider’s reputation for safety and quality.

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

Because natural gas and crude oil prices and drilling activity have recently been at historically high levels, in 2007 and 2008, oilfield service companies have been acquiring 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 2007. Additionally, prices for natural gas and crude oil and utilization rates for drilling rigs declined significantly in the fourth quarter of 2008 and the first quarter of 2009. A sustained decline in these prices could result in a lower number of wells that are commercially viable for the natural gas and oil 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, 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 Diamondback acquisition, 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:


	•	improve our existing services and related equipment;

	•	address the increasingly sophisticated needs of our customers; and

	•	anticipate changes in technology and industry standards and respond to technological developments on a timely basis.

If we are not successful in acquiring new equipment or upgrading our existing equipment on a timely and cost-effective basis in response to technological developments or changes in standards in our industry, we could lose market share. In addition, current competitors or new market entrants may develop new technologies, services or standards that could render some of our services or equipment obsolete, which could have a material adverse effect on our operations.

Our industry has recently experienced shortages in the availability of qualified field personnel. Any difficulty we experience 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 is currently 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. Therefore, we may have problems finding enough skilled and unskilled laborers in the future if the demand for our services increases. In that event, it is possible that we will have to raise wage rates to attract and train workers from other fields in order to retain or expand our current work force. If we are not able to increase our service rates sufficiently to compensate for wage rate increases, our 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.

The loss of key members of our management or the failure to attract and motivate key personnel could have an adverse effect on our business, financial condition and results of operations.

We depend to a large extent on the services of some of our executive officers and directors. The loss of the services of David E. Wallace, our Chief Executive Officer, Jacob B. Linaberger, our President, Rhys R. Reese, an Executive Vice President and our Chief Operating Officer, and other key personnel, or the failure to attract and motivate key personnel, could have an adverse effect on our business, financial condition and results of operations. We have entered into employment agreements with Messrs. Wallace, Reese and Linaberger that contain non-compete agreements. Notwithstanding these agreements, we may not be able to retain our executive officers and may not be able to enforce all of the provisions in the employment agreements. We do not maintain key person life insurance on the lives of any of our executive officers or directors. The death or disability of any of our executive officers or directors may adversely affect our operations.

Our operations are subject to inherent risks, some of which are beyond our control, and these risks may not be fully covered under our insurance policies. The occurrence of a significant event that is not covered by insurance could have a material adverse effect on our financial condition and results of operations.

Our operations are subject to hazards inherent in the oil and natural gas industry, such as, but not limited to, accidents, blowouts, explosions, craterings, fires, oil spills and hazardous materials spills. These conditions can cause:


	•	personal injury or loss of life;

	•	destruction of property, equipment, the environment and wildlife; and

	•	suspension of operations.

The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our financial condition and results of operations. In addition, claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a wellsite location where our equipment and services are being used may result in us being named as a defendant in lawsuits asserting large claims. The frequency and severity of such incidents affect our operating costs, insurability and relationships with customers, employees and regulators. Any increase in the frequency or severity of such incidents could affect our ability to obtain projects from oil and natural gas companies.

We do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. In addition, we are subject to various self-retentions and deductibles under our insurance policies. The occurrence of an event not fully insured against, or the failure of an insurer to meet its insurance obligations, could result in substantial losses. We also may not be able to maintain adequate insurance in the future at rates we consider reasonable, and insurance may not be available to cover any or all of these risks, or, even if available, that it will be adequate or that insurance premiums or other costs will not rise significantly in the future, so as to make such insurance cost prohibitive. In addition, our insurance is subject to coverage limits and some policies exclude coverage for damages resulting from environmental contamination.

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.

As a result of the Diamondback acquisition, we acquired additional assets that are subject to stringent environmental laws and regulations, with which the failure to comply may subject us to significant costs and liabilities. We may discover previously unknown liabilities associated with these newly acquired assets, including liabilities under the same stringent environmental laws and regulations relating to the releases of pollutants into the environment and environmental protection as applicable to our existing facilities. Such discovery may cause our operation of these new assets to incur increased costs to address these liabilities or to attain compliance with such environmental requirements.

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.

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.

Diamondback’s management and auditors identified significant deficiencies that, in the aggregate, resulted in a material weakness in the operation of Diamondback’s internal controls during the period ended December 31, 2005 and the year ended December 31, 2006, which could result in its, and in the future, our, financial statements being materially misleading.

In connection with preparing its financial statements for the period ended December 31, 2005 and the year ended December 31, 2006, Diamondback and its auditors identified numerous significant deficiencies relating to the lack of a complete and thorough period-end closing and financial reporting process and related controls that, in the aggregate, constituted a material weakness. The Public Company Accounting Oversight Board has defined a material weakness as a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. Accordingly, a material weakness increases the risk that the financial information regarding Diamondback that we report, including information in our future financial statements and annual and quarterly reports relating to the assets and operations acquired from Diamondback, contains material errors.

We are in the process of integrating the assets and operations that we acquired from Diamondback into our existing accounting and financial reporting systems and other internal control systems. Because Diamondback’s historical accounting and financial reporting systems were different and more decentralized than our own, this integration process may present significant challenges and may be more difficult and time consuming than we currently anticipate. If we fail to achieve this integration effectively or timely, our ability to maintain an effective system of internal controls over financial reporting and the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected. This could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock.

Complying with Section 404 of the Sarbanes-Oxley Act of 2002 may strain our financial and management resources.

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. We have incurred and expect to continue to incur significant costs and have spent and expect to continue to spend significant management time to comply with Section 404. As a result, management’s attention has been and may continue to be diverted from other business concerns, which could have a material adverse effect on our financial condition and results of

operations. In addition, we may need to hire additional accounting and financial staff with appropriate experience and technical accounting knowledge, and we cannot assure you that we will be able to do so in a timely fashion.

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.

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

As of December 31, 2008, our total debt on a consolidated basis was approximately $208.2 million. Our total debt could increase, as we have a total borrowing capacity of $116.7 million under our syndicated credit facility as of December 31, 2008 and we could issue additional notes or other indebtedness in the future. Our syndicated credit facility and the terms of the indenture under which we issued our Second Lien Notes in November 2008 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.

Our overall level of indebtedness could have important consequences. For example, it could:


	•	impair our ability to make investments and obtain additional financing for working capital, capital expenditures, acquisitions or other general corporate purposes;

	•	limit our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make principal and interest payments on our indebtedness;

	•	limit our ability to borrow funds that may be necessary to operate or expand our business;

	•	put us at a competitive disadvantage to competitors that have less debt;

	•	increase our vulnerability to interest rate increases; and

	•	hinder our ability to adjust to rapidly changing economic and industry conditions.

Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Description of Our Indebtedness” for a discussion of our revolving credit facility.

Unionization efforts could increase our costs or limit our flexibility.

Presently, none of our employees work under collective bargaining agreements. Unionization efforts have been made from time to time within our industry, to varying degrees of success. Any such unionization could increase our costs or limit our flexibility.

Severe weather could have a material adverse impact on our business.

Our business could be materially and adversely affected by severe weather. Repercussions of severe weather conditions may include:


	•	curtailment of services;


	•	weather-related damage to equipment resulting in suspension of operations;

	•	weather-related damage to our facilities;

	•	inability to deliver materials to jobsites in accordance with contract schedules; and

	•	loss of productivity.

In addition, oil and natural gas operations of potential customers located in the Appalachian, Mid-Continent and Rocky Mountain regions of the United States can be adversely affected by seasonal weather conditions, primarily in the spring. Many municipalities impose weight restrictions on the paved roads that lead to our jobsites due to the muddy conditions caused by spring thaws. This can limit our access to these jobsites and our ability to service wells in these areas. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs in those regions.

A terrorist attack or armed conflict could harm our business.

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


Item 1B.	*Unresolved Staff Comments*

None.


Item 2.	*Properties*

Our principal executive offices are located at 1380 Rt. 286 East, Suite #121, Indiana, Pennsylvania 15701. We purchased the building that houses our principal executive offices in April 2005. We currently conduct our business from 36 service centers, 5 of which we own and 31 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; Wooster, Ohio; 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, Enid, Clinton, Cleveland, Marlow, Countyline, Sweetwater, Coalgate and Elk City, Oklahoma; Van Buren, Arkansas; and Hays, Kansas. Our Rocky Mountain region service centers are located in Vernal, Utah; Farmington, New Mexico; Rock Springs, Wyoming; Williston, North Dakota; and Trinidad and Brighton, Colorado. Our Southwest region service centers are located in Alvarado, Cresson, Tolar, Midland and Victoria, Texas; and Artesia, New Mexico. 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:


		Is the Lease Renewable at Our Sole		Do We Have an Option to Purchase
Location	Expiration Date	Option?		the Property?

Bradford, PA	September, 2011		Yes		No
Cleveland, OK	March, 2009		No		Yes
Mercer, PA(1)	N/A		No		No
Wooster, OH	December, 2009		Yes		No
Gaylord, MI	November, 2010		Yes		Yes
Bossier City, LA	December, 2012		Yes		No
Enid, OK(1)	N/A		No		No
Black Lick, PA(1)	N/A		No		No
Vernal, UT	September, 2017		No		No
Van Buren, AR	May, 2009		Yes		No
Buckhannon, WV	February, 2010		Yes		No
Norton, VA	March, 2009		Yes		No
Alvarado, TX	March, 2011		Yes		Yes
Farmington, NM	January, 2015		Yes		No
Trinidad, CO(1)	N/A		No		No
Oklahoma City, OK(1)	N/A		No		No
Hays, KS	August, 2010		Yes		No
Jane Lew, WV	October, 2015		Yes		No
Rock Springs, WY	March, 2017		Yes		No
Brighton, CO	September, 2010		Yes		No
Williston, ND	October, 2012		Yes		No
Artesia, NM	June, 2010		Yes		Yes
Oklahoma City, OK	August, 2009		No		No
Sweetwater, OK	November, 2013		Yes		No
Coalgate, OK	January, 2012		Yes		No
Countyline, OK	November, 2013		Yes		No
Marlow, OK	November, 2013		Yes		No
Cresson, TX	November, 2013		Yes		No
Midland, TX	June, 2015		No		No
Tolar, TX	November, 2013		Yes		No
Elk City, OK(1)	N/A		No		No
Victoria, TX	May, 2013		Yes		No
Broussard, LA	September, 2011		Yes		No


(1)		The lease is month-to-month.


Item 3.	*Legal Proceedings*

We are named as a defendant, from time to time, in litigation relating to our normal business operations. Our management is not aware of any significant pending litigation that would have a material adverse effect on our financial position, results of operations or cash flows.


Item 4.	*Submission of Matters to a Vote of Security Holders*

No matters were submitted to a vote of our stockholders in the fourth quarter of the year ended December 31, 2008.

PART II


Item 5.	*Market for the Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities*

Market Information for Common Stock

Our common stock is traded on the The NASDAQ Stock Market LLC under the symbol “SWSI.” As of March 4, 2009, there were 23,609,538 shares outstanding, held by approximately 188 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 The NASDAQ Global Select Market during 2007 and 2008.


	High		Low

Fiscal Year Ended December 31, 2008
First Quarter	$	26.73	$	17.14
Second Quarter	$	34.42	$	21.73
Third Quarter	$	35.71	$	23.46
Fourth Quarter	$	23.65	$	8.60
Fiscal Year Ended December 31, 2007
First Quarter	$	25.54	$	21.20
Second Quarter	$	28.02	$	22.18
Third Quarter	$	26.24	$	17.10
Fourth Quarter	$	23.45	$	18.87

Dividend Policy

We have not declared or paid any dividends on our common stock, and we do not currently anticipate paying any dividends on our common stock in the foreseeable future. Instead, we currently intend to retain all future earnings to fund the development and growth of our business. Any future determination relating to our dividend policy will be at the discretion of our board of directors and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant.

Purchases of Equity Securities By the Issuer and Affiliated Purchases

We did not make any purchases of our equity securities in the fourth quarter of the year ended December 31, 2008.


Item 6.	*Selected Financial Data*

The selected consolidated financial information contained below is derived from our Consolidated Financial Statements and should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our audited consolidated financial statements.


	Year Ended December 31,
				2005			2006			2007			2008
	2004			(Superior Well			(Superior Well			(Superior Well			(Superior Well
	(Partnerships)			Services, Inc.)			Services, Inc.)			Services, Inc.)			Services, Inc.)
	(In thousands, except per share information)

Statements of Income Data:
Revenue	$	76,041		$	131,733		$	244,626		$	350,770		$	520,889
Cost of revenue		54,447			90,258			165,877			252,539			406,044

Gross profit		21,594			41,475			78,749			98,231			114,845
Selling, general and administrative expenses		11,339			17,809			25,716			36,390			45,702

Operating income		10,255			23,666			53,033			61,841			69,143
Interest expense		310			566			478			282			2,834
Other (expense) income		(148	)		193			159			766			(135	)
Income tax expense		—			13,826			20,791			24,570			27,362

Net income	$	9,797		$	9,467		$	31,923		$	37,755		$	38,812

Pro Forma income tax expense (unaudited)(1)		(4,249	)		—			—			—			—

Net income adjusted for pro forma income tax expense (unaudited)	$	5,548		$	—		$	—		$	—		$	—

Net income per common share(2)
Basic	$	0.29		$	0.49		$	1.63		$	1.63		$	1.67
Diluted	$	0.29		$	0.49		$	1.63		$	1.63		$	1.64
Average Shares Outstanding
Basic		19,376,667			19,317,436			19,568,749			23,100,402			23,150,463
Diluted		19,376,667			19,317,436			19,568,749			23,195,914			23,661,608
Statements of Cash Flow Data:
Net cash provided by operations	$	12,790		$	16,742		$	35,949		$	69,303		$	51,706
Net cash used in investing		(19,290	)		(40,091	)		(78,902	)		(128,100	)		(174,060	)
Net cash provided by financing		6,751			32,570			88,940			7,555			118,481
Capital expenditures, net of construction payables		19,300			39,920			69,816			117,774			90,424
Acquisitions, net of cash acquired		—			—			9,150			9,931			84,242
Depreciation and amortization		5,057			8,698			14,453			25,277			41,806
Balance Sheet Data (at period end):
Cash and cash equivalents	$	1,544		$	10,765		$	56,752		$	5,510		$	1,637
Property, plant and equipment, net		40,594			72,691			141,424			240,863			453,990
Total assets		56,682			113,091			259,034			327,087			658,230
Long-term debt		11,093			1,258			1,597			9,165			208,042
Partners’ capital		33,819			—			—			—			—
Stockholders’ Equity		—			91,393			213,904			253,599			337,615
Other Financial Data:
EBITDA(3)	$	15,164		$	32,557		$	69,385		$	89,845		$	113,336


(1)		Prior to our initial public offering in August 2005, we were not subject to federal or state income taxes due to our partnership structure. Pro forma income tax expense (unaudited) has been computed at statutory rates to reflect the pro forma effect on net income for periods prior to our holding company restructuring in August 2005.

(2)		Share and per share data have been retroactively restated to reflect our holding company restructuring in connection with our initial public offering in August 2005. For the calculations of earnings per share for the year ended December 31, 2004, all shares are assumed to have been issued at the beginning of the period resulting in 19,376,667 average shares outstanding.

(3)		We define EBITDA as earnings (net income) before interest expense, income tax expense, non-cash stock compensation expense, depreciation and amortization. This term, as we define it, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. EBITDA should not be considered in isolation or as a substitute for operating income, net income, cash flows provided by operating, investing and financing activities or other income or cash flow statement data prepared in accordance with GAAP. Our management uses EBITDA:


	•	as a measure of operating performance because it assists us in comparing our performance on a consistent basis, since it removes the impact of our capital structure and asset base from our operating results;

	•	as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations;

	•	to assess compliance with financial ratios and covenants included in credit facilities;

	•	in communications with lenders concerning our financial performance; and

	•	to evaluate the viability of potential acquisitions and overall rates of return.

The following table presents a reconciliation of EBITDA with our net income for each of the periods indicated:


	Year Ended December 31,
			2005		2006		2007		2008
	2004		(Superior Well		(Superior Well		(Superior Well		(Superior Well
	(Partnerships)		Services, Inc.)		Services, Inc.)		Services, Inc.)		Services, Inc.)

*Reconciliation of EBITDA to Net Income:*
Net income	$	9,797	$	9,467	$	31,923	$	37,755	$	38,812
Income tax expense		—		13,826		20,791		24,570		27,362
Interest expense		310		566		478		282		2,834
Stock compensation expense		—		—		1,740		1,961		2,522
Depreciation and amortization		5,057		8,698		14,453		25,277		41,806

EBITDA	$	15,164	$	32,557	$	69,385	$	89,845	$	113,336


Item 7.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*

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

Overview

We are a Delaware corporation formed in 2005 to serve as the parent holding company for an oilfield services business operating under the Superior Well Services name since 1997. 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 in December 2006 we completed a follow-on offering of 3,690,000 shares of common stock at a price of $25.50 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) (“Series A Preferred Stock”) 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 and six water disposal wells. 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. 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, down-hole surveying and completion, production and rental tool 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):


	Year Ended December 31,
	2006				2007				2008
	(Dollars in thousands)

Revenue:
Technical services	$	244,626	100.0	%	$	350,770	100.0	%	$	514,568	98.8	%
Fluid logistics		—	—			—	—			6,321	1.2	%

Total revenue	$	244,626	100.0	%	$	350,770	100.0	%	$	520,889	100.0	%

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 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. 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 2007 and 2008. 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 0.4% or our revenues for the year ended December 31, 2008. 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 and roustabout services, as well as the sale and rental of equipment. These services require skilled personnel and various types and sizes 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 9.4% and 13.1% of our revenues for years ended December 31, 2008 and 2007, 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. In addition, we also perform workover services aimed at improving the production rate of existing oil and natural gas wells, including perforating new hydrocarbon bearing zones in a well once a deeper zone or formation has been depleted.

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, 2008, we also owned approximately 400 frac tanks which are rented 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, 2008, we owned and operated six 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. Fluid logistics accounted for approximately 1.2% of our revenues for the year ended December 31, 2008.

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 natural gas and crude oil commodity prices and production depletion rates.

We generate revenue from our technical pumping services, down-hole surveying and completion, production and rental tool services by charging our customers a set-up charge plus an hourly rate based on the type of equipment used. The set-up charges and hourly rates are determined by a competitive bid process and depend upon the type of service to be performed, the equipment and personnel required for the particular job and the market conditions in the region in which the service is performed. Each job is given a base time allotment of six hours. We generally charge an increased hourly rate for each hour worked beyond the initial six hour base time allotment. We also charge customers for the materials, such as stimulation fluids, cement and nitrogen, that we use in each job. Material charges include the cost of the materials plus a markup and are based on the actual quantity of materials used.

We generate revenue from our fluid logistics services by charging our customers based on volumes transported, quantities of fluids disposed 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 and the rates charged are generally driven by market conditions in the region the disposal well is located. Frac tank rental 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) EBITDA.

Operating Income per Operating Region.

We currently service customers in five operating regions through our 36 service centers. Our Appalachian region service centers are located in Bradford, Black Lick and Mercer, Pennsylvania; Wooster, Ohio; 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, Enid, Clinton, Cleveland, Marlow, Countyline, Sweetwater, Coalgate, and Elk City, Oklahoma; Hays, Kansas; and Van Buren, Arkansas. Our Rocky Mountain region service centers are located in Vernal, Utah; Farmington, New Mexico; Rock Springs, Wyoming; Williston, North Dakota; and Trinidad and Brighton, Colorado. Our Southwest region service centers are located in Alvarado, Cresson, Tolar, Midland and Victoria, Texas; and Artesia, New Mexico.

The operating income generated in each of our operating regions is an important part of our operational analysis. We monitor operating income separately for each of our operating regions and analyze trends to determine our relative performance in each region. Our analysis enables us to more efficiently allocate our equipment and field personnel among our various operating regions and determine if we need to increase our marketing efforts in a particular region. By comparing our operating income on an operating region basis, we can quickly identify market increases or decreases in the diverse geographic areas in which we operate. It has been our experience that when we establish a new service center in a particular operating region, it may take from 12 to 24 months before that service center has a positive impact on the operating income that we generate in the relevant region.

Material and Labor Expenses as a Percentage of Revenue.

Material and labor expenses are composed primarily of cost of materials, maintenance, fuel and the wages of our field personnel. The cost of these expenses as a percentage of revenue has historically remained relatively stable for our established service centers.

Our material costs primarily include the cost of inventory consumed while performing our stimulation, nitrogen and cementing services. Increases in our material and fuel costs are frequently passed on to our customers. However, due to the timing of our marketing and bidding cycles, there is generally a delay of several weeks or months from the time that we incur an actual price increase until the time that we can pass on that increase to our customers.

Our labor costs consist primarily of wages for our field personnel. As a result of on-going shortages 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. Historically, we have been able to increase service rates to our customers to compensate for wage rate increases.

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

Our selling, general and administrative expenses, or SG&A expenses, include 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, as well as a result of our becoming a public company.

EBITDA.

We define EBITDA as net income before interest expense, income tax expense, non-cash stock compensation expense and depreciation and amortization expense. Our management uses EBITDA:


	•	as a measure of operating performance because it assists us in comparing our performance on a consistent basis, since it removes the impact of our capital structure and asset base from our operating results;

	•	as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations;

	•	to assess compliance with financial ratios and covenants included in credit facilities;

	•	in communications with lenders concerning our financial performance; and

	•	to evaluate the viability of potential acquisitions and overall rates of return.

How We Manage Our Operations

Our management team uses a variety of tools to manage our operations. These tools include monitoring: (1) service crew 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, with full utilization deemed to be approximately 24 jobs per month for each of our service crews and approximately 30 jobs per month for each of our trucks. By monitoring the relative performance of each of our service crews, we can more efficiently allocate our personnel and equipment to maximize our overall crew utilization.

Equipment Maintenance Performance.

Preventative maintenance on our equipment is an important factor in our profitability. If our equipment is not maintained properly, our repair costs may increase and, during levels of high activity, our ability to operate efficiently could be significantly diminished due to having trucks and other equipment out of service. Our maintenance crews perform monthly inspections and preventative maintenance on each of our trucks and other mechanical equipment. Our management monitors the performance of our maintenance crews at each of our service centers by monitoring the level of maintenance expenses as a percentage of revenue. A rising level of maintenance expenses as a percentage of revenue at a particular service center can be an early indication that our preventative maintenance schedule is not being followed. In this situation, management can take corrective measures, such as adding additional maintenance personnel to a particular service center to help reduce maintenance expenses as well as ensure that maintenance issues do not interfere with operations.

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 Overview

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 natural gas and crude oil 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 natural gas and crude oil commodity prices. For example, the Energy Information Administration of the U.S. Department of Energy, or EIA, forecasts that U.S. natural gas consumption will increase at an average annual rate of 0.2% through 2030. The EIA also forecasts that U.S. oil production will increase at an average annual rate of 1.7% and natural gas production will increase at an average annual rate of 0.3%.

The recent drop in commodity prices for oil and gas, coupled with the volatility in the equity and credit markets have caused some exploration and production companies to announce reductions in their capital spending. Although recently the volatility and weakness in natural gas and oil prices have caused natural gas and oil exploration and production companies to reduce their exploration and production expenditures. We believe that over the long term oil and natural gas exploration and production companies will continue to expand their exploration and drilling activities to replace production from the high decline rate reservoirs. In recent years, much of this expansion has focused on natural gas. According to Baker Hughes rig count data, the average total rig count in the United States increased 52% from 918 in 2000 to 1,399 through the first week of February 2009, while the average natural gas rig count increased 53% from 720 in 2000 to 1,104 through the first week of February 2009. However, the rig count began to decline in the fourth quarter of 2008 and has fallen precipitously in early 2009 with a current total rig count as of February 20, 2009 of approximately 1,300 rigs in the United States, compared to 1,995 rigs as of September 26, 2008, while the number of rigs drilling for natural gas has increased by more than 172% since 1996, and natural gas production has increased by only approximately 8% over the same period. This is

largely a function of increasing decline rates for natural gas wells in the United States. We believe, over the long-term, a continued increase in U.S. drilling and workover activity will be required for the natural gas industry to help meet the expected increased demand for natural gas in the United States.

Business Outlook

The current economic and credit environment has lowered demand for energy and resulted in significantly lower prices for crude oil and natural gas. 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 our customers ability to access the financial and credit markets. During the last half of 2008, the financial and credit markets weakened substantially and demand for natural gas and crude oil declined. As a result, natural gas and crude oil prices have fallen sharply, which has caused a decline in the demand for our services as customers have reduced their exploration and production expenditures. With the current commodity price and credit environment, we expect that drilling activity will be substantially lower in 2009 compared to 2008, which we believe will reduce demand and prices we receive for our services. If economic conditions continue to worsen, the demand for our services could continue to decrease as customers make further reductions in their oil and gas expenditures. Additionally, the reduction in cash flows being experienced by some of our customers due to lower commodity prices coupled with the weakening of the credit and capital markets could have an adverse impact on our results of operations and cash flows. 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.

Our Growth Strategy

Our growth strategy contemplates engaging in organic expansion opportunities and, to a lesser extent, complementary acquisitions of other oilfield services businesses. Our organic expansion activities generally consist of establishing service centers in new locations, including purchasing related equipment and hiring experienced local personnel. Historically, many of our customers have asked us to expand our operations into new regions that they enter. Once we establish a new service center, we seek to expand our operations by attracting new customers and hiring additional local personnel.

Our revenues from each operating region, and their relative percentage of our total revenue, consisted of the following (dollars in thousands):


	2006					2007					2008
			Percent of					Percent of					Percent of
Region	Revenue		Revenue			Revenue		Revenue			Revenue		Revenue

Appalachian	$	118,943		48.6	%	$	158,894		45.3	%	$	179,173		34.4	%
Southeast		58,491		23.9			66,690		19.0			92,971		17.8
Southwest		6,832		2.8			37,565		10.7			82,857		15.9
Mid-Continent		43,566		17.8			56,063		16.0			105,607		20.3
Rocky Mountain		16,794		6.9			31,558		9.0			60,281		11.6

Total	$	244,626		100	%	$	350,770		100	%	$	520,889		100	%

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 growth strategy, we will require access to capital on competitive terms to the extent that we do not generate sufficient cash from operations. We intend to finance future acquisitions primarily by using capacity available under our bank credit facility and equity or debt offerings or a combination of both. For a more detailed discussion of our capital resources, please read “— Liquidity and Capital Resources”.

Our Results of Operations

Our results of operations are derived primarily by three interrelated variables: (1) market price for the services we provide; (2) drilling activities of our customers; and (3) cost of materials and labor. To a large extent, the pricing environment for our services will dictate our level of profitability. Our pricing is also dependent upon the prices and market demand for oil and natural gas, which affect the level of demand for, and the pricing of, our services and fluctuates with changes in market and economic condition and other factors. In recent months, increased capacity in certain of our operating regions has resulted in significant downward pricing pressure and increased discounts in our service prices. We expect this downward pressure to continue in these regions until the level of activity increases to absorb the excess capacity or the amount of equipment and crews servicing these regions decreases through relocation to other regions with 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.

Historical market conditions are reflected in the table below:


	Three Months Ended December 31,							Year Ended December 31,
	2007		2008		% Change			2007		2008		% Change

Average rig count(1)
Crude Oil		334		414		24.0	%		297		379		27.6	%
Natural gas		1,451		1,479		1.9			1,466		1,491		1.7

Total U.S. land rigs		1,785		1,893		6.1	%		1,763		1,870		6.1	%

Commodity prices (avg.):
Crude Oil (West Texas Intermediate) ($/bbl)	$	90.68	$	58.74		(35.2	)%	$	72.34	$	99.65		37.8	%
Natural gas (Henry Hub) ($/mcf)		6.94		6.36		(8.4	)%		6.95		8.84		3.9	%


(1)		Estimate of activity as measured by average active U.S. land drilling rigs based on Baker Hughes Inc. rig count information

The current economic and credit environment has lowered demand for energy and resulted in significantly lower prices for crude oil and natural gas. During the last half of 2008, the financial and credit markets weakened and caused a drop in the demand for oil and gas. As a result, oil and gas prices have fallen sharply, which has caused a decline in the demand for our services as customers have reduced their exploration and production expenditures. With the current commodity price and credit environment, we expect that drilling activity will be substantially lower in 2009 compared to 2008, which we believe will reduce demand and prices we receive for our services. 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.

Results for the three months ended December 31, 2007 and 2008

Our results of operations from our primary categories of services consisted of the following for each of the three month periods ended December 31, 2007 and 2008:


	Three Months Ended December 31,
	2007		2008

Statement of Operations Data
Revenue:
Technical pumping services	$	84,727	$	142,372
Down-hole surveying services		10,211		10,855
Completion services		—		2,158

Total Technical Services		94,938		155,385
Fluid logistics		—		6,321

Total revenue		94,938		161,706
Expenses:
Cost of revenue		72,961		125,145
Selling, general and administrative		9,768		14,088

Total expenses		82,729		139,233

Operating income	$	12,209	$	22,473

Revenue

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


	Three Months Ended December 31,
					$			%
	2007		2008		Change			Change

Revenues by service type:
Stimulation	$	49,798	$	108,358	$	58,560			117.6	%
Cementing		19,734		24,558		4,824			24.4
Nitrogen		15,195		9,456		(5,739	)		(37.8	)

Technical pumping services		84,727		142,372		57,645			68.0
Down-hole surveying services		10,211		10,855		644			6.3
Completion services		—		2,158		2,158			100.0

Total Technical Services		94,938		155,385		60,447			63.7
Fluid logistics		—		6,321		6,321			100.0

Total revenue	$	94,938	$	161,706	$	66,768			70.3	%

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


	Three Months Ended December 31,
					$			%
	2007		2008		Change			Change

Region:
Appalachian	$	45,633	$	43,791	$	(1,842	)		(4.0	)%
Southeast		17,479		29,992		12,513			71.6
Southwest		10,378		32,739		22,361			215.5
Rocky Mountain		7,041		17,509		10,468			148.7
Mid-Continent		14,407		37,675		23,268			161.5

Total	$	94,938	$	161,706	$	66,768			70.3	%

Revenues reached $161.7 million for the fourth quarter of 2008 which increased 70.3% as compared to the same period last year. The year-over-year revenue growth was driven by strong activity increases in our stimulation and cementing services. The decrease in nitrogen revenues during the fourth quarter of 2008 as compared to the fourth quarter of 2007 was due to a non-recurring nitrogen project performed in 2007. Increased activity levels at service centers that were established within the last twelve months (“New Centers”), as well as the Diamondback asset acquisition completed in November 2008, led to the increases in revenue in the fourth quarter of 2008 as compared to the fourth quarter of 2007. New Centers and the Diamondback asset acquisition represented $28.7 million and $26.0 million of the revenue increases between the fourth quarter of 2008 as compared to the fourth quarter of 2007, respectively. As a percentage of revenue, sales discounts increased in high single digits in 2008 as compared to 2007 due to increased capacity and increased competition in certain of our operating regions which resulted in significant downward pricing pressure on our service prices. New service centers historically have higher sales discounts than our established service centers because they typically price their services below competitors to initially penetrate new markets. All of our operating regions experienced higher sales discounts for the fourth quarter of 2008 as compared to the fourth quarter of 2007. Our stimulation and cementing services continue to see the greatest downward pricing pressure. During the fourth quarter of 2008 we saw the negative impact from reduction or elimination of fuel surcharges negotiated with several of our customers earlier in the year.

Cost of Revenue

Cost of revenue increased 71.5% or $52.2 million for the three months ended December 31, 2008 compared to the three months ended December 31, 2007. As a percentage of revenue, cost of revenue increased to 77.4% for the fourth quarter of 2008 from 76.9% for the fourth quarter of 2007 due to a mix change to jobs with higher material content, as well as increased costs for materials that could not be passed through to our customers via price increases because of the current competitive environment. New Centers and the Diamondback asset acquisition represented approximately $19.9 million and $19.9 million of the cost of revenue increases between the fourth quarter of 2008 compared to the fourth quarter of 2007, respectively. As a percentage of revenue, material costs increased in the fourth quarter of 2008 compared to the fourth quarter of 2007 by 4.0%. The year-over-year increase in material costs as a percentage of revenue was due to higher sand, chemical and cement costs, as well as transportation expenses incurred to deliver materials. The material increases as a percentage of revenue was partially offset by lower labor expenses as a percentage of revenue. Labor expenses as a percentage of revenues decreased 2.9% to 18.5% in the fourth quarter of 2008 compared to the fourth quarter of 2007 due to a mix change to jobs with higher material content, as well as increased utilization on a higher revenue base.

Selling, General and Administrative Expenses

SG&A expenses increased 44.2% or $4.3 million for the three months ended December 31, 2008 compared to the three months ended December 31, 2007. As a percentage of revenue, SG&A expenses decreased by 1.6% to 8.7% for the fourth quarter of 2008 from 10.3% for the fourth quarter of 2007 due to the ability to leverage certain of these fixed costs over a higher revenue base. During the fourth quarter of 2008, we completed the Diamondback

asset acquisition which increased SG&A expenses by $2.5 million. As a result of the growth in our operations, aggregate labor expenses increased by $3.3 million to $8.8 million for the fourth quarter of 2008 compared to the fourth quarter of 2007. As a percentage of revenue, the portion of labor expenses included in SG&A expenses decreased 0.4% to 5.5% in the fourth quarter of 2008 compared to the fourth quarter of 2007. Additionally, in connection with the Diamondback asset purchase, we originally planned to finance a portion of the acquisition price with public debt and equity offerings. Due to deterioration in the financial markets these public offerings were unable to be completed and $0.4 million in offering costs was expensed.

Operating Income

Operating income was $22.5 million for the three months ended December 31, 2008 compared to $12.2 million for the three months ended December 31, 2007, an increase of 84.1%. As a percentage of revenue, operating income increased to 13.9% in the fourth quarter of 2008 from 12.9% in the fourth quarter of 2007. The primary reasons for the increase in operating income were the improved profitability from new service centers and the Diamondback asset acquisition. New Centers and the Diamondback asset acquisition increased operating income by approximately $8.8 million and $3.5 million in the fourth quarter of 2008 compared to the fourth quarter of 2007, respectively. It has been our experience that when we establish a new service center in a particular operating region, it may take from 12 to 24 months before that service center has a positive impact on the operating income that we generate in the relevant region. EBITDA increased $16.0 million in the fourth quarter of 2008 compared to the fourth quarter of 2007 to $36.4 million. For a definition of EBITDA, and a reconciliation of EBITDA to net income, please see “Selected Financial Data.” Net income increased $5.0 million to $11.9 million in the fourth quarter of 2008 compared to the fourth quarter of 2007 due to increased activity levels described above.

Results for the year ended December 31, 2007 and 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, 2008:


	Year Ended December 31,
	2006		2007		2008
	(In thousands)

Statement of Operations Data
Revenue:
Technical pumping services	$	219,624	$	304,949	$	463,313
Down-hole surveying services		25,002		45,821		49,097
Completion services		—		—		2,158

Total Technical Services		244,626		350,770		514,568
Fluid logistics		—		—		6,321

Total revenue		244,626		350,770		520,889
Expenses:
Cost of revenue		165,877		252,539		406,044
Selling, general and administrative		25,716		36,390		45,702

Total expenses		191,593		288,929		451,746

Operating income	$	53,033	$	61,841	$	69,143

Revenue

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


	Year Ended December 31,
					$			%
	2007		2008		Change			Change

Revenues by service type:
Stimulation	$	190,678	$	334,571	$	143,893			75.5	%
Cementing		72,337		93,954		21,617			29.9
Nitrogen		41,934		34,788		(7,146	)		(17.0	)

Technical pumping services		304,949		463,313		158,364			51.9
Down-hole surveying services		45,821		49,097		3,276			7.1
Completion services		—		2,158		2,158			100.0

Total Technical Services		350,770		514,568		163,798			46.7
Fluid logistics		—		6,321		6,321			100.0

Total revenue	$	350,770	$	520,889	$	170,119			48.5	%

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


	Year Ended December 31,
					$		%
	2007		2008		Change		Change

Region:
Appalachian	$	158,894	$	179,173	$	20,279		12.8	%
Southeast		66,690		92,971		26,281		39.4
Southwest		37,565		82,857		45,292		120.6
Rocky Mountain		31,558		60,281		28,723		91.0
Mid-Continent		56,063		105,607		49,544		88.4

Total	$	350,770	$	520,889	$	170,119		48.5	%

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 when compared to the same period last year. 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 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). Rock Springs, Wyoming did not generate any 2008 revenues and is planned to commence operations during the first quarter of 2009. 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 service 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 continue to see the greatest downward pricing pressure. 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 via price increases because of the current 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 for year ended December 31, 2008 compared to year ended December 31, 2007 by 1.5%. New Centers and the Diamondback asset 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)

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 the ability to leverage certain of these fixed costs over a higher revenue base. As a result of the growth in our operation, 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

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. It has been our experience that when we establish a new service center in a particular operating region, it may take from 12 to 24 months before that service center has a positive impact on the operating income that we generate in the relevant region. EBITDA increased $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 EBITDA, and a reconciliation of 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.

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Revenue

The following table summarizes the dollar and percentage changes for the types of oilfield service revenues for the twelve month period ended December 31, 2007 when compared to the same period in 2006 (dollars in thousands):


	Year Ended December 31,
					$		%
	2006		2007		Change		Change

Revenues by service type:
Stimulation	$	142,846	$	190,678	$	47,832		33.5	%
Cementing		51,419		72,337		20,918		40.7
Nitrogen		25,359		41,934		16,575		65.4

Total Technical pumping revenues		219,624		304,949		85,325		38.9
Down-hole surveying services		25,002		45,821		20,819		83.3

Total revenue	$	244,626	$	350,770	$	106,144		43.4	%

The following table summarizes the dollar and percentage change in our revenues from each operating region for the twelve month period ended December 31, 2007 when compared to the same period in 2006 (dollars in thousands):


	Year Ended December 31,
					$		%
	2006		2007		Change		Change

Region:
Appalachian	$	118,943	$	158,894	$	39,951		33.6	%
Southeast		58,491		66,690		8,199		14.0
Southwest		6,832		37,565		30,733		449.8
Rocky Mountain		16,794		31,558		14,764		87.9
Mid-Continent		43,566		56,063		12,497		28.7

Total	$	244,626	$	350,770	$	106,144		43.4	%

Revenue was $350.8 million for the year ended December 31, 2007 compared to $244.6 million for the year ended December 31, 2006, an increase of 43.4%. Increased activity levels, as well as down-hole asset acquisitions made during 2006 and 2007 led to the increases in 2007. Approximately $20.3 million of the total increase was attributable to New Centers in 2007. During 2007, we acquired the assets of two down-hole surveying companies and opened five start-up service centers. Four of our five start-up service centers in 2007 were opened during the second half of the year. New Center revenue by operating region increased in 2007 by $7.1 million, $12.0 million, $0.7 million and $0.5 million in the Appalachian, Mid-Continent, Southwest and Rocky Mountain operating regions, respectively. New Centers include: Jane Lew, West Virginia (Appalachian), Clinton, Oklahoma (Mid-Continent), Hays, Kansas (Mid-Continent down-hole acquisition), Artesia, New Mexico (Southwest), Williston, North Dakota (Rocky Mountain down-hole acquisition), Brighton, Colorado (Rocky Mountain), and Rock Springs, Wyoming (Rocky Mountain). Brighton, Colorado and Rock Springs, Wyoming were opened late in 2007, but did not generate any 2007 revenues. Existing service center revenue by operating region increased in 2007 by $32.9 million, $8.2 million, $0.5 million, $30.0 million and $14.3 million in the Appalachian, Southeast, Mid-Continent, Southwest and Rocky Mountain operating regions, respectively. As a percentage of revenue, sales discounts increased by 4.8% in 2007 as compared to 2006 due to increased capacity and increased competition in certain of our operating regions which resulted in significant downward pricing pressure on our service prices.

Revenue from our technical pumping services increased by approximately 38.8% to $304.9 million for the year ended December 31, 2007 from $219.6 million for the year ended December 31, 2006. Approximately $11.9 million of this increase was attributable to new service centers. The opening of our new service centers in

Oklahoma, Colorado, Wyoming and New Mexico in 2007 was significantly delayed due to late equipment deliveries, facility procurement delays and holdups in obtaining regulatory permits. These delays caused the new 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. New service center revenue by operating region increased in 2007 by $7.0 million, $4.2 million and $0.7 million in the Appalachian, Mid-Continent and Southwest operating regions, respectively. Existing service center revenue by operating region increased in 2007 by $28.7 million, $8.1 million, $1.1 million, $30.0 million and $5.4 million in the Appalachian, Southeast, Mid-Continent, Southwest and Rocky Mountain operating regions, respectively. Increased activity levels at existing service centers were partially offset by higher sales discounts in 2007 as compared to 2006 as a result of increased capacity and greater competition in the operating regions served by these service centers.

Revenue from our down-hole surveying services increased approximately 83.3% to $45.8 million for the year ended December 31, 2007 from $25.0 million for the year ended December 31, 2006. The revenue increase in 2007 was driven by new service centers that were acquired during 2006 and 2007. Revenue by operating region increased in 2007 by $4.3 million, $0.1 million, $7.1 million and $9.4 million in the Appalachian, Southeast, Mid-Continent and Rocky Mountain operating regions, respectively. New service center revenue by operating region increased in 2007 by $0.1 million, $7.8 million, and $0.5 million in the Appalachian, Mid-Continent, and Rocky Mountain operating regions, respectively. Increased activity levels at existing service centers were partially offset by higher sales discounts in 2007 as compared to 2006 as a result of increased capacity and greater competition in cased hole services.

Cost of Revenue

Cost of revenue increased 52.2% to $252.5 million for the year ended December 31, 2007 compared to $165.9 million for the year ended December 31, 2006. Approximately $18.7 million of the aggregate increase in cost of revenues was attributable to the establishment of new service centers. New service center cost of revenue by operating region increased in 2007 by $5.7 million, $9.4 million, $2.6 million and $1.0 million in the Appalachian, Mid-Continent, Southwest and Rocky Mountain operating regions, respectively. The aggregate dollar increase in cost of revenues was due to the fact that these costs vary with revenue and higher activity levels. As a percentage of revenue, cost of revenue increased to 72.0% for the year ended December 31, 2007 from 67.8% for the year ended December 31, 2006. This percentage increase between periods was primarily due to higher labor expense, depreciation and material costs as a percentage of revenue in 2007 as compared to 2006. Additionally, higher sales discounts lowered net revenues and resulted in an increase in the cost of revenue as a percentage of revenue.

Labor expenses as a percentage of revenues increased 1.7% to 19.9% in 2007 when compared to 2006 due to lower utilizations than expected at new service centers established during 2007. Delays in receiving equipment and regulatory permits deferred revenue producing activities at the new service centers opened during the second half of 2007, which lowered our utilizations from our projected levels. These delays postponed the opening of the Clinton service center, which commenced operations during the third quarter of 2007, and the Brighton, Artesia and Rock Springs service centers that were established in the fourth quarter of 2007. Aggregate labor expenses in cost of revenue increased $25.3 million to $69.7 million in 2007 due to the hiring of additional personnel in connection with the establishment of new service centers and the expansion of existing service centers. Material costs as a percentage of revenues increased by 0.9% to reach 40.7% in 2007 as compared to 2006. Higher sand transportation costs were the primary reason for the increase, as well as greater cement trucking costs for new service centers without bulk handling facilities. Delays in receiving regulatory and environmental approvals postponed the construction of bulk handling facilities at these new service centers, which resulted in additional trucking costs to transport cement from other centers. Depreciation expense as a percentage of revenues increased 1.3% to 7.0% in 2007 when compared to 2006 due to higher amounts of capital spending in 2007, as well as lower utilizations than expected at new service centers established during 2007.

Selling, General and Administrative Expenses

SG&A expenses were $36.4 million for the year ended December 31, 2007 compared to $25.7 million for the year ended December 31, 2006, an increase of 41.5%. Approximately $3.6 million of the increase in SG&A

expenses in 2007 when compared to 2006 was due to the establishment of new service centers. New service center SG&A expenses by operating region increased in 2007 by $1.0 million, $1.3 million, $0.6 million and $0.7 million in the Appalachian, Mid-Continent, Southwest and Rocky Mountain operating regions, respectively. During 2007 we hired additional personnel to manage the growth in our operations and added seven service centers. As a result of this growth, 2007 expenses for labor, office, rent and insurance expenses increased $6.6 million, $1.3 million, $0.8 million and $0.5 million, respectively. Additionally, legal and professional and vehicle expenses increased $0.3 million and $0.3 million, respectively. As a percentage of revenue, the portion of labor expenses included in SG&A expenses remained consistent at 6.0% in both 2006 and 2007. Aggregate labor expenses increased $6.6 million to $21.1 million in 2007 due to revenue growth and the establishment of seven service centers during 2007.

Operating Income and EBITDA

Operating income was $61.8 million for the year ended December 31, 2007 compared to $53.0 million for the year ended December 31, 2006, an increase of 16.6%. As a percentage of revenue, operating income decreased from 21.7% in 2006 to 17.6% in 2007. The primary reasons for this decrease were higher discounts for our services, costs incurred for the five start-up service centers, delays in opening new service centers as well as the increases in our cost of revenue and SG&A expenses as described above. These decreases were partially offset by increased drilling activity by our customers in our existing service centers. Operating income in 2007 decreased by approximately $5.0 million due to the five start-up service centers established during the year. It has been our experience that when we establish a new service center in a particular operating region, it may take from 12 to 24 months before that service center has a positive impact on the operating income that we generate in the relevant region. EBITDA increased $20.5 million in 2007 to $89.8 million. For a definition of EBITDA, a reconciliation of EBITDA to net income and a discussion of EBITDA as a performance measure, please see footnote 3 to “Selected Financial Data.” Net income increased $5.8 million to $37.8 million in 2007 due to increased activity levels described above.

Items Impacting Comparability of Our Financial Results

Changes in Our Legal Structure

Prior to our initial public offering in August 2005, our operations were conducted by two separate operating partnerships under common control, Superior Well Services, Ltd. and Bradford Resources, Ltd. Pursuant to a contribution agreement among Superior Well, Inc. and the former partners of these two operating partnerships, the operations of these two partnerships were combined under a holding company structure immediately prior to the closing of our initial public offering. In December 2006, Bradford Resources, Ltd. was merged into Superior Well Services, Ltd. Superior Well Services, Ltd. is a Pennsylvania limited partnership that became a wholly owned subsidiary of Superior Well Services, Inc. in connection with its initial public common stock offering. Superior Well Services, Inc. serves as the parent holding company for this structure. Following the closing of the contribution agreement and our initial public offering as discussed in Note 1 to our historical consolidated financial statements, we began to report our results of operations and financial condition as a corporation on a consolidated basis, rather than as two operating partnerships on a combined basis.

In November 2008, Superior purchased the pressure pumping, fluid logistics and completion, production and rental tool assets from Diamondback Energy Holdings, LLC (“Diamondback”). In connection with the asset purchase, Superior formed SWSI Fluids, LLC to acquire the fluid logistics assets. SWSI Fluids LLC is a wholly owned subsidiary of Superior.

Prior to 2005, we did not incur income taxes because our operations were conducted by two separate operating partnerships that were not subject to income tax. In 2005 and prior, our historical combined financial statements of Superior Well Services, Ltd. and Bradford Resources, Ltd. include a pro forma adjustment for income taxes calculated at the statutory rate resulting in a pro forma net income adjusted for income taxes. Prior to becoming a public company, partnership capital distributions were made to the former partners of our operating partnerships to fund the tax obligations resulting from the partners being taxed on their proportionate share of the partnerships’ taxable income. As a consequence of our change in structure, we recorded a non-cash adjustment of $8.6 million to record the deferred tax asset and liabilities arising from the differences in the financial and tax basis of assets and

liabilities that existed at that time. Following our initial public offering, we incur income taxes under our new holding company structure, and our consolidated financial statements reflect the actual impact of income taxes.

Non-cash Compensation Expense

Effective January 1, 2006, we adopted Statement of Financial Accounting Standards No. 123(R), Share-Based Payment, or SFAS No. 123R. Under this standard, companies are required to 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 and 2008 include $2.0 million and $2.5 million, respectively, of additional compensation expense as a result of the adoption of SFAS No. 123R and its application to the restricted stock awards that we primarily granted in January 2007 and 2008.

Liquidity and Capital Resources

Prior to the completion of our initial public offering, cash generated from operations, borrowings under our existing credit facilities and funds from partner contributions were our primary sources of liquidity. Following completion of our initial public offering, we have relied on cash generated from operations, public and private offerings of debt and equity securities and borrowings under our revolving credit facility to satisfy our liquidity needs. Our ability to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance, and more broadly, on the availability of equity and debt financing, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. At December 31, 2008, we had $1.6 million of cash and cash equivalents and $116.7 million of availability under our bank credit facilities that can be used for planned capital expenditures and to make acquisitions. We believe this is adequate to meet operational and capital expenditures needs in 2009.

Financial Condition and Cash Flows

Financial Condition

Our working capital increased $49.4 million to $87.8 million at December 31, 2008 compared to December 31, 2007, primarily due to a $50.5 million increase in trade accounts receivable that resulted from higher revenue activities discussed above in “— Our Results of Operations.” In addition, inventory increased by $17.8 in 2008 due mainly to the Diamondback asset acquisition and, to a lesser extent, higher inventory levels required to service the increase in revenue activities. Higher 2008 revenue activities and the Diamondback acquisition caused accounts payable and other accrued liabilities to increase by $11.8 million and $8.4 million, respectively. Cash from operations along with draws on our revolving credit facility was used to fund capital expenditures (excluding acquisitions) totaling $90.4 million in 2008.

Cash flows from operations

Our cash flow from operations decreased $17.6 million to $51.7 million for the year ended December 31, 2008 compared to December 31, 2007, primarily due to working capital requirements arising from the Diamondback acquisition that occurred on November 18, 2008. The Diamondback acquisition required the funding of operational working capital, which was not able to be offset by accounts receivable collections because billings were outstanding for a limited time at December 31, 2008. For a detailed comparison of 2008 and 2007 operating results please see “Our Results of Operations” — “Year ended December 31, 2008 Compared to Year Ended December 31, 2007.” Working capital decreased cash flow from operations due to growth in accounts receivable, advance payments on materials for future delivery, inventory and prepaid expenses that resulted from higher revenue activities and the Diamondback acquisition. Receivables, advance payments on materials for future delivery, inventory, and prepaid expenses increased by $50.5 million, $15.0 million, $6.5 million and $1.9 million, respectively for the year ended December 31, 2008 as compared to the year ended December 31, 2007. These decreases were partially offset due to higher amounts of deferred income taxes and depreciation and amortization of $20.3 million and $41.8 million, respectively. Additionally, the decrease in cash flows from operations for the year ended December 31, 2008 as compared to the year ended December 31, 2007, was offset due to increases in accounts payable and accrued liabilities of $13.7 million and $5.3 million, respectively.

Cash flows used in investing activities

Net cash used in investing activities increased from $128.1 million for the year ended December 31, 2007 to $174.1 million for the year ended December 31, 2008. The increase was due to the Diamondback asset acquisition. During 2008, non-acquisition related expenditures for property, plant and equipment declined from $117.8 million for the year ended December 31, 2007 to $90.4 million for the year ended December 31, 2008.

Cash flows from financing activities

Net cash provided by financing activities increased $110.9 million to $118.5 million for the year ended December 31, 2008. Superior’s revolving credit facilities funded $76 million for the Diamondback and Nuex asset acquisitions during 2008. Additionally, the revolving credit facilities were used to fund the 2008 increase in working capital discussed above in “— Financial Condition.”

Capital Requirements

The oilfield services business is capital-intensive, requiring significant investment to expand and upgrade operations. Our capital requirements have consisted primarily of, and we anticipate will continue to be:


	•	expansion capital expenditures, such as those to acquire additional equipment and other assets or upgrade existing equipment to grow our business; and

	•	maintenance or upgrade capital expenditures, which are capital expenditures made to extend the useful life of partially or fully depreciated assets or to maintain the operational capabilities of existing assets.

We continually monitor new advances in pumping equipment and down-hole technology and commit capital funds to upgrade and purchase additional equipment to meet our customers’ needs. For the year ended December 31, 2008, we made capital expenditures of approximately $90.4 million to purchase new and upgrade existing pumping and down-hole surveying equipment. Additionally, we purchased operating assets from Nuex Wireline, Inc. (“Nuex”) and Diamondback Energy Holdings, LLC (“Diamondback”). The Nuex assets were purchased for approximately $6.0 million in cash. Superior purchased the pressure pumping, fluid logistics and completion, production and rental tools assets from Diamondback for approximately $202.0 million. The Diamondback acquisition consideration consisted of $71.5 million in cash, $42.9 million of 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. These purchases and upgrades allow us to deploy additional services. Our 2009 capital expenditure budget is approximately $20 million. The decrease in the 2009 capital expenditure budget is due to the substantial decline in drilling rig activity which is expected to decrease the demand for our services. We plan to monitor our servicing opportunities and expect to adjust our expenditures accordingly. We plan to focus our planned 2009 capital expenditures budget on expanding our ability to service the Marcellus Shale activity in the Appalachian region, as well as expanding our nitrogen and cementing capabilities in all of our operating regions.

Given our objective of growth through organic expansions and selective acquisitions, we anticipate that we will continue to invest capital to acquire businesses and assets. We plan to continue to monitor the economic environment and demand for our services and adjust our growth as necessary. We actively consider a variety of businesses and assets for potential acquisitions, although currently we have no agreements or understandings with respect to any acquisition. For a discussion of the primary factors we consider in deciding whether to pursue a particular acquisition, please read “— Our Growth Strategy.” Management believes that cash flows from operations, combined with cash and cash equivalents and borrowing under our revolving credit facility will provide us with sufficient capital resources and liquidity to manage our routine operations and fund capital expenditures that are presently projected.

The following table summarizes our contractual cash obligations as of December 31, 2008 (in thousands):


			Less Than						After 5
Contractual Cash Obligations	Total		1 Year		1-3 Years		4-5 Years		Years

Long term and short term debt	$	261,179	$	5,879	$	14,064	$	240,616	$	620
Capital leases		3,632		1,382		2,250		—		—
Operating leases		32,333		9,396		13,858		6,883		2,196
Purchase obligations		103,070		10,545		24,509		30,670		37,346

Total	$	400,214	$	27,202	$	54,681	$	278,169	$	40,162

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 of “Notes to Consolidated Financial Statements,” included in this Form 10-K.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of December 31, 2008.

Description of Our Indebtedness

In October 2005, we entered into a $20 million revolving credit facility with our existing lending institution, which was increased to $45.0 million in July 2008. Interest on the revolving credit facility was at LIBOR plus a spread of 1% to 1.25%, based upon certain financial ratios. In September 2008, the revolving credit facility was repaid with proceeds from the syndicated credit facility. The weighted average interest rate for the revolving credit facility was 3.8% during 2008.

In August 2006, we entered into a standby term loan facility with our existing lending institution. The standby term loan facility provided an additional $30 million of borrowing capacity that could be used to finance equipment purchases. Interest on the revolving credit facility was at LIBOR plus a spread of 1% to 1.25%, based upon certain financial ratios. In September 2008, the standby term loan facility was repaid with the proceeds from the syndicated credit facility. The weighted average interest rate for the standby term loan facility was 3.6% during 2008.

On September 30, 2008, we entered into a credit agreement (the “Credit Agreement”) evidencing a new syndicated credit facility with a syndicate of lenders and financial institutions. The syndicated credit facility matures on March 31, 2013 and provides for a $250.0 million secured revolving credit facility. The syndicated credit facility replaced our existing $45.0 million revolving credit facility and $30.0 million standby term loan facility. The interest rate on borrowings under the syndicated credit facility is set, at our option, at either LIBOR plus a spread of 1.5% to 2.5% or the prime lending rate plus a spread of 0.0% to 0.25%. The applicable spreads are based on the ratio of our “total debt” to its “EBITDA,” in each case as those terms are defined in the Credit Agreement. The weighted average interest rate for the standby term loan facility was 3.9% during 2008. At December 31, 2008, we had $127.0 million outstanding under the syndicated credit facility, $6.3 million in letters of credit outstanding and $116.7 million of available capacity.

In connection with the Diamondback asset purchase (Note 3), we issued an aggregate principal amount of $80 million second lien notes due November 2013 (“Second Lien Notes”). In connection with the issuance of the Second Lien Notes, we entered into an indenture with our subsidiaries as guarantors and the Wilmington Trust FSB, as trustee (the “Indenture”). Interest on the 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.

The standby syndicated credit facility and the 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: 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. Both the Credit Agreement and the Indenture contain a total debt to EBITDA ratio and an interest coverage ratio as specified in the respective agreements. At

December 31, 2008, we were in compliance with the financial covenants required under the Credit Agreement and the Indenture.

At December 31, 2008, we had $1.2 million of other indebtedness, collateralized by specific buildings and equipment.

Accounting standards not yet adopted

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” (“SFAS 157”) which is intended to increase consistency and comparability in fair value measurements by defining fair value, establishing a framework for measuring fair value, and expanding disclosures about fair value measurements. SFAS 157 applies to other accounting pronouncements that require or permit fair value measurements and is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. In February 2008, the FASB issued SFAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13,” which removes certain leasing transactions from the scope of SFAS 157, and SFAS 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. In October 2008, the FASB also issued SFAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” which clarifies the application of SFAS 157 in an inactive market and illustrates how an entity would determine fair value when the market for a financial asset is not active. Beginning January 1, 2009, we will adopt the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis, which include those measured at fair value in goodwill impairment testing, indefinite-lived intangible assets measured at fair value for impairment assessment, nonfinancial long-lived assets measured at fair value for impairment assessment, asset retirement obligations initially measured at fair value, and those initially measured at fair value in a business combination. We are currently evaluating the impact of adopting the provisions of SFAS 157; however, we do not expect it to have an effect on our consolidated financial statements.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51” (“SFAS 160”). This statement amends ARB No. 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the loss of control of a subsidiary. Upon its adoption on January 1, 2009, noncontrolling interests will be classified as equity in our financial statements. SFAS 160 also changes the way the consolidated income statement is presented by requiring net income to include the net income for both the parent and the noncontrolling interest, with disclosure of both amounts on the consolidated statement of income. The calculation of earnings per share will continue to be based on income amounts attributable to the parent. The provisions of this standard must be applied retroactively upon adoption. We are currently evaluating the impact of adopting SFAS 160; however, we do not expect it to have an effect on our consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141R, “Business Combinations,” a replacement of SFAS No. 141 (“SFAS 141R”). This statement replaces SFAS 141 to establish accounting and reporting standards for business combinations in the first annual reporting period beginning after December 15, 2008. Early adoption of this statement is prohibited. SFAS 141R retains the fundamental requirements in SFAS 141 that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. Upon its adoption on January 1, 2009, non-controlling interests will be classified as equity in the Superior financial statements. We are currently evaluating the impact of adopting SFAS 141R.

In March 2008, the FASB affirmed the consensus of FASB Staff Position (“FSP”) APB 14-a, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement),” (“FSP APB 14-a”) which applies to all convertible debt instruments that have a “net settlement feature”, which means instruments that by their terms may be settled either wholly or partially in cash upon conversion. FSP APB 14-a requires issuer’s of convertible debt instruments that may be settled wholly or partially in cash upon conversion to separately account for the liability and equity components in a manner reflective of the issuer’s nonconvertible debt borrowing rate. Previous guidance provided for accounting for this type of convertible debt instrument entirely

as debt. FSP APB 14-a is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. We are currently evaluating the impact of adopting FSP APB 14-a.

In April 2008, the FASB issued FSP No. FAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP No. FAS 142-3”). FSP No. FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS 142. The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS 141 and other U.S. generally accepted accounting principles. FSP No. FAS 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. We are currently evaluating the impact of adopting FSP No. FAS 142-3.

In June 2008, the FASB issued FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP No. EITF 03-6-1”). FSP No. EITF 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share, or EPS, under the two-class method described in paragraphs 60 and 61 of SFAS 128. The guidance in this FSP applies to the calculation of EPS under SFAS 128 for share-based payment awards with rights to dividends or dividend equivalents. FSP No. EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. All prior-period EPS data presented should be adjusted retrospectively to conform with the provisions of this FSP. Early application is not permitted. We are currently evaluating the impact of adopting FSP No. EITF 03-6-1.

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 prospectus.

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 natural gas and oil 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.

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 building and improvements, range from 5 to 15 years for disposal wells and equipment and range from 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

In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), 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 natural gas and crude oil prices. Projections of our future cash flows are inherently subjective and contingent upon a number of variable factors, including but not limited to:


	•	changes in general economic conditions in regions in which our services are located;

	•	the price of natural gas and crude oil;

	•	our ability to negotiate favorable sales arrangements; and

	•	our competition from other service providers.

We currently have not recorded any impairment of an asset. Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.

Goodwill and Other Intangible Assets

In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”), no amortization is recorded for goodwill and /or intangible assets deemed to have indefinite lives 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. Our goodwill impairment test is performed at the business segment levels, technical services and fluid logistics, as they represent our reporting units. Per SFAS 142, 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 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. For the years ended December 2006, 2007 and 2008, the fair value of our reporting units exceeded their carrying amount, thus no impairment charge was recorded.

At December 31, 2008, our intangible assets consisted of $31.7 million of goodwill and $10.1 million of customer relationships, trade names 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, 2006, 2007 and 2008, we recorded amortization expense of $345,000, $805,000 and $1,138,000, 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 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 $110,000 per employee.

Stock-Based Compensation

Effective January 1, 2006, we adopted Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment” (“SFAS 123R”). Under this standard, companies are required to 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, 2006, 2007 and 2008 include $1,740,000, $1,961,000 and $2,522,000 of additional compensation expense, respectively, as a result of the adoption of SFAS 123R. 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. We are 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 Superior’s 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:


	•	a decrease in domestic spending by the oil and natural gas exploration and production industry;

	•	a decline in or substantial volatility of natural gas and crude oil commodity prices;

	•	current weaknesses in the credit and capital markets and lack of credit availability;

	•	overcapacity and competition in our industry;

	•	unanticipated costs, delays and other difficulties in executing our growth strategy, including difficulties associated with the integration of the Diamondback acquisition;

	•	the loss of one or more significant customers;

	•	the increased credit risk of our customers;

	•	the loss of or interruption in operations of one or more key suppliers;

	•	the incurrence of significant costs and liabilities in the future resulting from our failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment; and

	•	other financial, operational and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings.


Item 7A.	*Quantitative and Qualitative Disclosures about Market Risk*

Quantitative and Qualitative Disclosures about Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risk to which we are exposed is the risk related to interest rate fluctuations. To a lesser extent, we are also exposed to risks related to increases in the prices of fuel and raw materials consumed in performing our services. We do not engage in commodity price hedging activities.

Interest Rate Risk. We are exposed to changes in interest rates as a result of our 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, 2007 and December 31, 2008 would result in an increase in interest expense and a corresponding decrease in net income, of less than $0.1 million and $1.3 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 14% and 12% in 2006, 12% and 9% in 2007 and 13% and 9% in 2008 of our revenue. Eight customers accounted for 45%, 42% and 44% of our revenue for the years ended December 31, 2006, 2007 and 2008, respectively. At December 31, 2008, one customer accounted for 17% and eight customers accounted for 51% of our accounts receivable.

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


Item 8.	*Financial Statements and Supplementary Data*

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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, 2008. 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, 2008, our internal control over financial reporting is effective based on those criteria. The Company has excluded Diamondback from its Report on Internal Control over Financial Reporting for fiscal 2008 due to the timing of the closing date of the acquisition on November 18, 2008 and the expectation that internal control over financial reporting related to Diamondback will be changed to conform with our internal control over financial reporting in 2009. 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 12, 2009

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Superior Wells Services, Inc.

We have audited the accompanying consolidated balance sheets of Superior Well Services, Inc. (Superior) as of December 31, 2008 and 2007, and the related statements of income, changes in stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2008. 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, 2008, 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.

As indicated in the accompanying Management’s Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls over the business acquired from Diamondback Holdings, LLC (Diamondback), which acquired assets, assumed liabilities, and operations are included in the consolidated balance sheet of Superior as of December 31, 2008, and the related consolidated statements of operations, stockholders’ equity and cash flows for the year then ended. Diamondback acquired assets constituted approximately 36.6% of consolidated assets as of December 31, 2008, and 5.0% and 4.9% of consolidated revenue and income from continuing operations before income taxes, respectively, for the year then ended. Management did not assess the effectiveness of internal control over financial reporting of Diamondback because of the timing of the acquisition which was completed on November 18, 2008 and the expectation that the internal control over financial reporting related to Diamondback will be changed to conform to Superior’s internal control over financial reporting in 2009. Our audit of internal

control over financial reporting of Superior also did not include an evaluation of the internal control over financial reporting of Diamondback.

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, 2008 and 2007, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2008, 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, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

/s/ Schneider Downs & Co., Inc.

Pittsburgh, Pennsylvania

March 12, 2009

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,		December 31,
	2007		2008
	(In thousands, except
	per share data)

Current Assets:
Cash and cash equivalents	$	5,510	$	1,637
Trade accounts receivable, net of allowance of $1,629 and $2,755, respectively		54,002		104,549
Inventories		9,933		27,781
Prepaid expenses and other current assets		1,027		3,860
Assets held for sale		—		1,440
Advances on materials for future delivery		—		3,732
Income taxes receivable		3,722		1,934
Deferred income taxes		1,827		3,746

Total current assets		76,021		148,679
Property, plant and equipment, net		240,863		453,990
Goodwill		5,850		31,726
Intangible assets, net of accumulated amortization of $1,815 and $2,953, respectively		3,242		10,120
Deferred income taxes		366		530
Other assets		745		13,185

Total assets	$	327,087	$	658,230

Current Liabilities:
Accounts and construction payable-trade	$	31,497	$	43,330
Current portion of long-term obligations		390		1,291
Advance payments on servicing contracts		70		405
Accrued wages and health benefits		2,126		5,481
Other accrued liabilities		3,546		10,370

Total current liabilities		37,629		60,877
Long-term debt		9,165		208,042
Deferred income taxes		26,694		49,082
Long-term capital leases		—		2,171
Asset retirement obligation		—		443
Stockholders’ Equity:
Preferred stock, non-voting, par $0.01 per share, 10,000,000 shares authorized Series A 4% Convertible Preferred stock, non-voting, 75,000 shares issued at December 31, 2008 (liquidation preference $75 million)		—		1
Common stock, voting, par $.01 per share, 70,000,000 shares authorized, 23,474,552 and 23,620,578 shares issued at December 31, 2007 and 2008, respectively		234		236
Additional paid-in capital		184,432		229,741
Retained earnings		68,933		107,637

Total stockholders’ equity		253,599		337,615

Total liabilities and stockholders’ equity	$	327,087	$	658,230

The accompanying notes are an integral part of these consolidated financial statements.

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME


	Years Ended December 31,
	2006			2007			2008

Revenue	$	244,626		$	350,770		$	520,889
Cost of revenue		165,877			252,539			406,044

Gross profit		78,749			98,231			114,845
Selling, general and administrative expenses		25,716			36,390			45,702

Operating income		53,033			61,841			69,143
Interest expense		(478	)		(282	)		(2,834	)
Other income (expense)		159			766			(135	)

Income before income taxes		52,714			62,325			66,174
Income taxes
Current		16,033			14,110			7,058
Deferred		4,758			10,460			20,304

		20,791			24,570			27,362

Net income before dividends on preferred stock		31,923			37,755			38,812

Dividends on preferred stock		—			—			(108	)
Net income available to common stockholders	$	31,923		$	37,755		$	38,704

Earnings per common share:
Basic	$	1.63		$	1.63		$	1.67

Diluted	$	1.63		$	1.63		$	1.64

Weighted average shares outstanding-basic		19,568,749			23,100,402			23,150,463
Weighted average shares outstanding-diluted		19,568,749			23,195,914			23,661,608

The accompanying notes are an integral part of these consolidated financial statements.

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY


	Superior Well Services, Inc.
						Additional			Retained
	Preferred		Common			Paid-in			Earnings
	Stock		Stock			Capital			(Deficit)			Total
	(In thousands)

BALANCE, DECEMBER 31, 2005	$	—	$	194		$	91,944		$	(745	)	$	91,393
Net income										31,923			31,923
Issuance of restricted stock awards				3			286						289
Share-based compensation							1,740						1,740
Issuance of common stock in connection with initial public offering				37			88,522						88,559

BALANCE, DECEMBER 31, 2006		—		234			182,492			31,178			213,904
Net income										37,755			37,755
Issuance of restricted stock awards				1			135						136
Restricted stock retired				(1	)		(156	)					(157	)
Share-based compensation							1,961						1,961

BALANCE, DECEMBER 31, 2007		—		234			184,432			68,933			253,599
Net income										38,812			38,812
Issuance of preferred stock in connection with acquisition, net of offering expenses		1					42,844						42,845
Issuance of restricted stock awards				2			175						177
Restricted stock retired							(232	)					(232	)
Share-based compensation							2,522						2,522
Preferred stock dividends										(108	)		(108	)

BALANCE, DECEMBER 31, 2008	$	1	$	236		$	229,741		$	107,637		$	337,615

The accompanying notes are an integral part of these consolidated financial statements.

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2006			2007			2008
	(In thousands)

Cash flows from operations:
Net income	$	31,923		$	37,755		$	38,812
Adjustments to reconcile net income to net cash provided by operations:
Deferred income taxes		4,758			10,460			20,304
Depreciation and amortization		14,453			25,277			41,806
Loss on disposal of equipment		224			302			221
Stock-based compensation		1,740			1,961			2,522
Changes in assets and liabilities:
Trade accounts receivable		(23,944	)		(6,677	)		(50,471	)
Advance on materials for future delivery		—			—			(14,992	)
Inventory		(3,190	)		(2,982	)		(6,461	)
Prepaid expenses and other assets		249			(119	)		(1,931	)
Income tax receivable		—			(3,722	)		1,788
Accounts payable		6,220			7,759			13,717
Income taxes payable		542			(542	)		—
Advance payments on servicing contracts		324			(733	)		335
Accrued wages and health benefits		621			664			2,393
Other accrued liabilities		2,029			(100	)		3,663

Net cash provided by operations		35,949			69,303			51,706
Cash flows from investing:
Expenditure for property, plant and equipment, net of construction payables		(69,816	)		(117,774	)		(90,424	)
Acquisition of businesses, net of cash acquired		(9,150	)		(9,931	)		(84,242	)
Purchase of short-term investments		—			(18,967	)		—
Proceeds from sales of short-term investments		—			18,967			—
Proceeds (expenditures) for other assets		(15	)		(429	)		(1,183	)
Proceeds from sale of property, plant and equipment		79			34			1,789

Net cash used in investing		(78,902	)		(128,100	)		(174,060	)
Cash flows from financing:
Principal payments on long-term debt		(27,019	)		(52,274	)		(212,276	)
Proceeds from long-term borrowings		27,111			59,850			330,920
Net proceeds from common stock offerings		88,559			—			—
Issuance/retirement of restricted stock, net		289			(21	)		(55	)
Payment of preferred dividends		—			—			(108	)

Net cash provided by financing		88,940			7,555			118,481

Net increase (decrease) in cash and cash equivalents		45,987			(51,242	)		(3,873	)
Cash and cash equivalents, beginning of period		10,765			56,752			5,510

Cash and cash equivalents, end of period	$	56,752		$	5,510		$	1,637

Supplemental disclosure of cash flow data:
Interest paid	$	437		$	292		$	1,000
Income taxes paid	$	15,008		$	18,262		$	5,270
Equipment acquired through seller financed debt	$	450		$	—		$	—
Second lien notes issued in acquisition	$	—		$	—		$	80,000
Preferred stock issued in acquisition	$	—		$	—		$	42,945

The accompanying notes are an integral part of these consolidated financial statements

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	Organization

Superior Well Services, Inc. (“Superior”) was formed as a Delaware corporation on March 2, 2005 for the purpose of serving as the parent holding company for Superior GP, L.L.C. (“Superior GP”), Superior Well Services, Ltd. (“Superior Well”) and Bradford Resources, Ltd. (“Bradford”). In May 2005, Superior and the partners of Superior Well and Bradford entered into a contribution agreement that resulted in the partners of Superior Well and Bradford contributing their respective partnership interests to Superior in exchange for shares of common stock of Superior (the “Contribution Agreement”). In December 2006, Bradford was merged into Superior Well. Superior Well is a Pennsylvania limited partnership that became a wholly owned subsidiary of Superior in connection with its initial public common stock offering.

In November 2008, Superior purchased the pressure pumping, fluid logistics and completion, production and rental tool assets of Diamondback Energy Holdings, LLC (“Diamondback”). In connection with the asset purchase, Superior formed SWSI Fluids, LLC to acquire the fluid logistics assets. SWSI Fluids LLC is a wholly owned subsidiary of Superior.

Superior provides a wide range of well services to oil and gas companies, that include technical pumping, down-hole surveying, fluid logistics and completion, production and rental tool services, in many of the major oil and natural gas producing regions of the United States.


2.	Summary of Significant Accounting Policies

Basis of Presentation

The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). These financial statements reflect all adjustments that, in our opinion, are necessary to fairly present our financial position and results of operations. Significant intercompany accounts and transactions have been eliminated in consolidation.

The accompanying consolidated financial statements include the accounts of Superior and its wholly-owned subsidiaries Superior Well, Superior GP and SWSI Fluids LLC. Superior Well and Bradford (“Partnerships”), prior to the effective date of the Contribution Agreement, were entities under common control arising from common direct or indirect ownership of each. The transfer of the Partnerships assets and liabilities to Superior (see Note 1) represented a reorganization of entities under common control and was accounted for at historical cost. Prior to the reorganization, the Partnerships were not subject to federal and state corporate income taxes

Estimates and Assumptions

Superior uses certain estimates and assumptions that affect reported amounts and disclosures. These estimates are based on judgments, probabilities and assumptions that are believed to be reasonable but inherently uncertain and unpredictable. Assumptions may be incomplete or inaccurate, and unanticipated events and circumstances may occur. Superior is subject to risks and uncertainties that may cause actual results to differ from estimated amounts.

Cash and Cash Equivalents

All cash and cash equivalents are stated at cost, which approximates market. Superior considers all highly liquid investments purchased with a maturity of three months or less to be cash equivalents. Superior maintains cash at various financial institutions that may exceed federally insured amounts.

Trade Accounts Receivable

Accounts receivable are carried at the amount owed by customers. Superior grants credit to all qualified customers, which are mainly regional, independent natural gas and oil companies. Management periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of its customers. Once

an account is deemed not to be collectible, the remaining balance is charged to the reserve account. For the years ended December 31, 2006, 2007 and 2008, Superior recorded a provision for uncollectible accounts receivable of $637,600, $857,100 and $1,021,900, respectively.

Assets held for sale

Superior classifies certain assets as held for sale based on management having the authority and intent of entering into commitments for sale transactions expected to close in the next twelve months. When management identifies an asset held for sale, Superior estimates the net selling price of such an asset. If the net selling price is less than the carrying amount of the asset, a reserve for loss is established. Fair value is determined at prevailing market conditions, appraisals or current estimated net sales proceeds from pending offers. At December 31, 2008, Superior identified $1.4 million of assets held for sale. These assets were part of the Diamondback asset purchase (Note 3) and generated no income from operations after their November 2008 acquisition.

Advances on Material for Future Delivery

In October 2008, Superior entered into a take-or-pay contract with Preferred Rocks USS, Inc. to purchase fracturing sand beginning in November 2008 through December 2015. In connection with the take-or-pay contract Superior advanced $15 million for materials that will be delivered in the future. The advance on materials for future delivery will be used to offset future purchase commitments under the take-or-pay contract. At December 31, 2008, the portion of the advance expected to offset future purchases within the next twelve months amounted to $3.7 million and is reflected in current assets. Other Assets includes $11.3 million for advances expected to offset future purchases after one year.

Property, Plant and Equipment

Superior’s property, plant and equipment are stated at cost less accumulated depreciation. The costs are depreciated using the straight-line and accelerated methods over their estimated useful lives. The estimated useful lives range from 15 to 30 years for building and improvements, range from 5 to 15 years for disposal wells and related equipment and range from 5 to 10 years for equipment and vehicles. Depreciation expense, excluding intangible amortization, amounted to $14,108,000, $24,472,000 and $40,590,000 in 2006, 2007 and 2008, respectively.

Repairs and maintenance costs that do not extend the useful lives of the asset are expensed in the period incurred. Gain or loss resulting from the retirement or other disposition of assets is included in income.

Superior reviews long-lived assets for impairment whenever there is evidence that the carrying value of such assets may not be recoverable. The review consists of comparing the carrying value of the assets with the assets’ expected future undiscounted cash flows. An impairment loss would be recognized when estimated future cash flows expected to result from the use of the assets and their eventual dispositions are less than the assets’ carrying value. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions.

Revenue Recognition

Superior’s revenue is comprised principally of service revenue. Product sales represent approximately 1% of total revenues. Services and products are generally sold based on fixed or determinable pricing agreements with the customer and generally do not include rights of return. Service revenue is recognized, net of discount, when the services are provided and collectibility is reasonably assured. Generally, Superior’s services performed for customers are completed at the customer’s site within one day. Superior recognizes revenue from product sales when the products are delivered to the customer and collectibility is reasonably assured. Products are delivered and used by our customers in connection with the performance of our cementing services. Product sale prices are determined by published price lists provided to our customers.

Inventories

Inventories, which consist principally of materials consumed in Superior’s services provided to customers, are stated at the lower of cost or market using the specific identification and, the first-in, first-out methods.

Insurance Expense

Superior partially self-insures employee health insurance plan costs. The estimated costs of claims under this self-insurance program are accrued as the claims are incurred (although actual settlement of the claims may not be made until future periods) and may subsequently be revised based on developments relating to such claims. The self-insurance accrual is estimated based upon our historical experience, as well as any known unpaid claims activity. Judgment is required to determine the appropriate accrual levels for claims incurred but not yet received and paid. The accrual estimates are based primarily upon recent historical experience adjusted for employee headcount changes. Historically, the lag time between the occurrence of an insurance claim and the related payment has been approximately two months and the differences between estimates and actuals have not been material. The estimates could be affected by actual claims being significantly different. Presently, Superior maintains an insurance policy that covers claims in excess of $110,000 per employee.

Income Taxes

Superior accounts for income taxes in accordance with the provisions of Statements of Financial Accounting Standards (‘‘SFAS”) No. 109, “Accounting for Income Taxes” (SFAS 109”). This statement requires a company to recognize deferred tax liabilities and assets for the expected future tax consequences of events that have been recognized in Superior’s financial statements or tax returns. Using this method, deferred tax liabilities and assets were determined based on the difference between the financial carrying amounts and tax bases of assets and liabilities using enacted tax rates. Prior to becoming wholly-owned subsidiaries of Superior, the Partnerships were not taxable entities for federal or state income tax purposes and, accordingly, were not subject to federal or state corporate income taxes.

Effective January 1, 2007, we adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48 “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48, as amended May 2007 by FASB Staff Position FIN 48-1, “Definition of ‘Settlement’ in FASB Interpretation No. 48,” prescribes a minimum recognition threshold and measurement methodology that a tax position taken or expected to be taken in a tax return is required to meet before being recognized in financial statements. The adoption of FIN 48 did not have any impact on Superior’s total liabilities or stockholders’ equity. Superior’s balance sheets at December 31, 2007 and 2008 do not include any liabilities associated with uncertain tax positions; further Superior has no unrecognized tax benefits that if recognized would change the 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. Superior classifies 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 and 2008 were insignificant in each period. We are subject to U.S. Federal income tax examinations for the years after 2005 and we are subject to various state tax examinations for years after 2005.

Asset Retirement Obligations

Superior has an obligation to plug and abandon its disposal wells at the end of their operations. Superior records the fair value of an asset retirement obligation as a liability in the period in which it incurs legal obligation associated with the retirement of the assets and capitalizes an equal amount as a cost of the assets, depreciating it over the life of the assets. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted to reflect the passage of time, changes in the estimated future cash flows underlying the obligation, acquisition or construction of assets and settlements of obligations. In November 2008, the asset retirement obligation was assumed through the Diamondback asset purchase. Accretion expense in 2008 was insignificant.

Fair Value of Financial Instruments

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115” (SFAS 159). This statement permits entities to measure eligible assets and liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. We adopted SFAS 159 on January 1, 2008 and did not elect to apply the fair value method to any eligible assets or liabilities at that time.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” (SFAS 157) which is intended to increase consistency and comparability in fair value measurements by defining fair value, establishing a framework for measuring fair value, and expanding disclosures about fair value measurements. This statement applies to other accounting pronouncements that require or permit fair value measurements and is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. On January 1, 2008, we adopted, without material impact on our consolidated financial statements, the provisions of SFAS 157 related to financial assets and liabilities.

SFAS 157 requires disclosure about how fair value is determined for assets and liabilities and establishes a hierarchy for which these assets and liabilities must be grouped, based on significant levels of inputs as follows:


	Level 1	quoted prices in active markets for identical assets or liabilities;

	Level 2	quoted prices in active markets for similar assets and liabilities and inputs that are observable for the asset or liability; or

	Level 3	unobservable inputs for the asset or liability, such as discounted cash flow models or valuations.

The determination of where assets and liabilities fall within this hierarchy is based upon the lowest level of input that is significant to the fair value measurement.

Superior’s financial instruments are not held for trading purposes.

Acquisitions

Assets acquired in business combinations were recorded on Superior’s consolidated balance sheets as of the respective acquisition dates based upon their estimated fair values at such dates. The results of operations of businesses acquired by Superior have been included in Superior’s consolidated statements of income since their respective dates of acquisition. The excess of the purchase price over the estimated fair values of the underlying net assets acquired, including other intangible assets was allocated to goodwill. In certain circumstances, the allocations are based upon preliminary estimates and assumptions. Accordingly, the allocations are subject to revision when we receive final information. Revisions to the fair values, will be recorded by us as further adjustments to the purchase price allocations.

Goodwill and Other Intangible Assets

the difference. Any impairment charge would reduce earnings. For the years ended December 2006, 2007 and 2008, the fair value of our reporting units exceeded their carrying amount, thus no impairment charge was recorded.

Superior’s intangible assets consist of $31.7 million of goodwill and $10.1 million of customer relationships, trade names 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, 2006, 2007 and 2008, Superior recorded amortization expense of $345,000, $805,000 and $1,138,000, respectively. The estimated amortization expense for the five succeeding years approximates $2,380,000, $2,371,000, $2,220,000, $1,768,000 and $1,404,000 for 2009, 2010, 2011, 2012 and 2013, respectively.

Concentration of Credit Risk

Substantially all of Superior’s customers are engaged in the oil and gas industry. This concentration of customers may impact overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions. Two customers individually accounted for 14% and 12% in 2006, 12% and 9% in 2007 and 13% and 9% in 2008 of our revenue. Eight customers accounted for 45%, 42% and 44% of our revenue for the years ended December 31, 2006, 2007 and 2008, respectively. At December 31, 2008, one customer accounted for 17% and eight customers accounted for 51% of Superior’s accounts receivable.

Stock Based Compensation

Effective January 1, 2006, Superior adopted Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment” (“SFAS 123R”). Under this standard, companies are required to 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. The years ended December 31, 2006, 2007 and 2008 includes $1,740,000, $1,961,000 and $2,522,000 of additional compensation expense, respectively, as a result of the adoption of SFAS 123R. Superior had no stock based compensation prior to 2006.

Weighted average shares outstanding

The consolidated financial statements include “basic” and “diluted” per share information. Basic per share information is calculated by dividing net income available to common stockholders by the weighted average number of shares outstanding. For the three months and year ended December 31, 2008, net income was reduced by $108,000 of preferred dividend payments to arrive at net income available to common stockholders. Diluted per share information is calculated by also considering the impact of restricted common stock on the weighted average number of shares outstanding.

Although the restricted shares are considered legally issued and outstanding under the terms of the restricted stock agreement, they are still excluded from the computation of basic earnings per share. Once vested, the shares are included in basic earnings per share as of the vesting date. Superior includes unvested restricted stock with service conditions in the calculation of diluted earnings per share using the treasury stock method. Assumed proceeds under the treasury stock method would include unamortized compensation cost and potential windfall tax benefits. If dilutive, the stock is considered outstanding as of the grant date for diluted earnings per share computation purposes. If anti-dilutive, it would be excluded from the diluted earnings per share computation. 46,086 restricted shares were considered to be dilutive for the three months ended December 31, 2007. The restricted shares were anti-dilutive for the three month periods ended December 31, 2006 and 2008. 95,512 and 150,489 restricted shares were considered to be dilutive for the year ended December 31, 2007 and 2008. The restricted shares were anti-dilutive for the year ended December 31, 2006.

Additionally, we account for the effect of Convertible Preferred Stock in the diluted earnings per share calculation using the “if converted” method. Under this method, the $75 million of Convertible Preferred Stock is assumed to be converted to common shares at the conversion price of $25.00, which equals 3 million “if converted” shares. The number of “if-converted” shares is weighted for the number of days outstanding in the period, 44 days in 2008, to arrive at the number of “if-converted” shares for the three months and year ended December 31, 2008.

Therefore, this equates to 1,434,783 and 360,656 of “if-converted” shares for the three months and year ended December 31, 2008, respectively. Superior did not have Convertible Preferred Stock outstanding in 2006 and 2007, so there were no “if-converted” shares to account for during those periods.

Accounting Standards Not Yet Adopted

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51” (“SFAS 160”). This statement amends ARB No. 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the loss of control of a subsidiary. Upon its adoption on January 1, 2009, any noncontrolling interests would be classified as equity in the Superior financial statements. SFAS 160 also changes the way the consolidated income statement is presented by requiring net income to include the net income for both the parent and the noncontrolling interest, with disclosure of both amounts on the consolidated statement of income. The calculation of earnings per share will continue to be based on income amounts attributable to the parent. The provisions of this standard must be applied retroactively upon adoption. We are currently evaluating the impact of adopting SFAS 160; however, we do not expect it to have an effect on our consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141R, “Business Combinations,” a replacement of SFAS No. 141 (“SFAS 141R”). This statement replaces SFAS 141 to establish accounting and reporting standards for business combinations in the first annual reporting period beginning after December 15, 2008. Early adoption of this statement is prohibited. SFAS 141R retains the fundamental requirements in SFAS 141 that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. Upon its adoption on January 1, 2009, noncontrolling interests will be classified as equity in the Superior financial statements. We are currently evaluating the impact of adopting SFAS 141R.

In March 2008, the FASB affirmed the consensus of FASB Staff Position (“FSP”) APB 14-a, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement )” (“FSP APB 14-a”), which applies to all convertible debt instruments that have a “net settlement feature”, which means instruments that by their terms may be settled either wholly or partially in cash upon conversion. FSP APB 14-a requires issuer’s of convertible debt instruments that may be settled wholly or partially in cash upon conversion to separately account for the liability and equity components in a manner reflective of the issuer’s nonconvertible debt borrowing rate. Previous guidance provided for accounting for this type of convertible debt instrument entirely as debt. FSP APB 14-a is effective for financial statements issued for fiscal years beginning after December 15, 2008

and interim periods within those fiscal years. We are currently evaluating the impact of adopting FSP APB 14-a.; however, we do not expect it to have an effect on our consolidated financial statements.

In April 2008, the FASB issued FSP No. FAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP No. FAS 142-3”). FSP No. FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS 142. The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS 141 and other U.S. generally accepted accounting principles. FSP No. FAS 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. We are currently evaluating the impact of adopting FSP No. FAS 142-3; however, we do not expect it to have an effect on our consolidated financial statements.

In June 2008, the FASB issued FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP No. EITF 03-6-1”). FSP No. EITF 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share, or EPS, under the two-class method described in paragraphs 60 and 61 of SFAS 128. The guidance in this FSP applies to the calculation of EPS under SFAS 128 for share-based payment awards with rights to dividends or dividend equivalents. FSP No. EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. All prior-period EPS data presented should be adjusted retrospectively to conform with the provisions of this FSP. Early application is not permitted. We are currently evaluating the impact of adopting FSP No. EITF 03-6-1.


3.	Business Combinations

Assets acquired in business combinations were recorded on Superior’s consolidated balance sheets as of the date of the respective acquisition based upon their estimated fair values at such dates. The results of operations of businesses acquired by Superior have been included in Superior’s consolidated statements of income since their respective dates of acquisition. The excess of the purchase price over the estimated fair values of the underlying net assets acquired, including identifiable intangible assets was allocated to goodwill. When appropriate, we engage third-party appraisal firms to assist in fair value determination of equipment, identifiable intangible assets and any other significant assets or liabilities and the determination of the fair-value of non-cash consideration that may be issued to seller. In certain circumstances, the allocations are based upon preliminary estimates and assumptions. Accordingly, the allocations are subject to revision when we receive final information. Revisions to the fair values, will be recorded by us as further adjustments to the purchase price allocations.

Acquisitions During the Year ended December 31, 2007:

In February 2007, Superior purchased substantially all the operating assets of ELI Wireline Services, Inc. (“ELI”) for approximately $7.9 million in cash. ELI provides open hole services and cased hole completion services. The operating assets include three cased hole trucks, three open hole trucks, two cavern storage logging units with sonar calipers and various tools and logging systems that are compatible with Superior’s existing systems. The acquired assets were integrated into Superior’s Mid-Continent operations and expand our presence in Kansas, Oklahoma and Nebraska. ELI’s purchase cost included $4.3 million, $2.0 million and $1.6 million of property, plant and equipment, goodwill and intangible assets, respectively. No pro forma information has been provided as the acquisition was not significant.

In November 2007, Superior purchased substantially all the operating assets of Madison Wireline Services, Inc. (“Madison”) in Williston, North Dakota for approximately $3.0 million in cash. Included in the acquisition were four cased-hole trucks suitable for cased-hole completion and various tools and logging systems that are compatible with Superior’s existing systems. The acquired operations were integrated into Superior’s Rocky Mountain operations and expanded our national footprint into North Dakota, South Dakota and Montana. No pro forma information has been provided as the acquisition was not significant.

Acquisitions During the Year ended December 31, 2008:

In July 2008, Superior purchased substantially all the operating assets of Nuex Wireline, Inc. (“Nuex”) for approximately $6.0 million in cash and potential payments of up to $1.5 million over a three-year period pursuant to an earnout arrangement. Nuex provides cased hole completion services. The operating assets included five cased hole trucks and various tools and logging systems that are compatible with Superior’s existing systems. Superior retained all of Nuex’s sixteen employees. The acquired operations were integrated into Superior’s Rocky Mountain operations, which expands our presence in Brighton, Colorado. Nuex’s purchase cost was allocated as follows: $1.5 million, $3.6 million and $0.9 million to property, plant and equipment, goodwill and intangible assets, respectively. No pro forma information has been provided as the acquisition was not significant.

In November 2008, Superior purchased the pressure pumping, fluid logistics and completion, production and rental tools business lines from Diamondback Energy Holdings, LLC (“Diamondback”) for approximately $202.0 million. The acquisition consideration consisted of $71.5 million in cash, $42.9 million of Series A 4% Convertible Preferred Stock ($75 million liquidation preference) (Preferred Stock) with a perpetual term 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. Each share of Preferred Stock is entitled to a liquidation preference of $1,000 per share and is convertible into 40 shares of common stock subject to adjustment (representing a conversion price of $25 per share based on the liquidation preference). The fair value of the Preferred Stock was estimated using quotes obtained from an investment bank that used a convertible valuation tool used by investment banks, convertible investors and other market participants to value equity-linked securities. The Second Lien Notes are due in November 2013 and are pre-payable without penalty at the Company’s option. The interest rate on the Second Lien Notes is initially set at 7% and escalates 1% annually. The fair value of the second lien notes was estimated by using Standard & Poors leveraged loan composite indices with similar terms and maturity. As part of the acquisition, Superior acquired 128,000 horsepower, 105 transports and trucks, 400 frac tanks and six water disposal wells. The assets that Superior 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 thus expanding our presence in the Mid-Continent and Southwest regions.

The following table summarizes the preliminary purchase price allocation of the fair value of assets acquired and liabilities assumed in connection with Diamondback acquisition. The initial purchase price allocations may be adjusted within one year of the purchase date for changes in estimates of the fair value of assets acquired and liabilities assumed (dollars in thousands):


Property, plant & equipment	$	165,165
Inventory and other current assets		12,364
Trade names		4,240
Customer relationships		2,800
Goodwill		22,294
Accrued paid time off		(1,018	)
Capital lease obligations		(3,434	)
Asset retirement obligation		(443	)

Net assets acquired	$	201,968

The amount of goodwill that is expected to be deductible for tax purposes is $22.3 million.

We calculated the unaudited pro forma impact of the assets we acquired from Diamondback on our operating results for the years ended December 31, 2007 and 2008. The following unaudited pro forma results give effect to Diamondback acquisition, assuming that it had occurred on January 1, 2007 and 2008, as applicable.

We derived the unaudited pro forma results of these acquisitions based upon historical financial information obtained from the sellers and certain management assumptions. In addition, we assumed debt service costs related to these acquisitions based upon the actual cash investments, calculated at a rate of 3.9% per annum, plus an assumed tax expense calculated at our effective tax rate for the years ended December 31, 2007 and 2008.

The following unaudited pro forma results do not purport to be indicative of the results that would have been obtained had the transactions described above been completed on the indicated dates or that may be obtained in the future (in thousands, except per share data).


	Year Ended December 31,
	2007		2008

Revenues	$	565,255	$	758,536
Income from continuing operations	$	72,145	$	85,477
Net income	$	43,704	$	50,133
Per share data:
Income from continuing operations-basic	$	3.12	$	3.69
Income from continuing operations-diluted	$	2.75	$	3.25
Net income-basic	$	1.76	$	2.04
Net income-diluted	$	1.67	$	1.91

Superior does not believe the unaudited pro forma effect of the remainder of the acquisitions completed in 2007 or 2008 is material, either individually or when aggregated, to the reported results of operations.


4.	Property, Plant and Equipment

Property, plant and equipment at December 31, 2007 and 2008 consisted of the following:


	December 31, 2007			December 31, 2008
	(In thousands)

Property, Plant and Equipment:
Land	$	420		$	453
Building and improvements		4,776			16,621
Equipment and vehicles		266,444			500,101
Disposal wells and equipment		—			8,764
Construction in progress		29,814			28,065

		301,454			554,004
Accumulated depreciation		(60,591	)		(100,014	)

Total property, plant and equipment, net	$	240,863		$	453,990


5.	Short and Long-term Obligations

Debt

In October 2005, Superior entered into a $20.0 million revolving credit facility with its existing lending institution, which was increased to $45.0 million in July 2008. Interest on the revolving credit facility was at LIBOR plus a spread of 1% to 1.25%, based upon certain financial ratios. In September 2008 the revolving credit facility was repaid with proceeds from a syndicated credit facility, described in the second following paragraph. The weighted average interest rate for the revolving credit facility was 3.8% during 2008.

In August 2006, Superior entered into a standby term loan facility with its existing lending institution. The standby term loan facility provided an additional $30.0 million of borrowing capacity that could be used to finance equipment purchases. Interest on the revolving credit facility was at LIBOR plus a spread of 1% to 1.25%, based upon certain financial ratios. In September 2008 the standby term loan facility was repaid with the proceeds from a syndicated credit facility, described in the following paragraph. The weighted average interest rate for the standby term loan facility was 3.6% during 2008.

On September 30, 2008, Superior entered into a credit agreement (the “Credit Agreement”) evidencing a new syndicated credit facility (the “Syndicated Credit Facility”) with a syndicate of lenders and financial institutions. The Syndicated Credit Facility matures on March 31, 2013 and provides for a $250.0 million secured revolving

credit facility. The Syndicated Credit Facility replaces the Company’s $45.0 million revolving credit facility and $30.0 million standby term loan facility. Borrowings under the Credit Agreement are secured by substantially all of the Company’s business assets. The interest rate on borrowings under the Credit Agreement is set, at the Company’s option, at either LIBOR plus a spread of 1.5% to 2.5% or the prime lending rate plus a spread of 0.0% to 0.25%. The applicable spreads are based on the ratio of the Company’s “total debt” to its “EBITDA,” in each case as those terms are defined in the Credit Agreement. Under the Credit Agreement, the Company is subject to certain limitations, including limitations on its 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 make distributions. The Company is also subject to financial covenants which include a total debt to EBITDA ratio and an interest coverage ratio. These covenants are subject to a number of exceptions and qualifications set forth in the Credit Agreement. At December 31, 2008, Superior had $127.0 million outstanding under the syndicated credit facility, $6.3 million in letters of credit outstanding and $116.7 million of available capacity. Borrowing under our Syndicated Credit Facility is secured by our cash, investment property, accounts receivable, inventory, intangibles and equipment. The syndicated credit facility contains leverage ratio and fixed charge coverage ratio covenants. At December 31, 2008, we were in compliance with the financial covenants required under our Syndicated Credit Facility. The weighted average interest rate for the standby term loan facility was 3.9% during 2008.

In connection with the Diamondback asset purchase (Note 3), Superior issued an aggregate principal amount of $80 million second lien notes due November 2013 (“Second Lien Notes”). The Second Lien Notes are secured by a second priority lien on the assets secured by the Syndicated Credit Facility. In connection with the issuance of the Second Lien Notes, Superior entered into an Indenture (the “Indenture”), among Superior, its subsidiaries (the “Guarantors”) and the Wilmington Trust FSB, as trustee (the “Trustee”). Under the Second Lien Notes indenture, the Company is subject to certain limitations, including limitations on its 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 make distributions. The Company is also subject to financial covenants which include a total debt to EBITDA ratio and an interest coverage ratio. These covenants are subject to a number of exceptions and qualifications set forth in the Second Lien Notes indenture. Interest on the 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. At December 31, 2008, we were in compliance with the financial covenants required under our Second Lien Notes indenture.

Long-term debt at December 31, 2007 and 2008 consisted of the following (amounts in thousands):


	2007		2008

Syndicated credit facility with interest rates at either LIBOR plus a spread of 1.5-2.5% or the prime lending rate plus a spread of 0-0.25% due March 2013, collateralized by cash, investment property, accounts receivable, inventory, intangibles and equipment	$	—	$	127,000
Second lien notes due November 2013 with an initial interest rate of 7.0% per annum which increases 1% per annum on the anniversary date of the indenture, collateralized by a second priority lien on the Company’s assets secured by the Syndicated Credit Facility				80,000
Revolving credit facility with interest rates at LIBOR plus a spread of 1-1.25% due October 2009, collateralized by accounts receivable, inventory and equipment		7,957		—
Mortgage notes payable to a bank with interest at the bank’s prime lending rate minus 1%, payable in monthly installments of $8,622 plus interest through January 2021, collateralized by real property		1,221		1,109
Note payable to sellers with an interest rate of 7% due through September 2008, collateralized by equipment		233		—
Notes payable to sellers with nominal interest rates due through December 2010, collateralized by specific buildings and equipment		144		90

		9,555		208,199
Less — Payments due within one year		390		157

Total.	$	9,165	$	208,042

Principal payments required under our long-term debt obligations during the next five years and thereafter are as follows: 2009-$157,000, 2010-$126,000, 2011-$103,000, 2012-$103,000, 2013-$207,103,000 and thereafter $608,000.

Capital Lease Obligations

In connection with the Diamondback asset purchase (Note 3), Superior recorded capital leases on equipment that extend through 2011. Assets held under capital leases totaling $3.1 million net book value are included in property, plant and equipment within the equipment and vehicles asset class. Amortization of assets recorded under capital leases is reported in depreciation, amortization and accretion expense.

Future minimum lease payments under capital leases as of December 31, 2008 are (amounts in thousands):


2009	$	1,382
2010		1,961
2011		289

Total minimum payments		3,632
Less amounts representing interest		327

Total obligation under capital leases		3,305
Less current portion		1,134

Long-term portion	$	2,171


6.	Stockholders’ equity

Common Stock

We are authorized to issue 70,000,000 shares of common stock, $0.01 par value per share, of which 23,474,552 and 23,620,578 shares of common stock were outstanding as of December 31, 2007 and 2008, respectively. All of our currently outstanding shares of common stock are listed on the NASDAQ Global Select Market under the symbol “SWSI”.

Subject to the rights of the holders of any outstanding shares of preferred stock, each share of common stock is entitled to: (i) one vote on all matters presented to the stockholders, with no cumulative voting rights; (ii) receive such dividends as may be declared by the Board of Directors out of funds legally available therefore; and (iii) in the event of our liquidation or dissolution, share ratably in any distribution of our assets.

In August 2005, Superior completed its initial public offering of 6,460,000 shares of its common stock, which included 1,186,807 shares sold by selling stockholders and 840,000 shares sold by Superior to cover the exercise by the underwriters of an option to purchase additional shares to cover over-allotments. Proceeds to Superior, net of the underwriting discount and offering expenses, were approximately $61.8 million.

In December 2006, Superior completed a follow-on offering of 3,690,000 shares of its common stock, which included 690,000 shares sold by Superior to cover the exercise by the underwriters of an option to purchase additional shares to cover over-allotments. Proceeds to Superior, net of the underwriting discount and offering expenses, were approximately $88.6 million.

Preferred Stock

We are authorized to issue 10,000,000 shares of preferred stock, $0.01 par value per share, of which 75,000 shares of preferred stock were outstanding at December 31, 2008. The preferred stock is issuable in series with such voting rights, if any, designations, powers, preferences and other rights and such qualifications, limitations and restrictions as may be determined by our Board of Directors. The Board may fix the number of shares constituting each series and increase or decrease the number of shares of any series.

In November 2008, we issued 75,000 shares of Series A 4% Convertible Preferred Stock (“Series A”) in connection with the Diamondback asset purchase. The Series A is perpetual and ranks senior to our common stock with respect to payment of dividends, and amounts upon liquidation, dissolution or winding up. As of December 31, 2008, 75,000 shares of a Series A 4% Convertible Preferred Stock were outstanding.

Dividends

Series A preferred stockholders are entitled to receive, when, as and if declared by the Board of Directors out of our assets legally available therefore, cumulative cash dividends at the rate per annum of $40.00 per share of Series A Preferred Stock. Dividends on the Series A Preferred Stock are payable quarterly in arrears on December 1, March 1, June 1 and September 1 of each year (and, in the case of any undeclared and unpaid dividends, at such additional times and for such interim periods, if any, as determined by the Board of Directors), at such annual rate. Dividends are cumulative from the date of the original issuance of the Series A Preferred Stock, whether or not in any dividend period or periods we have assets legally available for the payment of such dividends.

Beginning on December 1, 2008, we have declared and paid the regularly scheduled dividend on outstanding preferred stock.

Liquidation Preference

The Series A preferred stockholders are entitled to receive, in the event that we are liquidated, dissolved or wound up, whether voluntary or involuntary, $1,000 per share (“Liquidation Value”) plus an amount per share equal to all dividends undeclared and unpaid thereon to the date of final distribution to such holders (the “Liquidation Preference”), and no more. Until the Series A preferred stockholders have been paid the Liquidation Preference in full, no payment will be made to any holder of Junior Stock upon our liquidation, dissolution or winding up. The term “Junior Stock” means our common stock and any other class of our capital stock issued and outstanding that

ranks junior as to the payment of dividends or amounts payable upon liquidation, dissolution and winding up to the Series A preferred stock. As of December 31, 2008, our Series A preferred stock had a liquidation preference of $75.1 million.

Redemption

The Series A Preferred Stock is redeemable at any time on or after November 18, 2013 and the Company, at its option, may redeem any or all at 101% of the Liquidation Value, plus, all accrued dividends with respect thereto to the redemption. The redemption price is payable in cash.

Voting Rights

Except as otherwise from time to time required by applicable law or upon certain events of preferred default, as defined, the Series A preferred stockholders have no voting rights and their consent is not required for taking any corporate action. When and if the Series A preferred stockholders are entitled to vote, each holder will be entitled to one vote per share.

Conversion

Each share of Series A preferred stock is convertible, in whole or in part at the option of the holders thereof, into shares of common stock at a conversion price of $25.00 per share of common stock (equivalent to a conversion rate of 40 shares of common stock for each share of Series A preferred stock), representing 3,000,000 common shares at December 31, 2008. The right to convert shares of Series A preferred stock called for redemption will terminate at the close of business on the day preceding a redemption date.

Stock Incentive Plan

In July 2005, Superior adopted a stock incentive plan for its employees, directors and consultants. The 2005 Stock Incentive Plan permits the grant of non-qualified stock options, incentive stock options, stock appreciation rights, restricted stock awards, phantom stock awards, performance awards, bonus stock awards or any combination of the foregoing to employees, directors and consultants. A maximum of 2,700,000 shares of common stock may be issued pursuant to awards under the 2005 Stock Incentive Plan. The Compensation Committee of the Board of Directors, which is composed entirely of independent directors, determines all awards made pursuant to the 2005 Stock Incentive Plan.

Effective January 1, 2006, Superior adopted SFAS 123R. Under this standard, companies are required to account for equity 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.

During 2006, Superior granted restricted common stock awards that totaled 290,900 shares. Superior’s non-employee directors, officers and key employees received restricted common stock awards during 2006 of 50,000, 67,000 and 173,900, respectively. During 2007, Superior granted restricted common stock awards that totaled 135,200 shares. Superior’s non-employee directors, officers and key employees received restricted common stock awards during 2007 of 22,000, 26,000 and 87,200, respectively. During 2008, Superior granted restricted common stock awards that totaled 176,400 shares. Superior’s non-employee directors, officers and key employees received restricted common stock awards during 2008 of 12,000, 32,500 and 131,900, respectively. Each award is subject to a service requirement that requires the director, officer or key employee to continuously serve as a member of the Board of Directors or as an employee of Superior from the date of grant through the number of years following the date of grant as set forth in the following schedule. Under the terms of the Stock Incentive Plan, vested shares may be issued net of a number of shares necessary to satisfy the participant’s income tax obligation. Such amounts are

recorded as shares retired. The forfeiture restrictions lapse with respect to a percentage of the aggregate number of restricted shares in accordance with the following schedule:


	Percentage of Total Number of
	Restricted Shares as to Which
Number of Full Years	Forfeiture Restrictions Lapse

Less than 1 year		0	%
1 year		15	%
2 years		30	%
3 years		45	%
4 years		60	%
5 years or more		100	%

Under the 2005 Stock Incentive Plan, the fair value of the restricted stock awards is based on the closing market price of Superior’s common stock on the date of grant. A summary of the activity of Superior’s restricted stock awards are as follows:


				Weighted Average
	Number of			Grant Date Fair
	Shares			Value per Share

Nonvested at December 31, 2005		—		$	—
Granted		290,900			28.48
Vested		—			—
Forfeited		(5,000	)		28.56

Nonvested at December 31, 2006		285,900			28.47
Granted		135,200			23.05
Vested		(36,770	)		28.22
Forfeited		(5,450	)		25.54
Retired		(7,465	)		28.29

Nonvested at December 31, 2007		371,415			26.57
Granted		176,400			16.98
Vested		(50,479	)		26.92
Forfeited		(22,870	)		24.26
Retired		(11,380	)		27.28

Nonvested at December 31, 2008		463,086		$	22.97

The aggregate market value of cumulative awards was approximately $13.1 million, before the impact of income taxes. At December 31, 2008, Superior’s unrecognized compensation costs related to non-vested awards amounted to $6.9 million. Superior is recognizing the expense in connection with the restricted share awards ratably over the five year vesting period. Compensation expense related to the stock incentive plan for the years ended December 31, 2006, 2007 and 2008 was $1,740,000, $1,961,000 and $2,522,000, respectively.


7.	Income taxes

Superior accounts for income taxes and the related accounts under the liability method. Deferred taxes and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted rates expected to be in effect during the year in which the basis differences reverse.

As indicated in Note 2, the conveyance of the Partnerships to Superior represented a reorganization of entities under common control. Prior to becoming wholly-owned subsidiaries of Superior, the Partnerships were not taxable entities for federal or state income tax purposes and, accordingly, were not subject to federal or state corporate income taxes. At the date of reorganization, Superior recorded a non-cash adjustment of $8.6 million to record the deferred tax asset and liabilities arising from the differences in the financial statement and tax bases of assets and

liabilities that existed at that time. Substantially all of the balance at reorganization is attributable to depreciation differences in property, plant and equipment. The adjustment resulted from the change in tax status from non-taxable entities to an entity which is subject to taxation.

The provision for income taxes is comprised of:


	For the Year Ended December 31,
	2006		2007		2008
	(Amounts in thousands)

Current:
State and local	$	2,524	$	2,246	$	1,602
U.S. federal		13,509		11,864		5,456

Total current		16,033		14,110		7,058
Deferred:
State and local		842		1,851		3,169
U.S. federal		3,916		8,609		17,135

Total deferred		4,758		10,460		20,304

Provision for income tax expense	$	20,791	$	24,570	$	27,362

Significant components of Superior’s deferred tax assets and liabilities are as follows:


	For the Year Ended December 31,
	2007			2008
	(Amounts in thousands)

Deferred tax assets:
Restricted stock	$	1,014		$	1,233
Accrued expenses and other		544			1,516
Alternative minimum tax		—			505
Allowance for doubtful accounts receivable		635			1,022

Total deferred tax assets		2,193			4,276

Deferred tax liabilities:
Depreciation differences on property, plant and equipment		(26,694	)		(49,082	)

Total deferred tax liabilities		(26,694	)		(49,082	)

Net deferred taxes	$	(24,501	)	$	(44,806	)

A reconciliation of income tax expense using the statutory U.S. income tax rate compared with actual income tax expense is as follows:


	For the Year Ended December 31,
	2006			2007			2008

Federal statutory tax rate		35	%		35	%		35	%
Impact of vesting of restricted stock		—			—			1
State income taxes, net of federal benefit		4			4			5

Effective income tax rate		39	%		39	%		41	%

We file tax returns in the United States federal jurisdiction and separate income tax returns in many state jurisdictions. We are subject to U.S. Federal income tax examinations for the years after 2005 and we are subject to various state tax examinations for years after 2005. Our continuing policy is to recognize interest related to income tax expense in interest expense and penalties in general and administrative expense. We do not have any accrued

interest or penalties related to tax amounts as of December 31, 2008. Throughout 2008, our unrecognized tax benefits were insignificant.


8.	401(k) Plan

Superior Well has a defined contribution profit sharing/401(k) retirement plan (“the Plan”) covering substantially all employees. Employees are eligible to participate after six months of service. Under terms of the Plan, employees are entitled to contribute up to 15% of their compensation, within limitations prescribed by the Internal Revenue Code. Superior Well makes matching contributions of 100% of employee contributions up to 4% of their compensation and may elect to make discretionary contributions to the Plan, all subject to vesting ratably over a three-year period. 401(k) expense was approximately $1,965,000, $2,408,000 and $943,000 in 2006, 2007 and 2008, respectively.


9.	Related-Party Transactions

Superior Well provides technical pumping services and down-hole surveying services to a customer owned by certain stockholders and directors of Superior. The total amounts of services provided to this affiliated party were approximately $4,658,000, $6,587,000 and $4,798,000 in 2006, 2007 and 2008, respectively. The accounts receivable outstanding from the affiliated party were $371,000 and $212,000 at December 31, 2007 and 2008, respectively.

Superior Well also regularly purchases, in the ordinary course of business, materials from vendors owned by certain stockholders and directors of Superior. The total amounts paid to these affiliated parties were approximately $2,552,000, $3,294,000 and $3,825,000 in 2006, 2007 and 2008, respectively. Superior Well had accounts payable to these affiliates of $191,000 and $250,000 at December 31, 2007 and 2008, respectively.

In connection with the Diamondback asset purchase (Note 3), Superior Well entered into a transition services agreement to provide temporary services to Diamondback Energy Holdings, LLC, which terminates on June 30, 2009. These services include assistance in payroll, information technologies and certain other corporate support service matters. The total amount of services provided to Diamondback in 2008 was approximately $49,000 and is reflected in accounts receivable at December 31, 2008.

In connection with the Diamondback asset purchase (Note 3), Superior Well entered into facility leases with an affiliate of Diamondback Holdings, LLC. The lease terms range from nine months to five years and the monthly lease payments are approximately $122,000. Rent expense for these leased facilities was $174,000 for the year ended December 31, 2008. Rent expense for these lease facilities that was unpaid at December 31, 2008 was approximately $143,000 and is reflected in accounts payable.


10.	Business segment information

SFAS No. 131, “Disclosure About Segments of an Enterprise and Related Information,” establishes standards for the reporting of information about operating segments, products and services, geographic areas, and major customers. The method of determining what information to report is based on the way our management organizes the operating segments for making operational decisions and assessing financial performance. We evaluate performance and allocate resources based on operating income (loss). Prior to 2008, we only had one reportable segment, technical services. As such, segment information for 2006 and 2007 is not separately presented below. In 2008, as a result of the Diamondback asset acquisition, we added fluids logistics services, thus we now have two reportable operating segments, technical services and fluid logistics, as seen below:


	Year ended December 31, 2008
	Technical		Fluid
	Services		Logistics		Corporate			Total
	(In thousands)

Net revenue	$	514,568	$	6,321	$	—		$	520,889
Depreciation and amortization	$	41,073	$	484	$	249		$	41,806
Operating income (loss)	$	79,056	$	715	$	(10,628	)	$	69,143
Capital expenditures	$	89,383	$	8	$	1,033		$	90,424
As of December 31, 2008 Segment assets	$	581,662	$	68,775	$	7,793		$	658,230

Changes in the carrying amount for goodwill for the year ended December 31, 2008 are as follows (amounts in thousands):


	Technical		Fluid
	Services		Logistics		Total

As of December 31, 2007	$	5,850	$	—	$	5,850
Goodwill acquired		19,009		6,867		25,876

As of December 31, 2008	$	24,859	$	6,867	$	31,726

We do not allocate interest expense, other expense or tax expense to the operating segments. The following table reconciles operating income as reported above to net income for the year ended December 31, 2008.


	2008
	(In thousands)

Segment operating income	$	69,143
Interest expense		2,834
Other expense		135
Income taxes		27,362

Net income	$	38,812

As a result of the Diamondback asset acquisition in November 2008, we added $6,321,000 of fluid logistics revenues and $715,000 of fluid logistics operating income for the three months ended December 31, 2008.

Also, as a result of the Diamondback asset acquisition in November 2008, we added $19,600,000 of technical services revenues, and $3,144,000 of technical services operating income for the three months ended December 31, 2008. For the three months ended December 31, 2008, the technical services’ and fluids logistics’ assets increased by $207,600,000 and $68,775,000, respectively.


11.	Commitments and Contingencies

Minimum annual rental payments, principally for non-cancelable real estate and vehicle leases with terms in excess of one year, in effect at December 31, 2008, were as follows: 2009-$9,396,000; 2010-$7,851,000; 2011-$6,007,000; 2012-$4,308,000 and 2013-$2,575,000.

Total rental expense charged to operations was approximately $1,915,000, $3,164,000 and $6,012,000 in 2006, 2007 and 2008, respectively.

In October 2008, we entered into a take-or-pay contract with Preferred Rocks USS, Inc. to purchase fracturing sand beginning in November 2008 through December 2015. In connection with the take-or-pay contract, Superior advanced $15 million for materials that will be delivered in the future. The advance on materials for future delivery will be used to offset future purchase commitments under the take-or-pay contract. Minimum purchases under the take-or-pay contract are estimated at $10.5 million, $12.1 million, $12.4 million, $12.8 million, $17.9 million, $18.4 million and $18.9 million in 2009, 2010, 2011, 2012, 2013, 2014 and 2015, respectively.

Superior had commitments of approximately $19.8 million for capital expenditures as of December 31, 2008.

Superior is involved in various legal actions and claims arising in the ordinary course of business. Management is of the opinion that the outcome of these lawsuits will not have a material adverse effect on the financial position, results of the operations or cash flow of Superior.


12.	Fair Value of Financial Instruments

The fair values are classified according to a hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs on the hierarchy consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs consist of quoted prices in active markets for similar assets and liabilities and inputs that are observable for the asset or liability. Level 3 inputs have the lowest priority. Superior uses appropriate valuation techniques based on the available inputs to measure the fair values of its assets and liabilities. When available, Superior measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

Superior’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, notes payable and long term debt. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value due to the short-term nature of such instruments. The carrying value of the Company’s revolving credit facility and mortgage notes payable approximates fair value at December 31, 2007 and 2008, since the interest rates are market-based and are generally adjusted periodically, representing Level 1 measurements.

The Second Lien Notes are not actively traded in an established market. The fair values of this debt are estimated by using Standard & Poors leveraged loan composite indices with similar terms and maturity, that is, a Level 2 fair value measurement. The fair value of the Second Lien Notes was $74.2 million compared to a carrying value of $80.0 million at December 31, 2008.


13.	Guarantees of Securities Registered

Superior filed a registration statement on Form S-3 that included $80 million of outstanding debt securities that were issued on November 18, 2008 and that are guaranteed by all of Superior’s subsidiaries. Superior, as the parent company, has no independent operating assets or operations. The subsidiaries’ guarantees of the debt securities are full and unconditional as well as joint and several. In addition, there are no restrictions on the ability of Superior to obtain funds from its subsidiaries by dividend or loan, and there are no restricted assets in any subsidiaries although all business assets secure debt.


14.	Quarterly Financial Information (Unaudited)

Quarterly financial information for the years ended December 31, 2008 and 2007 is presented below:


	2008
	First			Second			Third			Fourth
	Quarter			Quarter			Quarter			Quarter
	(In thousands, except share information)

Revenue	$	93,441		$	119,734		$	146,008		$	161,706
Cost of revenue(1)		78,778			92,435			109,686			125,145

Gross profit		14,663			27,299			36,322			36,561
Selling, general and administrative expenses(1)		9,544			10,682			11,388			14,088

Operating income		5,119			16,617			24,934			22,473
Interest expense		(177	)		(233	)		(466	)		(1,958	)
Other income (expense)		(343	)		(40	)		246			2
Income tax expense		(2,196	)		(6,753	)		(9,806	)		(8,607	)

Net income before dividends on preferred stock		2,403			9,591			14,908			11,910

Dividends on preferred stock		—			—			—			(108	)
Net income available to common stockholders	$	2,403		$	9,591		$	14,908		$	11,802

Net income per common share
Basic	$	0.10		$	0.41		$	0.64		$	0.51
Diluted	$	0.10		$	0.41		$	0.64		$	0.48
Average Shares Outstanding
Basic		23,141			23,153			23,154			23,154
Diluted		23,226			23,269			23,321			24,589


(1)		The Company had a $1.7 million reduction in compensation accruals in the fourth quarter of 2008. As a result, cost of revenue and selling, general and administrative expense were reduced by $1.4 million and $0.3 million, respectively.


	2007
	First			Second			Third			Fourth
	Quarter			Quarter			Quarter			Quarter
	(In thousands, except share information)

Revenue	$	76,708		$	84,807		$	94,317		$	94,938
Cost of revenue		53,986			59,480			66,112			72,961

Gross profit		22,722			25,327			28,205			21,977
Selling, general and administrative expenses		8,448			8,844			9,330			9,768

Operating income		14,274			16,483			18,875			12,209
Interest expense		(59	)		(47	)		(71	)		(105	)
Other income (expense)		559			209			33			(35	)
Income tax expense		(5,765	)		(6,485	)		(7,207	)		(5,113	)

Net income	$	9,009		$	10,160		$	11,630		$	6,956

Net income per common share
Basic	$	0.39		$	0.44		$	0.50		$	0.30
Diluted	$	0.39		$	0.44		$	0.50		$	0.30
Average Shares Outstanding
Basic		23,102			23,102			23,102			23,104
Diluted		23,116			23,166			23,142			23,150

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None


Item 9A.	*Controls and Procedures*

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Securities Exchange Act Rules 13a-15(f) or 15d-15(f)). Our internal control system is designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Our management assessed the effectiveness of its internal control over financial reporting as of December 31, 2008. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on its assessment, we believe that as of December 31, 2008, our internal control over financial reporting is effective based on those criteria. We have excluded the assets acquired from Diamondback Energy Holdings, LLC (“Diamondback”) from our Report on Internal Control over Financial Reporting for fiscal 2008 due to the timing of the closing date of the acquisition on November 18, 2008 and the expectation that internal control over financial reporting related to Diamondback will be changed to conform with our internal control over financial reporting in 2009. Activity related to Diamondback will be included in management’s fiscal 2009 internal control assessment. Diamondback constituted approximately 5.0% and 4.9% of consolidated revenue and income before income taxes, respectively, for the year ended December 31, 2008. There have been no significant changes in our internal controls or in other factors which could materially affect internal controls subsequent to the date our management carried out its evaluation.

Our independent registered public accounting firm has issued an attestation report on the effectiveness of our internal control over financial reporting. We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission and that any material information relating to us is recorded, processed, summarized and reported to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

Item 9B. Other Information

There was no information required to be disclosed in a report on Form 8-K during the fourth quarter of 2008 that was not reported on a report on Form 8-K during such period.

PART III


Item 10.	*Directors, Executive Officers and Corporate Governance*

The information responsive to Items 401, 405, 406 and 407 ( c)(3), (d)(4) and (d)(5) of Regulation S-K to be included in our definitive Proxy Statement for our 2008 Annual Meeting of Stockholders, to be filed within 120 days of December 31, 2008 pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (the “2009 Proxy Statement”), is incorporated herein by reference.

PART IV

Item 15. Exhibits and Financial Statement Schedules.


	(a)	Exhibits


3	.1	Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to Form 8-K filed on August 3, 2005).
3	.2	Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to Form 8-K filed on August 3, 2005).
3	.3	Certificate of Designations for Series A 4% Convertible Preferred Stock (incorporated by reference to Exhibit 3.1 to Form 8-K filed on November 21, 2008).
4	.1	Specimen Stock Certificate representing our common stock (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-1/A (Registration No. 333-124674) filed on June 24, 2005).
4	.2	Registration Rights Agreement dated as of July 28, 2005 by and among the Company and the stockholders signatory thereto (incorporated by reference to Exhibit 10.1 to Form 8-K filed on August 3, 2005).
4	.3†	Form of Restricted Stock Agreement for Employees without Employment Agreements (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-8(Registration No. 333-130615) filed on December 22, 2005).
4	.4†	Form of Restricted Stock Agreement for Executives with Employment Agreements (filed as Exhibit 4.2 to the Company’s Registration Statement on Form S-8(Registration No. 333-130615) filed on December 22, 2005).
4	.5†	Form of Restricted Stock Agreement for Non-Employee Directors (filed as Exhibit 4.3 to the Company’s Registration Statement on Form S-8(Registration No. 333-130615) filed on December 22, 2005).
4	.6†	2005 stock Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed on September 1, 2005).
4	.7	Indenture, dated as of November 18, 2008, between Superior Well Services Inc. and its Subsidiaries and Wilmington Trust FSB (as Trustee and Collateral Agent), relating to the Second Lien due 2013 (incorporated by reference to Exhibit 4.1 to Form 8-K filed on November 21, 2008).
10	.1†	Amended and Restated Employment Agreement between David E. Wallace and Superior Well Services Inc. dated September 15, 2008 (incorporated by reference to Exhibit 10.1 to Form 8-K filed on September 18, 2008).
10	.2†	Amended and Restated Employment Agreement between Jacob Linaberger and Superior Well Services Inc. dated September 15, 2008 (incorporated by reference to Exhibit 10.2 to Form 8-K filed on September 18, 2008).
10	.3†	Amended and Restated Employment Agreement between Thomas W. Stoelk and Superior Well Services Inc. dated September 15, 2008 (incorporated by reference to Exhibit 10.4 to Form 8-K filed on September 18, 2008).
10	.4†	Amended and Restated Employment Agreement between Rhys R. Reese and Superior Well Services Inc. dated September 15, 2008 (incorporated by reference to Exhibit 10.3 to Form 8-K filed on September 18, 2008).
10	.5†	Indemnification Agreement between David E. Wallace and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.7 to Form 8-K filed on August 3, 2005).
10	.6†	Indemnification Agreement between Jacob B. Linaberger and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.8 to Form 8-K filed on August 3, 2005).
10	.7†	Indemnification Agreement between Thomas W. Stoelk and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.9 to Form 8-K filed on August 3, 2005).
10	.8†	Indemnification Agreement between Rhys R. Reese and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.10 to Form 8-K filed on August 3, 2005).
10	.9†	Indemnification Agreement between Mark A. Snyder and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.12 to Form 8-K filed on August 3, 2005).
10	.10†	Indemnification Agreement between David E. Snyder and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.13 to Form 8-K filed on August 3, 2005).
10	.11†	Indemnification Agreement between Charles C. Neal and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.14 to Form 8-K filed on August 3, 2005).


10	.12†	Indemnification Agreement between John A. Staley, IV and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.15 to Form 8-K filed on August 3, 2005).
10	.13†	Indemnification Agreement between Anthony J. Mendicino and Superior Well Services, Inc. dated August 30, 2005 (incorporated by reference to Exhibit 10.16 to the Company’s Quarterly Report on Form 10-Q filed on September 1, 2005).
10	.14†	Employment Agreement between Daniel Arnold and Superior Well Services, Inc., dated May 14, 2007 (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed on August 8, 2007).
10	.15†	Indemnification Agreement between Daniel Arnold and Superior Well Services, Inc. dated May 14, 2007 (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q filed on August 8, 2007).
10	.16†	Employment Agreement between Arty Straehla and Superior Well Services Inc. dated November 18, 2008. (incorporated by reference to Exhibit 10.1 to Form 8-K filed on March 4, 2009).
10	.17†	Indemnification Agreement between Arty Straehla and Superior Well Services Inc. dated November 18, 2008. (incorporated by reference to Exhibit 10.2 to Form 8-K filed on March 4, 2009).
10	.18†	Non-Employee Director Compensation Summary (incorporated by reference to Exhibit 10.30 to the Company’s Annual Report on Form 10-K filed on March 11, 2008).
10	.19	Agreement dated October 2, 2007 between U.S. Silica and Superior Well Services, Inc. (incorporated by reference to Exhibit 10.30 to the Company’s Annual Report on Form 10-K filed on March 11, 2008).
10	.20	Revolving Credit Agreement among Superior Well Services Inc., Lenders Party, Citizens Bank of Pennsylvania (as Administrative Agent) and RBS Securities Corporation dated as of September 30, 2008 (incorporated by reference to Exhibit 10.1 to Form 8-K filed on October 3, 2008).
10	.21	Asset Purchase Agreement among Superior Well Services Inc., Superior Well Services, Limited, Diamondback Holdings, LLC and Diamondback’s Subsidiaries dated September 15, 2008 (incorporated by reference to Exhibit 10.1 to Form 8-K filed on September 18, 2008).
10	.22	First Amendment to Asset Purchase Agreement entered into by Superior Well Services Inc. and Superior Well Services, Limited and Diamondback Holdings, LLC and its Subsidiaries on November 18, 2008 (incorporated by reference to Exhibit 10.1 to Form 8-K filed on November 21, 2008).
10	.23	Registration Rights Agreement dated November 18, 2008 among Superior Well Services Inc., Designated Holders and Diamondback Holdings, LLC (incorporated by reference to Exhibit 10.2 to Form 8-K filed on November 21, 2008).
10	.24	Sand Purchase Agreement dated October 10, 2008 between Superior Well Services Inc. and Preferred Rocks USS, Inc. and U.S. Silica Company (incorporated by reference to Exhibit 10.1 to Form 10-Q filed on November 4, 2008).
12	.1*	Ratio of Earnings to Fixed Charges and Earnings to Fixed Charges and Preference Securities Dividends
23	.1*	Consent of Independent Registered Public Accounting Firm
24	.1*	Power of Attorney (included on signature page hereto).
31	.1*	Sarbanes-Oxley Section 302 certification of David E. Wallace for Superior Well Services, Inc. for the Annual Report on Form 10-K for the year ended December 31, 2008.
31	.2*	Sarbanes-Oxley Section 302 certification of. Thomas W. Stoelk for Superior Well Services, Inc. for the Annual Report on Form 10-K for the year ended December 31, 2008.
32	.1**	Sarbanes-Oxley Section 906 certification of David E. Wallace for Superior Well Services, Inc. for the Annual Report on Form 10-K for the year ended December 31, 2008.
32	.2**	Sarbanes-Oxley Section 906 certification of Thomas W. Stoelk for Superior Well Services, Inc. for the Annual Report on Form 10-K for the year ended December 31, 2008.


*		Filed herewith.

**		Furnished herewith.

†		Management contract or compensatory plan or arrangement.

		(b) Schedules

		Schedule II Valuation and qualifying accounts.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 12^th day of March, 2009.

SUPERIOR WELL SERVICES, INC.


	By:	/s/ Thomas W. Stoelk

Thomas W. Stoelk

Vice President and Chief Financial Officer

(principal financial officer)

Each person whose signature appears below hereby constitutes and appoints David E. Wallace and Thomas W. Stoelk, and each of them, his true and lawful attorney-in-fact and agent, with full powers of substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report of Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission granting to said attorneys-in-fact, and each of them, full power and authority to perform any other act on behalf of the undersigned required to be done in connection therewith.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the persons on behalf of the registrant in the capacities and on the dates indicated.


Signature	Title/Capacity	Date


/s/ David E. Wallace David E. Wallace	Chief Executive Officer and Chairman of the Board (principal executive officer)	March 12, 2009

/s/ Jacob B. Linaberger Jacob B. Linaberger	President	March 12, 2009

/s/ Thomas W. Stoelk Thomas W. Stoelk	Vice President & Chief Financial Officer (principal financial officer and principal accounting officer)	March 12, 2009

/s/ Rhys R. Reese Rhys R. Reese	Executive Vice President, Chief Operating Officer & Secretary	March 12, 2009

/s/ David E. Snyder David E. Snyder	Director	March 12, 2009

/s/ Mark A. Snyder Mark A. Snyder	Director	March 12, 2009

/s/ Charles C. Neal Charles C. Neal	Director	March 12, 2009

/s/ John A. Staley, IV John A. Staley, IV	Director	March 12, 2009


PART I
	Item 1.	Business	3
	Item 1A.	Risk Factors	12
	Item 1B.	Unresolved Staff Comments	22
	Item 2.	Properties	22
	Item 3.	Legal Proceedings	23
	Item 4.	Submission of Matters to a Vote of Security Holders	23

PART II
	Item 5.	Market for the Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities	24
	Item 6.	Selected Financial Data	25
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	49
	Item 8.	Financial Statements and Supplementary Data	51
	Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	77
	Item 9A.	Controls and Procedures	77
	Item 9B.	Other Information	77

PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	77
	Item 11.	Executive Compensation	78
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	78
	Item 13.	Certain Relationships, Related Transactions and Director Independence	78
	Item 14.	Principal Accounting Fees and Services	78

PART IV
	Item 15.	Exhibits and Financial Statement Schedules.	79
EX-12.1
EX-21.1
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2


Item 12.	*Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters*


Col. A	Col. B		Col. C				Col. D		Col. E
	Balance at		Additions
	Beginning		Charged to Costs		Charged to Other				Balance at end
Description	of Period		and Expenses		Accounts		Deductions		of Period

Year Ended December 31, 2006	$	134,000		637,636		—		—	$	771,636
Year Ended December 31, 2007	$	771,636		857,130		—		—	$	1,628,757
Year Ended December 31, 2008	$	1,628,757		1,171,920		—		45,677	$	2,755,000