SUPERIOR WELL SERVICES, INC. 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, 2007
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. þ

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


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, 2007, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $304,647,084 based on the closing sale price as reported on the The NASDAQ Global Select Market.

As of March 7, 2008, there were outstanding 23,613,516 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 shareholders 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 26 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. New service centers established or acquired in 2007 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). We will commence operations during the first and second quarters of 2008 at our Brighton, Colorado, and Rock Springs, Wyoming locations.

Since our inception, we have also completed several selective acquisitions, including (i) our June 2006 acquisition of assets and personnel of Petitt Wireline, Inc., which expanded our operations in Oklahoma, (ii) our October 2006 acquisition of the operating assets of Patterson Wireline, L.L.C., which expanded our operations in the Rocky Mountain region, (iii) our February 2007 acquisition of the operating assets of ELI Wireline Services, Inc., which expanded our operations in the Mid-Continent region, and (iv) our November 2007 acquisition of the operating assets and personnel of Madison Wireline Services, Inc., which expanded our operations in North Dakota. Today, we operate through our 26 service centers located in Pennsylvania, Alabama, West Virginia, Virginia, Mississippi, Texas, New Mexico, Ohio, Oklahoma, Kansas, North Dakota, Utah, Louisiana, Michigan, Arkansas, Wyoming and Colorado.

Our Services and Products

Technical Pumping Services

Stimulation Services. Our fluid-based stimulation services include fracturing and acidizing, which are designed to improve the flow of oil and natural gas from producing zones. Fracturing services are performed to enhance the production of oil and natural gas from formations with low permeability, which restricts the natural flow of the formation. The fracturing process consists of pumping a fluid gel into a cased well at sufficient pressure to fracture the formation. A proppant, typically sand, which is suspended in the gel is pumped into the fracture to prop it open. The size of a fracturing job is generally expressed in terms of pounds of proppant. The main pieces of equipment used in the fracturing process are the blender, which blends the proppant into the fracturing fluid, and the pumping unit, which is capable of pumping significant volumes at high pressures. Our fracturing pump units and blenders are capable of pumping slurries at pressures of up to 10,000 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 10,000 psi) that many of our smaller independent competitors currently do not offer. For these higher pressure projects, we typically arrange with third-party, independent laboratories to optimize and verify our fluid composition as part of our pre-job approval process. As of December 31, 2007, we had 31 stimulation crews of approximately six to thirty employees each and a fleet of 767 vehicles that includes high-tech, customized pump trucks, blenders and frac vans for use in our fluid-based stimulation services. In 2007, we provide basic stimulation services from seventeen different service centers: Black Lick, Pennsylvania; Bradford, Pennsylvania; Mercer, Pennsylvania; Norton, Virginia; Kimball, West Virginia; Jane Lew, West Virginia; Columbia, Mississippi; Cleveland, Oklahoma; Clinton, Oklahoma; Vernal, Utah; Cottondale, Alabama; Gaylord, Michigan; Van Buren, Arkansas; Alvarado, Texas; Farmington, New Mexico; Artesia, New Mexico; and Bossier City, Louisiana. We began providing stimulation services in Brighton, Colorado during January 2008.

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 2007. 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, 2007, we had ten nitrogen crews of approximately three to eight employees each and a fleet of 39 nitrogen pump trucks and 29 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, 2007, we had 59 cementing crews of approximately three to six employees each and a fleet of 141 cement trucks. We provide cementing services from sixteen different service centers: Black Lick, Pennsylvania; Bradford, Pennsylvania; Kimball, West Virginia; Jane Lew, West Virginia; Cleveland, Oklahoma; Clinton, Oklahoma; Columbia, Mississippi; Cottondale, Alabama; Gaylord, Michigan; Van Buren, Arkansas; Vernal, Utah; Alvarado, Texas; Norton, Virginia; Farmington, New Mexico; Artesia, New Mexico; and Bossier City, Louisiana.

Down-Hole Surveying Services

We offer two types of down-hole surveying services — logging and perforating. As of December 31, 2007, we owned a fleet of 86 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, 2007, we had 17 logging crews of approximately two to three employees each and 23 logging trucks. We provide logging services from eleven different service centers: Buckhannon, West Virginia; Kimball, West Virginia; Wooster, Ohio; Bradford, Pennsylvania; Black Lick, Pennsylvania; Cottondale, Alabama; Hominy, Oklahoma; 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, 2007, we had 35 perforating crews of approximately two to four employees each and 63 perforating trucks and cranes. We provide perforating services from eleven different service centers: Wooster, Ohio; Mercer, Pennsylvania; Black Lick, Pennsylvania; Buckhannon, West Virginia; Kimball, West Virginia; Cottondale, Alabama; Enid, Oklahoma; Hominy, Oklahoma; Hays, Kansas; Williston, North Dakota; and Trinidad, Colorado.

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. 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, 2007:


		2005(1)					2006(2)					2007(3)
		Percent of					Percent of		Percent of					Percent of
Region	Revenue	Revenue		Revenue			Revenue		Revenue			Revenue		Revenue

Appalachian		$	71,695		54.4	%	$	118,943		48.6	%	$	158,894		45.3	%
Southeast			34,274		26.0			58,491		23.9			66,690		19.0
Southwest			—		—			6,832		2.8			37,565		10.7
Mid-Continent			21,073		16.0			43,566		17.8			56,063		16.0
Rocky Mountain			4,691		3.6			16,794		6.9			31,558		9.0

Total		$	131,733		100	%	$	244,626		100	%	$	350,770		100	%


(1)		We commenced operations in the Rocky Mountain region in the first quarter of 2005 by establishing a service center in Vernal, Utah. We expanded our operations in the Appalachian and the Southeast regions in the second quarter of 2005 by establishing service centers in Gaylord, Michigan and Bossier City, Louisiana, respectively. In the fourth quarter of 2005, we expanded our operations in the Mid-Continent region by establishing a service center in Van Buren, Arkansas.

(2)		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.

(3)		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 second quarter of 2008.

During 2007, we provided services to over 1,200 customers, with our top five customers comprising approximately 34.3% of our total revenue. The following table shows information regarding our top five customers in 2007:


Customer	Length of Relationship		% of 2007 Revenue

Atlas America, Inc.(1)		9 years		12.0	%
Chesapeake Energy Corp(2)		4 years		8.7	%
EOG Resources, Inc.(3)		6 years		5.7	%
CNX Gas Company, LLC(4)		6 years		4.2	%
Consolidation Coal Company(5)		4 years		3.7	%


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

(2)		We service Chesapeake Energy Corp. from our Appalachian, Mid-Continent, Southwest and Southeast region service centers.

(3)		We service EOG Resources, Inc. from our Appalachian, Southwest and Southeast region service centers.

(4)		We service CNX Gas Company (a subsidiary of Consol Energy) from our Appalachian region service centers.

(5)		We service Consolidation Coal Company (a subsidiary of Consol Energy) from our Appalachian and Southeast region service centers.

We believe our relationship with these significant customers is good.

Suppliers

We purchase the materials used in our technical pumping services, such as fracturing sand, cement, nitrogen and fracturing and cementing chemicals from various third party and related-party suppliers. Raw materials essential to our business are normally readily available. Where we rely on a single supplier for materials essential to our business, we believe that we will be able to make satisfactory alternative arrangements in the event of interruption of supply. The following table provides key information regarding several of our major materials suppliers:


	Length of Relationship		% of 2007 Purchases
Raw Materials	with Largest Supplier		with Largest Supplier

Fracturing Sand		11 years		9.7	%
Fracturing and Cementing Chemicals		11 years		8.7	%
Nitrogen		9 years		8.5	%

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 2007 Purchases
Equipment	with Largest Supplier		with Largest Supplier

Frac Trailers		5 years		10.9	%
Blenders		11 years		10.4	%

In October 2007, we entered into a take-or-pay contract with U.S. Silica Company to purchase fracturing sand beginning in January 1, 2008 through December 31, 2009. Minimum purchases under the take-or-pay contract are estimated at $4.5 million and $7.2 million in 2008 and 2009, 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 and 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 could experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability, and our relationship with customers, employees and regulatory agencies. Any significant increase in the frequency or severity of these incidents, or the general level of compensation awards, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations.

We maintain insurance coverage of types and amounts that we believe to be customary in the industry, but we are not fully insured against all risks, either because insurance is not available or because of the high premium costs. 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.

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

In response to studies suggesting that emissions of certain gases, referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere, the current session of the U.S. Congress is considering climate change-related legislation to restrict greenhouse gas emissions. One bill recently approved by the U.S. Senate Environment and Public Works Committee, known as the Lieberman-Warner Climate Security Act or S.2191, would require a 70% reduction in emissions of greenhouse gases from sources within the United States between 2012 and 2050. The Lieberman-Warner bill proposes a “cap and trade” scheme of regulation of greenhouse gas emissions — a ban on emissions above a defined reducing annual cap. Covered parties will be authorized to emit greenhouse emissions through the acquisition and subsequent surrender of emission allowances that may be traded or acquired on the open market. Debate and a possible vote on this bill by the full Senate are anticipated to occur before mid-year 2008. In addition, at least one-third of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/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. Similarly, the oil and natural gas producers whom we serve could be required to obtain and surrender allowances for the combustion of fuels (e.g., oil or natural gas) that they produce. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may regulate carbon dioxide and other 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 EPA has publicly stated its goal of issuing a proposed rule to address carbon dioxide and other greenhouse gas emissions from vehicles and automobile fuels but the timing for issuance of this proposed rule is unsettled as the agency reviews its mandates under the Energy Independence and Security Act of 2007, which includes expanding the use of renewable fuels and raising the corporate average fuel economy standards. 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 under certain CAA

programs. New federal or state laws requiring adoption of a stringent greenhouse gas control program or imposing restrictions on emissions of carbon dioxide in areas of the United States in which we conduct business could adversely affect our cost of doing business and 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 and specified agencies of applicable agreement states that work cooperatively in implementing the federal regulations. In addition, our down-hole surveying services involve the use of explosive charges that are regulated by the U.S. Department of Justice, Bureau of Alcohol, Tobacco, Firearms, and Explosives. Standards implemented by these regulatory agencies require us to obtain licenses or other approvals for the use of such densitometers as well as explosive charges. We have obtained these licenses and approvals when necessary and believe that we are in substantial compliance with these federal requirements.

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

The federal Department of Homeland Security Appropriations Act of 2007 required the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to the act and, on November 20, 2007, further issued an Appendix A to the interim rule that established chemicals of interest and their respective threshold quantities that will trigger compliance with the interim rule. Facilities possessing greater than threshold levels of these chemicals of interest were required to prepare and submit to the DHS in January 2008 initial screening surveys that the agency would use to determine whether the facilities presented a high level of security risk. Covered facilities that are determined by DHS to pose a high level of security risk will be notified by DHS and will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information. We have not yet determined the extent to which our facilities are subject to the interim rule or the associated costs to comply, but it is possible that such costs could be substantial.

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, 2007, we employed 1,492 people, with approximately 74% 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.


Item 1A —	*Risk Factors*

Risks Related to Our Business and Our Industry

Our business depends on domestic spending by the oil and natural gas industry, and this spending and our business may be adversely affected by industry conditions that are beyond our control.

We depend on our customers’ willingness to make operating and capital expenditures to explore, develop and produce oil and natural gas in the United States. Industry conditions are influenced by numerous factors over which we have no control, such as:


	•	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.

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, 2007, 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 $98.18 per barrel to a low of $25.24 per barrel. Producers may reduce expenditures in reaction to declining natural gas and crude oil commodity prices. This has in the past and may in the future adversely affect our business.

A prolonged low level of activity in the oil and natural gas industry will adversely affect the demand for our products and services and our financial condition and results of operations.

We may incur substantial indebtedness or issue additional equity securities to 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, 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, including events related to the sub-prime mortgage market, 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.

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 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 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 2006, eight companies accounted for 42% and 45% 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 constituted approximately 12% and 9%, respectively, of our total revenue for the year ended December 31, 2007. 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. 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, 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. 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.

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 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 U.S. Nuclear Regulatory Commission and specified agencies of applicable agreement states that work cooperatively in implementing the federal regulations. In addition, our down-hole surveying operations involve the use of explosive charges that are regulated by the U.S. Department of Justice, Bureau of Alcohol, Tobacco, Firearms, and Explosives. Standards implemented by these regulatory agencies require us to obtain licenses or other approvals for the use of such densitometers as well as explosive charges.

Laws protecting the environment generally have become more stringent over time and are expected to continue to do so, which could lead to material increases in costs for future environmental compliance and remediation. The modification or interpretation of existing laws or regulations, or the adoption of new laws or regulations, could curtail

exploratory or developmental drilling for oil and natural gas and could limit our well services opportunities. Some environmental laws and regulations may impose 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.

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, 2007, our total debt on a consolidated basis was approximately $9.6 million. Our total debt could increase, as we have a total borrowing capacity of $50 million under our revolving credit facility and standby term loan facility, of which $36.9 million was available as of December 31, 2007. Our revolving credit facility and standby term loan facility 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 26 service centers, 5 of which we own and 21 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, Louisiana. Our Mid-Continent region service centers are located in Hominy, Enid, Clinton and Cleveland, 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, 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, 2008		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


(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, 2007.

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 10, 2008, there were 23,613,516 shares outstanding, held by approximately 121 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 2006 and 2007.


	High		Low

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
Fiscal Year Ended December 31, 2006
First Quarter	$	30.41	$	22.10
Second Quarter	$	40.13	$	22.86
Third Quarter	$	27.43	$	16.80
Fourth Quarter	$	26.62	$	17.81

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, 2007.


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
	2003			2004			(Superior Well			(Superior Well			(Superior Well
	(Partnerships)			(Partnerships)			Services, Inc.)			Services, Inc.)			Services, Inc.)
	(In thousands, except per share information)

Statements of Income Data:
Revenue	$	51,462		$	76,041		$	131,733		$	244,626		$	350,770
Cost of revenue		35,581			54,447			90,258			165,877			252,539

Gross profit		15,881			21,594			41,475			78,749			98,231
Selling, general and administrative expenses		7,609			11,339			17,809			25,716			36,390

Operating income		8,272			10,255			23,666			53,033			61,841
Interest expense		78			310			566			478			282
Other (expense) income		20			(148	)		193			159			766
Income tax expense		—			—			13,826			20,791			24,570

Net income	$	8,214		$	9,797		$	9,467		$	31,923		$	37,755

Pro Forma income tax expense (unaudited)(1)		(3,528	)		(4,249	)		—			—			—

Net income adjusted for pro forma income tax expense (unaudited)	$	4,686		$	5,548			—			—			—

Net income per common share(2)
Basic	$	0.24		$	0.29		$	0.49		$	1.63		$	1.63
Diluted	$	0.24		$	0.29		$	0.49		$	1.63		$	1.63
Average Shares Outstanding
Basic		19,376,667			19,376,667			19,317,436			19,568,749			23,100,402
Diluted		19,376,667			19,376,667			19,317,436			19,568,749			23,195,914
Statements of Cash Flow Data:
Net cash provided by operations	$	6,692		$	12,790		$	16,742		$	35,949		$	69,303
Net cash used in investing		(10,765	)		(19,290	)		(40,091	)		(78,902	)		(128,100	)
Net cash provided by financing		4,827			6,751			32,570			88,940			7,555
Capital expenditures, net of construction payables		9,150			19,300			39,920			69,816			117,774
Acquisitions, net of cash acquired		2,125			—			—			9,150			9,931
Depreciation and amortization		3,465			5,057			8,698			14,453			25,277
Balance Sheet Data (at period end):
Cash and cash equivalents	$	1,293		$	1,544		$	10,765		$	56,752		$	5,510
Property, plant and equipment, net		26,036			40,594			72,691			141,424			240,863
Total assets		37,225			56,682			113,091			259,034			327,087
Long-term debt		80			11,093			1,258			1,597			9,165
Partners’ capital		30,112			33,819			—			—			—
Stockholders’ Equity		—			—			91,393			213,904			253,599
Other Financial Data:
EBITDA(3)	$	11,757		$	15,164		$	32,557		$	67,645		$	87,884


(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 years ended December 31, 2003 through 2004, all shares are assumed to have been issued at the beginning of the period resulting in 19,376,667 average shares outstanding.

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


	•	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
	2003		2004		(Superior Well		(Superior Well		(Superior Well
	(Partnerships)		(Partnerships)		Services, Inc.)		Services, Inc.)		Services, Inc.)

*Reconciliation of EBITDA to Net Income:*
Net income	$	8,214	$	9,797	$	9,467	$	31,923	$	37,755
Income tax expense		—		—		13,826		20,791		24,570
Interest expense		78		310		566		478		282
Depreciation and amortization		3,465		5,057		8,698		14,453		25,277

EBITDA	$	11,757	$	15,164	$	32,557	$	67,645	$	87,884


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 in many of the major 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.

Services Offered

We derive our revenue from two primary categories of services — technical pumping services and down-hole surveying services. Substantially all of our customers are domestic oil and natural gas exploration and production companies that typically require both types of services in their operations. Our operating revenue from these operations, and their relative percentages of our total revenue, consisted of the following (dollars in thousands):


	Year Ended December 31,
	2005				2006				2007
	(Dollars in thousands)

Revenue:
Technical pumping services	$	119,210	90.5	%	$	219,624	89.8	%	$	304,949	86.9	%
Down-hole surveying services		12,523	9.5	%		25,002	10.2	%		45,821	13.1	%

Total revenue	$	131,733	100.0	%	$	244,626	100.0	%	$	350,770	100.0	%

The following is a brief description of our services:

Technical Pumping Services

We offer three types of technical pumping services — stimulation, nitrogen and cementing — which accounted for 54.3%, 12.0% and 20.6% of our revenue for the year ended December 31, 2007 and 58.4%, 10.4% and 21.0% of our revenue for the year ended December 31, 2006, 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 2006 and 2007. Our cementing services consist of blending high-grade cement and water with various additives to create a cement slurry that is pumped through the well casing into the void between the casing and the bore hole. Once the slurry hardens, the cement isolates fluids and gases, which protects the casing from corrosion, holds the well casing in place and controls the well.

Down-Hole Surveying Services

We offer two types of down-hole surveying services — logging and perforating — which collectively accounted for approximately 13.1% and 10.2% of our revenues for years ended December 31, 2007 and 2006, 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.

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

How We Evaluate Our Operations

Our management uses a variety of financial and operational measurements to analyze the performance of our services. These measurements include the following: (1) operating income per operating region; (2) material and labor expenses as a percentage of revenue; (3) selling, general and administrative expenses as a percentage of revenue; and (4) EBITDA.

Operating Income per Operating Region.

We currently service customers in five operating regions through our 26 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, Louisiana. Our Mid-Continent region service centers are located in Hominy, Enid, Clinton and Cleveland, 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, 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 evaluate our utilization levels and allocate our equipment and field personnel among our various operating regions, as well as 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, due to increased activity in the oilfield services and commercial trucking sectors, it is possible that we will have to raise wage rates to attract and train workers from other fields in order to maintain or expand our current work force. 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 fees for management services and administrative, marketing and maintenance employee compensation and related benefits, office and lease expenses, insurance costs and professional fees, as well as other costs and expenses not directly related to field operations. Our management continually evaluates the level of our general and administrative expenses in relation to our revenue because these expenses have a direct impact on our profitability. Our selling, general and administrative expenses have increased as a result of the growth in operations, as well as a result of our becoming a public company. For a discussion of the increase in costs associated with our public company status, please read “— Items Impacting Comparability of Our Financial Results — Public Company Expenses.”

EBITDA.

We define EBITDA as net income before interest expense, income tax expense and depreciation and amortization expense. Our management uses EBITDA:


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

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

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

	•	in communications with lenders concerning our financial performance; and

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

How We Manage Our Operations

Our management team uses a variety of tools to manage our operations. These tools include monitoring: (1) service crew 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. Current market indicators suggest an increasing demand for oil and natural gas coupled with a flat or declining production curve, which we believe should result in the continuation of historically high 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. oil and natural gas consumption will increase at an average annual rate of 1.1% through 2025. The EIA also forecasts that U.S. oil production will decline at an average annual rate of 0.5% and natural gas production will increase at an average annual rate of 0.8%.

We anticipate that oil and natural gas exploration and production companies will continue to respond to sustained increases in demand by expanding their exploration and drilling activities and increasing capital spending. In recent years, much of this expansion has focused on natural gas. According to Baker Hughes rig count data, the average total rig count in the United States increased 91.2% from 918 in 2000 to 1,755 through the third week of February 2008, while the average natural gas rig count increased 97.8% from 720 in 2000 to 1,424 through the third week of February 2008. While the number of rigs drilling for natural gas has increased by more than 250% since 1996, natural gas production has decreased by approximately 3% over the same period of time. This is largely a function of increasing decline rates for natural gas wells in the United States. We believe that a continued increase in U.S. drilling and workover activity will be required for the natural gas industry to help meet the expected increased demand for natural gas in the United States.

2008 Business Outlook

Our overall business outlook remains positive and we believe that our activity levels will remain stable during 2008. Although commodity prices and drilling activity remain at relatively high levels, we believe that increased competition due to capacity additions may continue to erode stimulation pricing in certain markets. The new capacity entered the market in 2007 in response to strong demand and favorable margins for oilfield services. In the fourth quarter of 2007, we experienced increased sales discounts in the low- to mid- single digits for our stimulation services. We believe stimulation pricing declines may be partially offset over time by higher asset utilization levels as our newer service centers become more established in their respective markets, as well as improved activity levels if commodity prices and drilling activity levels remain at or near existing levels. Although we experienced increased sales discounts in our other service offerings during 2007, they were less than those experienced in our stimulation business.

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):


	2005					2006					2007
			Percent of					Percent of					Percent of
Region	Revenue		Revenue			Revenue		Revenue			Revenue		Revenue

Appalachian	$	71,695		54.4	%	$	118,943		48.6	%	$	158,894		45.3	%
Southeast		34,274		26.0			58,491		23.9			66,690		19.0
Southwest		—		—			6,832		2.8			37,565		10.7
Mid-Continent		21,073		16.0			43,566		17.8			56,063		16.0
Rocky Mountain		4,691		3.6			16,794		6.9			31,558		9.0

Total	$	131,733		100	%	$	244,626		100	%	$	350,770		100	%

We also pursue selected acquisitions of complementary businesses both in existing operating regions and in new geographic areas in which we do not currently operate. In analyzing a particular acquisition, we consider the operational, financial and strategic benefits of the transaction. Our analysis includes the location of the business, strategic fit of the business in relation to our business strategy, expertise required to manage the business, capital required to integrate and maintain the business, the strength of the customer relationships associated with the business and the competitive environment of the area where the business is located. From a financial perspective, we analyze the rate of return the business will generate under various scenarios, the comparative market parameters applicable to the business and the cash flow capabilities of the business.

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

Our Results of Operations

Our results of operations are derived primarily by three interrelated variables: (1) market price for the services we provide; (2) drilling activities of our customers; and (3) cost of materials and labor. To a large extent, the pricing environment for our services will dictate our level of profitability. Our pricing is also dependent upon the prices and market demand for oil and natural gas, which affect the level of demand for, and the pricing of, our services and

fluctuates with changes in market and economic condition and other factors. 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 higher activity. To a lesser extent, seasonality can affect our operations in the Appalachian region and certain parts of the Mid-Continent and Rocky Mountain regions, which may be subject to a brief period of diminished activity during spring thaw due to road restrictions. As our operations have expanded in recent years into new operating regions in warmer climates, this brief period of diminished activity no longer has a significant impact on our overall results of operations.

Our results of operations from our two primary categories of services consisted of the following for each of the years in the three-year period ended December 31, 2007:


	Year Ended December 31,
	2005		2006		2007
	(In thousands)

Statement of Operations Data
Revenue:
Technical pumping services	$	119,210	$	219,624	$	304,949
Down-hole surveying services		12,523		25,002		45,821

Total revenue		131,733		244,626		350,770
Expenses:
Cost of revenue		90,258		165,877		252,539
Selling, general and administrative		17,809		25,716		36,390

Total expenses		108,067		191,593		288,929

Operating income	$	23,666	$	53,033	$	61,841

Fourth Quarter 2007 Results

Revenue.

In the fourth quarter of 2007, revenues were $94.9 million, an increase of 26.3% compared to $75.1 million in the fourth quarter of 2006. Increased activity levels, as well as down-hole asset acquisitions made during 2007, led to the increases in revenue in the fourth quarter of 2007 as compared to the fourth quarter of 2006. Increased 2007 activity levels were partially offset by higher discounts in 2007 as compared to 2006. As a percentage of revenues, sales discounts increased by 5.2% in fourth quarter of 2007 as compared to fourth quarter of 2006. In the fourth quarter of 2007, we experienced increased sales discounts in the low- to mid- single digits for our stimulation services. Although we experienced increased sales discounts in our other service offerings during 2007, they were less than those experienced in our stimulation business. All regions, other than Appalachia, experienced higher sales discounts in the fourth quarter of 2007 when compared to the fourth quarter of 2006. In addition to higher sales discounts, longer holiday shut-downs impacted activity levels for the fourth quarter of 2007 in each of our operating regions.

Cost of Revenue.

Cost of revenue was $73.0 million, an increase of 42.3% compared to $51.3 million in the fourth quarter of 2006. As a percentage of revenue, cost of revenue increased to 76.9% for fourth quarter of 2007 from 68.2% for the fourth quarter of 2006. This percentage increase between periods was primarily the result of higher labor expense, depreciation and material costs as a percentage of revenue in fourth quarter of 2007 as compared to the fourth quarter of 2006. As a percentage of revenue, labor expense, depreciation and material costs increased in the fourth quarter of 2007 as compared to the fourth quarter of 2006 by 3.5%, 1.8% and 2.4%, respectively. As discussed above, delays experienced at our new centers resulted in higher start up costs in the fourth quarter of 2007. Additionally, longer holiday shutdowns reduced utilization in each of our operating regions. Cost of revenues

associated with the five start-up service centers opened during 2007 increased fourth quarter 2007 expenses by $9.4 million as compared to the fourth quarter of 2006. Additionally, higher sales discounts lowered net revenues and resulted in an increase in the cost of revenue as a percentage of revenue in the fourth quarter of 2007 compared to the fourth quarter of 2006.

Labor expenses as a percentage of revenues increased 3.5% to 21.4% in the fourth quarter of 2007 compared to the fourth quarter of 2006 as a result of lower utilizations at new service centers established during 2007, as well as longer holiday shutdowns. Additionally, in the fourth quarter of 2007 we increased staffing and purchased additional equipment to begin servicing the Marcellus Shale activity in the Appalachian region. 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 utilization 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 included in cost of revenue increased $6.9 million in the fourth quarter of 2007 as compared to the fourth quarter of 2006 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 in the fourth quarter of 2007 to 42.7%, an increase of 2.4% compared to fourth quarter of 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 service centers. Depreciation expense as a percentage of revenues was 7.9% in fourth quarter of 2007, an increase of 1.8% compared to the fourth quarter of 2006 due to higher amounts of capital spending in 2007, as well as lower utilizations at new service centers established during 2007.

Selling, General and Administrative Expenses.

In the fourth quarter 2007, SG&A expenses were $9.8 million, an increase of 35.2% compared to $7.2 million in the fourth quarter of 2006. As a percentage of revenue, SG&A expenses increased to 10.3% for the fourth quarter of 2007 from 9.6% in the fourth quarter of 2006. During the fourth quarter of 2007, we hired additional personnel to manage the growth in our operations, acquired the assets of a down-hole surveying company and opened three new start-up service centers. As a result of this growth, expenses for labor, office expenses and depreciation increased in the fourth quarter of 2007 by $1.4 million, $0.4 million and $0.3 million, respectively, compared to the fourth quarter of 2006. The establishment of the five start-up service centers in 2007 increased SG&A expenses in the fourth quarter of 2007 compared to the fourth quarter of 2006 by approximately $1.3 million.

Operating Income.

Operating income for the fourth quarter of 2007 was $12.2 million, a decrease of 26.6% compared to $16.6 million in the fourth quarter of 2006. The five start-up service centers established in 2007 reduced operating income in the fourth quarter of 2007 by $3.5 million compared to the fourth quarter of 2006. As a percentage of revenue, operating income decreased from 22.1% in the fourth quarter of 2006 to 12.9% in the fourth quarter of 2007. The primary reasons for this decrease were higher discounts for our services, costs incurred for the new service centers opened in 2007, delays in opening new service centers and 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 at our existing service centers. 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 that region.

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

Revenue.

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. Revenue by operating region increased in 2007 by

$40.0 million, $8.2 million, $12.5 million, $30.7 million and $14.8 million in the Appalachian, Southeast, Mid-Continent, Southwest and Rocky Mountain operating regions, respectively. Approximately $20.3 million of the total increase was attributable to new service centers opened 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 service 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 service 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, five of which were start-up 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 $20.2 million in 2007 to $87.9 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.

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

Revenue.

Revenue was $244.6 million for the year ended December 31, 2006 compared to $131.7 million for the year ended December 31, 2005, an increase of 85.7%. Increased activity levels and pricing improvements led to the increases in 2006. Revenue by operating region increased in 2006 by $47.3 million, $24.2 million, $22.5 million, $6.8 million and $12.1 million in the Appalachian, Southeast, Mid-Continent, Southwest and Rocky Mountain operating regions, respectively. Approximately $56.5 million of the total increase was attributable to new service

centers. New service center revenue by operating region increased in 2006 by $17.5 million, $11.9 million, $8.2 million, $6.8 million and $12.1 million in the Appalachian, Southeast, Mid-Continent, Southwest and Rocky Mountain operating regions, respectively. New service centers include: Gaylord, Michigan (Appalachian), Buckhannon, West Virginia (Appalachian), Norton, Virginia (Appalachian), Bossier City, Louisiana (Southeast), Van Buren, Arkansas (Mid-Continent), Enid, Oklahoma (Mid-Continent), Alvarado, Texas (Southwest), Farmington, New Mexico (Rocky Mountain), Trinidad, Colorado (Rocky Mountain) and Vernal, Utah (Rocky Mountain). Existing service center revenue by operating region increased in 2006 by $29.7 million, $12.3 million and $14.4 million in the Appalachian, Southeast and Mid-Continent operating regions, respectively.

Revenue from our technical pumping services increased by approximately 84.2% to $219.6 million for the year ended December 31, 2006 from $119.2 million for the year ended December 31, 2005. Approximately $51.6 million of this increase was attributable to new service centers. New service center revenue by operating region increased in 2006 by $15.8 million, $11.9 million, $6.7 million, $6.8 million and $10.4 million in the Appalachian, Southeast, Mid-Continent, Southwest and Rocky Mountain operating regions, respectively. Existing service center revenue by operating region increased in 2006 by $25.5 million, $11.9 million and $11.4 million in the Appalachian, Southeast and Mid-Continent operating regions, respectively. Increased activity levels and pricing improvements led to the existing center increases in 2006.

Revenue from our down-hole surveying services increased approximately 99.6% to $25.0 million for the year ended December 31, 2006 from $12.5 million for the year ended December 31, 2005. Revenue by operating region increased in 2006 by $5.9 million, $0.4 million, $4.5 million and $1.7 million in the Appalachian, Southeast, Mid-Continent and Rocky Mountain operating regions, respectively. New service center revenue by operating region increased in 2006 by $1.7 million, $1.4 million, and $1.7 million in the Appalachian, Mid-Continent, and Rocky Mountain operating regions, respectively. Increased activity levels and pricing improvements led to the existing center increases in 2006.

Cost of Revenue.

Cost of revenue increased 83.8% to $165.9 million for the year ended December 31, 2006 compared to $90.3 million for the year ended December 31, 2005. Approximately $40.7 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 2006 by $10.1 million, $6.2 million, $6.8 million, $6.9 million and $10.7 million in the Appalachian, Southeast, 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. However, as a percentage of revenue these costs decreased between periods primarily because of higher crew utilization levels, pricing increases and the ability to leverage the fixed cost component of these costs over a higher base of revenue. As a percentage of revenue, cost of revenue decreased to 67.8% for the year ended December 31, 2006 from 68.5% for the year ended December 31, 2005. This percentage decrease was primarily due to an approximate 1.0% drop in cost of materials and labor expenses as a percentage of revenues in 2006 versus 2005. Labor expenses as a percentage of revenues decreased from 18.5% in 2005 to 18.2% in 2006. Aggregate labor expenses in cost of revenue increased $18.8 million to $44.5 million in 2006 due to the hiring of additional personnel in connection with the establishment of new service centers and the expansion of existing service centers.

Selling, General and Administrative Expenses.

SG&A expenses were $25.7 million for the year ended December 31, 2006 compared to $17.8 million for the year ended December 31, 2005, an increase of 44.4%. Approximately $7.1 million was attributable to the establishment of new service centers. New service center SG&A expenses by operating region increased in 2006 by $1.9 million, $0.7 million, $0.9 million, $1.8 million and $1.8 million in the Appalachian, Southeast, Mid-Continent, Southwest and Rocky Mountain operating regions, respectively. We hired additional personnel during 2006 to manage the growth in our operations. As a result of this growth, 2006 expenses for labor, office, rent and insurance expenses increased $5.2 million, $0.4 million, $0.5 million and $0.5 million, respectively. Additionally, legal and professional and franchise tax expenses increased $0.6 million and $0.5 million, respectively. The legal and professional and franchise tax expense increases were associated with becoming a public company in 2005. As

a percentage of revenue, the portion of labor expenses included in SG&A expenses decreased to 6.0% in 2006. Aggregate labor expenses increased $3.6 million to $10.3 million in 2006 due to revenue growth.

Operating Income.

Operating income was $53.0 million for the year ended December 31, 2006 compared to $23.7 million for the year ended December 31, 2005, an increase of 124.1%. As a percentage of revenue, operating income increased from 18.0% in 2005 to 21.7% in 2006. The primary reason for this increase was the increase in drilling activity by our customers in our existing locations, coupled with the establishment of new service centers and the expansion of operations in existing service centers. This increase in operating income was partially offset by the increases in our cost of revenue and SG&A expenses as described above. Approximately $8.7 million of this increase was attributable to new service centers. New service center operating income (expense) by operating region increased (decreased) in 2006 by $5.5 million, $5.0 million, $0.5 million, $(1.9) million and $(0.4) million in the Appalachian, Southeast, Mid-Continent, Southwest and Rocky Mountain operating regions, respectively. It has been our experience that when we establish a new service center in a particular operating region, it may take from 12 to 24 months before that service center has a positive impact on the operating income that we generate in the relevant region. EBITDA increased $35.1 million in 2006 to $67.6 million. For a definition of EBITDA, a reconciliation of EBITDA to net income and a discussion of EBITDA as a performance measure, please see footnote 3 to “Selected Financial Data.” Net income increased $22.5 million to $31.9 million in 2006 due to increased activity levels described above. In addition, income tax expense in 2005 included a non-cash adjustment of $8.6 million to deferred tax expense to establish deferred tax liabilities that existed at the time of the reorganization in connection with our initial public offering in August 2005. Prior to our reorganization, our business was not subject to federal or state corporate income taxes.

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.

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. As of December 31, 2007, the net deferred tax liability was approximately $24.5 million, resulting primarily from accelerated depreciation. Following our initial public offering, we incur income taxes under our new holding company structure, and our consolidated financial statements reflect the actual impact of income taxes.

Public Company Expenses.

Our general and administrative expenses have increased by approximately $1.5 million to $2.0 million per year as a result of becoming a public company following our initial public offering in 2005. These increases are due to the cost of tax return preparations, accounting support services, Sarbanes-Oxley compliance expenses, filing annual and quarterly reports with the SEC, investor relations, directors’ fees, directors’ and officers’ insurance and registrar and transfer agent fees. Our consolidated financial statements reflect the impact of these increased expenses and affect the comparability of our financial statements with periods prior to the completion of our initial public offering.

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, 2006 and 2007 include $1.7 million and $2.0 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 2006 and 2007.

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 equity offerings 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, 2007, we had $5.5 million of cash and cash equivalents and $36.9 million of availability under our bank credit facilities which can be used for planned capital expenditures and to make acquisitions.

Financial Condition and Cash Flows

Financial Condition.

Our working capital decreased $45.7 million to $38.4 million at December 31, 2007 compared to December 31, 2006, primarily due to a $51.2 million decrease in cash as a result of our 2007 expenditures for property, plant and equipment that was partially offset by cash flow from operations. Additionally, higher revenue activities caused receivables and inventory to increase by $6.7 million and $3.0 million, respectively. Cash from operations was used to fund capital expenditures and acquisitions totaling $127.7 million in 2007. The increase in accounts receivable and inventory was due to the higher revenue activity discussed above in “— Our Results of Operations.” Offsetting the increase in current assets was an increase in accounts payable of $7.8 million due to the higher revenue activity levels.

Cash flows from operations.

Our cash flow from operations increased $33.4 million to $69.3 million for the year ended December 31, 2007 compared to December 31, 2006, primarily due to higher income before income taxes. For a detailed comparison of 2007 and 2006 operating results please see “Our Results of Operations” under the sub-heading “Year ended December 31, 2007 Compared to Year Ended December 31, 2006.” Additionally, 2007 cash flow from operations increased due to higher amounts of deferred income taxes and depreciation and amortization of $5.7 million and $10.8 million, respectively. These increases were partially offset by working capital changes that decreased cash flows from operations by $6.5 million for the year ended December 31, 2007 as compared to the year ended December 31, 2006. Working capital decreased cash flow from operations due to growth in accounts receivable, inventory, prepaid expenses that resulted from higher revenue activities. Additionally working capital decreased

$0.7 million due to the timing of payments made on accrued liabilities. Receivables and inventory increased and accrued liabilities decreased by $6.7 million, $3.0 million and $0.7 million, respectively for the year ended December 31, 2007 as compared to the year ended December 31, 2006. Deferred income taxes also increased in 2007 as compared to 2006 due to higher levels of tax depreciation in the current year.

Cash flows used in investing activities.

Net cash used in investing activities increased from $78.9 million for the year ended December 31, 2006 to $128.1 million for the year ended December 31, 2007. The increase was due to higher amounts of capital expenditures to acquire $9.9 million of down-hole surveying assets and $117.8 million of equipment purchases for new and existing service centers. During 2007, goodwill and intangible assets increased by $5.6 million due to down-hole surveying asset acquisitions that occurred in 2007.

Cash flows from financing activities.

Net cash provided by financing activities decreased $81.4 million to $7.6 million for the year ended December 31, 2007. The 2006 net cash from financing activities was due to $88.6 million in net proceeds from our follow-on equity offering completed in December 2006. The 2007 net cash from financing activities was due to $7.6 million in net borrowing under our revolving credit facility.

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, 2007, we made capital expenditures of approximately $127.7 million to purchase new and upgrade existing pumping and down-hole surveying equipment. The 2007 capital expenditure amounts include approximately $9.9 million for down-hole asset purchases and $29.8 million of construction in progress for new capital equipment to be placed in service during 2008. These purchases and upgrades allow us to deploy additional service crews. Our 2008 capital expenditure budget is approximately $65 million. The decrease in the 2008 capital expenditure budget is due to fewer new service center planned openings in 2008 as compared to 2007. We plan to focus our planned 2008 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 significant amounts of capital to acquire businesses and assets. We actively consider a variety of businesses and assets for potential acquisitions, although currently we have no agreements or understandings with respect to any acquisition. For a discussion of the primary factors we consider in deciding whether to pursue a particular acquisition, please read “— Our Growth Strategy.” Management believes that cash flows from operations, combined with cash and cash equivalents and 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, 2007 (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	$	9,555	$	390	$	8,356	$	207	$	602
Operating leases		18,825		4,871		7,968		4,048		1,938
Purchase obligations		57,400		50,200		7,200		—		—

Total	$	85,780	$	55,461	$	23,524	$	4,255	$	2,540

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of December 31, 2007.

Description of Our Indebtedness

In October 2005, we entered into a $20.0 million revolving credit facility with our existing lending institution, which matures in October 2009. Interest on the revolving credit facility is at LIBOR plus a spread of 1.00% to 1.25%, based upon certain financial ratios, or the prime lending rate, at our option. As of December 31, 2007, we had $8.0 million of borrowings under our revolving credit facility and had $6.9 million of available capacity and $5.2 million in letters of credit outstanding.

In August 2006, we entered into a standby term loan facility with our existing lending institution. The standby term loan facility provides an additional $30.0 million of borrowing capacity that can be used to finance equipment purchases. The standby term loan facility matures in August 2009, at which time the outstanding aggregate principle balance under the standby term facility will convert to a single amortizing 60-month term loan. Interest on the standby term loan facility will be at LIBOR plus a spread of 1% to 1.25%, based upon certain financial ratios. As of December 31, 2007, we had no borrowings under the standby term loan facility and had $30.0 million of borrowing availability.

The standby term loan facility and revolving credit facility are secured by our cash, investment property, accounts receivable, inventory, intangibles and equipment. Both facilities contain leverage ratio and net worth covenants and a fixed charge coverage ratio as specified in the respective credit agreements. At December 31, 2007, we were in compliance with the financial covenants required under our revolving credit facility and our standby term loan facility.

At December 31, 2007, we had $1.6 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 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This standard only applies when other standards require or permit the fair value measurement of assets and liabilities. It does not increase the use of fair value measurement. SFAS 157 is effective for financial assets and liabilities in fiscal years beginning after November 15, 2007 and for non-financial assets and liabilities in fiscal years beginning after March 15, 2008. We do not expect the provisions of the statement that apply to financial assets and liabilities to have an effect on our consolidated financial statements. We are currently in the process of evaluating the impact of the provisions applicable to non-financial assets and liabilities.

In February 2007, the FASB issued SFAS No. 159. The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”), including an amendment of FASB Statement No. 115. This Statement provides companies with an option to report selected financial assets and liabilities at fair value. Under SFAS 159, companies that elect the fair value option will report unrealized gains and losses in earnings at each subsequent reporting date. In addition, SFAS 159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and

liabilities. The fair value option election is irrevocable, unless a new election date occurs. SFAS 159 is effective beginning January 1, 2008. We do not expect it to have an effect on our consolidated financial statements.

In December 2007, the FASB issued SFAS 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51 (“SFAS 160”) . This statement amends ARB 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 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 141R, Business Combinations, a replacement of (“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.

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. Substantially all of 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 buildings and improvements and range from five to ten years for equipment and vehicles. The estimated useful lives may be adversely impacted by technological advances, unusual wear or by accidents during usage. Management routinely monitors the condition of equipment. Historically, management has not changed the estimated useful lives of our property, plant and equipment and presently does not anticipate any significant changes to those estimates. Repairs and maintenance costs, which do not extend the useful lives of the asset, are expensed in the period incurred.

Impairment of Long-Lived Assets

In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we evaluate our long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management’s estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is recalculated when related events or circumstances change.

When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset or asset group. Our estimate of cash flows is based on assumptions regarding the future estimated cash flows, which in most cases is derived from our performance of services. The amount of future business is dependent in part on 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, no amortization is recorded for goodwill and /or intangible assets deemed to have indefinite lives for acquisitions completed after June 30, 2001. SFAS No. 142 requires that goodwill and non-amortizable assets be assessed annually for impairment. We completed the annual impairment test for 2007 and no impairment was determined. At December 31, 2007, our intangible assets consisted of $5.9 million of goodwill and $3.2 million of customer relationships and non-compete agreements that are amortized over their estimated useful lives which range from three to five years. For the years ended December 31, 2005, 2006 and 2007, we recorded amortization expense of $285,000, $345,000 and $805,000, 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 and 2007 include $1,740,000 and $1,961,000 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;


	•	overcapacity and competition in our industry;

	•	unanticipated costs, delays and other difficulties in executing our growth strategy;

	•	the loss of one or more significant 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 revolving credit facility established in October 2005 and our standby term loan facility established in August 2006, 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 December 31, 2006 and December 31, 2007 would result in an increase in interest expense and a corresponding decrease in net income, of less than $0.1 million and $0.1 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% and 12% and 9% of our revenue for the years ended December 31, 2006 and 2007, respectively. One customer accounted for 18% of our revenue for the year ended December 31, 2005. Eight customers accounted for 51%, 45% and 42% of our revenue for the years ended December 31, 2005, 2006 and 2007, respectively. At December 31, 2007, one customer accounted for 15% and eight customers accounted for 54% 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 trucks and other motorized equipment. The prices for fuel and the raw materials in our inventory are volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages. Although we are generally able to pass along price increases to our customers, due to pricing commitments and the timing of our marketing and bidding cycles there is generally a delay of several weeks or months from the time that we incur a price increase until the time that we can pass it along to our customers.


Item 8.	*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, 2007. 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, 2007, our internal control over financial reporting is effective based on those criteria. The effectiveness of our internal control over financial reporting has been audited by Schneider Downs & Co., Inc., our independent registered public accounting firm, as stated in their report, which is included herein.

Indiana, Pennsylvania

March 10, 2008

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, 2007 and 2006, and the related statements of income, changes in capital and stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. 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, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Superior’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on Superior’s internal control over financial reporting based on our audits.

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

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

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Superior as of December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, Superior maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, 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 10, 2008

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,			December 31,
	2006			2007
	(In thousands, except
	per share data)

Current Assets:
Cash and cash equivalents	$	56,752		$	5,510
Trade accounts receivable, net of allowance of $772 and $1,629, respectively		47,325			54,002
Inventories		6,951			9,933
Prepaid expenses and other current assets		908			1,027
Income taxes receivable		—			3,722
Deferred income taxes		507			1,827

Total current assets		112,443			76,021
Property, Plant and Equipment:
Land		420			420
Building and improvements		3,323			4,776
Equipment and vehicles		149,195			266,444
Construction in progress		24,922			29,814

		177,860			301,454
Accumulated depreciation		(36,436	)		(60,591	)

Total property, plant and equipment, net		141,424			240,863
Goodwill		2,850			5,850
Intangible assets, net of accumulated amortization of $1,010 and $1,815, respectively		1,416			3,242
Deferred income taxes		585			366
Other assets		316			745

Total assets	$	259,034		$	327,087

Current Liabilities:
Accounts and construction payable-trade	$	21,565		$	31,497
Income taxes payable		542			—
Current portion of long-term debt		382			390
401(k) plan contribution and withholding		1,982			1,615
Advance payments on servicing contracts		803			70
Accrued wages and health benefits		1,462			2,126
Other accrued liabilities		1,664			1,931

Total current liabilities		28,400			37,629
Long-term debt		1,597			9,165
Deferred income taxes		15,133			26,694
Stockholders’ Equity:
Common stock, voting, par $.01 per share, 70,000,000 shares authorized, 23,352,567 and 23,474,552 shares issued at December 31, 2006 and 2007, respectively		234			234
Additional paid-in capital		182,492			184,432
Retained earnings		31,178			68,933

Total stockholders’ equity		213,904			253,599

Total liabilities and stockholders’ equity	$	259,034		$	327,087

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

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL AND STOCKHOLDERS’ EQUITY


	Partnerships									Superior Well Services, Inc.
				Accumulated									Additional			Retained
	Partners’			Comprehensive			Less: Notes			Common			Paid-in			Earnings
	Capital			Income (Loss)			Receivable			Stock			Capital			(Deficit)			Total
	(In thousands)

BALANCE, DECEMBER 31, 2004	$	33,885		$	2		$	(68	)	$	—		$	—		$	—		$	33,819
Net income prior to reorganization		10,212																		10,212
Net (loss) after reorganization																	(745	)		(745	)

Net income for 2005																				9,467
Other					(2	)														(2	)

Total comprehensive income																				9,465

Distributions to partners		(13,719	)																	(13,719	)
Collection of notes receivable								68												68
Reorganization effected through contribution of partnership interests to Superior Well Services, Inc.		(30,378	)								141			30,237						—
Issuance of common stock in connection with initial public offering											53			61,707						61,760

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 follow-on 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

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,
	2005			2006			2007
	(In thousands)

Cash flows from operations:
Net income	$	9,467		$	31,923		$	37,755
Adjustments to reconcile net income to net cash provided by operations:
Deferred income taxes		9,284			4,758			10,460
Depreciation and amortization		8,698			14,453			25,277
Loss on disposal of equipment		280			224			302
Stock-based compensation		—			1,740			1,961
Changes in assets and liabilities:
Trade accounts receivable		(12,089	)		(23,944	)		(6,677	)
Inventory		(1,926	)		(3,190	)		(2,982	)
Prepaid expenses and other assets		(821	)		249			(119	)
Income tax receivable		—			—			(3,722	)
Accounts payable		2,627			6,220			7,759
Income taxes payable		—			542			(542	)
401(k) plan contribution and withholding		260			1,071			(367	)
Advance payments on servicing contracts		278			324			(733	)
Accrued wages and health benefits		176			621			664
Other accrued liabilities		508			958			267

Net cash provided by operations		16,742			35,949			69,303
Cash flows from investing:
Expenditure for property, plant and equipment, net of construction payables		(39,920	)		(69,816	)		(117,774	)
Acquisition of businesses, net of cash acquired		—			(9,150	)		(9,931	)
Purchase of short-term investments		—			—			(18,967	)
Proceeds from sales of short-term investments		—			—			18,967
Proceeds from sale of property, plant and equipment		—			79			34
Proceeds (expenditures) for other assets		(239	)		(15	)		(429	)
Advances on notes receivable		68			—			—

Net cash used in investing		(40,091	)		(78,902	)		(128,100	)
Cash flows from financing:
Principal payments on long-term debt		(12,236	)		(27,019	)		(52,274	)
Proceeds from long-term borrowings		720			27,111			59,850
Proceeds from notes payable		10,511			—			—
Payments on notes payable		(14,466	)		—			—
Net proceeds from common stock offerings		61,760			88,559			—
Issuance/retirement of restricted stock, net		—			289			(21	)
Distributions to partners		(13,719	)		—			—

Net cash provided by financing		32,570			88,940			7,555

Net increase (decrease) in cash and cash equivalents		9,221			45,987			(51,242	)
Cash and cash equivalents, beginning of period		1,544			10,765			56,752

Cash and cash equivalents, end of period	$	10,765		$	56,752		$	5,510

Supplemental disclosure of cash flow data:
Interest paid	$	587		$	437		$	292
Income taxes paid	$	5,156		$	15,008		$	18,262
Equipment acquired through seller financed debt	$	—		$	450		$	—

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 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.

Superior Well provides a wide range of well services to oil and gas companies, primarily technical pumping and down-hole surveying services, in many of the major oil and natural gas producing regions of the United States.


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 and Superior GP. Superior Well and Bradford (“Partnerships”), prior to the effective date of the Contribution Agreement, were entities under common control arising from common direct or indirect ownership of each. The transfer of the Partnerships assets and liabilities to Superior (see Note 1) represented a reorganization of entities under common control and was accounted for at historical cost. Prior to the reorganization, the Partnerships were not subject to federal and state corporate income taxes. The 2005 statement of income reflects federal and state income taxes for the five months of operations following the reorganization. Additionally, Superior recorded a non-cash adjustment of $8.6 million to record the deferred tax asset and liabilities arising from the differences in the financial statement and tax bases of assets and liabilities that existed at that time. The $8.6 million non-cash adjustment is included in the deferred income tax provision for the year ended December 31, 2005.

Estimates and Assumptions

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

Cash and Cash Equivalents

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

Trade Accounts Receivable

Accounts receivable are carried at the amount owed by customers. Superior grants credit to all qualified customers, which are mainly 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, 2005, 2006 and 2007, Superior recorded a provision for uncollectible accounts receivable of $144,200, $637,600 and $857,100, respectively.

Property, Plant and Equipment

Superior’s property, plant and equipment are stated at cost less accumulated depreciation. The costs are depreciated using the straight-line and accelerated methods over their estimated useful lives. The estimated useful lives range from 15 to 30 years for building and improvements and range from 5 to 10 years for equipment and vehicles. Depreciation expense, excluding intangible amortization, amounted to $8,413,000, $14,108,000 and $24,472,000 in 2005, 2006 and 2007, respectively.

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

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

Revenue Recognition

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

Inventories

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

Insurance Expense

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

Effective January 1, 2007, we adopted Financial Accounting Standards Board (FASB) Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” 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, 2006 and 2007 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. The Internal Revenue Service commenced an examination of our U.S. income tax return for 2005 in the second quarter 2007. We reached a settlement, signed in January 2008, with the Internal Revenue Service on tax issues relating to the 2005 tax year. The results of the settlement did not have a significant impact on Superior’s tax position or interest expense. Superior classifies interest expense and penalties related to income tax expense as interest expense. Interest and penalties for the years ended December 2006 and 2007 were insignificant in each period.

Fair Value of Financial Instruments

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 notes payable and long-term debt approximates fair value, since the interest rates are market-based and are generally adjusted periodically.

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 date 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 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.

During 2006 and 2007, the Company made acquisitions of businesses in each of the years for approximately $9.2 million and $9.9 million, respectively. The acquisitions resulted in $2.9 million and $3.0 million in goodwill in 2006 and 2007, respectively. Intangible assets of approximately $800,000 and $2.6 million, in 2006 and 2007

respectively, consist of customer lists and covenants not to compete which are being amortized over an average life of 5 years. These acquisitions were not material to the Company’s operations, financial position, or cash flows.

Goodwill and Other Intangible Assets

In accordance with SFAS No. 142, no amortization is recorded for goodwill and /or intangible assets deemed to have indefinite lives for acquisitions completed after June 30, 2001. SFAS No. 142 requires that goodwill and non-amortizable assets be assessed annually for impairment. Superior completed the annual impairment test for 2006 and 2007 and no impairment was determined. Superior’s intangible assets consist of $5.9 million of goodwill and $3.2 million of customer relationships and non-compete agreements that are amortized over their estimated useful lives which range from three to five years. For the years ended December 31, 2005, 2006 and 2007, Superior recorded amortization expense of $285,000, $345,000 and $805,000, respectively. The estimated amortization expense for the five succeeding years approximates $916,000, $726,000, $726,000, $667,000 and $207,000 for 2008, 2009, 2010, 2011 and 2012, 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% and 12% and 9% of Superior’s revenue, respectively, for the years ended December 31, 2006 and 2007. In 2005, one customer accounted for 18% of Superior’s revenue. Eight customers accounted for 51%, 45% and 42% of Superior’s revenue for the years ended December 31, 2005, 2006 and 2007, respectively. At December 31, 2007, one customer accounted for 15% and eight customers accounted for 54% 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 and 2007 includes $1,740,000 and $1,961,000 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 by the weighted average number of shares outstanding. 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. The restricted shares were anti-dilutive for the three and twelve month periods ended December 31, 2006.

The weighted average shares outstanding for the computation of basic and diluted earnings per share for the year ended December 31, 2005 has been computed taking into account the 14,103,474 shares issued to former partners in connection with the reorganization described in Note 2, effective immediately prior to the initial public offering, the 5,273,193 shares issued by Superior in the initial public offering, which included 840,000 shares sold

by Superior to cover the underwriters’ over-allotment option, each from the respective date of issuance. This resulted in 19,317,436 average shares outstanding for the year ended December 31, 2005.

Accounting Standards Not Yet Adopted

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This standard only applies when other standards require or permit the fair value measurement of assets and liabilities. It does not increase the use of fair value measurement. SFAS No. 157 is effective for financial assets and liabilities in fiscal years beginning after November 15, 2007 and for non-financial assets and liabilities in fiscal years beginning after March 15, 2008. We do not expect the provisions of the statement that apply to financial assets and liabilities to have an effect on our consolidated financial statements. We are currently in the process of evaluating the impact of the provisions applicable to non-financial assets and liabilities.

In February 2007, the FASB issued SFAS No. 159 (“SFAS 159”), The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115. This Statement provides companies with an option to report selected financial assets and liabilities at fair value. Under SFAS 159, companies that elect the fair value option will report unrealized gains and losses in earnings at each subsequent reporting date. In addition, SFAS 159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. The fair value option election is irrevocable, unless a new election date occurs. SFAS 159 is effective beginning January 1, 2008. We do not expect it to have an effect on our consolidated financial statements.

In December 2007, the FASB issued SFAS 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51 (“SFAS 160”) . This statement amends ARB 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 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 this Statement; however, we do not expect it to have an effect on our consolidated financial statements.

In December 2007, the FASB issued SFAS 141R, Business Combinations, a replacement of SFAS 141. 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 this Statement.


3.	Notes Receivable — Limited Partners

Superior Well sold limited partnership interests, amounting to 40% ownership, to three individuals during the year ended December 31, 2000. Capital contributions made to Superior Well for these limited partnership interests aggregated $200,000, of which $87,000 was received in cash and $113,000 was received through issuance of notes receivable. The notes receivable were due in monthly installments totaling $1,338, including interest at 7.5%, through January 2010. The notes were repaid prior to the initial public offering.


4.	Debt

In October 2005, Superior entered into a revolving credit facility with its existing lending institution. The agreement provides for a $20 million revolving credit facility and matures in October 2009. Interest on the revolving credit facility will be at LIBOR plus a spread of 1% to 1.25%, based upon certain financial ratios. The loan is secured by Superior’s

accounts receivable, inventory and equipment. The revolving credit facility requires Superior to maintain a maximum debt to EBITDA ratio and a minimum amount of adjusted net tangible worth, as defined under the credit agreement. At December 31, 2007, Superior had $8.0 million outstanding under the revolving credit facility, $6.9 million of borrowing availability, $5.2 million of outstanding letters of credit and was in compliance with its financial covenants. At December 31, 2006, Superior has no amounts outstanding under the revolving credit facility. The weighted average interest rates for the years ended December 31, 2006 and 2007 were 6.4% and 6.3%, respectively.

In August 2006, Superior entered into a standby term loan facility with its existing lending institution. The standby term loan facility provides an additional $30 million of borrowing capacity that can be used to finance equipment purchases. The standby term loan facility matures in August 2009, at which time the outstanding aggregate principle balance under the standby term loan facility will convert to a single amortizing 60 month term loan. Interest on the revolving credit facility will be at LIBOR plus a spread of 1% to 1.25%, based upon certain financial ratios. The standby term loan facility contains leverage ratio and net worth covenants similar to those in the revolving credit facility, as well as, a fixed charge coverage ratio covenant as specified in the standby term loan facility. The standby term loan facility is secured by Superior’s cash, investment property, accounts receivable, inventory, intangibles and equipment. At December 31, 2006 and 2007, Superior had no outstanding borrowings under the standby term loan facility. At December 31, 2007 the standby term loan facility had $30 million of borrowing availability and was in compliance with its financial covenants. The weighted average interest rate for the years ended December 31, 2006 was 6.4%. Superior did not borrow under the standby term loan facility during 2007.

Long-term debt at December 31, 2006 and 2007 consisted of the following (amounts in thousands):


	2006		2007

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 rates approximating the bank’s prime lending rate minus 1%, payable in monthly installments of $8,622 plus interest through January 2021, collateralized by real property		1,331		1,221
Note payable to sellers with an interest rate of 7% due through September 2008, collateralized by equipment		450		233
Notes payable to sellers with nominal interest rates due through December 2010, collateralized by specific buildings and equipment		198		144

		1,979		9,555
Less — Payments due within one year		382		390

Total	$	1,597	$	9,165

Principal payments required under our long-term debt obligations during the next five years and thereafter are as follows: 2008-$390,000, 2009-$8,114,000, 2010-$139,000, 2011-$103,000, 2012-$103,000 and thereafter $706,000.


5.	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,
	2005		2006		2007
	(Amounts in thousands)

Current:
State and local	$	852	$	2,524	$	2,246
U.S. federal		3,690		13,509		11,864

Total current		4,542		16,033		14,110
Deferred:
State and local		1,667		842		1,851
U.S. federal		7,617		3,916		8,609

Total deferred		9,284		4,758		10,460

Provision for income tax expense	$	13,826	$	20,791	$	24,570

As discussed above, Superior recorded a net deferred tax liability of $8.6 million related to the temporary differences that existed on the date of reorganization. Significant components of Superior’s deferred tax assets and liabilities are as follows:


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

Deferred tax assets:
Restricted stock	$	589		$	1,014
Accrued expenses and other		207			544
Allowance for doubtful accounts receivable		296			635

Total deferred tax assets		1,092			2,193

Deferred tax liabilities:
Depreciation differences on property, plant and equipment		(15,133	)		(26,694	)

Total deferred tax liabilities		(15,133	)		(26,694	)

Net deferred taxes	$	(14,041	)	$	(24,501	)

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,
	2005			2006			2007
	(Amounts in thousands)

Income before income taxes	$	23,293		$	52,714		$	62,325
Statutory U.S. income tax rate		35	%		35	%		35	%

Tax expense using statutory U.S. income tax rate		8,153			18,450			21,814
State income taxes		621			2,349			2,663
Deferred income taxes established at date of reorganization		8,708			—			—
Tax effect of pre-tax income prior to reorganization not subject to income taxes		(3,574	)		—			—
Other		(82	)		(8	)		93

Income tax expense	$	13,826		$	20,791		$	24,570

Effective income tax rate		59	%		39	%		39	%


6.	401(k) Plan

Superior Well has a defined contribution profit sharing/401(k) retirement plan (“the Plan”) covering substantially all employees. Employees are eligible to participate after six months of service. Under terms of the Plan, employees are entitled to contribute up to 15% of their compensation, within limitations prescribed by the Internal Revenue Code. Superior Well makes matching contributions of 25% of employee contributions up to 12% of their compensation and may elect to make discretionary contributions to the Plan, all subject to vesting ratably over a five-year period. In addition, Superior makes a discretionary annual profit sharing contribution. 401(k) expense was approximately $944,000, $1,965,000 and $2,408,000 in 2005, 2006 and 2007, respectively.


7.	Related-Party Transactions

Superior Well provides technical pumping services and down-hole surveying services to a customer owned by certain shareholders and directors of Superior. The total amounts of services provided to this affiliated party were approximately $5,588,000, $4,658,000 and $6,587,000 in 2005, 2006 and 2007, respectively. The accounts receivable outstanding from the affiliated party were $499,000 and $371,000 at December 31, 2006 and 2007, respectively.

Superior Well also regularly purchases, in the ordinary course of business, materials from vendors owned by certain shareholders and directors of Superior. The total amounts paid to these affiliated parties were approximately $2,141,000, $2,552,000 and $3,294,000 in 2005, 2006 and 2007, respectively. Superior Well had accounts payable to these affiliates of $442,000 and $191,000 at December 31, 2006 and 2007, respectively.

Prior to Superior’s initial public offering in August 2005, administrative and management services were provided to Superior Well by affiliates that were owned by certain partners of Superior Well. The total amounts paid to these affiliated entities was approximately $594,000 in 2005. Following Superior’s initial public offering, Superior Well no longer requires these administrative and management services.


8.	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, 2007, were as follows: 2008-$4,871,000; 2009-$4,372,000; 2010-$3,596,000; 2011-$2,652,000 and 2012-$1,396,000.

Total rental expense charged to operations was approximately $968,000, $1,915,000 and $3,164,000 in 2005, 2006 and 2007, respectively.

In October 2007, Superior entered into a take-or-pay contract with U.S. Silica Company to purchase fracturing sand for the two year period beginning January 1, 2008 and ending December 31, 2009. Minimum purchases under the take-or-pay contract are estimated at $4.5 million and $7.2 million in 2008 and 2009, respectively.

Superior had commitments of approximately $45.7 million for capital expenditures as of December 31, 2007.

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.


9.	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. 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

The aggregate market value of cumulative awards was approximately $10.0 million, before the impact of income taxes. At December 31, 2007, Superior’s compensation costs related to non-vested awards amounted to $6.3 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 and 2007 was $1,740,000 and $1,961,000, respectively.


10.	Quarterly Financial Information (Unaudited)

Quarterly financial information for the years ended December 31, 2007 and 2006 is presented below:


	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	$	0.39		$	0.44		$	0.50		$	0.30
Basic	$	0.39		$	0.44		$	0.50		$	0.30
Diluted
Average Shares Outstanding
Basic		23,102			23,102			23,102			23,104
Diluted		23,116			23,166			23,142			23,150


	2006
	First			Second			Third			Fourth
	Quarter			Quarter			Quarter			Quarter
	(In thousands, except share information)

Revenue	$	47,687		$	54,589		$	67,205		$	75,145
Cost of revenue		31,736			37,704			45,152			51,285

Gross profit		15,951			16,885			22,053			23,860
Selling, general and administrative expenses		5,526			6,153			6,813			7,224

Operating income		10,425			10,732			15,240			16,636
Interest expense		(38	)		(49	)		(77	)		(314	)
Other income (expense)		141			50			1			(33	)
Income tax expense		(4,172	)		(4,302	)		(5,802	)		(6,515	)

Net income	$	6,356		$	6,431		$	9,362		$	9,774

Net income per common share	$	0.33		$	0.33		$	0.48		$	0.49
Basic	$	0.33		$	0.33		$	0.48		$	0.49
Diluted
Average Shares Outstanding
Basic		19,377			19,377			19,377			20,139
Diluted		19,377			19,377			19,377			20,139


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

None


Item 9A.	*Controls and Procedures*

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.

As required by SEC rule 13a-15(b), we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in rules 13a-15(c) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our Chief Executive Officer and Chief Financial Officer, based upon their evaluation as of December 31, 2007, the end of the period covered in this report, concluded that our disclosure controls and procedures were effective.

Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2007, is set forth on page [ ] of this Annual Report on Form 10-K and is incorporated by reference herein.

The effectiveness of internal control over financial reporting as of December 31, 2007 has been audited by Schneider Downs & Co., Inc., the independent registered public accounting firm who also audited the Company’s consolidated financial statements. Schneider Downs & Co., Inc.’s attestation report on the effectiveness of our internal control over financial reporting is included herein.

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 2007 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 and 406 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, 2007 pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (the “2008 Proxy Statement”), is incorporated herein by reference.


Item 11.	*Executive Compensation*

The information responsive to Item 402 of Regulation S-K to be included in our 2008 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).
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 August 31, 2005).
10	.1	Credit Agreement dated as of October 18, 2005, among Superior Well Services, Inc., Superior Well Services, Ltd., Bradford Resources, Ltd. and Citizens Bank of Pennsylvania (filed as Exhibit 10.1 to Form 8-K filed on October 21, 2005).
10	.2†	Employment Agreement between David E. Wallace and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.2 to Form 8-K filed on August 3, 2005).
10	.3†	Employment Agreement between Jacob B. Linaberger and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.3 to Form 8-K filed on August 3, 2005)
10	.4†	Employment Agreement between Thomas W. Stoelk and Superior Well Services, Inc., effective as of June 1, 2005 (incorporated by reference to Exhibit 10.4 to Form 8-K filed on August 3, 2005).
10	.5†	Employment Agreement between Rhys R. Reese and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.5 to Form 8-K filed on August 3, 2005).
10	.6†	Employment Agreement between Fred E. Kistner and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.6 to Form 8-K filed on August 3, 2005).
10	.7†	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	.8†	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	.9†	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	.10†	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	.11†	Indemnification Agreement between Fred E. Kistner and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.11 to Form 8-K filed on August 3, 2005).
10	.12†	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	.13†	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	.14†	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	.15†	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	.16†	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	.17	Fifth Amended and Restated Promissory Note dated March 31, 2005 (incorporated by reference to Exhibit 10.8 to Registration Statement on Form S-1/A (Registration No. 333-124674) filed on July 15, 2005).
10	.21	Guaranty and Suretyship Agreement dated June 3, 2005 by Superior Well Services, Ltd. (incorporated by reference to Exhibit 10.12 to Registration Statement on Form S-1/A (Registration No. 333-124674) filed on July 15, 2005).
10	.22	Guaranty and Suretyship Agreement dated June 3, 2005 by Allegheny Mineral Corporation (incorporated by reference to Exhibit 10.13 to Registration Statement on Form S-1/A (Registration No. 333-124674) filed on July 15, 2005).
10	.23	Guaranty and Suretyship Agreement dated June 3, 2005 by Armstrong Cement & Supply Corporation (incorporated by reference to Exhibit 10.14 to Registration Statement on Form S-1/A (Registration No. 333-124674) filed on July 15, 2005).
10	.24	Guaranty and Suretyship Agreement dated June 3, 2005 by Glacial Sand & Gravel Company (incorporated by reference to Exhibit 10.15 to Registration Statement on Form S-1/A (Registration No. 333-124674) filed on July 15, 2005).
10	.25	Standby Term Loan Note (incorporated by reference to Exhibit 10.1 to Form 8-K filed on August 21, 2006).
10	.26	First Amendment to Credit Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K filed on August 21, 2006).
10	.27†	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	.28†	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	.29	Third Amendment to Credit Agreement, dated May 15, 2007 (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q filed on August 8, 2007).
10	.30*†	Non-Employee Director Compensation Summary
10	.31*	Agreement dated October 2, 2007 between U.S. Silica and Superior Well Services, Inc.
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, 2007.
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, 2007.
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, 2007.
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, 2007.


*		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 10^th day of March, 2008.

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 10, 2008

/s/ Jacob B. Linaberger Jacob B. Linaberger	President	March 10, 2008

/s/ Thomas W. Stoelk Thomas W. Stoelk	Vice President & Chief Financial Officer (principal financial officer and principal accounting officer)	March 10, 2008

/s/ Rhys R. Reese Rhys R. Reese	Executive Vice President, Chief Operating Officer & Secretary	March 10, 2008

/s/ David E. Snyder David E. Snyder	Director	March 10, 2008

/s/ Mark A. Snyder Mark A. Snyder	Director	March 10, 2008

/s/ Charles C. Neal Charles C. Neal	Director	March 10, 2008

/s/ John A. Staley, IV John A. Staley, IV	Director	March 10, 2008


PART I
	Item 1.	Business	3
	Item 1A.	Risk Factors	11
	Item 1B.	Unresolved Staff Comments	17
	Item 2.	Properties	18
	Item 3.	Legal Proceedings	18
	Item 4.	Submission of Matters to a Vote of Security Holders	18

PART II
	Item 5.	Market for the Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities	19
	Item 6.	Selected Financial Data	20
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	39
	Item 8.	Financial Statements and Supplementary Data	40
	Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	55
	Item 9A.	Controls and Procedures	56
	Item 9B.	Other Information	56

PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	56
	Item 11.	Executive Compensation	56
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	57
	Item 13.	Certain Relationships, Related Transactions and Director Independence	57
	Item 14.	Principal Accounting Fees and Services	57
PART IV
	Item 15.	Exhibits and Financial Statement Schedules	58
EX-10.30
Exhibit 10.31
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2


	Years Ended December 31,
	2005			2006			2007

Revenue	$	131,733		$	244,626		$	350,770
Cost of revenue		90,258			165,877			252,539

Gross profit		41,475			78,749			98,231
Selling, general and administrative expenses		17,809			25,716			36,390

Operating income		23,666			53,033			61,841
Interest expense		(566	)		(478	)		(282	)
Other income		193			159			766

Income before income taxes		23,293			52,714			62,325
Income taxes
Current		4,542			16,033			14,110
Deferred		9,284			4,758			10,460

		13,826			20,791			24,570

Net income	$	9,467		$	31,923		$	37,755

Earnings per common share:
Basic	$	0.49		$	1.63		$	1.63

Diluted	$	0.49		$	1.63		$	1.63

Weighted average shares outstanding-basic		19,317,436			19,568,749			23,100,402
Weighted average shares outstanding-diluted		19,317,436			19,568,749			23,195,914


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


Item 13.	*Certain Relationships, Related Transactions, and Director Independence*


Col. A	Col. B		Col. C				Col. D		Col. E
			Additions
	Balance at		(1)		(2)
	Beginning		Charged to Costs		Charged to Other				Balance at end
Description	of Period		and Expenses		Accounts		Deductions		of Period

Year Ended December 31, 2005	$	—		144,200		—		10,200	$	134,000
Year Ended December 31, 2006	$	134,000		637,636		—		—	$	771,636
Year Ended December 31, 2007	$	771,636		857,130		—		—	$	1,628,766