UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-K

þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Basic Energy Services, Inc.

Delaware (State or other jurisdiction of incorporation or organization)		54-2091194 (I.R.S. Employer Identification No.)
400 W. Illinois, Suite 800 Midland, Texas (Address of principal executive offices)		79701 (Zip code)

Registrant’s telephone number, including area code: (432) 620-5500

Securities registered pursuant to Section 12(b) of the Act:

Common Stock, $0.01 par value per share (Title of Class)		New York Stock Exchange (Name of each exchange on which registered)

Securities registered pursuant to Section 12(g) of the Act:

     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) has 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 the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

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

Large Accelerated Filer o           Accelerated Filer o           Non-Accelerated Filer þ

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

     The aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $407,580,173 as of March 20, 2006 (based on a closing price of  $26.99  per share and 15,101,155 shares held by non-affiliates).

     33,706,703 shares of the registrant’s Common Stock were outstanding as of March 20, 2006.

     Documents incorporated by reference: Portions of the definitive proxy statement for the registrant’s Annual Meeting of Stockholders (to be filed within 120 days of the close of the registrant’s fiscal year) are incorporated by reference into Part III.

 

 

BASIC ENERGY SERVICES, INC.
Index to Form 10-K

Part I			2
Items 1. and 2. Business and Properties			2
General			2
Our Competitive Strengths			2
Our Business Strategy			3
General Industry Overview			4
Overview of Our Segments and Services			6
Properties			13
Customers			13
Operating Risks and Insurance			13
Competition			14
Safety Program			14
Environmental Regulation			14
Employees			16
Item 1A. Risk Factors			17
Risks Relating to Our Business			17
Risks Relating to Our Relationship with DLJ Merchant Banking			22
Risks Relating to Ownership of Our Common Stock			22
Item 1B. Unsolved Staff Comments			23
Item 3. Legal Proceedings			23
Item 4. Submission of Matters to a Vote of Security Holders			24
Executive Officers and Other Key Employees			24
Part II			25
Item 5. Market Price for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			25
Market Price for Registrant’s Common Equity			25
Securities Authorized for Issuance under Equity Compensation Plans			25
Recent Sales of Unregistered Securities			26
Use of Proceeds from Registered Securities			27
Purchases of Equity Securities by the Issuer and Affiliated Purchasers			28
Item 6. Selected Financial Data			29
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation			31
Management’s Overview			31
Recent Strategic Acquisitions and Expansions			32
Segment Overview			34
Operating Cost Overview			38
Critical Accounting Policies and Estimates			38
Results of Operations			41
Liquidity and Capital Resources			44
Other Matters			48
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			50
Item 8. Financial Statements and Supplementary Data			51
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			86
Item 9A. Controls and Procedures			86
Item 9B. Other Information			86
Part III			86
Part IV			87
Item 15. Exhibits and Financial Statement Schedules			87
Signatures			90
Subsidiaries of the Company
Consent of KPMG LLP
Certification by CEO required by Rule 13a-14a/15d-14a
Certification by CFO required by Rule 13a-14a/15d-14a
Certification by CEO pursuant to Section 906
Certification by CFO pursuant to Section 906

CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS

     This annual report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We have based these forward looking statements largely on our current expectations and projections about future events and financial trends affecting the financial condition of our business. These forward-looking statements are subject to a number of risks, uncertainties and assumptions, including, among other things, the risk factors discussed in this annual report and other factors, most of which are beyond our control.

     The words “believe,” “may,” “estimate,” “continue,” “anticipate,” “intend,” “plan,” “expect” and similar expressions are intended to identify forward-looking statements. All statements other than statements of current or historical fact contained in this annual report are forward looking-statements. Although we believe that the forward-looking statements contained in this annual report are based upon reasonable assumptions, the forward-looking events and circumstances discussed in this annual report may not occur and actual results could differ materially from those anticipated or implied in the forward-looking statements.

     Important factors that may affect our expectations, estimates or projections include:

	•		a decline in, or substantial volatility of, oil and gas prices, and any related changes in expenditures by our customers;
	•		the effects of future acquisitions on our business;
	•		changes in customer requirements in markets or industries we serve;
	•		competition within our industry;
	•		general economic and market conditions;
	•		our access to current or future financing arrangements;
	•		our ability to replace or add workers at economic rates; and
	•		environmental and other governmental regulations.

     Our forward-looking statements speak only as of the date of this annual report. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

     This annual report includes market share, industry data and forecasts that we obtained from internal company surveys (including estimates based on our knowledge and experience in the industry in which we operate), market research, consultant surveys, publicly available information, industry publications and surveys. These sources include Oil & Gas Journal magazine, World Oil magazine, Baker Hughes Incorporated, the Association of Energy Service Companies, and the Energy Information Administration of the U.S. Department of Energy. Industry surveys, publications, consultant surveys and forecasts generally state that the information contained therein has been obtained from sources believed to be reliable. Although we believe such information is accurate and reliable, we have not independently verified any of the data from third party sources cited or used for our management’s industry estimates, nor have we ascertained the underlying economic assumptions relied upon therein. For example, the number of onshore well servicing rigs in the U.S. could be lower than our estimate to the extent our two larger competitors have continued to report as stacked rigs equipment that is not actually complete or subject to refurbishment. Statements as to our position relative to our competitors or as to market share refer to the most recent available data.

PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

General

     We provide a wide range of well site services to oil and gas drilling and producing companies, including well servicing, fluid services, drilling and completion services and well site construction services. These services are fundamental to establishing and maintaining the flow of oil and gas throughout the productive life of a well. Our broad range of services enables us to meet multiple needs of our customers at the well site. Our operations are managed regionally and are concentrated in the major United States onshore oil and gas producing regions in Texas, New Mexico, Oklahoma and Louisiana and the Rocky Mountain states. We provide our services to a diverse group of over 1,000 oil and gas companies. We operate the third-largest fleet of well servicing rigs (also commonly referred to as workover rigs) in the United States, representing over 12% of the overall available U.S. fleet, with our two larger competitors controlling approximately 32% and 19%, respectively, according to the Association of Energy Services Companies and other publicly available data.

     We currently conduct our operations through the following four business segments:

	•		Well Servicing. Our well servicing segment (48% of our revenues in 2005) currently operates our fleet of over 320 well servicing rigs and related equipment. This business segment encompasses a full range of services performed with a mobile well servicing rig, including the installation and removal of downhole equipment and elimination of obstructions in the well bore to facilitate the flow of oil and gas. These services are performed to establish, maintain and improve production throughout the productive life of an oil and gas well and to plug and abandon a well at the end of its productive life. Our well servicing equipment and capabilities are essential to facilitate most other services performed on a well.
	•		Fluid Services. Our fluid services segment (29% of our revenues in 2005) currently utilizes our fleet of over 475 fluid services trucks and related assets, including specialized tank trucks, storage tanks, water wells, disposal facilities and related equipment. These assets provide, transport, store and dispose of a variety of fluids. These services are required in most workover, drilling and completion projects and are routinely used in daily producing well operations.
	•		Drilling and Completion Services. Our drilling and completion services segment (13% of our revenues in 2005) currently operates our fleet of 56 pressure pumping units, 25 air compressor packages specially configured for underbalanced drilling operations and 12 cased-hole wireline units. These services are designed to initiate or stimulate oil and gas production. The largest portion of this business consists of pressure pumping services focused on cementing, acidizing and fracturing services in niche markets.

•

Well Site Construction Services. Our well site construction services segment (10% of our revenues in 2005) currently utilizes our fleet of over 200 operated power units, which include dozers, trenchers, motor graders, backhoes and other heavy equipment. We utilize these assets primarily to provide services for the construction and maintenance of oil and gas production infrastructure, such as preparing and maintaining access roads and well locations, installation of small diameter gathering lines and pipelines and construction of temporary foundations to support drilling rigs.

Our Competitive Strengths

     We believe that the following competitive strengths currently position us well within our industry:

     Significant Market Position. We maintain a significant market share for our well servicing operations in our core operating areas throughout Texas and a growing market share in the other markets that we serve. Our fleet of over 320 well servicing rigs represents the third-largest fleet in the United States, and our goal is to be one of the top two providers of well site services in each of our core operating areas. Our market position allows us to expand the

range of services performed on a well throughout its life, such as completion, maintenance, workover and plugging and abandonment services.

     Modern and Active Fleet. We operate a modern and active fleet of well servicing rigs. We believe over 95% of the active U.S. well servicing rig fleet was built prior to 1985. Approximately 86 of our rigs at December 31, 2005 were either 2000 model year or newer, or have undergone major refurbishments during the last four years. As of December 31, 2005, we have taken delivery of 35 newbuild well servicing rigs since October 2004 as part of a 102-rig newbuild commitment, driven by our desire to maintain one of the most efficient, reliable and safest fleets in the industry. The remainder of these newbuilds is scheduled to be delivered to us prior to the end of December 2007. In addition to our regular maintenance program, we have an established program to routinely monitor and evaluate the condition of our fleet. We selectively refurbish rigs and other assets to maintain the quality of our service and to provide a safe work environment for our personnel and have made major refurbishments on 46 of our rigs since the beginning of 2001. Approximately 98% of our fleet was active or available for work and the remainder was awaiting refurbishment at December 31, 2005. We believe only approximately 66% of the well servicing rig fleet of our two major competitors are active and available for work. Since 2003, we have obtained annual independent reviews and evaluations of substantially all of our assets, which confirmed the location and condition of these assets.

     Extensive Domestic Footprint in the Most Prolific Basins. Our operations are concentrated in the major United States onshore oil and gas producing regions in Texas, New Mexico, Oklahoma and Louisiana and the Rocky Mountain states. We operate in states that accounted for approximately 57% of the approximately 900,000 existing onshore oil and gas wells in the 48 contiguous states and approximately 77% of onshore oil production and 72% of onshore gas production in 2005. We believe that our operations are located in the most active U.S. well services markets, as we currently focus our operations on onshore domestic oil and gas production areas that include both the highest concentration of existing oil and gas production activities and the largest prospective acreage for new drilling activity. This extensive footprint allows us to offer our suite of services to more than 1,000 customers who are active in those areas and allows us to redeploy equipment between markets as activity shifts.

     Diversified Service Offering for Further Revenue Growth. We believe our range of well site services provides us a competitive advantage over smaller companies that typically offer fewer services. Our experience, equipment and network of 71 service locations position us to market our full range of well site services to our existing customers. By utilizing a wider range of our services, our customers can use fewer service providers, which enables them to reduce their administrative costs and simplify their logistics. Furthermore, offering a broader range of services allows us to capitalize on our existing customer base and management structure to grow within existing markets, generate more business from existing customers, and increase our operating profits as we spread our overhead costs over a larger revenue base.

     Decentralized Management with Strong Corporate Infrastructure. Our corporate group is responsible for maintaining a unified infrastructure to support our diversified operations through standardized financial and accounting, safety, environmental and maintenance processes and controls. Below our corporate level, we operate a decentralized operational organization in which our seven regional managers are responsible for their regional operations, including asset management, cost control, policy compliance and training and other aspects of quality control. With an average of over 28 years of industry experience, each regional manager has extensive knowledge of the customer base, job requirements and working conditions in each local market. Below our seven regional or product line managers, our 66 area managers are directly responsible for customer relationships, personnel management, accident prevention and equipment maintenance, the key drivers of our operating profitability. This management structure allows us to monitor operating performance on a daily basis, maintain financial, accounting and asset management controls, integrate acquisitions, prepare timely financial reports and manage contractual risk.

Our Business Strategy

     We intend to increase our shareholder value by pursuing the following strategies:

     Establish and Maintain Leadership Position in Core Operating Areas. We strive to establish and maintain market leadership positions within our core operating areas. To achieve this goal, we maintain close customer relationships, seek to expand the breadth of our services and offer high quality services and equipment that meet the

scope of customer specifications and requirements. In addition, our significant presence in our core operating areas facilitates employee retention and attraction, a key factor for success in our business. Our significant presence in our core operating areas also provides us with brand recognition that we intend to utilize in creating leading positions in new operating areas.

     Expand Within Our Regional Markets. We intend to continue strengthening our presence within our existing geographic footprint through internal growth and acquisitions of businesses with strong customer relationships, well-maintained equipment and experienced and skilled personnel. Our larger competitors have not actively pursued acquisitions of small to mid-size regional businesses or assets in recent years due to the small relative scale and financial impact of these potential acquisitions. In contrast, we have successfully pursued these types of acquisitions, which remain attractive to us and make a meaningful impact on our overall operations. We typically enter into new markets through the acquisition of businesses with strong management teams that will allow us to expand within these markets. Management of acquired companies often remain with us and retain key positions within our organization, which enhances our attractiveness as an acquisition partner. We have a record of successfully implementing this strategy, as demonstrated by our 2003 acquisitions of FESCO Holdings, Inc., PWI Inc. and New Force Energy Services, Inc., which expanded our exposure to the active drilling environment of the Rocky Mountain states, the active well services and drilling markets along the Gulf Coast and the pressure pumping business, respectively. Additionally, in December 2004 we expanded our presence along the Gulf Coast with the acquisition of three inland barges, two of which have been refurbished and were available for service in the second quarter of 2005.

     Develop Additional Service Offerings Within the Well Servicing Market. We intend to continue broadening the portfolio of services we provide to our clients by leveraging our well servicing infrastructure. A customer typically begins a new maintenance or workover project by securing access to a well servicing rig, which generally stays on site for the duration of the project. As a result, our rigs are often the first equipment to arrive at the well site and typically the last to leave, providing us the opportunity to offer our customers other complementary services. We believe the fragmented nature of the well servicing market creates an opportunity to sell more services to our core customers and to expand our total service offering within each of our markets. We have expanded our suite of services available to our customers and increased our opportunities to cross-sell new services to our core well servicing customers through recent acquisitions and internal growth. We expect to continue to develop or selectively acquire capabilities to provide additional services to expand and further strengthen our customer relationships.

     Pursue Growth Through Selective Capital Deployment. We intend to continue growing our business through selective acquisitions, continuing a newbuild program and/or upgrading our existing assets. Our capital investment decisions are determined by an analysis of the projected return on capital employed of each of those alternatives. Acquisitions are evaluated for “fit” with our area and regional operations management and are thoroughly reviewed by corporate level financial, equipment, safety and environmental specialists to ensure consideration is given to identified risks. We also evaluate the cost to acquire existing assets from a third party, the capital required to build new equipment and the point in the oil and gas commodity price cycle. Based on these factors, we make capital investment decisions that we believe will support our long-term growth strategy, and these decisions may involve a combination of asset acquisitions and the purchase of new equipment. In 2005, we completed eight separate acquisitions for an aggregate purchase price of $25.4 million, net of cash acquired, and took delivery of 31 new well servicing rigs.

General Industry Overview

     Demand for services offered by our industry is a function of our customers’ willingness to make capital expenditures to explore for, develop and produce hydrocarbons in the U.S., which in turn is affected by current and expected levels of oil and gas prices. The following industry statistics illustrate the growing spending dynamic in the U.S. oil and gas sector:

•

As oil and gas prices rebounded beginning in early 1999, total expenditures for all U.S. exploration and production activities (including offshore activities that we do not serve) increased to an estimated $56 billion in 2003 and $62 billion in 2004 and were expected to reach $66 billion in 2005, according to Oil & Gas Journal in April 2005.

•

A survey of 18 U.S. major integrated and 130 independent oil and gas companies by World Oil Magazine projected the U.S. drilling activity in 2006 to be skewed more towards independent players. Specifically, independent oil and gas companies, which represent over 90% of our revenues, are expected to drill almost 33% more wells in 2006 than in 2005, while the major integrated producers are expected to drill only 16% more wells over the same period. This trend is primarily driven by the increased acquisitions of proved oil and gas properties by independent producers. When these types of properties are acquired, purchasers typically intensify drilling, workover and well maintenance activities to accelerate production from the newly acquired reserves.

     Increased spending by oil and gas operators is generally driven by oil and gas prices. The table below sets forth average daily closing prices for the Cushing WTI Spot Oil Price and the Energy Information Agency average wellhead price for natural gas since 1999:

		Cushing WTI Spot				Average Wellhead Price
Period		Oil Price ($/bbl)				Natural Gas ($/mcf)
1/1/99 - 12/31/99		$	19.34			$	2.19
1/1/00 - 12/31/00			30.38				3.69
1/1/01 - 12/31/01			25.97				4.01
1/1/02 - 12/31/02			26.18				2.95
1/1/03 - 12/31/03			31.08				4.98
1/1/04 - 12/31/04			41.51				5.49
1/1/05 - 12/31/05			56.64				7.28

     Increased expenditures for exploration and production activities generally involve the deployment of more drilling and well servicing rigs, which often serves as an indicator of demand for our services. Rising oil and gas prices since early 1999 and the corresponding increase in onshore oil exploration and production spending have led to expanded drilling and well service activity, as the U.S. land-based drilling rig count increased approximately 36% from year-end 2002 to year-end 2003, 11% from year-end 2003 to year-end 2004, and 22% from year-end 2004 to year-end 2005. In addition, the U.S. land-based workover rig count increased approximately 13% from year-end 2002 to year-end 2003, 10% from year-end 2003 to year-end 2004, and 17% from year-end 2004 to year-end 2005, according to Baker Hughes.

     Exploration and production spending is generally categorized as either an operating expenditure or a capital expenditure. Activities designed to add hydrocarbon reserves are classified as capital expenditures, while those associated with maintaining or accelerating production are categorized as operating expenditures.

     Capital expenditure spending tends to be relatively sensitive to volatility in oil or gas prices because project decisions are tied to a return on investment spanning a number of years. As such, capital expenditure economics often require the use of commodity price forecasts which may prove inaccurate in the short amount of time required to plan and execute a capital expenditure project (such as the drilling of a deep well). When commodity prices are depressed for even a short period of time, capital expenditure projects are routinely deferred until prices return to an acceptable level.

     In contrast, both mandatory and discretionary operating expenditures are substantially more stable than exploration and drilling expenditures. Mandatory operating expenditure projects involve activities that cannot be avoided in the short term, such as regulatory compliance, safety, contractual obligations and projects to maintain the well and related infrastructure in operating condition (for example, repairs to a central tank battery, downhole pump, saltwater disposal system or gathering system). Discretionary operating expenditure projects may not be critical to the short-term viability of a lease or field but these projects are relatively insensitive to commodity price volatility. Discretionary operating expenditure work is evaluated according to a simple short-term payout criterion which is far less dependent on commodity price forecasts.

     Our business is influenced substantially by both operating and capital expenditures by oil and gas companies. Because existing oil and gas wells require ongoing spending to maintain production, expenditures by oil and gas companies for the maintenance of existing wells are relatively stable and predictable. In contrast, capital expenditures by oil and gas companies for exploration and drilling are more directly influenced by current and expected oil and gas prices and generally reflect the volatility of commodity prices.

Overview of Our Segments and Services

Well Servicing Segment

     Our well servicing segment encompasses a full range of services performed with a mobile well servicing rig, also commonly referred to as a workover rig, and ancillary equipment. Our rigs and personnel provide the means for hoisting equipment and tools into and out of the well bore, and our well servicing equipment and capabilities are essential to facilitate most other services performed on a well. Our well servicing segment services, which are performed to maintain and improve production throughout the productive life of an oil and gas well, include:

	•		maintenance work involving removal, repair and replacement of down-hole equipment and returning the well to production after these operations are completed;
	•		hoisting tools and equipment required by the operation into and out of the well, or removing equipment from the well bore, to facilitate specialized production enhancement and well repair operations performed by other oilfield service companies; and
	•		plugging and abandonment services when a well has reached the end of its productive life.

     Regardless of the type of work being performed on the well, our personnel and rigs are often the first to arrive at the well site and the last to leave. We generally charge our customers an hourly rate for these services, which rate varies based on a number of considerations including market conditions in each region, the type of rig and ancillary equipment required, and the necessary personnel.

     Our fleet included 323 well service rigs as of December 31, 2005, including 35 newbuilds since October 2004 and 46 rebuilds since the beginning of 2001. We operate from more than 70 facilities in Texas, Wyoming, Oklahoma, North Dakota, New Mexico, Louisiana, Colorado and Montana, most of which are used jointly for our business segments. Our rigs are mobile units that generally operate within a radius of approximately 75 to 100 miles from their respective bases. Prior to December 2004, our well servicing segment consisted entirely of land-based equipment. During December 2004, we acquired three inland barges, two of which are equipped with rigs, have been refurbished and were placed into service in the second quarter of 2005. Inland barges are used to service wells in shallow water marine environments, such as coastal marshes and bays.

     The following table sets forth the location, characteristics and number of the well servicing rigs that we operated at December 31, 2005. We categorize our rig fleet by the rated capacity of the mast, which indicates the maximum weight that the rig is capable of lifting. This capability is the limiting factor in our ability to provide services. These figures do not include 67 new well servicing rigs that we have contracted for delivery from January 2006 through December 2007 as part of a 102-rig newbuild commitment:

						Operating Division
		Rated				Permian				South				Ark-La-				Mid-				Northern				Southern
Rig Type		Capacity				Basin				Texas				Tex				Continent				Rockies				Rockies				Stacked				Total
Swab			N/A				3				1				8				4				0				0				0				16
Light Duty		<90 tons					6				2				0				24				2				0				3				37
Medium Duty		>90-<125 tons					91				33				17				38				15				14				1				209
Heavy Duty		³ 125 tons					27				3				6				5				6				3				2				52
24-Hour		³125 tons					1				4				0				0				0				0				0				5
Drilling Rigs		³125 tons					0				0				0				0				0				2				0				2
Inland Barge		³125 tons					0				0				2				0				0				0				0				2
Total							128				43				33				71				23				19				6				323

     Management currently estimates that there are approximately 3,500 onshore well servicing rigs currently in the U.S., owned by an estimated 125 contractors, and that the actual number that are actively marketed and operable without major capital expenditures may be as much as 20% lower than this estimate. Based on information from U.S. contractors reporting their utilization to Weatherford-AESC, there were 2,671 well servicing rigs working in December 2005. This figure represents a projected utilization rate of 90% for the available fleet that are operable without major capital expenditures.

     According to the Guiberson Well Service Rig Count, by 1982 substantial new rig construction increased the total well servicing rig fleet to a total of 8,063 well servicing rigs operating in the United States owned by a large number of small companies, several multi-regional contractors and a few large national contractors. The largest well servicing contractor at that time had less than 500 rigs, or less than 6% of the total number of operating rigs. Due to increased competition and lower day rates, the domestic well servicing fleet has declined substantially over the last 20 years and has experienced considerable consolidation that has affected companies of all sizes, including the consolidation of several larger regional companies. Specifically, the well servicing segment of our industry has consolidated from nine large competitors (with 50 or more well servicing rigs) ten years ago to four today. The excess capacity of rigs that has existed in the industry since the early 1980’s has also been reduced due to the lack of new rig construction, retirements due to mechanical problems, casualties, exports to foreign markets and, to some extent, cannibalization efforts by rig operators, wherein parts are stripped from idle rigs to outfit refurbishments on an active rig fleet.

     Based on the most recent publicly available information, our two largest competitors own a combined 2,047 rigs of which 1,346 are operated and 701 are stacked. These two competitors’ total rigs represent approximately 58% of the industry’s total fleet. We have the third-largest fleet with over 320 rigs, or over 10% of the overall available U.S. industry’s fleet. Due to the fragmented nature of the market, we believe only one company other than us and our two larger competitors owns more than 50 rigs (with a total of only 134 rigs) and a total of an estimated 120 companies own the approximately 900 estimated remaining well servicing rigs, or approximately 26% of the industry’s total fleet.

     Maintenance. Regular maintenance is generally required throughout the life of a well to sustain optimal levels of oil and gas production. We believe regular maintenance comprises the largest portion of our work in this business segment. We provide well service rigs, equipment and crews for these maintenance services. Maintenance services are often performed on a series of wells in proximity to each other. These services consist of routine mechanical repairs necessary to maintain production, such as repairing inoperable pumping equipment in an oil well or replacing defective tubing in a gas well, and removing debris such as sand and paraffin from the well. Other services include pulling the rods, tubing, pumps and other downhole equipment out of the well bore to identify and repair a production problem. These downhole equipment failures are typically caused by the repetitive pumping action of an oil well. Corrosion, water cut, grade of oil, sand production and other factors can also result in frequent failures of downhole equipment.

     The need for maintenance activity does not directly depend on the level of drilling activity, although it is somewhat impacted by short-term fluctuations in oil and gas prices. Demand for our maintenance services is affected by changes in the total number of producing oil and gas wells in our geographic service areas. Accordingly, maintenance services generally experience relatively stable demand.

     Our regular well maintenance services involve relatively low-cost, short-duration jobs which are part of normal well operating costs. Demand for well maintenance is driven primarily by the production requirements of the local oil or gas fields and, to a lesser degree, the actual prices received for oil and gas. Well operators cannot delay all maintenance work without a significant impact on production. Operators may, however, choose to temporarily shut in producing wells when oil or gas prices are too low to justify additional expenditures, including maintenance.

     Workover. In addition to periodic maintenance, producing oil and gas wells occasionally require major repairs or modifications called workovers, which are typically more complex and more time consuming than maintenance operations. Workover services include extensions of existing wells to drain new formations either through

perforating the well casing to expose additional productive zones not previously produced, deepening well bores to new zones or the drilling of lateral well bores to improve reservoir drainage patterns. Our workover rigs are also used to convert former producing wells to injection wells through which water or carbon dioxide is then pumped into the formation for enhanced oil recovery operations. Workovers also include major subsurface repairs such as repair or replacement of well casing, recovery or replacement of tubing and removal of foreign objects from the well bore. These extensive workover operations are normally performed by a workover rig with additional specialized auxiliary equipment, which may include rotary drilling equipment, mud pumps, mud tanks and fishing tools, depending upon the particular type of workover operation. Most of our well servicing rigs are designed to perform complex workover operations. A workover may require a few days to several weeks and generally requires additional auxiliary equipment. The demand for workover services is sensitive to oil and gas producers’ intermediate and long-term expectations for oil and gas prices. As oil and gas prices increase, the level of workover activity tends to increase as oil and gas producers seek to increase output by enhancing the efficiency of their wells.

     New Well Completion. New well completion services involve the preparation of newly drilled wells for production. The completion process may involve selectively perforating the well casing in the productive zones to allow oil or gas to flow into the well bore, stimulating and testing these zones and installing the production string and other downhole equipment. We provide well service rigs to assist in this completion process. Newly drilled wells are frequently completed by well servicing rigs to minimize the use of higher cost drilling rigs in the completion process. The completion process typically requires a few days to several weeks, depending on the nature and type of the completion, and generally requires additional auxiliary equipment. Accordingly, completion services require less well-to-well mobilization of equipment and generally provide higher operating margins than regular maintenance work. The demand for completion services is directly related to drilling activity levels, which are sensitive to expectations relating to and changes in oil and gas prices.

     Plugging and Abandonment. Well servicing rigs are also used in the process of permanently closing oil and gas wells no longer capable of producing in economic quantities. Plugging and abandonment work can be performed with a well servicing rig along with wireline and cementing equipment; however, this service is typically provided by companies that specialize in plugging and abandonment work. Many well operators bid this work on a “turnkey” basis, requiring the service company to perform the entire job, including the sale or disposal of equipment salvaged from the well as part of the compensation received, and complying with state regulatory requirements. Plugging and abandonment work can provide favorable operating margins and is less sensitive to oil and gas pricing than drilling and workover activity since well operators must plug a well in accordance with state regulations when it is no longer productive. We perform plugging and abandonment work throughout our core areas of operation in conjunction with equipment provided by other service companies.

Fluid Services Segment

     Our fluid services segment provides oilfield fluid supply, transportation and storage services. These services are required in most workover, drilling and completion projects and are routinely used in daily producing well operations. These services include:

	•		transportation of fluids used in drilling and workover operations and of salt water produced as a by-product of oil and gas production;
	•		sale and transportation of fresh and brine water used in drilling and workover activities;
	•		rental of portable frac tanks and test tanks used to store fluids on well sites; and
	•		operation of company-owned fresh water and brine source wells and of non-hazardous wastewater disposal wells.

     This segment utilizes our fleet of fluid services trucks and related assets, including specialized tank trucks, portable storage tanks, water wells, disposal facilities and related equipment. The following table sets forth the type, number and location of the fluid services equipment that we operated at December 31, 2005:

		Operating Division
		Northern				Permian				Ark-La-				South				Mid-
		Rockies				Basin				Tex				Texas				Continent				Total
Fluid Services Trucks			87				122				112				118				38				477
Salt Water Disposal Wells			—				12				10				9				8				39
Fresh/Brine Water Stations			—				28				—				3				1				32
Fluid Storage Tanks			219				265				422				248				71				1,225

     Requirements for minor or incidental fluid services are usually purchased on a “call out” basis and charged according to a published schedule of rates. Larger projects, such as servicing the requirements of a multi-well drilling program or frac program, generally involve a bidding process. We compete for services both on a call out basis and for multi-well contract projects.

     We provide a full array of fluid sales, transportation, storage and disposal services required on most workover, drilling and completion projects. Our breadth of capabilities in this business segment allows us to serve as a one-stop source for our customers. Many of our smaller competitors in this segment can provide some, but not all, of the equipment and services required by customers, requiring them to use several companies to meet their requirements and increasing their administrative burden.

     As in our well servicing segment, our fluid services segment has a base level of business volume related to the regular maintenance of oil and gas wells. Most oil and gas fields produce residual salt water in conjunction with oil or gas. Fluid service trucks pick up this fluid from tank batteries at the well site and transport it to a salt water disposal well for injection. This regular maintenance work must be performed if a well is to remain active. Transportation and disposal of produced water is considered a low value service by most operators, and it is difficult for us to command a premium over rates charged by our competition. Our ability to out perform competitors in this segment depends on our ability to achieve significant economies relating to logistics — specifically, proximity between areas where salt water is produced and our company owned disposal wells. Ownership of disposal wells eliminates the need to pay third parties a fee for disposal. We operate salt water disposal wells in most of our markets.

     Workover, drilling and completion activities also provide the opportunity for higher operating margins from tank rentals and fluid sales. Drilling and workover jobs typically require fresh or brine water for drilling mud or circulating fluid used during the job. Completion and workover procedures often also require large volumes of water for fracturing operations, a process of stimulating a well hydraulically to increase production. Spent mud and flowback fluids are required to be transported from the well site to an approved disposal facility.

     Competitors in the fluid services industry are mostly small, regionally focused companies. There are currently no companies that have a dominant position on a nationwide basis. The level of activity in the fluid services industry is comprised of a relatively stable demand for services related to the maintenance of producing wells and a highly variable demand for services used in the drilling and completion of new wells. As a result, the level of onshore drilling activity significantly affects the level of activity in the fluid services industry. While there are no industry-wide statistics, the Baker Hughes Land Drilling Rig Count is an indirect indication of demand for fluid services because it directly reflects the level of onshore drilling activity.

     Fluid Services and Support Trucks. We currently own and operate over 475 fluid service tank trucks equipped with a fluid hauling capacity of up to 150 barrels. Each fluid service truck is equipped to pump fluids from or into wells, pits, tanks and other storage facilities. The majority of our fluid service trucks are also used to transport water to fill frac tanks on well locations, including frac tanks provided by us and others, to transport produced salt water to disposal wells, including injection wells owned and operated by us, and to transport drilling and completion fluids to and from well locations. In conjunction with the rental of our frac tanks, we generally use our fluid service trucks to transport water for use in fracturing operations. Following completion of fracturing operations, our fluid service trucks are used to transport the flowback produced as a result of the fracturing operations from the well site to disposal wells. Fluid services trucks are generally provided to oilfield operators within a 50-mile radius of our nearest yard. Our “hot oil” trucks are used to remove paraffin, a by-product of oil production in many fields, from the well bore. If paraffin is

left untreated, it can inhibit a well’s production. Our support trucks are used to move our fluid storage tanks and other equipment to and from the job sites of our customers.

     Salt Water Disposal Well Services. We own disposal wells that are permitted to dispose of salt water and incidental non-hazardous oil and gas wastes. Our transport trucks frequently transport fluids that are disposed of in these salt water disposal wells. The disposal wells have injection capacities ranging up to 3,500 barrels per day. Our salt water disposal wells are strategically located in close proximity to our customers’ producing wells. Most oil and gas wells produce varying amounts of salt water throughout their productive lives. In the states in which we generate oil and gas wastes and salt water produced from oil and gas wells are required by law to be disposed of in authorized facilities, including permitted salt water disposal wells. Injection wells are licensed by state authorities and are completed in permeable formations below the fresh water table. We maintain separators at most of our disposal wells permitting us to salvage residual crude oil, which is later sold for our account.

     Fresh and Brine Water Stations. Our network of fresh and brine water stations, particularly, in the Permian Basin, where surface water is generally not available, are used to supply water necessary for the drilling and completion of oil and gas wells. Our strategic locations, in combination with our other fluid handling services, give us a competitive advantage over other service providers in those areas in which these other companies cannot provide these services. These locations also allows us to expand our customer base.

     Fluid Storage Tanks. Our fluid storage tanks can store up to 500 barrels of fluid and are used by oilfield operators to store various fluids at the well site, including water, brine, drilling mud and acid for frac jobs, flowback, temporary production and mud storage. We transport the tanks on our trucks to well locations that are usually within a 50-mile radius of our nearest yard. Frac tanks are used during all phases of the life of a producing well. We generally rent fluid services tanks at daily rates for a minimum of three days. A typical fracturing operation can be completed within four days using 10 to 40 frac tanks.

Drilling and Completion Services Segment

     Our drilling and completion services segment provides oil and gas operators with a package of services that include the following:

	•		niche pressure pumping, such as cementing, acidizing, fracturing, coiled tubing and pressure testing;
	•		cased-hole wireline services; and
	•		underbalanced drilling in low pressure and fluid sensitive reservoirs.

     This segment currently operates 56 pressure pumping units to conduct a variety of services designed to stimulate oil and gas production or to enable cement slurry to be placed in or circulated within a well. As of December 31, 2005, we also operated 25 air compressor packages, including foam circulation units, for underbalanced drilling and 12 wireline units for cased-hole measurement and pipe recovery services.

     Just as a well servicing rig is required to perform various operations over the life cycle of a well, there is a similar need for equipment capable of pumping fluids into the well under varying degrees of pressure. During the drilling and completion phase, the well bore is lined with large diameter steel pipe called casing. Casing is cemented into place by circulating slurry into the annulus created between the pipe and the rock wall of the well bore. The cement slurry is forced into the well by pressure pumping equipment located on the surface. Cementing services are also utilized over the life of a well to repair leaks in the casing, to close perforations that are no longer productive and ultimately to “plug” the well at the end of its productive life.

     A hydrocarbon reservoir is essentially an interval of rock that is saturated with oil and/or gas, usually in combination with water. Three primary factors determine the productivity of a well that intersects a hydrocarbon reservoir: porosity — the percentage of the reservoir volume represented by pore space in which the hydrocarbons reside, permeability — the natural propensity for the flow of hydrocarbons toward the well bore, and “skin” — the degree to which the portion of the reservoir in close proximity to the well bore has experienced reduced permeability

as a result of exposure to drilling fluids or other contaminants. Well productivity can be increased by artificially improving either permeability or skin through stimulation methods.

     Permeability can be increased through the use of fracturing methods. The reservoir is subjected to fluids pumped into it under high pressure. This pressure creates stress in the reservoir and causes the rock to fracture thereby creating additional channels through which hydrocarbons can flow. In most cases, sand or another form of proppant is pumped with the fluid as a means of holding open the newly created fractures.

     The most common means of reducing near-well bore damage, or skin, is the injection of a highly reactive solvent (such as hydrochloric acid) solution into the area where the hydrocarbons enter the well. This solution has the effect of dissolving contaminants which have accumulated and are restricting flow. This process is generically known as acidizing.

     As a well is drilled, long intervals of rock are left exposed and unprotected. In order to prevent the exposed rock from caving and to prevent fluids from entering or leaving the exposed sections, steel casing is lowered into the hole and cemented in place. Pressure pumping equipment is utilized to force a cement slurry into the area between the rock face and the casing, thereby securing it. After a well is drilled and completed, the casing may develop leaks as a result of abrasion from production tubing, exposure to corrosive elements or inadequate support from the original attempt to cement it in place. When a leak develops, it is necessary to place specialized equipment into the well and to pump cement in such a way as to seal the leak. Repairing leaks in this manner is known as “squeeze” cementing — a method that utilizes pressure pumping equipment.

     Our pressure pumping business focuses on single-truck, lower horsepower cementing, acidizing and fracturing services in niche markets. Major pressure pumping companies have deemphasized new well cementing and stimulation work in the shallow well markets and do not aggressively pursue the remedial work available in many of the deeper well markets.

     The following table sets forth the type, number and location of the drilling and completion services equipment that we operated at December 31, 2005:

		Operating Division
										Northern				Southern
		Ark-La-Tex				Mid-Continent				Rockies				Rockies				Total
Pressure Pumping Units			12				41				3				—				56
Coiled Tubing Units			—				3				—				—				3
Air/Foam Packages			—				—				—				25				25
Wireline Units			—				12				—				—				12

     Currently, there are only three pressure pumping companies that provide their services on a national basis. These three companies also control a majority of the activities in the U.S. market. For the most part, these companies have concentrated their assets in markets characterized by complex work with the potential for high profit margins. This has created an opportunity in the markets for pressure pumping services in mature areas with less complex requirements. We, along with a number of smaller, regional companies, have concentrated our efforts on these markets. One of our major well servicing competitors also participates in the pressure pumping business, but primarily outside our core areas of operations for pumping services.

     Like our fluid services business, the level of activity of our pressure pumping business is tied to drilling and workover activity. The bulk of pressure pumping work is associated with cementing casing in place as the well is drilled or pumping fluid that stimulates production from the well during the completion phase. Pressure pumping work is awarded based on a combination of price and expertise. More complex work is less sensitive to price and routine work is often awarded on the basis of price alone.

     Cased-hole wireline services typically utilize a single truck equipped with a spool of wireline that is used to lower and raise a variety of specialized tools in and out of a cased wellbore. These tools can be used to measure pressures and temperatures as well as the condition of the casing and the cement that holds the casing in place. Other applications for wireline tools include placing equipment in or retrieving equipment from the wellbore, or

perforating the casing and cutting off pipe that is stuck in the well so that the free section can be recovered. Electric wireline contains a conduit that allows signals to be transmitted to or from tools located in the well. A simpler form of wireline, slickline, lacks an electrical conduit and is used only to perform mechanical tasks such as setting or retrieving various tools. Wireline trucks are often used in place of a well servicing rig when there is no requirement to remove tubulars from the well in order to make repairs. Wireline trucks, like well servicing rigs, are utilized throughout the life of a well.

     Underbalanced drilling services, unlike pressure pumping and wireline services, are not utilized universally throughout oil and gas operations. Underbalanced drilling is a technique that involves maintaining the pressure in a well at or slightly below that of the surrounding formation using air, nitrogen, mist, foam or lightweight drilling fluids instead of conventional drilling fluid. Underbalanced drilling services are utilized in areas where conventional drilling fluids or stimulation techniques will severely damage the producing formation or in areas where drilling performance can be substantially improved with a lightened drilling fluid. In these cases, the drilling fluid is lightened to make the natural pressure of the formation greater than the hydrostatic pressure of the drilling fluid, thereby creating a situation where pressure is forcing fluid out of the formation (i.e., underbalanced) as opposed to into the formation (i.e., over balanced). The most common method of lightening drilling fluid is to mix it with air as the fluid is pumped into the well. By varying the volume of air pumped with the fluid, the net hydrostatic pressure can be adjusted to the desired level. In extreme cases, air alone can be used to circulate rock cuttings from the well.

     Since reservoir pressure depletes over time as a well is produced, it may be desirable to use underbalanced fluids in workover operations associated with an existing well. Our air compressors, pressure boosters, trailer-mounted foam units and associated equipment are used in a variety of drilling and workover applications involving lightened fluids. Due to its limited application, there is only one service company providing these services on a national basis. The rest of the market is serviced by small regional firms or rig contractors who supply the equipment as part of the rig package.

Well Site Construction Services Segment

     Our well site construction services segment employs an array of equipment and assets to provide services for the construction and maintenance of oil and gas production infrastructure. These services are primarily related to new drilling activities, although the same equipment is utilized to maintain oil and gas field infrastructure. Our well site construction services segment includes dirt work for the following services:

	•		preparation and maintenance of access roads;
	•		building of drilling locations;
	•		installation of small gathering lines and pipelines; and
	•		maintenance of production facilities.

     This segment utilizes a fleet of power units, including dozers, trenchers, motor graders, backhoes and other heavy equipment used in road construction. In addition, we own rock pits in some markets in our Rocky Mountain division to ensure a reliable source of rock to support our construction activities. We also own a substantial quantity of wooden mats in our Gulf Coast operations to support the well site construction requirements in that marshy environment. This range of services, coupled with our fluid service capabilities in the same markets, differentiates us from our more specialized competitors.

     Companies engaged in oilfield construction and maintenance services are typically privately owned and highly localized. There are currently no companies that provide these services on a nationwide basis. Our well site construction services in the Gulf Coast and the Rocky Mountain states have a significant presence in these markets. We believe that our existing infrastructure will allow us to expand these operations.

     Contracts for well site construction services are normally awarded by our customers on the basis of competitive bidding and may range in scope from several days to several months in duration.

Properties

     Our principal executive offices are currently located at 400 W. Illinois, Suite 800, Midland, Texas 79701. During 2005 we also purchased and are currently renovating a facility in Midland County, Texas to consolidate our corporate office and to expand our refurbishment capacities. We currently conduct our business from 71 area offices, 32 of which we own and 39 of which we lease. Each office typically includes a yard, administrative office and maintenance facility. Of our 71 area offices, 45 are located in Texas, five are in Wyoming, eight are in Oklahoma, three are in New Mexico, three are in Louisiana, three are in Colorado, two are in Montana and two are in North Dakota.

Customers

     We serve numerous major and independent oil and gas companies that are active in our core areas of operations. During 2005, we provided services to more than 1,000 customers, with our top five customers comprising only 16% of our revenues. The majority of our business is with independent oil and gas companies. While we believe we could redeploy equipment in the current market environment if we lost a single material customer, or a few of them, such loss could have an adverse effect on our business until the equipment is redeployed.

Operating Risks and Insurance

     Our operations are subject to hazards inherent in the oil and gas industry, such as accidents, blowouts, explosions, craterings, fires and oil spills, that can cause:

	•		personal injury or loss of life;
	•		damage or destruction of property, equipment and the environment; and
	•		suspension of operations.

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

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

     Despite our efforts to maintain high safety standards, we 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 relationships with customers, employees and regulatory agencies. Any significant increase in the frequency or severity of these incidents, or the general level of compensation awards, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations.

     Although we maintain insurance coverage of types and amounts that we believe to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of the high premium costs. We do maintain employer’s liability, pollution, cargo, umbrella, comprehensive commercial general liability, workers’ compensation and limited physical damage insurance. There can be no assurance, however, that any insurance obtained by us will be adequate to cover any losses or liabilities, or that this insurance will continue to be available or available on terms which are acceptable to us. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on us.

Competition

     Our competition includes small regional contractors as well as larger companies with international operations. Our two largest competitors, Key Energy Services, Inc. and Nabors Well Services Co., combined own approximately 59% of the U.S. total well servicing rigs. Both of these competitors are public companies or subsidiaries of public companies that operate in most of the large oil and gas producing regions in the U.S. These competitors have centralized management teams that direct their operations and decision-making primarily from corporate and regional headquarters. In addition, because of their size, these companies market a large portion of their work to the major oil and gas companies.

     We differentiate ourselves from our major competition by our operating philosophy. We operate a decentralized organization, where local management teams are largely responsible for sales and marketing to develop stronger relationships with our customers at the field level. We target areas that are attractive to independent oil and gas operators who in our opinion tend to be more aggressive in spending, less focused on price and more likely to award work based on performance. With the major oil and gas companies divesting mature U.S. properties, we expect our target customers’ well population to grow over time through acquisition of properties formerly operated by major oil and gas companies. We concentrate on providing services to a diverse group of large and small independent oil and gas companies. These independents typically are relationship driven, make decisions at the local level and are willing to pay higher rates for services. We have been successful using this business model and believe it will enable us to continue to grow our business and maintain or expand our operating margins.

Safety Program

     Our business involves the operation of heavy and powerful equipment which can result in serious injuries to our employees and third parties and substantial damage to property. We have comprehensive safety and training programs designed to minimize accidents in the work place and improve the efficiency of our operations. In addition, many of our larger customers now place greater emphasis on safety and quality management programs of their 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, we believe many competitors, and particularly smaller contractors, have not undertaken similar training programs for their employees.

     We believe our approach to safety management is consistent with our decentralized management structure. Company-mandated policies and procedures provide the overall framework to ensure our operations minimize the hazards inherent in our work and are intended to meet regulatory requirements, while allowing our operations to satisfy customer-mandated policies and local needs and practices.

Environmental Regulation

     Our well site servicing operations are subject to stringent federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, commonly referred to as the “EPA”, issue regulations to implement and enforce these laws, which often require difficult and costly compliance measures. Failure to comply with these laws and regulations may result in the assessment of substantial administrative, civil and criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities. In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of that person. Strict adherence with these regulatory requirements increases our cost of doing business and consequently affects our profitability. We believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a materially adverse effect upon our capital expenditures, earnings or our competitive position.

     The Comprehensive Environmental Response, Compensation and Liability Act, referred to as “CERCLA” or the Superfund law, and comparable state laws impose liability, without regard to fault 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 or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of 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 investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the costs of some health studies. In addition, companies that incur liability frequently confront additional claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

     The federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, 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 gas from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies as non-hazardous wastes as long as these wastes are not commingled with regulated hazardous wastes. Moreover, in the ordinary course of our operations, industrial wastes such as paint wastes and waste solvents as well as wastes generated in the course of us 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 have been used for many years as service yards in support of oil and natural gas exploration and production activities. Although we have utilized operating and disposal practices that were standard in the industry at the time, there is the possibility that repair and maintenance activities on rigs and equipment stored in these service yards, as well as well bore fluids stored at these yards, may have resulted in the disposal or release of hydrocarbons or other wastes on or under these yards or other locations where these wastes have been taken for disposal. In addition, we own or lease properties that in the past were operated by third parties whose operations were not under our control. These properties and the hydrocarbons or wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination. We believe that we are in substantial compliance with the requirements of CERCLA and RCRA.

     Our operations are also subject to the federal Clean Water Act and analogous state laws. Under the Clean Water Act, the Environmental Protection Agency has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, or seek coverage under a general permit. Some of our properties may require permits for discharges of storm water runoff and, as part of our overall evaluation of our current operations, we are applying for stormwater discharge permit coverage and updating stormwater discharge management practices at some of our facilities. We believe that we will be able to obtain, or be included under, these permits, where necessary, and make minor modifications to existing facilities and operations that would not have a material effect on us.

     The federal Clean Water Act and the federal Oil Pollution Act of 1990, which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States, require some owners or operators of facilities that store or otherwise handle oil to prepare and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans”, relating to the possible discharge of oil into surface waters. In the course of our ongoing operations, we are in the process of updating SPCC plans for several of our facilities and currently expect to complete and implement these plans by the end of 2005. We believe we are in substantial compliance with these regulations.

     Our underground injection operations are subject to the federal Safe Drinking Water Act, as well as analogous state and local laws and regulations. Under Part C of the Safe Drinking Water Act, the EPA established the Underground Injection Control program, which established the minimum program requirements for state and local programs regulating underground injection activities. The Underground Injection Control program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. The substantial majority of our saltwater disposal wells are located in the State of Texas and regulated by the Texas Railroad Commission, also known as the “RRC”. We also operate salt water disposal wells in Oklahoma and

Wyoming and are subject to similar regulatory controls in those states. Regulations in these states require us to obtain a permit from the applicable regulatory agencies to operate each of our underground injection wells. We believe that we have obtained the necessary permits from these agencies for each of our underground injection wells and that we are in substantial compliance with permit conditions and commission rules. Nevertheless, these regulatory agencies have the general authority to suspend or modify one or more of these permits if continued operation of one of our underground injection wells is likely to result in pollution of freshwater, substantial violation of permit conditions or applicable rules, or leaks to the environment. Although we monitor the injection process of our wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third parties for property damages and personal injuries. In addition, our sales of residual crude oil collected as part of the saltwater injection process could impose liability on us in the event that the entity to which the oil was transferred fails to manage the residual crude oil in accordance with applicable environmental health and safety laws.

     We maintain insurance against some risks associated with underground contamination that may occur as a result of well service activities. However, this insurance is limited to activities at the wellsite and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.

     We are also subject to the requirements of the federal Occupational Safety and Health Act (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 the public. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

Employees

     As of December 31, 2005, we employed approximately 3,280 people, with approximately 85% employed on an hourly basis. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements, and we consider our relations with our employees to be satisfactory.

ITEM 1A. RISK FACTORS

     The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, results of operation, financial condition and prospects.

Risks Relating to Our Business

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

     The demand for our services is primarily determined by current and anticipated oil and gas prices and the related general production spending and level of drilling activity in the areas in which we have operations. Volatility or weakness in oil and gas prices (or the perception that oil and gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower production spending on existing wells. This, in turn, could result in lower demand for our services and may cause lower rates and lower utilization of our well service equipment. A decline in oil and gas prices or a reduction in drilling activities could materially and adversely affect the demand for our services and our results of operations.

     Prices for oil and gas historically have been extremely volatile and are expected to continue to be volatile. For example, although oil and natural gas prices have recently hit record prices exceeding $60 per barrel and $14.00 per mcf, respectively, oil and natural gas prices fell below $11 per barrel and $2 per mcf, respectively, in early 1999. The Cushing WTI Spot Oil Price averaged $31.08, $41.51 and $56.64 per barrel in 2003, 2004 and 2005, respectively, and the average wellhead price for natural gas, as recorded by the Energy Information Agency, was $4.98, $5.49 and $7.28 per mcf for 2003, 2004 and 2005, respectively. Commodity prices have increased significantly in recent years, and these prices may not remain at current levels.

Our business depends on domestic spending by the oil and 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 gas in the United States. Customers’ expectations for lower market prices for oil and gas may curtail spending thereby reducing demand for our services and equipment.

     Industry conditions are influenced by numerous factors over which we have no control, such as the supply of and demand for oil and gas, domestic and worldwide economic conditions, political instability in oil and gas producing countries and merger and divestiture activity among oil and gas producers. The volatility of the oil and 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 gas reserves in our market areas also may have a negative long-term impact on our business, even in an environment of stronger oil and gas prices, to the extent existing production is not replaced and the number of producing wells for us to service declines.

We may not be able to grow successfully through future acquisitions or successfully manage future growth, and we may not be able to effectively integrate the businesses we do acquire.

     Our business strategy includes growth through the acquisitions of other businesses. We may not be able to continue to identify attractive acquisition opportunities or successfully acquire identified targets. In addition, we may not be successful in integrating our current or future acquisitions into our existing operations, which may result in unforeseen operational difficulties or diminished financial performance or require a disproportionate amount of our management’s attention. Even if we are successful in integrating our current or future 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. 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 existing credit agreement to fund future acquisitions.

Our auditors have previously identified material weaknesses in our internal controls, and if we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, investors could lose confidence in our financial reporting, which would harm our business and the trading price of our common stock.

     Effective internal controls, including internal control over financial reporting and disclosure controls and procedures, are necessary for us to provide reliable financial reports and effectively prevent fraud and to operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results could be materially harmed. We have in the past discovered, and may in the future discover, areas of our internal controls that need improvement.

     In July 2004, our independent auditors advised our board of directors that they had identified material weaknesses in our internal controls in connection with the audit of our 2003 consolidated financial statements. The material weaknesses noted consisted of an inadequacy of our procedures or errors regarding account reconciliations not being performed timely or properly; formal procedures for establishing certain accounting assumptions, estimates and/or conclusions; and recording of certain expenses in the incorrect period. Our auditors also noted certain other items specific to our operations that they did not consider to be material weaknesses.

     To improve our financial accounting organization and processes, we have established an internal audit department and have added new personnel and positions in our accounting and finance organization. We also implemented a new accounting software system throughout our operations during the third quarter of 2004 and adopted additional policies and procedures to address the items noted by our auditors and generally to strengthen our financial reporting system. We believe that as of December 31, 2005, we have remediated the material weaknesses previously identified. However, the process of designing and implementing an effective financial reporting system is a continuous effort that requires us to anticipate and react to changes in our business and the economic and regulatory environments and to expend significant resources to maintain a financial reporting system that is adequate to satisfy our reporting obligations.

     We have had only limited operating experience with the improvements we have made to date. We may not be able to implement and maintain adequate controls over our financial processes and reporting in the future, which may require us to restate our financial statements in the future. In addition, we may discover additional past, ongoing or future weaknesses or significant deficiencies in our financial reporting system in the future. Any failure to implement required new or improved controls, or difficulties encountered in their implementation, could cause us to fail to meet our reporting obligations or result in material misstatements in our financial statements. Any such failure also could adversely affect the results of the periodic management evaluations and annual auditor attestation reports regarding the effectiveness of our “internal control over financial reporting” that will be required when the SEC’s rules under Section 404 of the Sarbanes Oxley Act of 2002 become applicable to us beginning with our Annual Report on Form 10-K for the year ending December 31, 2006 to be filed in the first quarter of 2007. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could result in a lower trading price of our common stock.

We may require additional capital in the future, which may not be available to us.

     Our business is capital intensive, requiring specialized equipment to provide our services. We may need to raise additional funds through public or private debt or equity financings. Adequate funds may not be available when needed or may not be available on favorable terms. If we raise additional funds by issuing equity securities, dilution to existing stockholders may result. If funding is insufficient at any time in the future, we may be unable to fund maintenance requirements, acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could harm our business.

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

     The well services industry is highly competitive and fragmented and includes numerous small companies capable of competing effectively in our markets on a local basis as well as several large companies that possess substantially greater financial and other resources than we do. Our larger competitors’ greater resources could allow those competitors to compete more effectively than we can. The amount of equipment available may exceed demand, which could result in active price competition. Many contracts are awarded on a bid basis, which may further increase competition based primarily on price. In addition, recent market conditions have stimulated the reactivation of well servicing rigs and construction of new equipment, which could result in excess equipment and lower utilization rates in future periods.

We depend on several significant customers, and a loss of one or more significant customers could adversely affect our results of operations.

     Our customers consist primarily of major and independent oil and gas companies. During 2005 and 2004, our top five customers accounted for 15.9% and 20.7%, respectively, of our revenues. The loss of any one of our largest customers or a sustained decrease in demand by any of such customers could result in a substantial loss of revenues and could have a material adverse effect on our results of operations.

We are dependent on particular suppliers for our newbuild rig program and are vulnerable to delayed deliveries and future price increases.

     We currently purchase our well servicing rigs from a single supplier as part of a 102-rig commitment for rigs to be delivered through the end of December 2007, of which 35 rigs have been delivered as of December 31, 2005. There are also a limited number of suppliers that manufacture this type of equipment. Although pricing is generally fixed for this newbuild contract and program, future price increases could affect our ability to continue to increase the number of newbuild rigs in our fleet at economic levels. In addition, the failure of our current supplier to timely deliver the newbuild rigs could adversely affect our budgeted or projected financial and operational data.

Our industry has experienced a high rate of employee turnover. Any difficulty we experience replacing or adding personnel could adversely affect our business.

     We may not be able to find enough skilled labor to meet our needs, which could limit our growth. Our business activity historically decreases or increases with the price of oil and gas. We may have problems finding enough skilled and unskilled laborers in the future if the demand for our services increases. We have raised wage rates to attract workers from other fields and to retain or expand our current work force during the past year. If we are not able to increase our service rates sufficiently to compensate for wage rate increases, our operating results may be adversely affected.

     Other factors may also inhibit our ability to find enough workers to meet our employment needs. Our services require skilled workers who can 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 and retain skilled technical personnel. Our inability to employ or retain skilled technical personnel generally could have a material adverse effect on our operations.

Our success depends on key members of our management, the loss of any of whom could disrupt our business operations.

     We depend to a large extent on the services of some of our executive officers. The loss of the services of Kenneth V. Huseman, our President and Chief Executive Officer, or other key personnel could disrupt our operations. Although we have entered into employment agreements with Mr. Huseman and our other executive officers that contain, among other provisions, non-compete agreements, we may not be able to enforce the non-compete provisions in the employment agreements. Also, we do not have key man life insurance on these officers other than coverage of $1 million for Mr. Huseman.

Our operations are subject to inherent risks, some of which are beyond our control. These risks may be self-insured, or may not be fully covered under our insurance policies.

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

	•		personal injury or loss of life;
	•		damage to or destruction of property, equipment and the environment; 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 gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in us being named as a defendant in lawsuits asserting large claims.

     We maintain insurance coverage that we believe to be customary in the industry against these hazards. However, we do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. We are also self-insured up to retention limits with regard to workers’ compensation and medical and dental coverage of our employees and, with certain exceptions, we generally maintain no physical property damage coverage on our workover rig fleet, with the exception of our 24-hour workover rigs and newly manufactured rigs. We have deductibles per occurrence for workers’ compensation and medical and dental coverage of $150,000 and $125,000, respectively. We have lower deductibles per occurrence for automobile liability and general liability. We maintain accruals in our consolidated balance sheets related to self-insurance retentions by using third-party data and historical claims history.

     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. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of these risks, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitive. It is likely that, in our insurance renewals, our premiums and deductibles will be higher, and certain insurance coverage either will be unavailable or considerably more expensive than it has been in the recent past. 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 regulation regarding issues of health, safety and protection of the environment. Under these regulations, we may become liable for penalties, damages or costs of remediation. Any changes in laws and government regulations could increase our costs of doing business.

     Our operations are subject to federal, state and local laws and regulations relating to protection of natural resources and the environment, health and safety, waste management, and transportation of waste and other materials. Our fluid services segment includes disposal operations into injection wells that pose some risks of environmental liability, including leakage from the wells to surface or subsurface soils, surface water or groundwater. Liability under these laws and regulations could result in cancellation of well operations, fines and penalties, expenditures for remediation, and liability for property damage and personal injuries. Sanctions for noncompliance with applicable environmental laws and regulations also may include assessment of administrative, civil and criminal penalties, revocation of permits and issuance of corrective action orders.

     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 gas and could limit well servicing opportunities. Some environmental laws and regulations may impose strict liability, which means that in some situations we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or 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 costs associated with changes in environmental 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 indebtedness could restrict our operations and make us more vulnerable to adverse economic conditions.

     We now have, and will continue to have, a significant amount of indebtedness. As of December 31, 2005, our total debt, the majority of which bears interest at variable rates, was $126.9 million, including the aggregate principal amount due under the term loan portion of our senior credit facility of $90.0 million, outstanding balance due under credit revolver of $16.0 million and capital lease obligations in the aggregate amount of $20.9 million. For the year ended December 31, 2005, we made cash interest payments totaling $11.6 million. The impact of a 1% increase in interest rates on this amount of debt would result in increased interest expense (excluding the effects of our interest rate hedges) of approximately $1.1 million annually, or a decrease in net income of approximately $687,000.

     Our current and future indebtedness could have important consequences to you. 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;
	•		make us more vulnerable to a downturn in our business, our industry or the economy in general as a substantial portion of our operating cash flow will be required to make principal and interest payments on our indebtedness, making it more difficult to react to changes in our business and in industry and market conditions;
	•		limit our ability to obtain additional financing that may be necessary to operate or expand our business;
	•		put us at a competitive disadvantage to competitors that have less debt; and
	•		increase our vulnerability to interest rate increases to the extent that we incur variable rate indebtedness.

     If we are unable to generate sufficient cash flow or are otherwise unable to obtain the funds required to make principal and interest payments on our indebtedness, or if we otherwise fail to comply with the various covenants in our senior credit facility or other instruments governing any future indebtedness, we could be in default under the terms of our senior credit facility or such instruments. In the event of a default, the holders of our indebtedness could elect to declare all the funds borrowed under those instruments to be due and payable together with accrued and unpaid interest, the lenders under our credit facilities could elect to terminate their commitments thereunder and we or one or more of our subsidiaries could be forced into bankruptcy or liquidation. Any of the foregoing consequences could restrict our ability to grow our business and cause the value of our common stock to decline.

Our existing credit facility imposes restrictions on us that may affect our ability to successfully operate our business.

			Our senior credit facility limits our ability to take various actions, such as:
	•		limitations on the incurrence of additional indebtedness;
	•		restrictions on mergers, sales or transfer of assets without the lenders’ consent; and
	•		limitation on dividends and distributions.

     In addition, our senior credit facility requires us to maintain certain financial ratios and to satisfy certain financial conditions, several of which become more restrictive over time and may require us to reduce our debt or take some other action in order to comply with them. These restrictions could also limit our ability to obtain future financings, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We also may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under our senior credit facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facilities — 2005 Credit Facility” for a discussion of our senior credit facility.

One of our directors may have a conflict of interest because he is also currently an affiliate, director or officer of a private equity firm that makes investments in the energy sector. The resolution of this conflict of interest may not be in our or our stockholders’ best interests.

     Steven A. Webster, the Chairman of our Board of Directors, is the Co-Managing Partner of Avista Capital Holdings, L.P., a private equity firm that makes investments in the energy sector. This relationship may create a conflict of interest because of his responsibilities to Avista and its owners. His duties as a partner in, or director or officer of, Avista or its affiliates may conflict with his duties as a director of our company regarding corporate

opportunities and other matters. The resolution of this conflict may not always be in our or our stockholders’ best interest.

Risks Relating to Our Relationship with DLJ Merchant Banking

DLJ Merchant Banking effectively controls the outcome of stockholder voting and may exercise this voting power in a manner adverse to our other stockholders.

     As of Janurary 26, 2006, DLJ Merchant Banking effectively owned approximately 47.4% of our outstanding common stock. Accordingly, DLJ Merchant Banking is in a position to effectively control the outcome of matters requiring a stockholder vote, including the election of directors, adoption of amendments to our certificate of incorporation or bylaws or approval of transactions involving a change of control. The interests of DLJ Merchant Banking may differ from those of our other stockholders, and DLJ Merchant Banking may vote its common stock in a manner that may adversely affect our other stockholders. Please read “Security Ownership of Certain Beneficial Owners and Management” for a discussion of DLJ Merchant Banking’s ownership interests in us and “Certain Relationships and Related Party Transactions — Transactions with DLJ Merchant Banking” for a description of DLJ Merchant Banking.

Risks Relating to Ownership of Our Common Stock

Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

     Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

	•		a classified board of directors, so that only approximately one-third of our directors are elected each year;
	•		limitations on the removal of directors;
	•		the prohibition of stockholder action by written consent; and
	•		limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.

     Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors.

Because we have no plans to pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us.

     We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that the board of directors deems relevant. The terms of our existing senior credit facility restrict the payment of dividends without the prior written consent of the lenders. Investors

must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our common stock.

ITEM 1B. UNRESOLVED STAFF COMMENTS

     None.

ITEM 3. LEGAL PROCEEDINGS

     On September 3, 2004, David Hudson, Jr. et al commenced a civil action against us in the District Court of Panola County, Texas, 123^rd Judicial District, David Hudson, Jr., et al v. Basic Energy Services Company, Cause No. 2004-A-137. The complaint alleges that our operation of a saltwater disposal well has contaminated both the groundwater and the soil in the surrounding area. The relief requested in the complaint is monetary damages, injunctive relief, environmental remediation and a court order requiring us to provide drinking water to the community. In response to the complaint, we have retained counsel and filed a general denial. We are in the beginning stages of discovery and settlement negotiations are underway. Should negotiations fail, we intend to defend ourselves vigorously in this action.

     On October 18, 2005, Clifford Golden et al. commenced a civil action against us in the 123rd Judicial District Court of Panola County, Texas, Clifford Golden et al. v. Basic Energy Services, LP. The factual basis for this complaint and relief are similar to the Hudson litigation, including claims that our operation of a saltwater disposal well has contaminated both the groundwater and the soil in the surrounding area. In addition, this complaint alleges a wrongful death and personal injuries to unspecified persons. In response to this complaint, we have retained counsel and intend to defend ourselves vigorously in this action.

     On December 6, 2004, Karon Smith, et al commenced a civil action against us in the District Court of Hidalgo County, Texas, 206th Judicial District, Karon Smith, et al v. Basic Energy Services GP L.L.C., Cause No. C-42767-04-D. The complaint alleged that (i) one of our fluid services truck drivers disposed of oil-based waste at the plaintiff’s waste disposal facility, which was not equipped to accept oil-based waste, and (ii) the disposal of such oil-based waste resulted in plaintiff’s facility losing contracts to accept waste. On July 25, 2005, the jury in this case returned a verdict in favor of the plaintiff and awarded damages in the amount of $1.2 million. Our insurance company denied coverage of liability in this lawsuit. In March 2006, we believe that we reached a settlement of this matter in connection with a mediation for $1.0 million, which we have accrued as of December 31, 2005. We are pursuing coverage claims with our insurer.

     We are subject to other claims in the ordinary course of business. However, we believe that the ultimate dispositions of the above mentioned and other current legal proceedings will not have a material adverse effect on our financial condition or results of operations.

     Neither Basic, nor any entity required to be consolidated with Basic for purposes of this annual report, has been required to pay a penalty to the Internal Revenue Service for failing to make disclosures required with respect to certain transactions that have been identified by the Internal Revenue Service as abusive or that have a significant tax avoidance.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     None.

Executive Officers and Other Key Employees

Our executive officers and other key employees as of December 31, 2005 and their respective ages and positions are as follows:

Name		Age				Position
Kenneth V. Huseman			54			President, Chief Executive Officer and Director
James J. Carter			60			Executive Vice President and Secretary
Alan Krenek			50			Vice President, Chief Financial Officer and Treasurer
Dub W. Harrison			47			Vice President — Equipment & Safety
Mark D. Rankin			52			Vice President — Business Development
James E. Tyner			55			Vice President — Human Resources
Charles W. Swift			56			Vice President — Permian Basin

Set forth below is the description of the backgrounds of our executive officers and other key employees.

Kenneth V. Huseman (President — Chief Executive Officer and Director) has 27 years of well servicing experience. He has been our President, Chief Executive Officer and Director since 1999. Prior to joining us, he was Chief Operating Officer at Key Energy Services from 1996 to 1999. At Key Energy Services, Mr. Huseman expanded the number of rigs from less than 200 to 1,400, the shallow drilling business from 4 to 78 rigs and executed over 50 acquisitions. He was a Divisional Vice President at WellTech, Inc., from 1993 to 1996 where he closed two acquisitions for a total of 42 rigs, moved WellTech from the second largest to the largest player in the market and started a turnaround of operations in Argentina. He was a Vice President of Operations at Pool Energy Services Co. from 1982 to 1993, where he managed operations throughout the United States, including drilling operations in Alaska. Mr. Huseman graduated with a B.B.A. degree in Accounting from Texas Tech University.

James J. Carter (Executive Vice President and Secretary) has spent 24 years in the well services industry. He has been our Executive Vice President since January 2005. He served as our Chief Financial Officer from December 2000 until January 2005. From 1999 to 2000, Mr. Carter worked in a consulting and brokerage capacity, with a well services industry specialization. He worked at another well servicing company in financial management from 1996 to 1999, where he managed the financial turnaround of its Argentina operations, negotiated and closed acquisitions in various domestic markets and negotiated insurance coverages and vehicle leases. He worked in financial management positions at Pool Energy Services Co. from 1978 to 1993, where he managed operations analysis and financial support at the corporate level and managed financial operations in California and south Texas. Mr. Carter graduated with a B.S. degree in Accounting from Indiana University and an M.B.A. from Memphis University.

Alan Krenek (Vice President, Chief Financial Officer and Treasurer) has 17 years of related industry experience. He has been our Vice President, Chief Financial Officer and Treasurer since January 2005. From October 2002 to January 2005, he served as Vice President and Controller of Fleetwood Retail Corp., a subsidiary in the manufactured housing division of Fleetwood Enterprises, Inc. From March 2002 to August 2002, he was a consultant involved in management, assessment of operational and financial internal controls, cost recovery and cash flow management. Mr. Krenek pursued personal interests from November 2001 to March 2002. From December 1999 to November 2001, he acted as the Vice President of Finance and later the Chief Financial Officer of Digital Commerce Corporation, a business-to-government internet-based marketplace solutions company that filed for Chapter 11 bankruptcy protection in June 2001. From January 1997 to December 1999, Mr. Krenek was the Vice President, Finance of Global TeleSystems, Inc. From September 1995 to December 1996, he served as Corporate Controller of Landmark Graphics Corporation where he was responsible for SEC reporting, general accounting, financial policies and procedures and purchasing functions. He worked in various financial management positions at Pool Energy Services Co. from 1980 to 1993 and at Noble Corporation from 1993 to 1995. Mr. Krenek graduated with a B.B.A. degree in Accounting from Texas A&M University in 1977 and is a certified public accountant.

Dub W. Harrison (Vice President — Equipment & Safety) has spent 29 years in the well services industry. He has been a Vice President since 1995, during which time he established operations in east Texas, negotiated an acquisition to enter the south Texas market and implemented a consistent maintenance program. From 1987 to 1995, he worked in operations and maintenance management at Pool Energy Services Co.

Mark D. Rankin (Vice President — Business Development) has 28 years of related industry experience. He has been a Vice President since 2004. From 1997 to 2004, he was a consultant to oil and gas companies and was involved in operations research and work process redesign. From 1985 to 1995, he acted as Director of International Marketing and Marketing for U.S. Operations and a District Manager at Pool Energy Services. He was an International Sales Manager and Director of Planning and Market Research at Zapata Off-Shore Company from 1979 to 1985. From 1977 to 1989, he was a Contract Manager at Western Oceanic, Inc. He graduated with a B.A. in Political Science from Texas A&M University.

James E. Tyner (Vice President — Human Resources) has been a Vice President since January 2004. From 1999 to December 2003, he was the General Manager of Human Resources at CMS Panhandle Companies, where he directed delivery of HR Services. Mr. Tyner was the Director of Human Resources Administration and Payroll Services at Duke Energy’s Gas Transmission Group from 1998 to 1999. From 1981 to 1998, Mr. Tyner held various positions at Panhandle Eastern Corporation. At Panhandle, he managed all Human Resources functions and developed corporate policies and as a Certified Safety Professional, he designed and implemented programs to control workplace hazards. Mr. Tyner received a B.S. and M.S. from Mississippi State University.

Charles W. Swift (Vice President — Permian) has 33 years of related industry experience including 25 years specifically in the domestic well service business. He has been a Vice President since 1997 and was involved in integrating several acquisitions during our expansion phase in late 1997. He was a co-owner of S&N Well Service from 1986 to 1997 and expanded the business to 17 rigs at the time of sale of the company to us. From 1980 to 1986, he worked at Pool Energy Services Co. where he managed the well service and fluid services businesses. Mr. Swift graduated with a B.B.A. degree in International Trade from Texas Tech University.

PART II

ITEM 5.  MARKET PRICE FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Price for Registrant’s Common Equity

     Our common stock has traded on the New York Stock Exchange under the symbol “BAS” since December 9, 2005. The table below presents the high and low daily closing sales prices of the common stock, as reported by the New York Stock Exchange, for the fourth quarter of 2005.

		High				Low
Three Months Ended
December 31, 2005.		$	22.00			$	19.20

     As of March 20, 2006, we had 33,706,703 shares of common stock outstanding held by approximately 42 record holders.

     We have not declared or paid any cash dividends on our common stock, and we do not currently anticipate paying any cash dividends on our common stock in the foreseeable future. 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 by our board. We are also currently restricted in our ability to pay dividends under our senior credit facility.

Securities Authorized for Issuance under Equity Compensation Plans

     The following table provides information regarding options or warrants authorized for issuance under our equity compensation plans as of December 31, 2005:

Number of

Number of

securities

securities to be

Weighted

remaining

issued upon

average exercise

available for

exercise of

price of

future issuance

outstanding

outstanding

under equity

Plan Category

options

options

compensation plans

Equity compensation plans approved by security holders(1)

2,445,800

$

5.44

1,727,950

Equity compensation plans not approved by security holders

—

—

—

Total

2,445,800

$

5.44

1,727,950

Recent Sales of Unregistered Securities

     During the past three years, we have issued unregistered securities to a limited number of persons, as described below. None of these transactions involved any underwriters or public offerings, and we believe that each of these transactions was exempt from registration requirements pursuant to Section 3(a)(9) or Section 4(2) of the Securities Act of 1933, as amended, Regulation D promulgated thereunder or Rule 701 of the Securities Act of 1933. The recipients of these securities represented their intention to acquire the securities for investment only and not with a view to or for sale in connection with any distribution thereof, and appropriate legends were affixed to the share certificates and instruments issued in these transactions. No remuneration or commission was paid or given directly or indirectly. The following information gives effect to a 5-for-1 stock split effected as a stock dividend on September 26, 2005:

     On January 24, 2003, we issued one share of our common stock in exchange for each share of then-outstanding common stock of our predecessor, Basic Energy Services, Inc., and shares of our Series A 10% Cumulative Preferred Stock in exchange for all of the then-outstanding shares of its Series A 10% Cumulative Preferred Stock, and assumed all of the outstanding warrants and options then outstanding by this predecessor.

     On May 5, 2003, we issued an aggregate of 771,740 shares of common stock upon the exercise of all of our EBITDA Contingent Warrants, which were issued during December 2000 and August 2001 to our prior stockholders and certain members of management for aggregate consideration of $1,543.48.

     On May 5, 2003, we granted options to purchase an aggregate of 605,000 shares of common stock under our Amended and Restated 2003 Incentive Plan to employees and directors at an exercise price of $4.00 per share. We received no payments from the optionees upon issuance of the options.

     On October 1, 2003, we granted options to purchase an aggregate of 37,500 shares of common stock under our 2003 Incentive Plan to a new director at an exercise price of $5.1584 per share. We received no payments from the optionee upon issuance of the options.

     On October 3, 2003, we issued an aggregate of 3,650,000 shares of common stock, including 730,000 shares of common stock issued into escrow, to the former stockholders of FESCO Holdings, Inc. as consideration for all of the outstanding shares of FESCO Holdings, Inc. The implied value per share in connection with the share exchange was $5.1584 per share.

     On October 3, 2003, we issued an aggregate of 3,304,085 shares of common stock in exchange for all of the outstanding shares of our Series A 10% Cumulative Preferred Stock and accrued dividends. The implied value per share in connection with the share exchange was $5.1584 per share.

     On February 23, 2004, our board of directors approved the issuance of 837,500 shares of restricted stock to our officers under our 2003 Incentive Plan. These shares, as issued effective April 22, 2004 after stockholder approval of our Amended and Restated 2003 Incentive Plan, are subject to vesting in one-fourth increments for all officers other than Mr. Carter on February 24, 2005, 2006, 2007 and 2008, and with respect to shares owned by Mr. Carter, vesting one-half on February 24, 2005 and 2006. We received no payments from the recipients upon the issuance of these shares.

     On March 1, 2004, we granted options to purchase an aggregate of 37,500 shares of common stock under our 2003 Incentive Plan to a new director at an exercise price of $5.1584 per share. We received no payments from the optionee upon issuance of the options.

     On March 23, 2004, we granted options to purchase an aggregate of 50,000 shares of common stock under our Amended and Restated 2003 Incentive Plan to employees at an exercise price of $5.1584. We received no payments from optionees upon issuance of the options.

     On January 26, 2005, we granted options to purchase an aggregate of 100,000 shares of common stock under our Amended and Restated 2003 Incentive Plan to a new executive officer at an exercise price of $5.1584. We received no payment from the optionee upon the issuance of the options.

     On March 2, 2005, we granted options to purchase an aggregate of 865,000 shares of common stock under our Amended and Restated 2003 Incentive Plan to employees at an exercise price of $6.98.

     On May 16, 2005, we granted options to purchase an aggregate of 5,000 shares of common stock under our Amended and Restated 2003 Incentive Plan to employees at an exercise price of $6.98.

     On December 16, 2005 we granted options to purchase an aggregate of 37,500 shares of common stock under our Amended and Restated 2003 Incentive Plan to a new director at an exercise price of $21.01.

Use of Proceeds from Registered Securities

     In connection with our initial public offering, we issued and sold 5,000,000 shares of our common stock, par value $0.01 per share, at $20.00 per share, generating aggregate offering proceeds of $100.0 million. Further, selling stockholders sold 9,375,000 shares of our common stock at $20.00 per share, generating aggregate offering proceeds to the selling stockholders of $187.5 million. The shares were issued pursuant to a registration statement on Form S-1 (File No. 333-127517) which was declared effective, as amended, on December 8, 2005. The registration statement registered an aggregate of 14,375,000 shares of common stock at an aggregate offering price of $287.5 million. Of these shares, 9,375,000 shares (representing $187.5 million of the dollar amount registered) were registered on behalf of selling stockholders (including 1,875,000 shares subject to an option granted to the underwriters to cover over-allotments, if any) and 5,000,000 shares (representing $100.0 million of the dollar amount registered) were registered on our behalf. The over-allotment option was exercised in full prior to the closing of the offering.

     The offering of the common stock commenced on December 8, 2005 and 14,375,000 of the registered shares were sold. The underwriters were led by Goldman, Sachs & Co. and Credit Suisse First Boston LLC. The net cash proceeds to us from the sale of these shares was $91.5 million, after deducting underwriting discounts and commissions of $6.5 million and total other offering costs and expenses of approximately $2.0 million (for a total of $8.5 million in offering expenses). The offering terminated after all the securities registered were sold.

     We have used our net proceeds from the initial public offering: (i) to repay $70.0 million of the term loan under our credit facility; (ii) to repurchase 135,326 shares of our common stock at the initial offering price, less underwriting discounts and commissions, from nine officers on the closing date of the initial public offering for an aggregate price of approximately $2.5 million; and (iii) for working capital and general corporate purposes, with respect to the remaining proceeds of approximately $19.0 million.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

     The following table summarizes stock repurchase activity for the three months ended December 31, 2005:

Issuer Purchases of Equity Securities
		Total				Average								Maximum number of
		number of				price				Total number of share				shares that may yet be
		shares				paid per				s purchased as part of				purchased under the
Period		purchased(1)				share				publicly announced plan				plan(2)
October 1 – October 31			—				—				—				—
November 1 – November 30			—				—				—				—
December 1 – December 31			135,326			$	18.70				135,326				78,656
Total			135,326			$	18.70				135,326				78,656

ITEM 6. SELECTED FINANCIAL DATA

     The following table sets forth our selected historical financial information for the periods shown. The following information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements included elsewhere in this report. The amounts for each historical annual period presented below were derived from our audited financial statements.

		Year Ended December 31,
		2001				2002				2003				2004				2005
		(dollars in thousands, except per share data)
Statement of Operations Data:
Revenues:
Well servicing		$	62,943			$	73,848			$	104,097			$	142,551			$	221,993
Fluid services			36,766				34,170				52,810				98,683				132,280
Drilling and completion services			—				733				14,808				29,341				59,832
Well site construction services			—				—				9,184				40,927				45,647
Total revenues			99,709				108,751				180,899				311,502				459,752
Expenses:
Well servicing			40,906				55,643				73,244				98,058				137,392
Fluid services			21,363				22,705				34,420				65,167				82,551
Drilling and completion services			—				512				9,363				17,481				30,900
Well site construction services			—				—				6,586				31,454				32,000
General and administration (a)			10,813				13,019				22,722				37,186				55,411
Depreciation and amortization			9,599				13,414				18,213				28,676				37,072
Loss (gain) on disposal of assets			(10	)			351				391				2,616				(222	)
Total expenses			82,671				105,644				164,939				280,638				375,104
Operating income			17,038				3,107				15,960				30,864				84,648
Other income (expense):
Net interest expense			(3,303	)			(4,750	)			(5,174	)			(9,550	)			(12,660	)
Gain (loss) on early extinguishment of debt			(1,462	)			—				(5,197	)			—				(627	)
Other income (expense)			16				31				146				(398	)			220
Income (loss) from continuing operations before income taxes			12,289				(1,612	)			5,735				20,916				71,581
Income tax (expense) benefit			(4,688	)			382				(2,772	)			(7,984	)			(26,800	)
Income (loss) from continuing operations			7,601				(1,230	)			2,963				12,932				44,781
Discontinued operations, net of tax			—				—				22				(71	)			—
Cumulative effect of accounting change, net of tax			—				—				(151	)			—				—
Net income (loss)			7,601				(1,230	)			2,834				12,861				44,781
Preferred stock dividend			—				(1,075	)			(1,525	)			—				—
Accretion of preferred stock discount			—				(374	)			(3,424	)			—				—
Net income (loss) available to common stockholders		$	7,601			$	(2,679	)		$	(2,115	)		$	12,861			$	44,781
Basic earnings (loss) per share of common stock:
Continuing operations less preferred stock dividend and accretion		$	0.50			$	(0.13	)		$	(0.09	)		$	0.46			$	1.57
Discontinued operations			—				—				—				—				—
Cumulative effect of accounting change			—				—				—				—				—
Net income (loss) available to common stockholders		$	0.50			$	(0.13	)		$	(0.09	)		$	0.46			$	1.57
Diluted earnings (loss) per share of common stock:
Continuing operations less preferred stock dividend and accretion		$	0.50			$	(0.13	)		$	(0.09	)		$	0.42			$	1.35
Discontinued operations			—				—				—				—				—
Cumulative effect of accounting change			—				—				—				—				—
Net income (loss) available to common stockholders		$	0.50			$	(0.13	)		$	(0.09	)		$	0.42			$	1.35
Statement of Cash Flow Data:
Cash flows from operating activities			14,060				17,012				29,815				46,539				99,189
Cash flows from investing activities			(60,305	)			(45,303	)			(84,903	)			(73,587	)			(107,679	)
Cash flows from financing activities			(50,770	)			21,572				79,859				21,498				21,188
Capital expenditures:
Acquistions, net of cash acquired			44,928				31,075				61,885				19,284				25,378
Property and equipment			12,208				14,674				23,501				55,674				83,095

		As of December 31,
		2001				2002				2003				2004				2005
		(dollars in thousands)
Balance Sheet Data:
Cash and cash equivalents		$	7,645			$	926			$	25,697			$	20,147			$	32,845
Property and equipment, net			78,602				108,487				188,243				233,451				309,075
Total assets			126,207				156,502				302,653				367,601				496,957
Long-term debt			45,258				39,706				142,116				170,915				119,241
Mandatorily redeemable cumulative preferred stock			—				12,093				—				—				—
Stockholders’ equity			58,938				72,558				107,295				121,786				258,575

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

Management’s Overview

     We provide a wide range of well site services to oil and gas drilling and producing companies, including well servicing, fluid services, drilling and completion services and well site construction services. Our results of operations since the beginning of 2002 reflect the impact of our acquisition strategy as a leading consolidator in the domestic land-based well services industry during this period. Our acquisitions have increased our breadth of service offerings at the well site and expanded our market presence. In implementing this strategy, we have purchased businesses and assets in 37 separate acquisitions from January 1, 2001 to December 31, 2005. Our weighted average number of well servicing rigs has increased from 126 in 2001 to 316 in the fourth quarter of 2005, and our weighted average number of fluid service trucks has increased from 156 to 472 in the same period. In 2003, primarily through acquisitions, we significantly increased our drilling and completion (principally pressure pumping) services and entered the well site construction services segment. These acquisitions make changes in revenues, expenses and income not directly comparable.

     Our operating revenues from each of our segments, and their relative percentages of our total revenues, consisted of the following (dollars in millions):

		Year Ended December 31,
		2003								2004								2005
Revenues:
Well servicing		$	104.1				58	%		$	142.6				46	%		$	222.0				48	%
Fluid services			52.8				29	%			98.7				32	%			132.3				29	%
Drilling and completion services			14.8				8	%			29.3				9	%			59.8				13	%
Well site construction services			9.2				5	%			40.9				13	%			45.7				10	%
Total revenues		$	180.9				100	%		$	311.5				100	%		$	459.8				100	%

     Our core businesses depend on our customers’ willingness to make expenditures to produce, develop and explore for oil and gas in the United States. Industry conditions are influenced by numerous factors, such as the supply of and demand for oil and gas, domestic and worldwide economic conditions, political instability in oil producing countries and merger and divestiture activity among oil and gas producers. The volatility of the oil and 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 volatility affects the demand for our services and the price of our services. In addition, the discovery rate of new oil and gas reserves in our market areas also may have an impact on our business, even in an environment of stronger oil and gas prices. For a more comprehensive discussion of our industry trends, see “Business — General Industry Overview.”

     We derive a majority of our revenues from services supporting production from existing oil and gas operations. Demand for these production-related services, including well servicing and fluid services, tends to remain relatively stable, even in moderate oil and gas price environments, as ongoing maintenance spending is required to sustain production. As oil and gas prices reach higher levels, demand for all of our services generally increases as our customers engage in more well servicing activities relating to existing wells to maintain or increase oil and gas production from those wells. Because our services are required to support drilling and workover activities, we are also subject to changes in capital spending by our customers as oil and gas prices increase or decrease.

     We believe that the most important performance measures for our lines of business are as follows:

	•		Well Servicing — rig hours, rig utilization rate, revenue per rig hour and segment profits as a percent of revenues;
	•		Fluid Services — revenue per truck and segment profits as a percent of revenues;

	•		Drilling and Completion Services — segment profits as a percent of revenues; and
	•		Well Site Construction Services — segment profits as a percent of revenues.

Segment profits are computed as segment operating revenues less direct operating costs. These measurements provide important information to us about the activity and profitability of our lines of business. For a detailed analysis of these indicators for our company, see below in “— Segment Overview.”

     We expect our business strategy will continue to include growth through selective acquisitions. Our continued rate of growth will depend on our ability to identify attractive acquisition opportunities and to acquire identified targets at commercially reasonable prices. We will also continue integrating current or future acquisitions into our existing operations. While we believe our costs of integration for prior acquisitions have been reflected in our historical results of operations, integration of acquisitions may result in unforeseen operational difficulties or require a disproportionate amount of our management’s attention. As discussed below in “— Liquidity and Capital Resources,” we also must meet certain financial covenants in order to borrow money under our existing credit agreement to fund future acquisitions.

Recent Strategic Acquisitions and Expansions

     During the period 2003 through 2005, we grew significantly through acquisitions and capital expenditures. During 2003, this growth was focused more on acquisitions of new lines of related business and of regional platforms for our existing businesses. During 2004 and 2005, we directed our focus for growth more on the integration and expansion of our existing businesses, through capital expenditures and to a lesser extent, acquisitions.

     We discuss the aggregate purchase prices and related financing issues below in “— Liquidity and Capital Resources” and present the historical financial statements of certain significant acquisitions in the historical financial statements included with this report.

Selected 2003 Acquisitions

     The following is a summary of our four largest acquisitions during 2003. These acquisitions are indicative of our strategic expansion into new lines of business.

     New Force Energy Services, Inc.

     On January 27, 2003, we completed the acquisition of the business and assets of New Force Energy Services, Inc., a pressure pumping services company in north central Texas. This acquisition added 31 pressure pumping units and associated support equipment and three new locations in north central Texas and increased the services offered in our Permian Basin, North Texas and Ark-La-Tex divisions. This transaction was structured as an asset purchase for a total purchase price of approximately $7.7 million in cash and up to an additional $2.7 million in future contingent earnest payments, of which $1.6 million had been earned as of December 31, 2005.

     FESCO Holdings, Inc./First Energy Services Company

     On October 3, 2003, we completed the acquisition of FESCO Holdings, Inc., which we refer to as FESCO, a fluid and well site construction services provider that operates through its subsidiary First Energy Services Company. FESCO’s operations are concentrated in Wyoming, Montana, North Dakota and Colorado and historically have been largely dependent on drilling activity in the Rocky Mountain states. This transaction extended our operating presence in the Rocky Mountain states, a region that we expect will experience increased levels of demand for well site and fluid services due to increased drilling activity. We have supplemented FESCO’s fluid services capabilities with our well servicing capabilities and equipment to provide additional service offerings in the Rocky Mountain states. The transaction was structured as a stock-for-stock merger for a total purchase price of approximately $37.9 million, including $19.1 million of assumed FESCO debt.

     PWI Inc.

     On October 3, 2003, we completed the acquisition of substantially all the operating assets of PWI Inc. and certain other affiliated entities, which we refer to as PWI, a provider of onshore oilfield fluid, equipment rental, and well site construction services. These services include fluid transportation and sales, disposal services, oilfield equipment rental, well site construction and lease maintenance work. Through eight locations, PWI operated primarily in southeast Texas and southwest Louisiana. The PWI acquisition substantially enhanced our existing onshore Gulf Coast well servicing operations by adding fluid services and well site construction services to this market. This acquisition provided us established operations in an active region and enables us to cross-sell additional services in the area. We acquired the assets of PWI for $25.1 million in cash and up to an additional $2.5 million in future contingent earn-out payments. The contingent earn-out agreement was terminated by the parties entering into an agreement to pay $75,000 per year for four years beginning in October 2005.

     Pennant Services Company

     On October 3, 2003, we completed the acquisition of substantially all of the operating assets of Pennant Services Company, a well servicing company with operations in Wyoming and Utah. This acquisition added 13 well servicing rigs and associated workover equipment to our fleet, which have been integrated with FESCO’s operations to expand the range of services and equipment that we offer to customers in the Rocky Mountain states. We acquired these assets for $7.4 million in cash.

Selected 2004 Acquisitions

     During 2004, we made a number of smaller acquisitions and capital expenditures that we anticipate will serve as a platform for future growth. These include:

     Energy Air Drilling

     On August 30, 2004, we completed the acquisition of Energy Air Drilling Service Company, an underbalanced drilling services company, with operations in Farmington, New Mexico, and Grand Junction, Colorado. This acquisition added 18 air drilling packages, four trailer-mounted foam units, and additional compressors and boosters. This acquisition provided a platform to expand into the Southern Rockies market area, while expanding our service offerings. The transaction was structured as a securities purchase for a total purchase price of approximately $6.5 million in cash.

     AWS Wireline Services

     On November 1, 2004, we completed the acquisition of substantially all of the operating assets of AWS Wireline Services, a cased-hole wireline company based in Albany, Texas. This acquisition of six wireline units was our initial entry into the wireline business. This service is complementary to our existing pressure pumping service organization infrastructure in this same market area. This transaction was structured as an asset purchase for a total purchase price of approximately $4.3 million in cash.

Selected 2005 Acquisitions

     During 2005, we made several acquisitions that complement our existing lines of business. These included, among others:

     MD Well Service, Inc.

     On May 17, 2005, we completed the acquisition of MD Well Service, Inc., a well servicing company operating in the Rocky Mountain region. This transaction was structured as an asset purchase for a total purchase price of $6.0 million.

     Oilwell Fracturing Services, Inc.

     On October 10, 2005, we completed the acquisition of Oilwell Fracturing Services, Inc., a pressure pumping services company that provides acidizing and fracturing services with operations in central Oklahoma. This acquisition will strengthen the presence of our drilling and completion services segment in our Mid Continent division. This transaction was structured as a stock purchase for a total purchase price of approximately $16.1 million. The assets acquired in the acquisition included approximately $2.3 million in cash. The cash used to acquire Oilwell Fracturing Services was primarily from borrowings under our senior credit facility.

Segment Overview

Well Servicing

     In 2005, our well servicing segment represented 48% of our revenues. Revenue in our well servicing segment is derived from maintenance, workover, completion and plugging and abandonment services. We provide maintenance-related services as part of the normal, periodic upkeep of producing oil and gas wells. Maintenance-related services represent a relatively consistent component of our business. Workover and completion services generate more revenue per hour than maintenance work due to the use of auxiliary equipment, but demand for workover and completion services fluctuates more with the overall activity level in the industry.

     We typically charge our customers for services on an hourly basis at rates that are determined by the type of service and equipment required, market conditions in the region in which the rig operates, the ancillary equipment provided on the rig and the necessary personnel. Depending on the type of job, we may also charge by the project or by the day. We measure our activity levels by the total number of hours worked by all of the rigs in our fleet. We monitor our fleet utilization levels, with full utilization deemed to be 55 hours per week per rig. Through acquisitions and individual equipment purchases, our fleet has more than tripled since the beginning of 2001.

     The following is an analysis of our well servicing operations for each of the quarters and years in the years ended December 31, 2003, 2004 and 2005:

		Weighted																Segment
		Average								Rig								Profits
		Number of				Rig				Utilization				Revenue Per				Per Rig				Segment
		Rigs				Hours				Rate				Rig Hour				Hour				Profits %
2003:
First Quarter			252				128,200				71.2	%		$	188			$	52				27.2	%
Second Quarter			252				131,000				72.7	%		$	195			$	62				31.8	%
Third Quarter			252				133,200				73.9	%		$	200			$	62				30.8	%
Fourth Quarter			270				131,500				68.1	%		$	211			$	59				28.6	%
Full Year			257				523,900				71.4	%		$	199			$	59				29.6	%
2004:
First Quarter			272				145,900				75.0	%		$	218			$	69				31.5	%
Second Quarter			276				154,600				78.4	%		$	222			$	69				31.1	%
Third Quarter			282				162,400				80.5	%		$	234			$	72				30.6	%
Fourth Quarter			284				155,900				76.8	%		$	246			$	78				31.7	%
Full Year			279				618,800				77.8	%		$	230			$	72				31.2	%
2005:
First Quarter			291				175,300				84.3	%		$	255			$	94				37.1	%
Second Quarter			303				192,400				88.8	%		$	280			$	107				38.2	%
Third Quarter			311				198,000				89.0	%		$	299			$	108				36.0	%
Fourth Quarter			316				195,000				86.3	%		$	329			$	134				40.7	%
Full Year			305				760,700				87.1	%		$	292			$	111				38.1	%

     We gauge activity levels in our well servicing segment based on rig utilization rate, revenue per rig hour and segment profits per rig hour.

     Improving market conditions since 2003 have created increased demand for our services. Rig hours have increased due to a combination of the improved utilization of our well servicing rigs and the expansion of our well servicing fleet as a result of our newbuild rig program.

     We have been able to increase our revenue per rig hour from $188 in the first quarter of 2003 to $329 in the fourth quarter of 2005 mainly as a result of this higher utilization, which has contributed to our improved segment profits.

Fluid Services

     In 2005, our fluid services segment represented 29% of our revenues. Revenues in our fluid services segment are earned from the sale, transportation, storage and disposal of fluids used in the drilling, production and maintenance of oil and gas wells. The fluid services segment has a base level of business consisting of transporting and disposing of salt water produced as a by-product of the production of oil and gas. These services are necessary for our customers and generally have a stable demand but typically produce lower relative segment profits than other parts of our fluid services segment. Fluid services for completion and workover projects typically require fresh or brine water for making drilling mud, circulating fluids or frac fluids used during a job, and all of these fluids require storage tanks and hauling and disposal. Because we can provide a full complement of fluid sales, trucking, storage and disposal required on most drilling and workover projects, the add-on services associated with drilling and workover activity enable us to generate higher segment profits contributions. The higher segment profits are due to the relatively small incremental labor costs associated with providing these services in addition to our base fluid services segment. We typically price fluid services by the job, by the hour or by the quantities sold, disposed of or hauled.

     The following is an analysis of our fluid services operations for each of the quarters and years in the years ended December 31, 2003, 2004 and 2005 (dollars in thousands):

										Segment
		Weighted								Profits
		Average								Per
		Number of				Revenue Per				Fluid
		Fluid Service				Fluid Service				Service				Segment
		Trucks				Truck				Truck				Profits %
2003:
First Quarter			202			$	51			$	16				32.4	%
Second Quarter			209			$	53			$	18				34.7	%
Third Quarter			223			$	50			$	18				35.3	%
Fourth Quarter			363			$	56			$	21				35.8	%
Full Year			249			$	212			$	74				34.8	%
2004:
First Quarter			371			$	60			$	21				34.5	%
Second Quarter			376			$	61			$	20				33.4	%
Third Quarter			386			$	67			$	23				33.7	%
Fourth Quarter			411			$	68			$	23				34.3	%
Full Year			386			$	256			$	87				34.0	%
2005:
First Quarter			435			$	67			$	24				34.3	%
Second Quarter			447			$	71			$	26				37.0	%
Third Quarter			465			$	74			$	28				38.6	%
Fourth Quarter			472			$	79			$	31				39.8	%
Full Year			455			$	291			$	109				37.6	%

     We gauge activity levels in our fluid services segment based on revenue and segment profits per fluid service truck.

     We substantially increased our fluid services truck fleet as the result of the PWI and FESCO acquisitions in the fourth quarter of 2003. Improved market conditions since 2003 have enabled us to further increase our fluid services truck fleet through internal expansion.

     The majority of the increase in revenue per fluid services truck from $51,000 in the first quarter of 2003 to $79,000 in the fourth quarter of 2005 is due to the revenues derived from the expansion of our frac tank fleet and disposal facilities as well as minor pricing improvement from our fluid services trucks. Our segment profits per fluid services truck have increased because of these factors and increased utilization of our equipment.

Drilling and Completion Services

     In 2005, our drilling and completion services segment represented 13% of our revenues. Revenues from our drilling and completion services segment are generally derived from a variety of services designed to stimulate oil and gas production or place cement slurry within the wellbores. Our drilling and completion services segment includes pressure pumping, cased-hole wireline services and underbalanced drilling.

     Our pressure pumping operations concentrate on providing single-truck, lower horsepower cementing, acidizing and fracturing services in selected markets. We entered the market for pressure pumping in East Texas during late 2002, and we expanded our presence with the acquisition of New Force in January 2003. We entered this market in the Rocky Mountain states with the acquisition of FESCO, which had a small cementing business based in Gillette, Wyoming. In December 2003, we acquired the assets of Graham Acidizing and integrated these assets into our New Force and Ark-La-Tex operations.

     We entered the wireline business in 2004 as part of our acquisition of AWS Wireline, a regional firm based in North Texas. We entered the underbalanced drilling services business in 2004 through our acquisition of Energy Air Drilling Services, a business operating in northwest New Mexico and the western slope of Colorado markets. For a description of our wireline and underbalanced drilling services, please read “Business — Overview of Our Segments and Services — Drilling and Completion Services Segment.”

     In this segment, we generally derive our revenues on a project-by-project basis in a competitive bidding process. Our bids are generally based on the amount and type of equipment and personnel required, with the materials consumed billed separately. During periods of decreased spending by oil and gas companies, we may be required to discount our rates to remain competitive, which would cause lower segment profits.

     The following is an analysis of our drilling and completion services for each of the quarters and years in the years ended December 31, 2003, 2004 and 2005 (dollars in thousands):

						Segment
		Revenues				Profits %
2003:
First Quarter		$	2,642				45.3	%
Second Quarter		$	3,454				32.7	%
Third Quarter		$	4,183				38.2	%
Fourth Quarter		$	4,529				33.6	%
Full Year		$	14,808				36.8	%
2004:
First Quarter		$	4,865				35.5	%
Second Quarter		$	7,251				46.0	%
Third Quarter		$	8,463				41.0	%
Fourth Quarter		$	8,762				38.0	%
Full Year		$	29,341				40.4	%

						Segment
		Revenues				Profits %
2005:
First Quarter		$	10,764				45.6	%
Second Quarter		$	13,512				49.1	%
Third Quarter		$	15,883				48.2	%
Fourth Quarter		$	19,673				49.5	%
Full Year		$	59,832				48.4	%

     We gauge the performance of our drilling and completion services segment based on the segment’s operating revenues and segment profits. Improved market conditions since 2003 have enabled us to increase our pricing for these services, contributing to the improved segment profits as a percentage of segment revenues.

Well Site Construction Services

     In 2005, our well site construction services segment represented 10% of our revenues. Revenues from our well site construction services segment are derived primarily from preparing and maintaining access roads and well locations, installing small diameter gathering lines and pipelines, constructing foundations to support drilling rigs and providing maintenance services for oil and gas facilities. These services are independent of our other services and, while offered to some customers utilizing other services, are not offered on a bundled basis. We entered the well site construction services segment during the fourth quarter of 2003 in the Gulf Coast through the acquisition of PWI and in the Rocky Mountain states through our acquisition of FESCO.

     Within this segment, we generally charge established hourly rates or competitive bid for projects depending on customer specifications and equipment and personnel requirements. This segment allows us to perform services to customers outside the oil and gas industry, since substantially all of our power units are general purpose construction equipment. However, the majority of our current business in this segment is with customers in the oil and gas industry. If our customer base has the demand for certain types of power units that we do not currently own, we generally purchase or lease them without significant delay.

     The following is an analysis of our well site construction services for the quarter ended December 31, 2003 (when we first entered this segment), each of the quarters and years in the years ended December 31, 2004 and 2005 (dollars in thousands):

						Segment
		Revenues				Profits %
2003:
Fourth Quarter		$	9,184				28.3	%
2004:
First Quarter		$	8,776				24.6	%
Second Quarter		$	9,869				21.3	%
Third Quarter		$	11,297				24.3	%
Fourth Quarter		$	10,985				22.4	%
Full Year		$	40,927				23.1	%
2005:
First Quarter		$	8,948				20.6	%
Second Quarter		$	10,918				30.8	%
Third Quarter		$	11,367				31.6	%
Fourth Quarter		$	14,414				33.6	%
Full Year		$	45,647				29.9	%

     We gauge the performance of our well site construction services segment based on the segment’s operating revenues and segment profits. While we monitor our levels of idle equipment, we do not focus on revenues per piece of equipment. To the extent we believe we have excess idle power units, we may be able to divest ourselves of certain types of power units.

Operating Cost Overview

     Our operating costs are comprised primarily of labor, including workers’ compensation and health insurance, repair and maintenance, fuel and insurance. A majority of our employees are paid on an hourly basis. With a reduced pool of workers in the industry, it is possible that we will have to raise wage rates to attract workers from other fields and retain or expand our current work force. We believe we will be able to increase service rates to our customers to compensate for wage rate increases. We also incur costs to employ personnel to sell and supervise our services and perform maintenance on our fleet. These costs are not directly tied to our level of business activity. Compensation for our administrative personnel in local operating yards and in our corporate office is accounted for as general and administrative expenses. Repair and maintenance is performed by our crews, company maintenance personnel and outside service providers. Insurance is generally a fixed cost regardless of utilization and relates to the number of rigs, trucks and other equipment in our fleet, employee payroll and safety record.

Critical Accounting Policies and Estimates

     Our consolidated financial statements are impacted by the accounting policies used and the estimates and assumptions made by management during their preparation. A complete summary of these policies is included in note 2 of the notes to our historical consolidated financial statements. The following is a discussion of our critical accounting policies and estimates.

     Critical Accounting Policies

     We have identified below accounting policies that are of particular importance in the presentation of our financial position, results of operations and cash flows and which require the application of significant judgment by management.

     Property and Equipment. Property and equipment are stated at cost, or at estimated fair value at acquisition date if acquired in a business combination. Expenditures for repairs and maintenance are charged to expense as incurred. We also review the capitalization of refurbishment of workover rigs as described in note 2 of the notes to our historical consolidated financial statements.

     Impairments. We review our assets for impairment at a minimum annually, or whenever, in management’s judgment, events or changes in circumstances indicate that the carrying amount of a long-lived asset may not be recovered over its remaining service life. Provisions for asset impairment are charged to income when the sum of the estimated future cash flows, on an undiscounted basis, is less than the assets’ carrying amount. When impairment is indicated, an impairment charge is recorded based on an estimate of future cash flows on a discounted basis.

     Self-Insured Risk Accruals. We are self-insured up to retention limits with regard to workers’ compensation and medical and dental coverage of our employees. We generally maintain no physical property damage coverage on our workover rig fleet, with the exception of certain of our 24-hour workover rigs and newly manufactured rigs. We have deductibles per occurrence for workers’ compensation and medical and dental coverage of $150,000 and $125,000 respectively. We have lower deductibles per occurrence for automobile liability and general liability. We maintain accruals in our consolidated balance sheets related to self-insurance retentions by using third-party data and historical claims history.

     Revenue Recognition. We recognize revenues when the services are performed, collection of the relevant receivables is probable, persuasive evidence of the arrangement exists and the price is fixed and determinable.

     Income Taxes. We account for income taxes based upon Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (“SFAS No. 109”). Under SFAS No. 109, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax

rate is recognized in the period that includes the statutory enactment date. A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized.

     Critical Accounting Estimates

     The preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make certain estimates and assumptions. 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 revenues and expenses recognized during the reporting period. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable under the circumstances. However, actual results could differ from such estimates. The following is a discussion of our critical accounting estimates.

     Depreciation and Amortization. In order to depreciate and amortize our property and equipment and our intangible assets with finite lives, we estimate the useful lives and salvage values of these items. Our estimates may be affected by such factors as changing market conditions, technological advances in industry or changes in regulations governing the industry.

     Impairment of Property and Equipment. Our impairment of property and equipment requires us to estimate undiscounted future cash flows. Actual impairment charges are recorded using an estimate of discounted future cash flows. The determination of future cash flows requires us to estimate rates and utilization in future periods and such estimates can change based on market conditions, technological advances in industry or changes in regulations governing the industry.

     Allowance for Doubtful Accounts. We estimate our allowance for doubtful accounts based on an analysis of historical collection activity and specific identification of overdue accounts. Factors that may affect this estimate include (1) changes in the financial positions of significant customers and (2) a decline in commodity prices that could affect the entire customer base.

     Litigation and Self-Insured Risk Reserves. We estimate our reserves related to litigation and self-insure risk based on the facts and circumstances specific to the litigation and self-insured risk claims and our past experience with similar claims. The actual outcome of litigated and insured claims could differ significantly from estimated amounts. As discussed in “— Self-Insured Risk Accruals” above with respect to our critical accounting policies, we maintain accruals on our balance sheet to cover self-insured retentions. These accruals are based on certain assumptions developed using third-party data and historical data to project future losses. Loss estimates in the calculation of these accruals are adjusted based upon actual claim settlements and reported claims.

     Fair Value of Assets Acquired and Liabilities Assumed. We estimate the fair value of assets acquired and liabilities assumed in business combinations, which involves the use of various assumptions. These estimates may be affected by such factors as changing market conditions, technological advances in industry or changes in regulations governing the industry. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair value of property and equipment, intangible assets and the resulting amount of goodwill, if any. Our adoption of SFAS No. 142 on January 1, 2002 requires us to test annually for impairment the goodwill and intangible assets with indefinite useful lives recorded in business combinations. This requires us to estimate the fair values of our own assets and liabilities at the reporting unit level. Therefore, considerable judgment, similar to that described above in connection with our estimation of the fair value of acquired company, is required to assess goodwill and certain intangible assets for impairment.

     Cash Flow Estimates. Our estimates of future cash flows are based on the most recent available market and operating data for the applicable asset or reporting unit at the time the estimate is made. Our cash flow estimates are used for asset impairment analyses.

     Stock-Based Compensation. We account for stock-based compensation using the intrinsic value method presented by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” However, in accordance with SFAS No. 148, “Accounting for Stock-Based Compensation,” an amendment to SFAS No. 123,

we must estimate the fair value of our outstanding stock-based compensation awards for disclosure purposes. In so doing, we use an option-pricing model (Black-Scholes-Merton), which requires various assumptions as to interest rates, volatility, dividend yields and expected lives of stock-based awards.

     The fair value of common stock for options granted from July 1, 2004 through September 30, 2005 was estimated by management using an internal valuation methodology. We did not obtain contemporaneous valuations by an unrelated valuation specialist because we were focused on internal growth and acquisitions and because we had consistently used our internal valuation methodology for previous stock awards.

     We used a market approach to estimate our enterprise value at the dates on which options were granted. Our market approach uses estimates of EBITDA and cash flows multiplied by relevant market multiples. We used market multiples of publicly traded energy service companies that were supplied by investment bankers in order to estimate our enterprise value. The assumptions underlying the estimates are consistent with our business plan. The risks associated with achieving our forecasts were assessed in the multiples we utilized. Had different multiples been utilized, the valuations would have been different.

     As disclosed in Note 2 to our December 31, 2005 financial statements, we granted stock options as follows for the twelve-month period ended December 31, 2005:

						Weighted				Weighted				Weighted
		Number of				Average Exercise				Average Fair				Average Intrinsic
Grants Made		Options Granted				Price				Value Per Share				Value Per Share
January 2005			100,000			$	5.16			$	9.63			$	4.47
March 2005			865,000			$	6.98			$	12.78			$	5.80
May 2005			5,000			$	6.98			$	15.48			$	8.50
December 2005			37,500			$	21.01			$	21.01			$	0.00

     The reasons for the differences between the fair value per share at the option grant date and the IPO price of $20.00 are as follows:

	•		During the three months ended March 31, 2005, we closed four acquisitions which added two well servicing rigs, 12 fluid hauling trucks/trailers, two salt water disposal wells and other equipment. Industry conditions also improved in the first quarter. As a result of this, our revenues exceeded the first quarter projected revenues by 12%. In addition, we placed an order for six new well servicing rigs which were delivered throughout the remainder of 2005.
	•		During the three months ended June 30, 2005, we closed two acquisitions which added six well servicing rigs and additional pressure pumping equipment. Demand for our equipment and services continued to strengthen during this quarter. Our well servicing rig revenue per hour increased by 10% from the first quarter of 2005. Based on the market outlook, we placed an order for an additional 24 new well servicing rigs, five of which were put into service later in 2005.
	•		We increased our projected EBITDA and cash flows for 2005 and 2006 due to the acquisitions and improved operating results.
	•		Market prices of publicly traded energy service companies have increased significantly from January 1, 2005 due to increases in demand caused by increasing commodity prices.

     Based on the IPO price of $20.00, the intrinsic value of the options granted in the last twelve months was $12.8 million, all of which related to unvested options. We have recorded deferred compensation related to these options of $5.5 million, which is being recorded to compensation expense over the service period.

     Income Taxes. The amount and availability of our loss carryforwards (and certain other tax attributes) are subject to a variety of interpretations and restrictive tests. The utilization of such carryforwards could be limited or lost upon certain changes in ownership and the passage of time. Accordingly, although we believe substantial loss

carryforwards are available to us, no assurance can be given concerning the realization of such loss carryforwards, or whether or not such loss carryforwards will be available in the future.

     Asset Retirement Obligations. SFAS No. 143 requires us to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets and to capitalize an equal amount as a cost of the asset, depreciating it over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each quarter to reflect the passage of time, changes in the estimated future cash flows underlying the obligation, acquisition or construction of assets, and settlement of obligations.

Results of Operations

     The results of operations between periods will not be comparable, primarily due to the significant number of acquisitions made and their relative timing in the year acquired. See note 3 of the notes to our historical consolidated financial statements for more detail.

Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

     Revenues. Revenues increased by 48% to $459.8 million in 2005 from $311.5 million in 2004. This increase was primarily due to the internal expansion of our business segments, particularly well servicing and fluid services. The pricing and utilization of our services improved due to the increase in well maintenance and drilling activity caused by higher oil and gas prices.

     Well servicing revenues increased by 56% to $222.0 million in 2005 compared to $142.6 million in 2004. The increase was due mainly to our internal growth of this segment as well as an increase in our revenue per rig hour of approximately 27%, from $230 per hour to $292 per hour. Our weighted average number of rigs increased to 305 in 2005 compared to 279 in 2004, an increase of approximately 9%. In addition, the utilization rate of our rig fleet increased to 87.1% in 2005 compared to 77.8% in 2004.

     Fluid services revenues increased by 34% to $132.3 million in 2005 compared to $98.7 million in 2004. This increase was primarily due to our internal growth of this segment. Our weighted average number of fluid service trucks increased to 455 in 2005 compared to 386 in 2004, an increase of approximately 18%. During 2005, our average revenue per fluid service truck was approximately $291,000 as compared to $256,000 in 2004. The increase in average revenue per fluid service truck reflects the expansion of our frac tank fleet and saltwater disposal operations, and minor increases in prices charged for our services.

     Drilling and completion services revenues increased by 104% to $59.8 million in 2005 as compared to $29.3 million in 2004. The increase in revenues between these periods was primarily the result of acquisitions, including our acquisition of wireline and underbalanced drilling businesses in 2004, increased rates for our services and internal growth.

     Well site construction services revenues increased 12% to $45.6 million in 2005 as compared to $40.9 million in 2004.

     Direct Operating Expenses. Direct operating expenses, which primarily consist of labor, including workers compensation and health insurance, and maintenance and repair costs, increased by 33% to $282.8 million in 2005 from $212.2 million in 2004 as a result of additional rigs and trucks, as well as higher utilization of our equipment. Direct operating expenses decreased to 62% of revenues for the period from 68% in 2004, as fixed operating costs such as field supervision, insurance and vehicle expenses were spread over a higher revenue base. We also benefited from higher utilization and increased pricing of our services.

     Direct operating expenses for the well servicing segment increased by 40% to $137.4 million in 2005 as compared to $98.1 million in 2004 due primarily to increased activity and increased labor costs for our crews. Segment profits increased to 38.1% of revenues in 2005 compared to 31.2% in 2004, due to improved pricing for our services and higher utilization of our equipment.

     Direct operating expenses for the fluid services segment increased by 27% to $82.6 million in 2005 as compared to $65.2 million in 2004 due primarily to increased activity and expansion of our fluid services fleet. Segment profits increased to 37.6% of revenues in 2005 compared to 34.0% in 2004.

     Direct operating expenses for the drilling and completion services segment increased by 77% to $30.9 million in 2005 as compared to $17.5 million in 2004 due primarily to increased activity and expansion of our services and equipment. Our segment profits increased to 48.4% of revenues in 2005 from 40.4% in 2004.

     Direct operating expenses for the well-site construction services segment increased by 2% to $32.0 million in 2005 as compared to $31.5 million in 2004. Segment profits for this segment increased to 29.9% of revenues in 2005 as compared to 23.1% for the same period in 2004.

     General and Administrative Expenses. General and administrative expenses increased by 49% to $55.4 million in 2005 from $37.2 million in 2004 which included $2.9 million and $1.6 million of stock-based compensation expense in 2005 and 2004, respectively. The increase primarily reflects higher salary and office expenses related to the expansion of our business.

     Depreciation and Amortization Expenses. Depreciation and amortization expenses were $37.1 million in 2005 and $28.7 million in 2004, reflecting the increase in the size of and investment in our asset base. We invested $25.4 million for acquisitions in 2005 and an additional $83.1 million for capital expenditures in 2005 (excluding capital leases).

     Interest Expense. Interest expense increased by 35% to $13.1 million in 2005 from $9.7 million in 2004. The increase was due to an increase in the amount of long-term debt during the period and higher interest rates. Both prime and LIBOR interest rates increased substantially in 2005, and both our revolver and term loan interest rates are tied directly to these rates.

     Income Tax Expense (Benefit). Income tax expense was $26.8 million in 2005 as compared to $8.0 million in 2004. Our effective tax rate in 2005 and 2004 was approximately 38%.

     Loss on Early Extinguishment of Debt. In December 2005, we entered into a Third Amended and Restated Credit Agreement. In connection with this, we recognized a loss on the early extinguishment of debt and wrote-off unamortized debt issuance costs of approximately $627,000.

     Net Income. Our net income increased to $44.8 million in 2005 from $12.9 million in 2004. This improvement was due primarily to the factors described above, including our increased asset base and related revenues, higher utilization rates and increased revenues per rig and fluid service truck, and higher operating margins on our drilling and completion services equipment.

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

     Revenues. Revenues increased 72% to $311.5 million in 2004 from $180.9 million in 2003. This increase was primarily due to major acquisitions that we made in the fourth quarter of 2003, increased oilfield service activity resulting from continued strong oil and gas prices, the purchase of additional revenue generating equipment and the higher utilization derived from the redeployment of equipment to take advantage of increasing activity in some of our markets. We operated a weighted average of 279 rigs in 2004 compared to 257 in 2003, and 386 fluid service trucks in 2004 compared to 249 in 2003, which also contributed to the increase.

     Well servicing revenues increased 37% to $142.6 million in 2004 compared to $104.1 million in 2003. Our full-fleet utilization rate was 77.8% and revenue per rig hour was $230 in 2004 compared to 71.4% and $199, respectively, for 2003. The higher rig utilization was due to the general increase in activity caused by continued higher oil and gas prices and more aggressive deployment of our fleet in areas of increasing activity. The increasing rate per hour reflects price increases implemented by us combined with a changing geographic mix of activity.

     Fluid services revenues increased 87% to $98.7 million in 2004 from $52.8 million in 2003. During 2004, our average revenues per fluid service truck totaled $256,000, versus average revenues of $212,000 per truck during the same period in 2003.

     Drilling and completion service revenues were $29.3 million during 2004 as compared to $14.8 million during 2003. Our significant entry into this segment occurred in late January 2003 with the acquisition of New Force and other acquisitions occurring during the fourth quarter of 2003. The increase in revenues between periods is primarily the result of the addition of equipment and an increase in rates due to higher utilization.

     Well site construction service revenues were $40.9 million in 2004, as compared to $9.2 million in 2003. We entered this segment in the fourth quarter of 2003 with our acquisition of FESCO and PWI. This service line has benefited from the increase in drilling activity, primarily in the Rocky Mountains.

     Direct Operating Expenses. Direct operating expenses, which primarily consist of labor and repair and maintenance, increased 72% to $212.2 million in 2004 from $123.6 million in 2003 as a result of operating additional rigs and trucks, as well as higher utilization of our equipment. Direct operating expenses as a percentage of revenues for 2004 remained virtually unchanged from the 68.0% in 2003, as fixed operating costs such as field supervision, insurance and vehicle expenses were spread over a higher revenue base, and this was offset by unit increases in fuel and steel. The addition of our construction services line also contributed to the static margin as this service line generates a lower margin than our other service lines.

     Direct operating expenses for the well servicing segment increased 34% to $98.1 million in 2004 as compared to $73.2 million in 2003 due to increased activity. Segment profits increased to 31.2% of revenues in 2004 compared to 29.6% during 2003, as higher activity levels and rate increases were able to offset cost increases for fuel and supplies.

     Direct operating expenses for the fluid services segment increased 89% to $65.2 million in 2004 from $34.4 million in 2003. Segment profits for the fluid services segment decreased to 34.0% in 2004 from 34.8% in 2003. This was the result of higher fuel and disposal costs, which were partially offset by an increase in drilling related activity.

     Direct operating expenses for the drilling and completion services segment were $17.5 million in 2004 as compared to $9.4 million in 2003, and the segment profits for this segment were 40.4% for 2004. Our significant entry into this segment occurred in late January 2003 with the acquisition of New Force and other acquisitions occurring throughout the remainder of 2003.

     Direct operating expenses for our well site construction services segment in 2004 were $31.5 million, and the segment profits for this segment were 23.1% for this period as compared to $6.6 million in direct operating expenses and segment profits of 28.3% for the same period in 2003. We entered this segment in October 2003, as previously discussed.

     General and Administrative Expenses. General and administrative expenses increased 63.7% to $37.2 million in 2004 from $22.7 million in 2003, which included $1.6 million and $1.0 million of stock-based compensation expense in 2004 and 2003, respectively. The increase primarily reflects higher salary and office expenses related to the expansion of our business into the Rocky Mountains and the Gulf Coast region in the fourth quarter of 2003, the addition of our North Texas pressure pumping business (in our drilling and completion segment), and additional administrative personnel to support new service locations and growth of the company.

     Depreciation and Amortization Expenses. Depreciation and amortization expenses were $28.7 million for 2004 and $18.2 million for 2003, reflecting the increase in the size and investment in our asset base. We invested $19.3 million for acquisitions in 2004 and an additional $55.7 million for capital expenditures in 2004 (excluding capital leases).

     Interest Expense. Interest expense increased 85.6% to $9.7 million in 2004 from $5.2 million in 2003. The increase was due to an increase in long-term debt which was primarily used in connection with our acquisitions,

most of which was added in the fourth quarter of 2003, and capital expenditures for property and equipment. In addition, both prime and LIBOR interest rates increased in 2004, and our term loan interest rate is tied directly to these rates. Our 2003 interest expense was favorably impacted by the reduced interest rate we received in our January 2003 refinancing, as well as an additional reduction in interest rates in our October 2003 refinancing. As part of the refinancings in January 2003 and October 2003, we recognized a loss of $5.2 million from the early extinguishment of debt. As part of our 2004 refinancing, we further reduced our base interest rate by 50 basis points. See “— Liquidity and Capital Resources.”

     Income Tax Expense (Benefit). Income taxes increased to an $8.0 million expense in 2004 from a $2.8 million expense in 2003. The change was due to improved profitability offset in part by a decrease in the effective tax rate in 2004. The effective tax rate in 2004 was approximately 38.2% as compared to 48.3% in 2003. The decrease in the effective tax rate in 2004 was due primarily to an adjustment of the federal tax rate from 34% in previous years to 35% in 2003, and the associated effects on our deferred tax liability.

     Discontinued Operations. As part of the FESCO acquisition in October 2003, we acquired certain fluid services assets in Alaska that, prior to completing the acquisition, we decided to sell. Accordingly, these assets were treated as held for sale and therefore the financial results for the assets are reflected as discontinued operations. These assets were sold in the third quarter of 2004 at their carrying value. At the time of sale, we charged the remaining liability for a property lease to discontinued operations.

     Cumulative Effect of Accounting Change. As of January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligation” (“SFAS No. 143”). SFAS No. 143 requires us to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets and capitalize an equal amount as a cost of the asset depreciating it over the life of the asset. As a result of this adoption we recorded an expense, net of tax of approximately $151,000 in 2003.

     Net Income. Our net income increased to $12.9 million in 2004 from a net income of $2.8 million in 2003. This improvement was due primarily to the increase in revenues and margins in 2004 compared to 2003 detailed above.

Liquidity and Capital Resources

     Currently, our primary capital resources are net cash flows from our operations, utilization of capital leases as allowed under our credit facility and availability under our credit facility, of which approximately $124.4 million was available at December 31, 2005. As of December 31, 2005, we had cash and cash equivalents of $32.8 million compared to $20.1 million as of December 31, 2004. We have utilized, and expect to utilize in the future, bank and capital lease financing and sales of equity to obtain capital resources. When appropriate, we will consider public or private debt and equity offerings and non-recourse transactions to meet our liquidity needs.

Net Cash Provided by Operating Activities

     Cash flow from operating activities was $99.2 million for the year ended December 31, 2005 as compared to $46.5 million in 2004, and $29.8 million in 2003. The increase in operating cash flows in 2005 compared to 2004 was primarily due to expansion of our fleet and improvements in the segment profits and utilization of our equipment. The increase in operating cash flows in 2004 over 2003 was primarily due to improvements in the segment profits and utilization of our equipment and our acquisitions in late 2003. For 2004 and 2005, these favorable trends were negatively impacted by an increase in cash required to satisfy our working capital requirements, particularly the increase in accounts receivable.

Capital Expenditures

     Capital expenditures are the main component of our investing activities. Cash capital expenditures (including for acquisitions) for 2005 were $108.5 million as compared to $75.0 million in 2004, and $85.4 million in 2003. In 2005 and 2004, the majority of our capital expenditures were for the expansion of our fleet. In 2003 the majority of

our capital expenditures were for acquisitions. In 2003, we issued 3,650,000 shares of common stock as part of the FESCO acquisition which added a non-cash cost to acquisitions of $18.8 million and is in addition to the $85.4 million spent in 2003. In 2003, we experienced a significant increase in our acquisition activity as compared to the previous periods which allowed us to expand our services and regions where we operate. We also added assets through our capital lease program of approximately $10.3 million, $10.5 million, and $10.8 million in 2005, 2004 and 2003, respectively.

     For 2006, we currently have planned approximately $93 million in cash capital expenditures, none of which is planned for acquisitions. We do not budget acquisitions in the normal course of business, but we believe that we may spend a significant amount for acquisitions in 2006. The $93 million of capital expenditures planned for property and equipment is primarily for (1) purchase of additional equipment to expand our services, (2) continued refurbishment of our well servicing rigs and (3) replacement of existing equipment. As of December 31, 2005, we had executed letters of intent for acquisitions providing for an aggregate cash purchase price, including potential future payments, of approximately $105 million.

     We regularly engage in discussions related to potential acquisitions related to the well services industry. At present, we have not entered into any agreement, commitment or understanding with respect to any significant acquisition as “significant” is defined under SEC rules.

Capital Resources and Financing

     Our current primary capital resources are cash flow from our operations, the ability to enter into capital leases of up to an additional $29.0 million at December 31, 2005, the availability under our credit facility of $124.4 million at December 31, 2005 and a cash balance of $32.8 million at December 31, 2005. In 2005, we financed activities in excess of cash flow from operations primarily through the use of bank debt and capital leases. During 2004 and 2003, we utilized bank debt and the issuance of equity for cash as consideration for acquisitions.

     We have significant contractual obligations in the future that will require capital resources. Our primary contractual obligations are (1) our long-term debt, (2) our capital leases, (3) our operating leases, and (4) our asset retirement obligations. The following table outlines our contractual obligations as of December 31, 2005 (in thousands):

		Obligations Due in Periods Ended
Contractual		December 31,
Obligations		Total				2006				2007-2008				2009-2010				Thereafter
Long-term debt (excluding capital leases)		$	106,000			$	1,000			$	2,000			$	18,000			$	85,000
Capital leases			20,887				6,646				11,142				3,099				—
Operating leases			4,199				1,198				1,540				998				463
Asset retirement obligations			569				—				—				—				569
Total		$	131,655			$	8,844			$	14,682			$	22,097			$	86,032

     Our long-term debt, excluding capital leases, consists primarily of term loan indebtedness outstanding under our senior credit facility. Our capital leases relate primarily to light-duty and heavy-duty vehicles and trailers. Our operating leases relate primarily to real estate.

     The table above does not reflect any additional payments that we may be required to make pursuant to contingent earn-out agreements that are associated with certain acquisitions. At December 31, 2005, we had a maximum potential obligation of $1.2 million related to the contingent earn-out agreements. See note 3 of the notes to our historical consolidated financial statements for additional detail.

     The table above also does not reflect $9.6 million of outstanding standby letters of credit issued under our revolving line of credit. At December 31, 2005, of the $150.0 million in financial commitments under the revolving line of credit under our senior credit facility, there was only $124.4 million of available capacity due to the outstanding balance of $16.0 million and the $9.6 million of outstanding standby letters of credit. In the normal

course of business, we have performance obligations which are supported by surety bonds and letters of credit. These obligations primarily cover various reclamation and plugging obligations related to our operations, and collateral for future workers compensation and liability retained losses.

     Our ability to access additional sources of financing will be dependent on our operating cash flows and demand for our services, which could be negatively impacted due to the extreme volatility of commodity prices.

Credit Facilities

     2005 Credit Facility

     On December 15, 2005, we amended and restated our 2004 Credit Facility by entering into a Third Amended and Restated Credit Agreement with a syndicate of lenders (the “2005 Credit Facility”). Under the 2005 Credit Facility, Basic Energy Services, Inc. is the sole borrower and each of our subsidiaries is a subsidiary guarantor. The 2005 Credit Facility provides for a $90 million Term B Loan (“Term B Loan”) and a $150 million revolving line of credit (“Revolver”). The 2005 Credit Facility includes provisions allowing us to request an increase in commitments of up to $75 million at any time. Additionally, the 2005 Credit Facility permits us to make greater expenditures for acquisitions, capital expenditures and capital leases and to incur greater purchase money obligations, acquisition indebtedness and general unsecured indebtedness.

     The commitment under the Revolver provides for (1) the borrowing of funds, (2) the issuance of up to $20 million of letters of credit and (3) $2.5 million of swing-line loans. The amounts outstanding under the Term B Loan require quarterly amortization at various amounts during each quarter with all amounts outstanding being due and payable in full on December 15, 2011. All the outstanding amounts under the Revolver are due and payable on December 15, 2010. The 2005 Credit Facility is secured by substantially all of our tangible and intangible assets. We incurred approximately $1.8 million in costs in connection with the 2005 Credit Facility.

     At our option, borrowings under the Term B Loan bear interest at either (1) the “Alternative Base Rate” (i.e., the higher of the bank’s prime rate or the federal funds rate plus .50% per year) plus 1.0% or (2) the London Interbank Offered Rate (“LIBOR”) rate plus 2.0%.

     At our option, borrowings under the Revolver bear interest at either (1) the Alternative Base Rate plus a margin ranging from 0.50% to 1.25% or (2) the LIBOR rate plus a margin ranging from 1.50% to 2.25%. The margins vary depending on our leverage ratio. Fees on the letters of credit are due quarterly on the outstanding amount of the letters of credit at a rate ranging from 1.50% to 2.25% for participation fees and 0.125% for fronting fees. A commitment fee is due quarterly on the available borrowings under the Revolver at rates ranging from 0.375% to 0.50%.

     At December 31, 2005, we had outstanding $90.0 million under the Term B Loan and $16.0 million under the Revolver.

     Pursuant to the 2005 Credit Facility, we must apply proceeds from certain specified events to reduce principal outstanding under the Term B Loan, to the extent outstanding, and then to the Revolver, including:

	•		assets sales greater than $2.0 million individually or $7.5 million in the aggregate on an annual basis; and
	•		50% of the proceeds from any equity offering.

     The 2005 Credit Facility requires us to enter into an interest rate hedge, acceptable to the lenders, until May 28, 2006 on at least $65 million of our then-outstanding indebtedness.

     The 2005 Credit Facility contains various restrictive covenants and compliance requirements, including the following:

•

limitations on the incurrence of additional indebtedness;

	•		restrictions on mergers, sales or transfer of assets without the lenders’ consent;
	•		limitation on dividends and distributions; and
	•		various financial covenants, including:

	•		a maximum leverage ratio of 3.50 to 1.00 reducing to 3.25 to 1.00, and
	•		a minimum interest coverage ratio of 3.00 to 1.00.

     2004 Credit Facility

     On December 21, 2004, we amended and restated our credit facility with a syndicate of lenders (“2004 Credit Facility”) which increased aggregate commitments to us from $170 million to $220 million. The 2004 Credit Facility provided for a $170 million Term B Loan (“2004 Term B Loan”) and a $50 million revolving line of credit (“2004 Revolver”). The commitment under the 2004 Revolver allowed for (1) the borrowing of funds, (2) the issuance of up to $20 million of letters of credit and (3) $2.5 million of swing-line loans. The amounts outstanding under the 2004 Term B Loan required quarterly amortization at various amounts during each quarter with all amounts outstanding being due and payable in full on October 3, 2009. All the outstanding amounts under the 2004 Revolver would have been due and payable on October 3, 2008. The 2004 Credit Facility was secured by substantially all of our tangible and intangible assets. We incurred approximately $0.8 million in debt issuance costs in obtaining the 2004 Credit Facility.

     2003 Credit Facility

     In October 2003, we refinanced our 2003 Refinancing Facility by entering into a $170 million credit facility with a syndicate of lenders (the “2003 Credit Facility”). The interest rates and other terms were similar to our 2004 Credit Facility, but it provided for a $140 million Term B loan and $30.0 million revolving line of credit, including $10.0 million of letters of credit. At the date the 2003 Credit Facility was refinanced by the 2004 Credit Facility, the outstanding principal balance was approximately $139 million. We incurred approximately $5.1 million in debt issuance costs in obtaining the 2003 Credit Facility.

     2003 Refinancing Facility

     In January 2003, we refinanced our then-existing credit facilities by entering into a $62 million credit facility with a capital markets group for a combination of term and revolving loans, and a $22 million revolving line of credit with a bank (collectively, the “2003 Refinancing Facility”). The interest rates on the loans under the 2003 Refinancing Facility were tied to a variable index plus a margin. At the date the 2003 Refinancing Facility was terminated and refinanced by the 2003 Credit Facility, the outstanding principal balance was approximately $54 million. We incurred approximately $2.5 million in debt issuance costs in obtaining the 2003 Refinancing Facility.

     Other Debt

     We have a variety of other capital leases and notes payable outstanding that is generally customary in our business. None of these debt instruments are material individually or in the aggregate. As of December 31, 2005, we had total capital leases of approximately $21.0 million.

     Losses on Extinguishment of Debt

     In 2005 we recognized a loss on the early extinguishment of debt of $627,000 in connection with our 2005 Credit Facility discussed above. In 2003, we recognized a loss on the early extinguishment of debt. We paid termination fees of approximately $1.7 million and wrote off unamortized debt issuance costs of approximately $3.5 million, which resulted in a loss of approximately $5.2 million. The 2003 Refinancing Facility was done (1) to

provide for a facility which would better accommodate acquisitions and (2) to realize better interest rate margins and fees. The 2003 Credit Facility was primarily done to enable us to fund the significant acquisitions in the fourth quarter in 2003, which could not be economically negotiated under the facility related to the 2003 Refinancing Facility.

     In 2003, we adopted Statement of Financial Accounting Standards No. 145 “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections” (“SFAS No. 145”). The provisions of SFAS No. 145, which are currently applicable to us, rescind Statement No. 4, which required all gains and losses from extinguishment of debt to be aggregated and classified as an extraordinary item, and instead require that such gains and losses be reported in income from operations. We now record gains and losses from the extinguishment of debt in income from operations and have reclassified such gains and losses in the consolidated financial statements for 2002 to conform to the presentation in 2003.

     Credit Rating Agencies

     Effective November 22, 2005, in connection with the amendment and restatement of our 2004 Credit Facility, we have received credit ratings of Ba3 from Moody’s and B+ from Standard & Poor’s for our long-term debt under the 2004 Credit Facility. None of our debt or other instruments is dependent upon our credit ratings. However, the credit ratings may affect our ability to obtain financing in the future.

     Preferred Stock

     In October 2003, we converted our then-outstanding mandatorily redeemable preferred stock into shares of our common stock as part of our debt refinancing process.

Other Matters

     Net Operating Losses

     We used all of our then-available net operating losses for federal income tax purposes when we completed a recapitalization in December 2000, which included a significant amount of debt forgiveness. In 2002, our profitability suffered and, when combined with a significant level of capital expenditures, we ended 2002 with a net operating loss, or NOL, of $30.4 million. In 2003, we returned to profitability, but we again made significant investments in existing equipment, additional equipment and acquisitions. Due to these events, we again reported a tax loss in 2003 and ended the year with a $50.7 million NOL, including $7.0 million that was included in the purchase of FESCO. As of December 31, 2005, we had approximately $4.9 million of NOL carryforwards related to the pre-acquisition period of FESCO, which is subject to an annual limitation of approximately $900,000. The carryforwards begin to expire in 2017.

     Recent Accounting Pronouncements

     In December 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standard No. 123R, “Share-Based Payment” (“SFAS No. 123R”). Basic will adopt the provisions of SFAS No. 123R on January 1, 2006 using the modified prospective application. Accordingly, Basic will recognize compensation expense for all newly granted awards and awards modified, repurchased, or cancelled after January 1, 2006.

     Compensation cost for the unvested portion of awards that are outstanding as of January 1, 2006 will be recognized ratably over the remaining vesting period. The compensation cost for the unvested portion of awards will be based on the fair value at date of grant as calculated for Basic’s pro forma disclosure under SFAS No. 123. However, Basic will continue to account for any portion of awards outstanding on January 1, 2006 that were initially measured using the minimum value method under the intrinsic value method in accordance with APB No. 25. Basic will recognize compensation expense for awards under its Second Amended and Restated 2003 Incentive Plan (the “Incentive Plan”) beginning in January 1, 2006.

     Basic estimates that the effect on net income and earnings per share in the periods following adoption of SFAS No. 123R will be consistent with its pro forma disclosure under SFAS No. 123, except that estimated forfeitures will be considered in the calculation of compensation expense under SFAS No. 123R and volatility will be considered in determination of grant date fair value under SFAS 123R. However, the actual effect on net income and earnings per share will vary depending upon the number of options granted in future years compared to prior years and the number of shares exercised under the Incentive Plan. Further, Basic will use the Black-Scholes-Merton model to calculate fair value.

     Impact of Inflation on Operations

     Management is of the opinion that inflation has not had a significant impact on our business.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     We are exposed to changes in interest rates as a result of our credit facility. We had a total of $106 million of indebtedness outstanding under our credit facility at December 31, 2005. The impact of a 1% increase in interest rates on this amount of debt would result in increased interest expense (excluding effects of our interest rate hedges) of approximately $1.1 million annually, or a decrease in net income of approximately $687,000.

     We do not hold or issue derivative instruments for trading purposes. We do, however, have an interest rate derivate instrument that has been formally designated as a cash flow hedge instrument. This instrument effectively converts the variable interest payments on $65 million of our 2005 Term B Loan into fixed interest payments.

     The table below provides scheduled principle payments and fair value information about our market-risk sensitive instruments as of December 31, 2005 (dollars in thousands):

		Expected Year of Maturity
		2006				2007				2008				2009				2010				Thereafter				Total				Fair Value
Debt
Variable rate		$	1,000			$	1,000			$	1,000			$	1,000			$	17,000			$	85,000			$	106,000			$	106,000
Average interest rate(1)

		Average Notional Amounts Outstanding (2)
		2006				2007				2008				2009				2010				Thereafter				Total				Fair Value
Interest Rate Derivatives
Variable to Fixed		$	26,356				—				—				—				—				—			$	26,356			$	422
Average pay rate			3.03	%			—				—				—				—				—				3.03	%			N/A
Average received rate			4.83	%			—				—				—				—				—				4.83	%			N/A