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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, 2006
OR
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the transition period from          to          
 
Commission file no. 001-32693
 
 
 
 
Basic Energy Services, Inc.
(Exact name of registrant as specified in its charter)
 
     
Delaware   54-2091194
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)
 
         
400 W. Illinois, Suite 800     79701  
Midland, Texas     (Zip code )
(Address of principal executive offices)        
 
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   New York Stock Exchange
(Title of Class)
  (Name of each exchange on which registered)
 
Securities registered pursuant to Section 12(g) of the Act:
None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o     No þ
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  Yes o     No þ
 
Indicate by check mark whether the registrant (1) 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 þ     Non-Accelerated Filer o
 
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 $532,887,772 as of June 30, 2006 (based on a closing price of $30.57 per share and 17,431,723 shares held by non-affiliates).
 
38,300,105 shares of the registrant’s Common Stock were outstanding as of March 8, 2007.
 
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
 
         
  2
  2
  2
  2
  3
  4
  6
  12
  13
  13
  13
  14
  14
  16
  16
  16
  21
  21
  22
  22
  22
  22
       
  24
  24
  24
  24
  25
  26
  26
  28
  29
  33
  33
  36
  39
  44
  45
  46
  82
  82
  82
       
  82
  82
  82
  86
 Subsidiaries of the Company
 Consent of KPMG LLP
 Certification by Chief Executive Officer
 Certification by Chief Financial Officer
 Certification of CEO Pursuant to Section 906
 Certification of CFO Pursuant to Section 906


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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 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.


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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, Arkansas 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 11% of the overall available U.S. fleet, with our two larger competitors controlling approximately 25% and 14%, 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 (45% of our revenues in 2006) currently operates our fleet of over 360 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 (27% of our revenues in 2006) currently utilizes our fleet of 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 (21% of our revenues in 2006) currently operates our fleet of pressure pumping units, air compressor packages specially configured for underbalanced drilling operations, cased-hole wireline units and an array of specialized rental equipment and fishing tools. We entered the rental and fishing tool business through an acquisition in the first quarter of 2006. 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 (7% of our revenues in 2006) currently utilizes our fleet of earth moving equipment, which includes 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 360 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 maintenance, workover, completion and plugging and abandonment services.


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Modern and Active Fleet.  We operate a modern and active fleet of well servicing rigs. We believe over 80% of the active U.S. well servicing rig fleet was built prior to 1985. Approximately 128 of our rigs at December 31, 2006 were either 2000 model year or newer, or have undergone major refurbishments during the last five years. As of December 31, 2006, we have taken delivery of 66 newbuild well servicing rigs since October 2004 as part of a 120-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 57 of our rigs since the beginning of 2001. Approximately 99% of our fleet was active or available for work and the remainder was awaiting refurbishment at December 31, 2006. 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, Arkansas and Louisiana and the Rocky Mountain states. We operate in states that accounted for approximately 56% of the approximately 900,000 existing onshore oil and gas wells in the 48 contiguous states and approximately 69% of onshore oil production and 85% of onshore gas production in 2006. 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 92 area offices 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 nine regional or service line 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 25 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 nine regional or service line managers, our 81 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


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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. During the past three years, our acquisitions have included: Energy Air Drilling and AWS Wireline services in 2004; three inland barges that increased our presence along the Gulf Coast in December 2004, two of which have been refurbished and were available for service in the second quarter of 2005; Oilwell Fracturing Services, Inc., a pressure pumping services company operating in our Mid-Continent region in 2005, and in 2006 LeBus Oil Field Service Co., a fluid service company operating in our Ark-La-Tex region, and G&L Tool, Ltd., a rental and fishing tool company included in our drilling and completion line of business.
 
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 2006, we completed 10 separate acquisitions for an aggregate purchase price of $135.6 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 operating and 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, oil and gas companies have increased their drilling and workover activities. The increased activity resulted in increased exploration and production spending compared to the prior year of 30% in 2005 and 17% in 2006, according to www.WorldOil.com.


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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       7.51  
1/1/06 — 12/31/06
    66.05       6.42  
 
 
Source: U.S. Department of Energy.
 
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 11% from year-end 2003 to year-end 2004, 22% from year-end 2004 to year-end 2005, and 17% from year-end 2005 to year-end 2006. In addition, the U.S. land-based workover rig count increased approximately 10% from year-end 2003 to year-end 2004, 17% from year-end 2004 to year-end 2005 and decreased 1% from year-end 2005 to year-end 2006, 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 expenditures by oil and gas companies tend 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 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.


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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 365 well service rigs as of December 31, 2006, including 66 newbuilds since October 2004 and 77 rebuilds since the beginning of 2001. We operate from more than 90 facilities in Texas, Wyoming, Oklahoma, North Dakota, New Mexico, Louisiana, Colorado and Montana. 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 were equipped with rigs, have been refurbished and were placed into service in the second quarter of 2005. In January 2007, we acquired two additional inland barges equipped with rigs in the acquisition of Parker Drilling Offshore USA, LLC. 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, 2006. 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 54 new well servicing rigs that we have contracted for delivery from January 2007 through December 2007 as part of a 120-rig newbuild commitment:
 
                                                                     
        Operating Region        
        Permian
    South
    Ark-La-
    Mid-
    Northern
    Southern
             
Rig Type
  Rated Capacity   Basin     Texas     Tex     Continent     Rockies     Rockies     Stacked     Total  
 
Swab
  N/A     3       1       7       6       0       0       1       18  
Light Duty
  <90 tons     7       2       0       22       2       0       1       34  
Medium Duty
  ³90-<125 tons     112       36       25       42       18       18       1       252  
Heavy Duty
  ³125 tons     28       4       5       6       5       3       0       51  
24-Hour
  ³125 tons     1       4       0       0       0       0       0       5  
Drilling Rigs
  ³125 tons     0       0       0       0       0       3       0       3  
Inland Barge
  ³125 tons     0       0       2       0       0       0       0       2  
                                                                     
Total
        151       47       39       76       25       24       3       365  
                                                                     
 
Management currently estimates that there are approximately 3,500 onshore well service 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 15% lower than this estimate. Based on information from U.S. contractors reporting their utilization to Weatherford-AESC, there were 2,580 well servicing rigs working in


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December 2006. This figure represents a projected utilization rate of 91% 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 market a combined 1,336 rigs. As reported by the AESC, these two competitors’ total rigs represent approximately 47% of the industry’s marketed fleet. We have the third-largest fleet with over 360 rigs, or approximately 13% of the 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 60 rigs (with a total of only 147 rigs) and a total of an estimated 100 companies own the approximately 1,000 estimated remaining rigs, or approximately 35% 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


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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, 2006:
 
                                                 
    Operating Region        
    Northern
    Permian
    Ark-La-
    South
    Mid-
       
    Rockies     Basin     Tex     Texas     Continent     Total  
 
Fluid Services Trucks
    89       198       192       128       39       646  
Salt Water Disposal Wells
    0       15       20       9       7       51  
Fresh/Brine Water Stations
    0       34       0       1       0       35  
Fluid Storage Tanks
    286       268       676       292       78       1,600  


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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.  We currently own and operate over 640 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.
 
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.


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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.
 
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 fresh water, brine 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 5 to 50 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:
 
  •  pressure pumping services, such as cementing, acidizing, fracturing, coiled tubing and pressure testing;
 
  •  cased-hole wireline services;
 
  •  underbalanced drilling in low pressure and fluid sensitive reservoirs; and
 
  •  rental and fishing tools.
 
This segment currently operates 69 pressure pumping units, with over 58,000 of horsepower capacity, 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, 2006, we also operated 43 air compressor packages, including foam circulation units, for underbalanced drilling and 11 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.


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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 primarily on lower horsepower cementing, acidizing and fracturing services in 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, 2006:
 
                                                 
    Operating Region        
                Northern
    Southern
    Permian
       
    Ark-La-Tex     Mid-Continent     Rockies     Rockies     Basin     Total  
 
Pressure Pumping Units
    14       51       4       0       0       69  
Coiled Tubing Units
    0       3       0       0       0       3  
Air/Foam Packages
    0       2       0       37       4       43  
Wireline Units
    0       11       0       0       0       11  
Rental and Fishing Tool Stores
    0       9       1       0       8       18  
 
Currently, there are only three pressure pumping companies that provide their services on a national basis. 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


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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.
 
Our rental and fishing tool business provides a range of specialized services and equipment that are utilized on a non-routine basis for both drilling and well servicing operations. Drilling and well servicing rigs are equipped with a complement of tools to complete routine operations under normal conditions for most projects in the geographic area where they are employed. When problems develop with drilling or servicing operations, or conditions require non-routine equipment, our customers will rely on a provider of rental and fishing tools to augment equipment that is provided with a typical drilling or well servicing rig package.
 
The term “fishing” applies to a wide variety of downhole operations designed to correct a problem that has developed when drilling or servicing a well. Most commonly the problem involves equipment that has become lodged in the well and cannot be removed without special equipment. Our customers employ our technicians and our tools that are specifically suited to retrieve the trapped equipment, or “fish,” in order for operations to resume.
 
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 operations 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.
 
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. We currently conduct our business from 92 area offices, 45 of which we own and 47 of which we lease. Each office


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typically includes a yard, administrative office and maintenance facility. Of our 92 area offices, 61 are located in Texas, 8 are in Oklahoma, 5 are in Wyoming, 5 are in New Mexico, 4 are in Colorado, 3 are in Louisiana, 2 are in Montana, 2 are in North Dakota, 1 is in Arkansas and 1 is in Utah.
 
Customers
 
We serve numerous major and independent oil and gas companies that are active in our core areas of operations. During 2006, we provided services to several customers, with no one customer comprising over 4% 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 47% of the U.S. marketable 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


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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 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.


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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 recently updated and implemented SPCC plans for several of our facilities. 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


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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, 2006, we employed approximately 4,000 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 levels exceeding $70 per barrel and $10 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 $41.51, $56.64 and $66.05 per barrel in 2004, 2005, and 2006 respectively, and the average wellhead price for natural gas, as recorded by the Energy Information Agency, was $5.49, $7.51 and $6.42 per mcf for 2004, 2005, and 2006 respectively. Commodity prices have increased significantly in recent years, and these prices may not remain at current levels.


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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.
 
We may require additional capital in the future. We cannot assure you that we will be able to generate sufficient cash internally or obtain alternative sources of capital on favorable terms, if at all. If we are unable to fund capital expenditures our business may be adversely affected.
 
We anticipate that we will continue to make substantial capital investments to purchase additional equipment to expand our services, refurbish our well servicing rigs and replace existing equipment. For the year ended December 31, 2005, we invested approximately $83.1 million in cash for capital expenditures, excluding acquisitions. For the year ended December 31, 2006, we invested approximately $104.6 million in cash for capital expenditures, excluding acquisitions. Historically, we have financed these investments through internally generated funds, debt and equity offerings, our capital lease program and our secured credit facilities. These significant capital investments require cash that we could otherwise apply to other business needs. However, if we do not incur these expenditures while our competitors make substantial fleet investments, our market share may decline and our business may be adversely affected. In addition, if we are unable to generate sufficient cash internally or obtain alternative sources of capital to fund our proposed capital expenditures, acquisitions, take advantage of business opportunities or respond to competitive pressures, it could materially adversely affect our results of operations, financial condition and growth. If we raise additional funds by issuing equity securities, dilution to existing stockholders may result.
 
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


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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 2006, our top five customers accounted for 16% and 15%, 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 120-rig commitment for rigs to be delivered through the end of December 2007, of which 66 rigs have been delivered as of December 31, 2006. 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.
 
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.


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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 on our workover rig fleet. 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 risk 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, 2006, our total debt was $262.7 million, including the aggregate principal amount due under our Senior Notes and capital lease obligations in the aggregate amount of $37.7 million. For the year ended December 31, 2006, we made cash interest payments totaling $12.6 million.
 
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;


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  •  limit our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make principal and interest payments on our indebtedness;
 
  •  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 revolving credit facility and the indenture governing our Senior Notes impose restrictions on us that may affect our ability to successfully operate our business.
 
Our revolving credit facility and the indenture governing our Senior Notes limit 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 revolving 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. The failure to comply with any of these financial conditions, such as financial ratios or covenants would cause a default under our revolving credit facility. A default, if not waived, could result in acceleration of the outstanding indebtedness under our revolving credit facility, in which case the debt would become immediately due and payable. In addition, a default or acceleration of indebtedness under our revolving credit facility could result in a default or acceleration of our Senior Notes or other indebtedness with cross-default or cross-acceleration provisions. If this occurs, we may not be able to pay our debt or borrow sufficient funds to refinance it. Even if new financing is available, it may not be available on terms that are acceptable to us. 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 revolving credit facility. In February 2007, we amended and restated our 2005 Credit Facility by entering into a Fourth Amended and Restated Credit Agreement. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facilities” for a discussion of our Credit Facilities.
 
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


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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
 
Affiliates of DLJ Merchant Banking will have a substantial influence on the outcome of stockholder voting and may exercise this voting power in a manner that may not be in the best interest of our other stockholders.
 
As of March 8, 2007, DLJ Merchant Banking Partners III, L.P. and affiliated funds (“DLJ Merchant Banking”), which are managed by affiliates of Credit Suisse, a Swiss Bank, and Credit Suisse Securities (USA) LLC, beneficially owned approximately 47.2% of our outstanding common stock. Accordingly, DLJ Merchant Banking is in a position to have a substantial influence on 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.
 
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.


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ITEM 1B.  UNRESOLVED STAFF COMMENTS
 
None.
 
ITEM 3.   LEGAL PROCEEDINGS
 
From time to time, Basic is a party to litigation or other legal proceedings that Basic considers to be a part of the ordinary course of business. Basic is not currently involved in any legal proceedings that it considers probable or reasonably possible, individually or in the aggregate, to result in a material adverse effect on its financial condition, results of operations or liquidity.
 
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, 2006 and their respective ages and positions are as follows:
 
             
Name
 
Age
 
Position
 
Kenneth V. Huseman
  54   President, Chief Executive Officer and Director
Alan Krenek
  51   Senior Vice President, Chief Financial Officer, Treasurer and Secretary
Charles W. Swift
  57   Senior Vice President — Rig and Truck Operations
Dub W. Harrison
  49   Vice President — Equipment & Safety
Mark D. Rankin
  53   Vice President — Risk Management
James E. Tyner
  56   Vice President — Human Resources
T.M. “Roe” Patterson
  32   Vice President — Corporate Development, Rental and Fishing Tool Operations
 
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 28 years of well servicing experience. He has been our President, Chief Executive Officer and Director of Basic Energy Services since 1999. Prior to joining Basic, he was Chief Operating Officer at Key Energy Services from 1996 to 1999. He was a Divisional Vice President at WellTech, Inc., from 1993 to 1996. From 1982 to 1993, he was employed at Pool Energy Services Co., 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.
 
Alan Krenek (Senior Vice President, Chief Financial Officer, Treasurer and Secretary) has 19 years of related industry experience. He has been our Vice President, Chief Financial Officer and Treasurer since January 2005. He became Senior Vice President and Secretary in May 2006. 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. 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.
 
Charles W. Swift (Senior Vice President — Rig and Truck Operations) has 34 years of related industry experience including 26 years specifically in the domestic well service business. He was named Senior Vice


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President — Rig and Truck Operations in July 2006, has served as 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 well service and fluid services businesses. Mr. Swift graduated with a B.B.A. degree in International Trade from Texas Tech University.
 
Dub W. Harrison (Vice President — Equipment & Safety) has spent 30 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 29 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 Co.. 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 June 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. in General Science and M.S. in Microbiology from Mississippi State University.
 
T. M. “Roe” Patterson (Vice President — Corporate Development, Rental & Fishing Tool Operations) has 12 years of related industry experience. He has been our Vice President of Corporate Development since February 2006. He became our Vice President of Rental and Fishing Tool Operations in July of 2006. Prior to joining us, he was president of his own manufacturing and oilfield service company, TMP Companies, Inc., from 2000 to 2006. He was the Contracts/Sales Manager for Permian Division of Patterson Drilling Company from 1996 to 2000. He was an Engine Sales Manager for West Texas Caterpillar from 1995 to 1996. Mr. Patterson graduated with a B.S. degree in Biology from Texas Tech University.


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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 period from our initial trading (December 9, 2005) until the end of the fourth quarter of 2005 and for each of the quarters in the year ended December 31, 2006:
 
                 
    High     Low  
 
2005:
               
Fourth Quarter
  $ 22.00     $ 19.20  
2006:
               
First Quarter
  $ 29.80     $ 20.36  
Second Quarter
  $ 36.82     $ 24.37  
Third Quarter
  $ 31.30     $ 23.13  
Fourth Quarter
  $ 26.84     $ 22.34  
 
As of March 8, 2007, we had 38,300,105 shares of common stock outstanding held by approximately 285 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, 2006:
 
                         
                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)
    2,457,780     $ 9.05       1,406,950  
Equity compensation plans not approved by security holders
                 
                         
Total
    2,457,780     $ 9.05       1,406,950  
                         
 
 
(1) Consists of the Basic Energy Services, Inc. Second Amended and Restated 2003 Incentive Plan (as amended effective April 22, 2005)


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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,  
    2002     2003     2004     2005     2006  
    (Dollars in thousands, except per share data)  
 
Statement of Operations Data:
                                       
Revenues:
                                       
Well servicing
  $ 73,848     $ 104,097     $ 142,551     $ 221,993     $ 330,725  
Fluid services
    34,170       52,810       98,683       132,280       194,636  
Drilling and completion services
    733       14,808       29,341       59,832       154,412  
Well site construction services
          9,184       40,927       45,647       50,375  
                                         
Total revenues
    108,751       180,899       311,502       459,752       730,148  
                                         
Expenses:
                                       
Well servicing
    55,643       73,244       98,058       137,392       186,428  
Fluid services
    22,705       34,420       65,167       82,551       118,378  
Drilling and completion services
    512       9,363       17,481       30,900       74,981  
Well site construction services
          6,586       31,454       32,000       35,067  
General and administration(a)
    13,019       22,722       37,186       55,411       81,318  
Depreciation and amortization
    13,414       18,213       28,676       37,072       62,087  
Loss (gain) on disposal of assets
    351       391       2,616       (222 )     277  
                                         
Total expenses
    105,644       164,939       280,638       375,104       558,536  
                                         
Operating income
    3,107       15,960       30,864       84,648       171,612  
Other income (expense):
                                       
Net interest expense
    (4,750 )     (5,174 )     (9,550 )     (12,660 )     (15,504 )
Gain (loss) on early extinguishment of debt
          (5,197 )           (627 )     (2,705 )
Other income (expense)
    31       146       (398 )     220       169  
                                         
Income (loss) from continuing operations before income taxes
    (1,612 )     5,735       20,916       71,581       153,572  
Income tax (expense) benefit
    382       (2,772 )     (7,984 )     (26,800 )     (54,742 )
                                         
Income (loss) from continuing operations
    (1,230 )     2,963       12,932       44,781       98,830  
Discontinued operations, net of tax
          22       (71 )            
Cumulative effect of accounting change, net of tax
          (151 )                  
                                         
Net income (loss)
    (1,230 )     2,834       12,861       44,781       98,830  
Preferred stock dividend
    (1,075 )     (1,525 )                  
Accretion of preferred stock discount
    (374 )     (3,424 )                  
                                         
Net income (loss) available to common stockholders
  $ (2,679 )   $ (2,115 )   $ 12,861     $ 44,781     $ 98,830  
                                         


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    Year Ended December 31,  
    2002     2003     2004     2005     2006  
    (Dollars in thousands, except per share data)  
 
Basic earnings (loss) per share of common stock:
                                       
Continuing operations less preferred stock dividend and accretion
  $ (0.13 )   $ (0.09 )   $ 0.46     $ 1.57     $ 2.87  
Discontinued operations
                             
Cumulative effect of accounting change
                             
                                         
Net income (loss) available to common stockholders
  $ (0.13 )   $ (0.09 )   $ 0.46     $ 1.57     $ 2.87  
                                         
Diluted earnings (loss) per share of common stock:
                                       
Continuing operations less preferred stock dividend and accretion
  $ (0.13 )   $ (0.09 )   $ 0.42     $ 1.35     $ 2.56  
Discontinued operations
                             
Cumulative effect of accounting change
                             
                                         
Net income (loss) available to common stockholders
  $ (0.13 )   $ (0.09 )   $ 0.42     $ 1.35     $ 2.56  
                                         
Other Financial Data:
                                       
Cash flows from operating activities
    17,012       29,815       46,539       99,189       145,678  
Cash flows from investing activities
    (45,303 )     (84,903 )     (73,587 )     (107,679 )     (241,351 )
Cash flows from financing activities
    21,572       79,859       21,498       21,188       114,193  
Capital expenditures:
                                       
Acquistions, net of cash acquired
    31,075       61,885       19,284       25,378       135,568  
Property and equipment
    14,674       23,501       55,674       83,095       104,574  
 
 
(a) Includes approximately $0, $994,000, $1,587,000, $2,890,000 and $3,429,000 of non-cash stock compensation expense for the years ended December 31, 2002, 2003, 2004, 2005 and 2006, respectively.
 
                                         
    As of December 31,  
    2002     2003     2004     2005     2006  
    (Dollars in thousands)  
 
Balance Sheet Data:
                                       
Cash and cash equivalents
  $ 926     $ 25,697     $ 20,147     $ 32,845     $ 51,365  
Property and equipment, net
    108,487       188,243       233,451       309,075       475,431  
Total assets
    156,502       302,653       367,601       496,957       796,260  
Long-term debt
    39,706       142,116       170,915       119,241       250,742  
Mandatorily redeemable cumulative preferred stock
    12,093                          
Stockholders’ equity (deficit)
    72,558       107,295       121,786       258,575       379,250  
 
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

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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 47 separate acquisitions from January 1, 2001 to December 31, 2006. Our weighted average number of well servicing rigs has increased from 126 in 2001 to 362 in the fourth quarter of 2006, and our weighted average number of fluid service trucks has increased from 156 to 640 in the same period. In 2006, primarily through acquisitions, we significantly increased our drilling and completion (principally pressure pumping and rental and fishing tools) service. 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,  
    2004     2005     2006  
 
Revenues:
                                               
Well servicing
  $ 142.6       46 %   $ 222.0       48 %   $ 330.7       45 %
Fluid services
    98.7       32 %     132.3       29 %     194.6       27 %
Drilling and completion services
    29.3       9 %     59.8       13 %     154.4       21 %
Well site construction services
    40.9       13 %     45.7       10 %     50.4       7 %
                                                 
Total revenues
  $ 311.5       100 %   $ 459.8       100 %   $ 730.1       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 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, which is substantially driven by the cost to


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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. 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 2004 through 2006, we grew significantly through acquisitions and capital expenditures. 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. During 2006, we completed ten acquisitions, of which G&L Tool, Ltd. was considered significant for purposes of Statement of Financial Accounting Standards No. 141 “Business Combinations.”
 
We discuss the aggregate purchase prices and related financing issues below in “— Liquidity and Capital Resources” and present the pro forma effects of the acquisition of G&L Tool, Ltd. in note 3 of the audited historical financial statements included in this report.
 
Selected 2004 Acquisitions
 
During 2004, we made a number of smaller acquisitions and capital expenditures that served as a platform for future growth. These included:
 
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 complemented 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


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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.
 
Selected 2006 Acquisitions
 
During 2006, we made several acquisitions that complemented our existing lines of business and increased our presence in the rental tool business. These included, among others:
 
LeBus Oil Field Service Co.
 
On January 31, 2006, we acquired all of the outstanding capital stock of LeBus Oil Field Service Co. for an acquisition price of $26 million, subject to adjustments. This acquisition significantly expanded our fluid services line of business in the Ark-La-Tex region. The cash used to acquire LeBus was primarily from borrowings under our senior credit facility.
 
G&L Tool, Ltd.
 
On February 28, 2006, we acquired substantially all of the operating assets of G&L Tool, Ltd. for total consideration of $58.5 million cash. This acquisition provided an entry into the rental and fishing tool market and operates within our drilling and completion line of business. The purchase agreement also contained an earn-out agreement based on annual EBITDA targets. The cash used to acquire G&L was primarily from borrowings under our senior credit facility.
 
Chaparral Service, Inc.
 
On August 15, 2006, we acquired all of the outstanding capital stock and substantially all operating assets of the subsidiaries of Chaparral Service, Inc. for total consideration of $19 million cash, subject to adjustments. This acquisition expanded our well servicing and fluid services capabilities in the eastern New Mexico portion of the Permian Basin. The cash used to acquire Chaparral was primarily from operating cash.
 
Segment Overview
 
Well Servicing
 
In 2006, our well servicing segment represented 45% 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. Our fleet has increased from a weighted average number of 272 rigs in the first quarter of 2004 to 362 in the fourth quarter of 2006 through a combination of new build purchases and the remainder through acquisitions and other individual equipment purchases.


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The following is an analysis of our well servicing operations for each of the quarters and years in the years ended December 31, 2004, 2005 and 2006:
 
                                                 
    Weighted
                      Segment
       
    Average
          Rig
          Profits
       
    Number of
    Rig
    Utilization
    Revenue Per
    Per Rig
    Segment
 
    Rigs     Hours     Rate     Rig Hour     Hour     Profits %  
 
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 %
2006:
                                               
First Quarter
    327       209,000       89.4 %   $ 352     $ 152       43.4 %
Second Quarter
    341       221,800       91.0 %   $ 366     $ 161       43.9 %
Third Quarter
    353       230,100       91.2 %   $ 383     $ 173       45.1 %
Fourth Quarter
    362       218,900       84.6 %   $ 401     $ 169       42.1 %
Full Year
    346       879,800       88.9 %   $ 376     $ 164       43.6 %
 
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 2004 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 $218 in the first quarter of 2004 to $401 in the fourth quarter of 2006 mainly as a result of this higher utilization, which has contributed to our improved segment profits.
 
Fluid Services
 
In 2006, our fluid services segment represented 27% 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.


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The following is an analysis of our fluid services operations for each of the quarters and years in the years ended December 31, 2004, 2005 and 2006 (dollars in thousands):
 
                                 
                Segment
       
    Weighted
          Profits
       
    Average
          Per
       
    Number of
    Revenue Per
    Fluid
       
    Fluid Service
    Fluid Service
    Service
    Segment
 
    Trucks     Truck     Truck     Profits %  
 
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 %
2006:
                               
First Quarter
    529     $ 82     $ 32       39.0 %
Second Quarter
    568     $ 86     $ 34       39.9 %
Third Quarter
    614     $ 83     $ 32       38.5 %
Fourth Quarter
    640     $ 81     $ 32       39.3 %
Full Year
    588     $ 332     $ 130       39.2 %
 
We gauge activity levels in our fluid services segment based on revenue and segment profits per fluid service truck.
 
Improved market conditions since 2004 have enabled us to further increase our fluid services truck fleet through internal expansion. During 2006, we also expanded this segment with the acquisition of LeBus.
 
The majority of the increase in revenue per fluid services truck from $60,000 in the first quarter of 2004 to $81,000 in the fourth quarter of 2006 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 2006, our drilling and completion services segment represented 21% 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, underbalanced drilling and rental and fishing tool operations.
 
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 North Texas and East Texas operations.


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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.”
 
We entered the rental and fishing tool business through our acquisition of G&L in the first quarter of 2006. This acquisition added 16 stores in the north Texas, west Texas, and Oklahoma markets.
 
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 segment for each of the quarters and years in the years ended December 31, 2004, 2005 and 2006 (dollars in thousands):
 
                 
          Segment
 
    Revenues     Profits %  
 
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 %
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 %
2006:
               
First Quarter
  $ 27,455       49.5 %
Second Quarter
  $ 40,939       53.1 %
Third Quarter
  $ 42,109       51.3 %
Fourth Quarter
  $ 43,909       51.2 %
Full Year
  $ 154,412       51.5 %
 
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 2004 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 2006, our well site construction services segment represented 7% 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


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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 services segment for each of the quarters and years in the years ended December 31, 2004, 2005 and 2006 (dollars in thousands):
 
                 
          Segment
 
    Revenues     Profits %  
 
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 %
2006:
               
First Quarter
  $ 10,265       25.5 %
Second Quarter
  $ 12,879       31.5 %
Third Quarter
  $ 13,483       30.2 %
Fourth Quarter
  $ 13,748       33.1 %
Full Year
  $ 50,375       30.5 %
 
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.
 
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.


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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 $150,000 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 actuarial 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.


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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.  On January 1, 2006, we adopted the fair value recognition provisions of Statement of Financial Accounting Standards No. 123R, “Share-Based Payment” (“SFAS No. 123R”). Prior to January 1, 2006, we accounted for share-based payments under the recognition and measurement provisions of Accounting Principles Board Opinion No. 25, “Accounting for stock Issued to Employees” (“APB No. 25”) which was permitted by Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123).
 
We adopted SFAS No. 123R using both the modified prospective method and the prospective method as applicable to the specific awards granted. The modified prospective method was applied to awards granted subsequent to the Company becoming a public company. Awards granted prior to the Company becoming public and which were accounted for under APB No. 25 were adopted by using the prospective method. The results of prior periods have not been restated. Compensation expense of the unvested portion of awards granted as a private company and outstanding as of January 1, 2006 will continue to be based upon the intrinsic value method calculated under APB No. 25.
 
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.
 
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.


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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, 2006 Compared to Year Ended December 31, 2005
 
Revenues.  Revenues increased by 59% to $730.1 million in 2006 from $459.8 million in 2005. This increase was primarily due to the internal expansion of our business segments, particularly well servicing and fluid services, and in part due to acquisitions. The pricing and utilization of our services, and thus related revenues, improved due to the increase in well maintenance and drilling activity caused by continued relatively high oil and gas prices.
 
Well servicing revenues increased by 49% to $330.7 million in 2006 compared to $222.0 million in 2005. 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 29%, from $292 per hour to $376 per hour. Our weighted average number of rigs increased to 346 in 2006 compared to 305 in 2005, an increase of approximately 13%. In addition, the utilization rate of our rig fleet increased to 88.9% in 2006 compared to 87.1% in 2005.
 
Fluid services revenues increased by 47% to $194.6 million in 2006 compared to $132.3 million in 2005. This increase was primarily due to our internal growth and acquisitions. Our weighted average number of fluid service trucks increased to 588 in 2006 compared to 455 in 2005, an increase of approximately 29%. The increase in weighted average number of fluid service trucks is primarily due to the internal expansion as wells as the trucks added from the LeBus acquisition. During 2006, our average revenue per fluid service truck was approximately $332,000 as compared to $291,000 in 2005. The increase in average revenue per fluid service truck reflects the expansion of our frac tank fleet and saltwater disposal operations, as well as increases in prices charged for our services.
 
Drilling and completion services revenues increased by 158% to $154.4 million in 2006 as compared to $59.8 million in 2005. The increase in revenue between these periods was primarily the result of internal expansion, the acquisition of Oilwell Fracturing Services in October 2005, the acquisition of G&L during February 2006 and improved pricing and utilization of our services.
 
Well site construction services revenues increased 10% to $50.4 million in 2006 as compared to $45.6 million in 2005.
 
Direct Operating Expenses.  Direct operating expenses, which primarily consist of labor, including workers compensation and health insurance, and maintenance and repair costs, increased by 47% to $414.9 million in 2006 from $282.8 million in 2005 as a result of additional rigs and trucks, increase in labor costs and higher utilization of our equipment. Direct operating expenses decreased to 57% of revenues in 2006 from 62% in 2005, 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 36% to $186.4 million in 2006 as compared to $137.4 million in 2005 due primarily due to the internal growth of this segment. Segment profits increased to 43.6% of revenues in 2006 compared to 38.1% in 2005, due to improved pricing for our services and higher utilization of our equipment.
 
Direct operating expenses for the fluid services segment increased by 43% to $118.4 million in 2006 as compared to $82.6 million in 2005 due primarily to increased activity and expansion of our fluid services fleet. Segment profits increased to 39.1% of revenues in 2006 compared to 37.6% in 2005.
 
Direct operating expenses for the drilling and completion services segment increased by 143% to $75.0 million in 2006 as compared to $30.9 million in 2005 due primarily to increased activity and expansion of our services and


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equipment, including the G&L acquisition. Our segment profits increased to 51.4% of revenues in 2006 from 48.4% in 2005.
 
Direct operating expenses for the well-site construction services segment increased by 10% to $35.0 million in 2006 as compared to $32.0 million in 2005. Segment profits for this segment increased to 30.3% of revenues in 2006 as compared to 29.9% in 2005.
 
General and Administrative Expenses.  General and administrative expenses increased by 47% to $81.3 million in 2006 from $55.4 million in 2005, which included $3.4 million and $2.9 million of stock-based compensation expense in 2006 and 2005, respectively. The increase primarily reflects higher salary and office expenses related to the expansion of our business as well as additional staffing and other costs to enhance internal controls as a public company.
 
Depreciation and Amortization Expenses.  Depreciation and amortization expenses were $62.1 million in 2006 as compared to $37.1 million in 2005, reflecting the increase in the size of and investment in our asset base. We invested $135.6 million for acquisitions in 2006 and an additional $131.0 million for capital expenditures in 2006 (including capital leases).
 
Interest Expense.  Interest expense increased by 33% to $17.5 million in 2006 from $13.1 million in 2005. The increase was due to an increase in the amount of long-term debt during the period. In April 2006, Basic issued $225.0 million in senior notes.
 
Income Tax Expense.  Income tax expense was $54.7 million in 2006 as compared to $26.8 million in 2005. Our effective tax rate in 2006 and 2005 was approximately 36% and 38%, respectively.
 
Loss on Early Extinguishment of Debt.  In April 2006, we used the proceeds from our issuance of $225 million aggregate principal amount of senior notes to pay in full our Term B Loan under or senior credit facility. In connection with the payment on the Term B Loan, we recognized a loss on the early extinguishment of debt and wrote-off unamortized debt issuance costs of approximately $2.7 million compared to an approximately $627,000 loss on the early extinguishment of debt in 2005 for amending and restating our credit facility.
 
Net Income.  Our net income increased to $98.8 million in 2006 from $44.8 million in 2005. 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, 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,


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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.  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 revenue per rig and fluid service truck, and higher operating margins on our drilling and completion services equipment.


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Liquidity and Capital Resources
 
Currently, our primary capital resources are net cash flows from our operations, utilization of capital leases as allowed under our 2005 Credit Facility and availability under our 2005 Credit Facility, of which approximately $139.4 million was available and $10.6 million letters of credit were outstanding at December 31, 2006. As of April 30, 2006, we had paid down all amounts under the revolving portion of our 2005 Credit Facility with the proceeds from our offering of Senior Notes and had availability of $140.4 million and $9.6 million of letters of credit outstanding under this facility. As of December 31, 2006, we had cash and cash equivalents of $51.4 million compared to $32.8 million as of December 31, 2005. 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 $145.7 million for the year ended December 31, 2006 as compared to $99.2 million in 2005, and $46.5 million in 2004. The increase in operating cash flows in 2006 compared to 2005 and to 2004 was primarily due to expansion of our fleet and improvements in the segment profits and utilization of our equipment. 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 2006 were $240.1 million as compared to $108.5 million in 2005, and $75.0 million in 2004. In 2006, the majority of our capital expenditures were for business acquisitions. In 2005 and 2004, the majority of our capital expenditures were for the expansion of our fleet. We also added assets through our capital lease program of approximately $26.4 million, $10.3 million, and $10.5 million in 2006, 2005 and 2004, respectively.
 
For 2007, we currently have planned approximately $130 million in cash capital expenditures and $30 million through capital leases, 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 2007. The $160 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. We regularly engage in discussions related to potential acquisitions related to the well services industry. As of December 31, 2006, we had executed six letters of intent for acquisitions providing for an aggregate purchase price, including potential future payments, of approximately $189.3 million. The acquisition of JetStar Consolidated Holdings, Inc. was completed on March 6, 2007 and was funded with common stock and available capacity under our credit facility revolver.
 
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 $12.3 million at December 31, 2006, the availability under our credit facility of $139.4 million at December 31, 2006 and a cash balance of $51.4 million at December 31, 2006. In 2006, we financed activities in excess of cash flow from operations primarily through the use of bank debt and capital leases. During 2006, we utilized bank debt and the issuance of senior notes for cash as consideration for acquisitions.


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We have significant contractual obligations in the future that will require capital resources. Our primary contractual obligations are (1) our long-term debt, (2) interest on senior notes, (3) our capital leases, (4) our operating leases, (5) our rig purchase obligations, (6) our asset retirement obligations, and (7) our other long-term liabilities. The following table outlines our contractual obligations as of December 31, 2006 (in thousands):
 
                                         
    Obligations Due in Periods Ended
       
    December 31,        
Contractual Obligations
  Total     2007     2008-2009     2010-2011     Thereafter  
 
Long-term debt (excluding capital leases)
  $ 225,000     $     $     $     $ 225,000  
Interest on senior notes
    148,957       16,031       32,063       32,063       68,800  
Capital leases
    37,743       12,001       19,454       6,288        
Operating leases
    13,606       2,551       4,458       2,693       3,904  
Rig purchase obligations
    39,823       39,823                    
Asset retirement obligations
    1,336                   486       850  
Other long-term liabilities
    1,733             793       106       834  
                                         
Total
  $ 468,198     $ 70,406     $ 56,768     $ 41,636     $ 299,388  
                                         
 
Our long-term debt, excluding capital leases, consists primarily of term loan indebtedness outstanding under our senior credit facility. Interest on senior notes relates to our future contractual interest obligation on our $225 million 7.125% Senior Notes offering in April of 2006. 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, 2006, we had a maximum potential obligation of $17.3 million related to the contingent earn-out agreements. This amount does not include the balance owed for an acquisition with no maximum earn-out exposure. In this situation, we will pay to the sellers an amount for each of the five consecutive 12 month periods equal to 50% of the amount by which annual EBITDA will be reached. See note 3 of the notes to our historical consolidated financial statements for additional detail.
 
The table above also does not reflect $10.6 million of outstanding standby letters of credit issued under our revolving line of credit. At December 31, 2006, of the $150.0 million in financial commitments under the revolving line of credit under our senior credit facility, there was only $139.4 million of available capacity due to the $10.6 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.
 
Senior Notes
 
In April 2006, we completed a private offering for $225,000,000 aggregate principal amount of 7.125% Senior Notes due April 15, 2016. The Senior Notes are jointly and severally guaranteed by each of our subsidiaries. The net proceeds from the offering were used to retire the outstanding Term B Loan balance and to pay down the outstanding balance under the revolving credit facility. Remaining proceeds were used for general corporate purposes, including acquisitions.
 
We issued the Senior Notes pursuant to an indenture, dated as of April 12, 2006, by and among us, the guarantor parties thereto and The Bank of New York Trust Company, N.A., as trustee.
 
Interest on the Senior Notes will accrue from and including April 12, 2006 at a rate of 7.125% per year. Interest on the Senior Notes is payable in cash semi-annually in arrears on April 15 and October 15 of each year, commencing on October 15, 2006. The Senior Notes will mature on April 15, 2016. The Senior Notes and the


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guarantees are unsecured and will rank equally with all of our and the guarantors’ existing and future unsecured and unsubordinated obligations. The Senior Notes and the guarantees will rank senior in right of payment to any of our and the guarantors’ existing and future obligations that are, by their terms, expressly subordinated in right of payment to the Senior Notes and the guarantees. The Senior Notes and the guarantees will be effectively subordinated to our and the guarantors’ secured obligations, including our senior secured credit facilities, to the extent of the value of the assets securing such obligations.
 
The indenture contains covenants that limit the ability of us and certain of our subsidiaries to:
 
  •  incur additional indebtedness;
 
  •  pay dividends or repurchase or redeem capital stock;
 
  •  make certain investments;
 
  •  incur liens;
 
  •  enter into certain types of transactions with affiliates;
 
  •  limit dividends or other payments by restricted subsidiaries; and
 
  •  sell assets or consolidate or merge with or into other companies.
 
These limitations are subject to a number of important qualifications and exceptions.
 
Upon an Event of Default (as defined in the indenture), the trustee or the holders of at least 25% in aggregate principal amount of the Senior Notes then outstanding may declare all of the amounts outstanding under the Senior Notes to be due and payable immediately.
 
We may, at our option, redeem all or part of the Senior Notes, at any time on or after April 15, 2011 at a redemption price equal to 100% of the principal amount thereof, plus a premium declining ratably to par and accrued and unpaid interest, if any, to the date of redemption.
 
At any time or from time to time prior to April 15, 2009, we, at our option, may redeem up to 35% of the outstanding Senior Notes with money that we raise in one or more equity offerings at a redemption price of 107.125% of the principal amount of the Senior Notes redeemed, plus accrued and unpaid interest, as long as:
 
  •  at least 65% of the aggregate principal amount of Senior Notes issued under the indenture remains outstanding immediately after giving effect to any such redemption; and
 
  •  we redeem the Senior Notes not more than 90 days after the closing date of any such equity offering.
 
If we experience certain kinds of changes of control, holders of the Senior Notes will be entitled to require us to purchase all or a portion of the Senior Notes at 101% of their principal amount, plus accrued and unpaid interest.
 
Credit Facilities
 
2007 Credit Facility
 
On February 6, 2007, we amended and restated our existing credit agreement by entering into a Fourth Amended and Restated Credit Agreement with a syndicate of lenders (the “2007 Credit Facility”). The amendments contained in the 2007 Credit Facility included:
 
  •  eliminating the $90 million class of Term B Loans;
 
  •  creating a new class of Revolving Loans, which increased the lender’s total revolving commitments from $150 million to $225 million
 
  •  increasing the “Incremental Revolving Commitments” under the 2007 Credit Facility from $75.0 million to an aggregate principal amount of $100 million;
 
  •  changing the applicable margins for Alternative Base Rate or Eurodollar revolving loans;


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  •  amending our negative covenants relating to our ability to incur indebtedness and liens, to add tests based on a percentage of our consolidated tangible assets in addition to fixed dollar amounts, or to increase applicable dollar limits on baskets or other tests for permitted indebtedness or liens;
 
  •  amending our negative covenants relating to our ability to pay dividends, or repurchase or redeem our capital stock, in order to conform more closely with permitted payments under our senior notes; and
 
  •  Eliminating certain restrictions on our ability to create or incur certain lease obligations.
 
Under the 2007 Credit Facility, Basic Energy Services, Inc. is the sole borrower and each of our subsidiaries is a subsidiary guarantor. The 2007 Credit Facility provides for a $225 million revolving line of credit (“Revolver”). The 2007 Credit Facility includes provisions allowing us to request an increase in commitments of up to $100.0 million aggregate principal amount at any time. Additionally, the 2007 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 $30 million of letters of credit and (3) $2.5 million of swing-line loans. All of the outstanding amounts under the Revolver are due and payable on December 15, 2010. The 2007 Credit Facility is secured by substantially all of our tangible and intangible assets. We incurred approximately $0.9 million in debt issuance costs in connection with the 2007 Credit Facility.
 
At our option, borrowings under the Revolver bears 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 a margin ranging from 0.25% to 0.5% or (2) an “Adjusted LIBOR Rate” (equal to (a) the London Interbank Offered Rate (the “LIBOR rate”) as determined by the Administrative Agent in effect for such interest period divided by (b) one minus the Statutory Reserves, if any, for such borrowing for such interest period) plus a margin ranging from 1.25% to 1.5%. 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 1.25% to 1.5% for participation fees and 0.125% for fronting fees. A commitment fee is due quarterly on the available borrowings under the Revolver at a rate of 0.375%.
 
At February 6, 2007, after giving affect to the amendments under the 2007 Credit Facility, we had no outstanding borrowings under the Revolver.
 
Pursuant to the 2007 Credit Facility, we must apply proceeds from certain specified events to reduce principal outstanding borrowings under the Revolver, including:
 
  •  assets sales greater than $2.0 million individually or $7.5 million in the aggregate on an annual basis;
 
  •  100% of the net cash proceeds from any debt issuance, including certain permitted unsecured senior or senior subordinated debt, but excluding certain other permitted debt issuances; and
 
  •  50% of the net cash proceeds from any equity issuance (including equity issued upon the exercise of any warrant or option).
 
The 2007 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;
 
  •  limitations 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 on April 1, 2007, and
 
  •  a minimum interest coverage ratio of 3.00 to 1.00.


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2005 Credit Facility
 
Under our Third Amended and Restated Credit Agreement with a syndicate of lenders (the “2005 Credit Facility”), as amended effective March 28, 2006, Basic Energy Services, Inc. was the sole borrower and each of our subsidiaries was a subsidiary guarantor. The 2005 Credit Facility provided for a $90 million Term B Loan (“Term B Loan”), which outstanding balance was repaid in April 2006, and provided for a $150 million revolving line of credit (“Revolver”). The 2005 Credit Facility included provisions allowing us to request an increase in commitments of up to $75 million at any time. The commitment under the Revolver provides for (1) the borrowing of funds, (2) the issuance of up to $30 million of letters of credit and (3) $2.5 million of swing-line loans. The amounts outstanding under the Term B Loan required 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 were due and payable on December 15, 2010. The 2005 Credit Facility was secured by substantially all of our tangible and intangible assets.
 
The 2005 Credit Facility contained customary events of default, which are subject to customary grace periods and materiality standards, including, among others, events of default upon the occurrence of: (1) non-payment of any amounts payable under the 2005 Credit Facility when due; (2) any representation or warranty made in connection with the 2005 Credit Facility being incorrect in any material respect when made or deemed made; (3) default in the observance or performance of any covenant, condition or agreement contained in the 2005 Credit Facility or related loan documents and such default shall continue unremedied or shall not be waived for 30 days; (4) failure to make payments on other indebtedness involving in excess of $1.0 million; (5) voluntary or involuntary bankruptcy, insolvency or reorganization of us or any of our subsidiaries; (6) entry of fines or judgments against us for payment of an amount in excess of $2.5 million; (7) an ERISA event which could reasonably be expected to cause a material adverse effect or the imposition of a lien on any of our assets; (8) any security agreement or document under the 2005 Credit Facility ceases to create a lien on any assets securing the 2005 Credit Facility; (9) any guarantee ceases to be in full force and effect; (10) any material provision of the 2005 Credit Facility ceases to be valid and binding or enforceable; (11) a change of control as defined in the 2005 Credit Agreement; of (12) any determination, ruling, decision, decree or order of any governmental authority, which prohibits or restrains Basic and its subsidiaries from conducting business and that could reasonably be expected to cause a material adverse effect.
 
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.
 
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, 2006, we had total capital leases of approximately $37.7 million.
 
Losses on Extinguishment of Debt
 
In April 2006, we recognized a loss on the early extinguishment of debt of $2.7 million representing unamortized deferred debt issuance costs in connection with the retirement of the Term B Loan.


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In 2005 we recognized a loss on the early extinguishment of debt of $627,000 in connection with our 2005 Credit Facility discussed above.
 
Credit Rating Agencies
 
In April 2006, we received credit ratings of Baa3 from Moody’s and B+ from Standard & Poor’s for our 2005 Credit Facility. Also, we received ratings of B1 from Moody’s and B from Standard & Poor’s for our Senior Notes. 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. On February 6, 2007, we received credit ratings of Ba1 from Moody’s and BB from Standard & Poor’s for our 2007 Credit Facility.
 
Preferred Stock
 
At December 31, 2006 and December 31, 2005, Basic had 5,000,000 shares of $.01 par value preferred stock authorized, of which none is designated.
 
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, 2006, we had approximately $4.0 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 September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (SAB 108), Considering the Effects of Prior Year Misstatements when Quantifying Misstatement in Current Year Financial Statements. The bulletin’s interpretations address diversity in practice in quantifying financial statement misstatements and the potential under current practice for the build up of improper amounts on the balance sheet. Basic adopted the interpretation in the fourth quarter of 2006. The adoption of SAB 108 did not have a material impact on the Company’s financial position, cash flows, or results of operations.
 
In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation No. 48 (FIN 48), Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109, Accounting for Income Taxes. The interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken, in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties accounting in interim periods, disclosure and transition. The interpretation is effective for fiscal years beginning after December 15, 2006. The cumulative effect of applying the provisions of this interpretation, which is required to be reported as an adjustment to our opening balance of retained earnings in 2007, is currently not expected to have a material impact on our results of operations, financial position or cash flows.
 
In December 2004, the FASB issued Statement of Financial Accounting Standard No. 123R, “Share-Based Payment” (“SFAS No. 123R”). We adopted the provisions of SFAS No. 123R on January 1, 2006 using the modified prospective application. Accordingly, we 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 our pro forma disclosure under SFAS No. 123.


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However, we 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. We began to recognize compensation expense for awards under our 2003 Incentive Plan on January 1, 2006.
 
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
 
As of December 31, 2006, we had no outstanding borrowings subject to variable interest rate risk. In April 2006, we completed a private offering for $225,000,000 aggregate principal amount of 7.125% Senior Notes. The net proceeds from the offering were used to retire the outstanding Term B Loan balance under our senior credit facility and to pay down the outstanding balance under the revolving credit facility. When the Term B Loan was retired, we settled an existing interest rate swap agreement and realized a gain on settlement of $287,000.
 
However, we do have available borrowing capacity under our revolving credit facility, and we will be subject to variable interest rate risk in the event we have outstanding borrowings under the revolving credit facility in the future. On March 6, 2007, we borrowed approximately $85.0 million, which was subject to variable interest rate risk, under the revolving credit facility to help fund the acquisition of JetStar Consolidated Holdings, Inc.


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ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
Basic Energy Services, Inc.
 
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 
         
    Page
 
  47
  48
  51
  52
  53
  54
  55
  81


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MANAGEMENT’S REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING
 
Management of Basic Energy Services, Inc. (“Basic” or “the Company”) is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting for the Company. As defined by the Securities and Exchange Commission (Rule 13a-15(f) under the Exchange Act of 1934, as amended), internal control over financial reporting is a process designed by, or under the supervision of Basic’s principal executive and principal financial officers and effected by its Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles.
 
The Company’s internal control over financial reporting is supported by written policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the Company’s transactions and dispositions of the Company’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorization of the Company’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the consolidated financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In connection with the preparation of the Company’s annual consolidated financial statements, management has undertaken an assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO Framework). Management’s assessment included an evaluation of the design of the Company’s internal control over financial reporting and testing of the operational effectiveness of those controls.
 
Based on this assessment, management has concluded that as of December 31, 2006, the Company’s internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles.
 
The Company acquired G&L Tool, Ltd., Arkla Cementing, Inc., Globe Well Service, Inc., Hennessey Rental Tools, Inc., Chaparral Service, Inc., Reddline Services, LLC and Rebel Testers, Ltd. during 2006, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006 any internal control evaluation over financial reporting the associated total assets of approximately $113.3 million and total revenues of approximately $65.1 million included in the consolidated financial statements of Basic Energy Services Inc. and subsidiaries as of and for the year ended December 31, 2006.
 
KPMG LLP, the independent registered public accounting firm that audited the Company’s consolidated financial statements included in this report, has issued an attestation report on management’s assessment of internal control over financial reporting.
 
     
     
     
     
/s/  Kenneth V. Huseman

Kenneth V. Huseman
 
/s/  Alan Krenek
Alan Krenek
Chief Executive Officer
  Chief Financial Officer


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Report of Independent Registered Public Accounting Firm
 
The Board of Directors and Stockholders
Basic Energy Services, Inc.:
 
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Basic Energy Services, Inc and subsidiaries (Company) maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
 
The Company acquired G&L Tool, Ltd, Arkla Cementing, Inc., Globe Well Services, Inc., Hennessey Rental Tools Inc., Chaparral Service, Inc., Reddline Services, LLC, and Rebel Testers, Ltd. (collectively the 2006 Excluded Acquisitions) during 2006, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, the 2006 Excluded Acquisitions’ internal control over financial reporting associated with total assets of $113.3 million and total revenues of $65.1 million included in the consolidated financial statements of Basic Energy Services, Inc. and subsidiaries as of and for the year ended December 31, 2006. Our audit of internal control over financial reporting of Basic Energy Services, Inc. also excluded an evaluation of the internal control over financial reporting of the 2006 Excluded Acquisitions.


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We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Basic Energy Services, Inc. as of December 31, 2006 and 2005, and the related consolidated statements of operations and comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2006. Our report dated March 15, 2007 expressed an unqualified opinion on those consolidated financial statements.
 
KPMG LLP
 
Dallas, Texas
March 15, 2007


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Report of Independent Registered Public Accounting Firm
 
The Board of Directors and Stockholders
Basic Energy Services, Inc:
 
We have audited the accompanying consolidated balance sheets of Basic Energy Services, Inc. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations and comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2006. In connection with our audits of the consolidated financial statements, we also have audited the accompanying financial statement schedule. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Basic Energy Services, Inc. and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
 
As discussed in Note 2 to the consolidated financial statements, effective January 1, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), Share Based Payment.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Basic Energy Services, Inc.’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 15, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
 
KPMG LLP
 
Dallas, Texas
March 15, 2007


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Basic Energy Services, Inc.
 
Consolidated Balance Sheets
 
                 
    December 31,  
    2006     2005  
    (In thousands, except share data)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 51,365     $ 32,845  
Trade accounts receivable, net of allowance of $3,963 and $2,775, respectively
    129,381       86,932  
Accounts receivable — related parties
    94       65  
Inventories
    8,409       1,648  
Prepaid expenses
    8,873       3,112  
Other current assets
    3,210       2,060  
Deferred tax assets
    8,432       6,020  
                 
Total current assets
    209,764       132,682  
                 
Property and equipment, net
    475,431       309,075  
Deferred debt costs, net of amortization
    6,536       4,833  
Goodwill
    101,579       48,227  
Other assets
    2,950       2,140  
                 
    $ 796,260     $ 496,957  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
               
Accounts payable
  $ 20,335     $ 13,759  
Accrued expenses
    43,719       33,548  
Income taxes payable
    12,301       7,210  
Current portion of long-term debt
    12,001       7,646  
Other current liabilities
    1,430       1,124  
                 
Total current liabilities
    89,786       63,287  
                 
Long-term debt
    250,742       119,241  
Deferred income
          17  
Deferred tax liabilities
    73,413       53,770  
Other long-term liabilities
    3,069       2,067  
Commitments and contingencies
               
Stockholders’ equity:
               
Preferred stock; $.01 par value; 5,000,000 shares authorized; none designated at December 31, 2006 and 2005, respectively
           
Common stock; $.01 par value; 80,000,000 shares authorized; 38,297,605 issued; 38,297,605 shares outstanding at December 31, 2006 and 33,931,935 issued; 33,785,359 shares outstanding at December 31, 2005
    383       339  
Additional paid-in capital
    256,527       239,218  
Deferred compensation
          (7,341 )
Retained earnings
    122,340       28,654  
Treasury stock, 146,576 shares at December 31, 2005, at cost
          (2,531 )
Accumulated other comprehensive income
          236  
                 
Total stockholders’ equity
    379,250       258,575  
                 
    $ 796,260     $ 496,957  
                 
 
See accompanying notes to consolidated financial statements.


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Basic Energy Services, Inc.
 
Consolidated Statements of Operations and Comprehensive Income
 
                         
    Years Ended December 31  
    2006     2005     2004  
    (Dollars in thousands, except per share amounts)  
 
Revenues:
                       
Well servicing
  $ 330,725     $ 221,993     $ 142,551  
Fluid services
    194,636       132,280       98,683  
Drilling and completion services
    154,412       59,832       29,341  
Well site construction services
    50,375       45,647       40,927  
                         
Total revenues
    730,148       459,752       311,502  
                         
Expenses:
                       
Well servicing
    186,428       137,392       98,058  
Fluid services
    118,378       82,551       65,167  
Drilling and completion services
    74,981       30,900       17,481  
Well site construction services
    35,067       32,000       31,454  
General and administrative, including stock-based compensation of $3,429, $2,890, and $1,587 in 2006, 2005 and 2004, respectively
    81,318       55,411       37,186  
Depreciation and amortization
    62,087       37,072       28,676  
(Gain) loss on disposal of assets
    277       (222 )     2,616  
                         
Total expenses
    558,536       375,104       280,638  
                         
Operating income
    171,612       84,648       30,864  
Other income (expense):
                       
Interest expense
    (17,466 )     (13,065 )     (9,714 )
Interest income
    1,962       405       164  
Loss on early extinguishment of debt
    (2,705 )     (627 )      
Other income (expense)
    169       220       (398 )
                         
Income from continuing operations before income taxes
    153,572       71,581       20,916  
Income tax expense
    (54,742 )     (26,800 )     (7,984 )
                         
Income from continuing operations
    98,830       44,781       12,932  
Discontinued operations, net of tax
                (71 )
                         
Net income available to common stockholders
  $ 98,830     $ 44,781     $ 12,861  
                         
Basic earnings per share of common stock:
                       
Continuing operations
  $ 2.87     $ 1.57     $ 0.46  
Discontinued operations
                 
                         
Net income available to common stockholders
  $ 2.87     $ 1.57     $ 0.46  
                         
Diluted earnings per share of common stock:
                       
Continuing operations
  $ 2.56     $ 1.35     $ 0.42  
Discontinued operations
                 
                         
Net income available to common stockholders
  $ 2.56     $ 1.35     $ 0.42  
                         
Comprehensive Income:
                       
Net income
  $ 98,830     $ 44,781     $ 12,861  
Unrealized gains on hedging activities
    51       193       43  
Less: reclassification adjustment for gain included in net income
    (287 )            
                         
Comprehensive Income:
  $ 98,594     $ 44,974     $ 12,904  
                         
 
See accompanying notes to consolidated financial statements.


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Basic Energy Services, Inc.
 
Consolidated Statements of Stockholders’ Equity
 
                                                                 
                                        Accumulated
       
                Additional
                Retained
    Other
    Total
 
    Common Stock     Paid-in
    Deferred
    Treasury
    Earnings
    Comprehensive
    Stockholders’
 
    Shares     Amount     Capital     Compensation     Stock     (Deficit)     Income     Equity  
    ( In thousands, except share data)  
 
Balance — December 31, 2003
    28,094,435     $ 56     $ 136,524     $ (297 )   $     $ (28,988 )   $     $ 107,295  
Issuance of restricted stock and stock options
    837,500       2       6,278       (6,280 )                        
Amortization of deferred compensation
                      1,587                         1,587  
Unrealized gain on interest rate swap agreement
                                        43       43  
Net income
                                  12,861             12,861  
                                                                 
Balance — December 31, 2004
    28,931,935       58       142,802       (4,990 )           (16,127 )     43       121,786  
Stock-based compensation awards
                5,241       (5,241 )                        
Amortization of deferred compensation
                      2,890                         2,890  
Unrealized gain on interest rate swap agreement
                                        193       193  
Forfeited 11,250 shares at cost of $0
                                               
Effect of stock split
          231       (231 )                              
Proceeds from common stock issuance, net of $2,044 of offering costs
    5,000,000       50       91,406                               91,456  
Purchase of 135,326 of treasury stock
                            (2,531 )                 (2,531 )
Net income
                                  44,781             44,781  
                                                                 
Balance — December 31, 2005
    33,931,935       339       239,218       (7,341 )     (2,531 )     28,654       236       258,575  
Adoption of Statement of Financial Accounting Standard No. 123R
                (7,341 )     7,341                          
Amortization of deferred compensation
                3,429                               3,429  
Unrealized gain on interest rate swap agreement
                                        51       51  
Settlement of interest rate swap agreement
                                        (287 )     (287 )
Offering costs
                (227 )                             (227 )
Exercise of stock warrants
    4,350,000       44       17,357                               17,401  
Purchase of treasury stock
                            (3,218 )                 (3,218 )
Exercise of stock options
    15,670             4,091             5,749       (5,144 )           4,696  
Net Income
                                  98,830             98,830  
                                                                 
Balance — December 31, 2006
    38,297,605     $ 383     $ 256,527     $     $     $ 122,340     $     $ 379,250  
                                                                 
 
See accompanying notes to consolidated financial statements.


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Basic Energy Services, Inc.
 
Consolidated Statements of Cash Flows
 
                         
    Years Ended December 31,  
    2006     2005     2004  
    (In thousands)  
 
Cash flows from operating activities:
                       
Net income
  $ 98,830     $ 44,781     $ 12,861  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation and amortization
    62,087       37,072       28,676  
Accretion on asset retirement obligation
    78       42       33  
Change in allowance for doubtful accounts
    1,188       (333 )     1,150  
Non-cash interest expense
    804       1,062       970  
Non-cash compensation
    3,429       2,890       1,587  
Loss on early extinguishment of debt
    2,705       627        
(Gain) loss on disposal of assets
    277       (222 )     2,616  
Deferred income taxes
    2,611       18,301       7,984  
Changes in operating assets and liabilities, net of acquisitions:
                       
Accounts receivable
    (32,933 )     (27,577 )     (13,841 )
Inventories
    (714 )     (262 )     394  
Prepaid expenses and other current assets
    (6,771 )     304       446  
Other assets
    (450 )     (49 )     (569 )
Accounts payable
    5,128       2,174       3,416  
Excess tax benefits from exercise of employee stock options
    (4,022 )            
Income tax payable
    6,344       7,013        
Deferred income and other liabilities
    (171 )     374       127  
Accrued expenses
    7,258       12,992       689  
                         
Net cash provided by operating activities
    145,678       99,189       46,539  
                         
Cash flows from investing activities:
                       
Purchase of property and equipment
    (104,574 )     (83,095 )     (55,674 )
Proceeds from sale of assets
    5,560       2,436       2,484  
Payments for other long-term assets
    (6,769 )     (1,642 )     (1,113 )
Payments for businesses, net of cash acquired
    (135,568 )     (25,378 )     (19,284 )
                         
Net cash used in investing activities
    (241,351 )     (107,679 )     (73,587 )
                         
Cash flows from financing activities:
                       
Proceeds from debt
    305,546       16,000       43,500  
Payments of debt
    (204,793 )     (81,924 )     (21,236 )
Proceeds from common stock, net of $2,044 of offering costs
          91,456        
Purchase of treasury stock
    (3,218 )     (2,531 )      
Offering costs related to initial public offering
    (227 )            
Excess tax benefits from exercise of employee stock options
    4,022              
Exercise of employee stock options
    674              
Proceeds from exercise stock warrants
    17,401              
Deferred loan costs and other financing activities
    (5,212 )     (1,813 )     (766 )
                         
Net cash provided by financing activities
    114,193       21,188       21,498  
                         
Net increase (decrease) in cash and equivalents
    18,520       12,698       (5,550 )
Cash and cash equivalents — beginning of year
    32,845       20,147       25,697  
                         
Cash and cash equivalents — end of year
  $ 51,365     $ 32,845     $ 20,147  
                         
 
See accompanying notes to consolidated financial statements.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements
December 31, 2006, 2005, and 2004
 
1.   Nature of Operations
 
Basic Energy Services, Inc. provides a 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 primarily provided by Basic’s fleet of equipment. Basic’s operations are concentrated in the major United States onshore oil and gas producing regions in Texas, New Mexico, Oklahoma, Arkansas and Louisiana, and the Rocky Mountain states.
 
2.   Summary of Significant Accounting Policies
 
Principles of Consolidation
 
The accompanying consolidated financial statements include the accounts of Basic and its wholly-owned subsidiaries. Basic has no interest in any other organization, entity, partnership, or contract that could require any evaluation under FASB Interpretation No. 46R or Accounting Research Bulletin No. 51. All intercompany transactions and balances have been eliminated.
 
Estimates and Uncertainties
 
Preparation of the accompanying consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amount of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Areas where critical accounting estimates are made by management include:
 
  •  Depreciation and amortization of property and equipment and intangible assets
 
  •  Impairment of property and equipment and goodwill
 
  •  Allowance for doubtful accounts
 
  •  Litigation and self-insured risk reserves
 
  •  Fair value of assets acquired and liabilities assumed
 
  •  Stock-based compensation
 
  •  Income taxes
 
  •  Asset retirement obligation
 
Revenue Recognition
 
Well Servicing — Well servicing consists primarily of maintenance services, workover services, completion services and plugging and abandonment services. Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Basic prices well servicing by the hour of service performed.
 
Fluid Services — Fluid services consists primarily of the sale, transportation, storage and disposal of fluids used in drilling, production and maintenance of oil and natural gas wells. Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Basic prices fluid services by the job, by the hour or by the quantities sold, disposed of or hauled.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

 
Drilling and Completion Services — Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Basic prices drilling and completion services by the hour, day, or project depending on the type of service performed. When Basic provides multiple services to a customer, revenue is allocated to the services performed based on the fair values of the services.
 
Well Site Construction Services — Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Basic prices well site construction services by the hour, day, or project depending on the type of service performed.
 
Cash and Cash Equivalents
 
Basic considers all highly liquid instruments purchased with a maturity of three months or less to be cash equivalents. Basic maintains its excess cash in various financial institutions, where deposits may exceed federally insured amounts at times.
 
Fair Value of Financial Instruments
 
The carrying value amount of cash, accounts receivable, accounts payable and accrued liabilities approximate fair value due to the short maturity of these instruments. The carrying amount of long-term debt approximates fair value because Basic’s current borrowing rate is based on a variable market rate of interest.
 
Inventories
 
For Rental and Fishing Tools, inventories consisting mainly of grapples, controls, and drill bits are stated at the lower of cost or market, with cost being determined on the average cost method. Other inventories, consisting mainly of rig components, repair parts, drilling and completion materials and gravel, are held for use in the operations of Basic and are stated at the lower of cost or market, with cost being determined on the first-in, first-out (“FIFO”) method.
 
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 and additions and improvements that significantly extend the lives of the assets are capitalized. Upon sale or other retirement of depreciable property, the cost and accumulated depreciation and amortization are removed from the related accounts and any gain or loss is reflected in operations. All property and equipment are depreciated or amortized (to the extent of estimated salvage values) on the straight-line method and the estimated useful lives of the assets are as follows:
 
         
Building and improvements
    20-30 years  
Well servicing units and equipment
    3-15 years  
Fluid services equipment
    5-10 years  
Brine and fresh water stations
    15 years  
Frac/test tanks
    10 years  
Pressure pumping equipment
    5-10 years  
Construction equipment
    3-10 years  
Disposal facilities
    10-15 years  
Vehicles
    3-7 years  
Rental equipment
    3-15 years  
Aircraft
    20 years  
Software and computers
    3 years  


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

The components of a well servicing rig generally require replacement or refurbishment during the well servicing rig’s life and are depreciated over their estimated useful lives, which ranges from 3 to 15 years. The costs of the original components of a purchased or acquired well servicing rig are not maintained separately from the base rig.
 
Impairments
 
In accordance with Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS No. 144”), long-lived assets, such as property, plant, and equipment, and purchased intangibles subject to amortization, are reviewed for impairment at a minimum annually, or whenever, in management’s judgment events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of such assets exceeds the fair value of the assets. Assets to be disposed of would be separately presented in the consolidated balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated. The assets and liabilities, if material, of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the consolidated balance sheet.
 
Goodwill and intangible assets not subject to amortization are tested annually for impairment, and are tested for impairment more frequently if events and circumstances indicate that the asset might be impaired. An impairment loss is recognized to the extent that the carrying amount exceeds the asset’s fair value.
 
Basic had no impairment expense in 2006, 2005 or 2004.
 
Deferred Debt Costs
 
Basic capitalizes certain costs in connection with obtaining its borrowings, such as lender’s fees and related attorney’s fees. These costs are being amortized to interest expense using the effective interest method.
 
Deferred debt costs of approximately $7.1 million at December 31, 2006 and $7.0 million at December 31, 2005, respectively, represent debt issuance costs and are recorded net of accumulated amortization of $523,000, and $2.2 million at December 31, 2006 and December 31, 2005, respectively. Amortization of deferred debt costs totaled approximately $804,000, $1,062,000 and $907,000 for the years ended December 31, 2006, 2005 and 2004, respectively.
 
In 2006, Basic recognized a loss on early extinguishment of debt related to deferred debt costs. (See note 5)
 
Goodwill and Other Intangible Assets
 
Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”) eliminates the amortization of goodwill and other intangible assets with indefinite lives. Intangible assets with lives restricted by contractual, legal, or other means will continue to be amortized over their useful lives. Goodwill and other intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. SFAS No. 142 requires a two-step process for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. If impairment is indicated, then the fair value of the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination. The amount of impairment for goodwill is measured as the excess of its carrying value over its fair value. Basic completed its assessment of goodwill impairment as of the date of adoption and completed a subsequent annual impairment assessment as of December 31 each year thereafter. The assessments did not result in any indications of goodwill impairment.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

 
Intangible assets subject to amortization under SFAS No. 142 consist of non-compete agreements. The gross carrying amount of non-compete agreements subject to amortization totaled approximately $2.9 million and $2.7 million at December 31, 2006 and 2005, respectively. Accumulated amortization related to these intangible assets totaled approximately $1.3 and $1.6 million at December 31, 2006 and 2005, respectively. Amortization expense for the years ended December 31, 2006, 2005 and 2004 was approximately $650,000, $519,000, and $457,000, respectively. Amortization expense for the next five succeeding years is estimated to be approximately $519,000, $418,000, $315,000, $217,000, and $81,000 in 2007, 2008, 2009, 2010, and 2011 respectively.
 
Basic has identified its reporting units to be well servicing, fluid services, drilling and completion services and well site construction services. The goodwill allocated to such reporting units as of December 31, 2006 is $22.1 million, $38.3 million, $37.5 million and $3.7 million, respectively. The change in the carrying amount of goodwill for the year ended December 31, 2006 of $53.4 million relates to goodwill from acquisitions and payments pursuant to contingent earn-out agreements, with approximately $12.1 million, $17.8 million and $23.5 million of goodwill additions relating to the well servicing, fluid services and drilling and completion units, respectively.
 
Stock-Based Compensation
 
On January 1, 2006, Basic adopted Statement of Financial Accounting Standards No. 123 (revised 2004) “Share-Based Payment” (“SFAS No. 123R”). Prior to January 1, 2006, the Company accounted for share-based payments under the recognition and measurement provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock issued to Employees” (“APB No. 25”) which was permitted by Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”).
 
Basic adopted SFAS No. 123R using both the modified prospective method and the prospective method as applicable to the specific awards granted. The modified prospective method was applied to awards granted subsequent to the Company becoming a public company. Awards granted prior to the Company becoming public and which were accounted for under APB No. 25 were adopted by using the prospective method. The results of prior periods have not been restated. Compensation expense cost of the unvested portion of awards granted as a private company and outstanding as of January 1, 2006 will continue to be based upon the intrinsic value method calculated under APB No. 25.
 
Under SFAS No. 123R, entities using the minimum value method and the prospective application are not permitted to provide the pro forma disclosures (as was required under Statement of Financial Accounting Standard No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”)) subsequent to adoption of SFAS No. 123R since they do not have the fair value information required by SFAS No. 123R. Therefore, in accordance with SFAS No. 123R, Basic will no longer include pro forma disclosures that were required by SFAS No. 123.
 
Income Taxes
 
Basic accounts for income taxes based upon Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (“SFAS 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.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

 
Concentrations of Credit Risk
 
Financial instruments, which potentially subject Basic to concentration of credit risk, consist primarily of temporary cash investments and trade receivables. Basic restricts investment of temporary cash investments to financial institutions with high credit standing. Basic’s customer base consists primarily of multi-national and independent oil and natural gas producers. It performs ongoing credit evaluations of its customers but generally does not require collateral on its trade receivables. Credit risk is considered by management to be limited due to the large number of customers comprising its customer base. Basic maintains an allowance for potential credit losses on its trade receivables, and such losses have been within management’s expectations.
 
Basic did not have any one customer which represented 10% or more of consolidated revenue for 2006, 2005, or 2004.
 
Derivative Instruments and Hedging Activities
 
In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), which establishes standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires that an entity recognize all derivative as either assets or liabilities on the balance sheet and measure those instruments at fair value. It establishes conditions under which a derivative may be designated as a hedge, and establishes standards for reporting changes in the fair value of a derivative. Basic adopted SFAS No. 133, as amended by SFAS No. 138, on January 1, 2001. Basic adopted the additional amendments pursuant to SFAS No. 149 for contracts entered or modified after June 30, 2003, if any. At inception, Basic formally documents the relationship between the hedging instrument and the underlying hedged item as well as risk management objective and strategy. Basic assesses, both at inception and on an ongoing basis, whether the derivative used in hedging transition is highly effective in offsetting changes in the fair value of cash flows of the respective hedged item.
 
In May 2004, Basic implemented a cash flow hedge to protect itself from fluctuation in cash flows associated with its credit facility. Changes in fair value of the hedging derivative were initially recorded in other comprehensive income, then recognized in income in the same period(s) in which the hedged transaction affected income. Ineffective portions of a cash flow hedging derivative’s change in fair value were recognized currently in earnings. Basic had no ineffectiveness related to its cash flow hedge in 2005 or 2004. The March 28, 2006 amendment to the 2005 credit facility deleted the requirement to maintain the cash flow hedge upon payoff of the Term B Loans. In April 2006, Basic paid off all outstanding borrowings under the Term B Loan (See note 5). Accordingly in April 2006, the interest rate swap was terminated and the balance remaining in accumulated comprehensive income was recognized in earnings.
 
Asset Retirement Obligations
 
As of January 1, 2003, Basic adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligation” (“SFAS No. 143”). SFAS No. 143 requires Basic 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. 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 settlements of obligations.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

 
Basic owns and operates salt water disposal sites, brine water wells, gravel pits and land farm sites, each of which is subject to rules and regulations regarding usage and eventual closure. The following table reflects the changes in the liability during years ended December 31, 2006 and 2005 (in thousands):
 
         
Balance, December 31, 2004
  $ 473  
Additional asset retirement obligations recognized through acquisitions
    74  
Accretion expense
    42  
Settlements
    (20 )
         
Balance, December 31, 2005
  $ 569  
Additional asset retirement obligations recognized through acquisitions
    289  
Accretion expense
    78  
Settlements
    (78 )
Increase in asset retirement obligations due to change in estimate
    479  
         
Balance, December 31, 2006
  $ 1,336  
         
 
Environmental
 
Basic is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require Basic to remove or mitigate the adverse environmental effects of disposal or release of petroleum, chemical and other substances at various sites. Environmental expenditures are expensed or capitalized depending on the future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated.
 
Litigation and Self-Insured Risk Reserves
 
Basic estimates its reserves related to litigation and self-insured risks based on the facts and circumstances specific to the litigation and self-insured claims and its past experience with similar claims in accordance with Statement of Financial Accounting Standard No. 5 “Accounting for Contingencies.” Basic maintains accruals in the consolidated balance sheets to cover self-insurance retentions (See note 7).
 
Comprehensive Income
 
Basic follows the provisions of Statement of Financial Accounting Standards No. 130, “Reporting of Comprehensive Income” (“SFAS No. 130”). SFAS No. 130 establishes standards for reporting and presentation of comprehensive income and its components. SFAS No. 130 requires all items that are required to be recognized under accounting standards as components of comprehensive income to be reported in a financial statement that is displayed with the same prominence as other financial statements. In accordance with the provisions of SFAS No. 130, gains and losses on cash flow hedging derivatives, to the extent effective, are included in other comprehensive income (loss).
 
Reclassifications
 
Certain reclassifications of prior year financial statement amounts have been made to conform to current year presentations.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

 
Recent Accounting Pronouncements
 
In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (SAB 108), Considering the Effects of Prior Year Misstatements when Quantifying Misstatement in Current Year Financial Statements. The bulletin’s interpretations address diversity in practice in quantifying financial statement misstatements and the potential under current practice for the build up of improper amounts on the balance sheet. Basic adopted the interpretation in the fourth quarter of 2006. The adoption of SAB 108 did not have a material impact on the Company’s financial position, cash flows, or results of operations.
 
In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation No. 48 (FIN 48), Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109, Accounting for Income Taxes. The interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken, in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties accounting in interim periods, disclosure and transition. The interpretation is effective for fiscal years beginning after December 15, 2006. The cumulative effect of applying the provisions of this interpretation, which is required to be reported separately as an adjustment to our opening balance of retained earnings in 2007, is currently not expected to have a material impact on our results of operations, financial position or cash flows.
 
In December 2004, the FASB issued SFAS No. 123R. As discussed under Note 2, “Stock-Based Compensation,” Basic adopted the provisions of SFAS No. 123R on January 1, 2006.
 
3.   Acquisitions
 
In 2006, 2005 and 2004, Basic acquired either substantially all of the assets or all of the outstanding capital stock of each of the following businesses, each of which were accounted for using the purchase method of accounting (in thousands):
 
                 
          Total Cash Paid
 
          (net of cash
 
    Closing Date     acquired)  
 
Action Trucking — Curtis Smith, Inc. 
    April 27, 2004     $ 821  
Rolling Plains
    May 30, 2004       3,022  
Perry’s Pump Service
    May 30, 2004       1,379  
Lone Tree Construction
    June 23, 2004       211  
Hayes Services
    July 1, 2004       1,595  
Western Oil Well
    July 30, 2004       854  
Summit Energy
    August 19, 2004       647  
Energy Air Drilling
    August 30, 2004       6,500  
AWS Wireline
    November 1, 2004       4,255  
                 
Total 2004
          $ 19,284  
                 


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

                 
          Total Cash Paid
 
          (net of cash
 
    Closing Date     acquired)  
 
R & R Hot Oil Service
    January 5, 2005       1,702  
Premier Vacuum Service, Inc. 
    January 28, 2005       1,009  
Spencer’s Coating Specialist
    February 9, 2005       619  
Mark’s Well Service
    February 25, 2005       579  
Max-Line, Inc. 
    April 28, 2005       1,498  
MD Well Service, Inc. 
    May 17, 2005       4,478  
179 Disposal, Inc. 
    August 4, 2005       1,729  
Oilwell Fracturing Services, Inc. 
    October 11, 2005       13,764  
                 
Total 2005
          $ 25,378  
                 
LeBus Oil Field Services Co. 
    January 31, 2006     $ 24,618  
G&L Tool, Ltd. 
    February 28, 2006       58,514  
Arkla Cementing, Inc. 
    March 27, 2006       5,012  
Globe Well Service, Inc. 
    May 30, 2006       11,674  
Hydro-Static Tubing Testers, Inc. 
    July 6, 2006       1,143  
Hennessey Rental Tools, Inc. 
    August 1, 2006       8,205  
Stimulation Services, LLC
    August 1, 2006       4,500  
Chaparral Service, Inc. 
    August 15, 2006       17,605  
Reddline Services, LLC
    August 24, 2006       1,900  
Rebel Testers, Ltd. 
    September 14, 2006       2,397  
                 
Total 2006
          $ 135,568  
                 
 
The operations of each of the acquisitions listed above are included in Basic’s statement of operations as of each respective closing date. The acquisition of G&L Tool, Ltd in 2006 is deemed significant and is discussed below in further detail.
 
G&L Tool, Ltd.
 
On February 28, 2006, Basic acquired substantially all of the assets of G&L Tool Ltd. (G&L) for $58.5 million plus a contingent earn-out payment not to exceed $21.0 million. The contingent earn-out payment will be equal to fifty percent of the amount by which the annual EBITDA (as defined in the purchase agreement) earned by the G&L assets exceeds an annual targeted EBITDA. There is no guarantee or assurance that the targeted EBITDA will be reached. This acquisition provided a platform to expand into the rental and fishing tool market operations. The cost of the G&L acquisition was allocated $40.8 million to property and equipment, $5.2 million to inventory, $12.5 million to goodwill, all of which is expected to be deductible for tax purposes, and $51,000 to non-compete agreements. During the year, an adjustment was made to the purchase price allocation which increased the value of inventory by $5.2 million and reduced fixed assets and goodwill by $3.8 million and $1.4 million, respectively. This allocation adjustment was made as a result of an increase to the fair market value of the asset and the increased ability for tracking certain assets obtained in the acquisition.

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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

 
The following unaudited pro-forma results of operations have been prepared as though the G&L acquisition had been completed on January 1, 2005. Pro forma amounts are based on the final purchase price allocations of the significant acquisitions and are not necessarily indicative of the results that may be reported in the future (in thousands, except per share data).
 
                 
    Twelve Months Ended December 31,  
    2006     2005  
 
Revenues
  $ 739,641     $ 499,177  
Net income
  $ 101,294     $ 52,527  
Earnings per common share — basic
  $ 2.94     $ 1.84  
Earnings per common share — diluted
  $ 2.62     $ 1.58  
 
Basic does not believe the pro-forma effect of the remainder of the acquisitions completed in 2004, 2005 or 2006 is material, either individually or when aggregated, to the reported results of operations.
 
Contingent Earn-out Arrangements and Final Purchase Price Allocations
 
Contingent earn-out arrangements are generally arrangements entered into on certain acquisitions to encourage the owner/manager to continue operating and building the business after the purchase transaction. The contingent earn-out arrangements of the related acquisitions are generally linked to certain financial measures and performance of the assets acquired in the various acquisitions. All amounts paid or reasonably accrued for related to the contingent earn-out payments are reflected as increases to the goodwill associated with the acquisitions of New Force Energy Services, Rolling Plains, Premier Vacuum Services and G&L Tool. Payments related to contingent earn-out agreements on Chaparral Services and Redline Services will be reflected as compensation expense when paid or accrued.
 
The following presents a summary of acquisitions that have a contingent earn-out arrangement in effect as of December 31, 2006 (in thousands):
 
                     
        Maximum
       
        Exposure of
       
    Termination date of
  Contingent
    Amount Paid or
 
    Contingent Earn-out
  Earn-out
    Accrued Through
 
Acquisition
  Arrangement   Arrangement     December 31, 2006  
 
New Force Energy Services
  January 27, 2008   $ 2,700     $ 2,191  
Rolling Plains
  April 30, 2009     *       3,157  
Premier Vacuum Services, Inc. 
  February 1, 2010     900       515  
Chaparral Services, Inc. 
  August 31, 2011     1,000       67  
Reddline Services LLC
  August 30, 2011     625       42  
G&L Tool, Ltd. 
  February 28, 2011     21,000       2,994  
                     
        $ 26,225     $ 8,966  
                     
 
 
* Basic will pay to the sellers an amount for each of the five consecutive 12 month periods beginning on May 1, 2004 equal to 50% of the amount by which annual EBITDA exceeds an annual targeted EBITDA. There is no guarantee or assurance that the targeted EBITDA will be reached.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

 
4.   Property and Equipment
 
Property and equipment consists of the following (in thousands):
 
                 
    December 31,
    December 31,
 
    2006     2005  
 
Land
  $ 2,913     $ 1,902  
Buildings and improvements
    13,293       8,634  
Well service units and equipment
    283,084       199,070  
Fluid services equipment
    87,139       59,104  
Brine and fresh water stations
    8,710       7,746  
Frac/test tanks
    49,582       31,475  
Pressure pumping equipment
    67,540       31,101  
Construction equipment
    27,342       24,224  
Disposal facilities
    25,913       16,828  
Vehicles
    32,215       23,329  
Rental equipment
    32,548       6,519  
Aircraft
    4,119       3,236  
Other
    8,807       8,602  
                 
      643,205       421,770  
Less accumulated depreciation and amortization
    167,774       112,695  
                 
Property and equipment, net
  $ 475,431     $ 309,075  
                 
 
Basic is obligated under various capital leases for certain vehicles and equipment that expire at various dates during the next five years. The gross amount of property and equipment and related accumulated amortization recorded under capital leases and included above consists of the following (in thousands):
 
                 
    December 31,
    December 31,
 
    2006     2005  
 
Light vehicles
  $ 23,843     $ 17,912  
Well service units and equipment
    808        
Fluid services equipment
    26,460       14,011  
Pressure pumping equipment
    1,820        
Construction equipment
    3,559       1,300  
                 
      56,490       33,223  
Less accumulated amortization
    13,785       8,474  
                 
    $ 42,705     $ 24,749  
                 
 
Amortization of assets held under capital leases of approximately $5.3 million, $1.3 million, and $1.8 million for the years ended December 31, 2006, 2005, and 2004, respectively, is included in depreciation and amortization expense in the consolidated statements of operations.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

 
5.   Long-Term Debt
 
Long-term debt consists of the following (in thousands):
 
                 
    December 31,
    December 31,
 
    2006     2005  
 
Credit Facilities:
               
Term B Loan
  $     $ 90,000  
Revolver
          16,000  
7.125% Senior Notes
    225,000        
Capital leases and other notes
    37,743       20,887  
                 
      262,743       126,887  
Less current portion
    12,001       7,646  
                 
    $ 250,742     $ 119,241  
                 
 
Senior Notes
 
On April 12, 2006, the Company issued $225.0 million of 7.125% Senior Notes due April 2016 in a private placement. Proceeds from the sale of the Senior Notes were used to retire the outstanding balance on the $90.0 million Term B Loan and to pay down approximately $96.0 million under the revolving credit facility, which amounts may be reborrowed to fund future acquisitions or for general corporate purposes. Interest payments on the Senior Notes are due semi-annually, on April 15 and October 15, commencing on October 15, 2006. The Senior Notes are unsecured. Under the terms of the sale of the Senior Notes, the Company was required to take appropriate steps to offer to exchange other Senior Notes with the same terms that have been registered with the Securities and Exchange Commission for the private placement Senior Notes. The Company completed the exchange offer for all of the Senior Notes on October 16, 2006.
 
The Senior Notes are redeemable at the option of the Company on or after April 15, 2011 at the specified redemption price as described in the Indenture. Prior to April 15, 2011, the Company may redeem, in whole or in part, at a redemption price equal to 100% of the principal amount of the Senior Notes redeemed plus the Applicable Premium as defined in the Indenture. Prior to April 15, 2009, the Company may redeem up to 35% of the Senior Notes with the proceeds of certain equity offerings at a redemption price equal to 107.125% of the principal amount of the 7.125% Senior Notes, plus accrued and unpaid interest to the date of redemption. This redemption must occur less than 90 days after the date of the closing of any such equity offering.
 
Following a change of control, as defined in the Indenture, the Company will be required to make an offer to repurchase all or any portion of the 7.125% Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest to the date of repurchase.
 
Pursuant to the Indenture, the Company is subject to covenants that limit the ability of the Company and its restricted subsidiaries to, among other things: incur additional indebtedness, pay dividends or repurchase or redeem capital stock, make certain investments, incur liens, enter into certain types of transactions with affiliates, limit dividends or other payments by restricted subsidiaries, and sell assets or consolidate or merge with or into other companies. These limitations are subject to a number of important qualifications and exceptions set forth in the Indenture. The Company was in compliance with the restrictive covenants at December 31, 2006.
 
As part of the issuance of the above-mentioned Senior Notes, the Company incurred debt issuance costs of approximately $4.6 million, which are being amortized to interest expense using the effective interest method over the term of the Senior Notes.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

 
The Senior Notes are jointly and severally guaranteed by the Company and all of its restricted subsidiaries. Basic Energy Services, Inc., the ultimate parent company, does not have any independent operating assets or operations. Subsidiaries other than the restricted subsidiaries that are guarantors are minor.
 
2005 Credit Facility
 
On December 15, 2005, Basic entered into a $240 million Third Amended and Restated Credit Agreement with a syndicate of lenders (“2005 Credit Facility”), which refinanced all of its then existing credit facilities. The 2005 Credit Facility, as amended effective March 28, 2006, provides for a $90 million Term B Loan (“2005 Term B Loan”) and a $150 million revolving line of credit (“Revolver”). The commitment under the Revolver allows for (a) the borrowing of funds (b) issuance of up to $30 million of letters of credit and (c) $2.5 million of swing-line loans (next day borrowing). The amounts outstanding under the 2005 Term B Loan require quarterly amortization at various amounts during each quarter with all amounts outstanding on December 15, 2011 being due and payable in full. 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 Basic’s tangible and intangible assets. Basic incurred approximately $1.8 million in debt issuance costs in obtaining the 2005 Credit Facility.
 
At Basic’s option, borrowings under the 2005 Term B Loan bear interest at either the (a) “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus .5% per annum) plus 1% or (b) the LIBOR rate plus 2.0%. At December 31, 2006, Basic had paid outstanding borrowings under the Term B Loan in full; therefore, a Term B Loan weighted average interest rate was not calculated. However, at December 31, 2005, Basic’s weighted average interest rate on its Term B Loan was 6.4%.
 
At Basic’s option, borrowings under the 2005 Revolver bear interest at either the (a) “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus .5% per annum) plus a margin ranging from .50% to 1.25% or (b) the LIBOR rate plus a margin ranging from 1.5% to 2.25%. The margins vary depending on Basic’s leverage ratio. At December 31, 2006, Basic’s margin on Alternative Base Rates and LIBOR tranches was .75% and 1.75%, respectively. Fees on the letters of credit are due quarterly on the outstanding amount of the letters of credit at a rate ranging from 1.5% to 2.25% for participation fees and .125% for fronting fees. A commitment fee is due quarterly on the available borrowings under the Revolver at rates ranging from .375% to .5%.
 
At December 31, 2006, Basic, under its Revolver, had no outstanding borrowings and $10.6 million of letters of credit and no amounts outstanding in swing-line loans. At December 31, 2006 and December 31, 2005 Basic had availability under its Revolver of $139.4 million and $124.4 million, respectively.
 
Pursuant to the 2005 Credit Facility, Basic must apply proceeds to reduce principal outstanding under the 2005 Revolver from (a) individual assets sales greater than $2 million or $7.5 million in the aggregate on an annual basis, and (b) 50% of the proceeds from any equity offering. The 2005 Credit Facility required Basic to enter into an interest rate hedge, through May 28, 2006 on at least $65 million of Basic’s then outstanding indebtedness. The March 28, 2006 amendment deleted this requirement upon payoff of the Term B Loans. In April 2006, Basic paid off all outstanding borrowings under the Term B Loan. Paydowns on the 2005 Term B Loan may not be reborrowed.
 
The 2005 Credit Facility contains various restrictive covenants and compliance requirements, which include (a) limiting of the incurrence of additional indebtedness, (b) restrictions on mergers, sales or transfers of assets without the lenders’ consent, (c) limitation on dividends and distributions and (d) various financial covenants, including (1) a maximum leverage ratio of 3.5 to 1.0 reducing over time to 3.25 to 1.0, (2) a minimum interest coverage ratio of 3.0 to 1.0 and (e) limitations on capital expenditures in any period of four consecutive quarters in excess of 20% of Consolidated Net Worth unless certain criteria are met. At December 31, 2006, Basic was in compliance with its covenants.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

 
Other Debt
 
Basic has a variety of other capital leases and notes payable outstanding that are generally customary in its business. None of these debt instruments are material individually or in the aggregate.
 
As of December 31, 2006 the aggregate maturities of debt, including capital leases, for the next five years and thereafter are as follows (in thousands):
 
                 
    Debt     Capital Leases  
 
2007
  $     $ 12,001  
2008
          10,891  
2009
          8,563  
2010
          5,719  
2011
          569  
Thereafter
    225,000        
                 
    $ 225,000     $ 37,743  
                 
 
Basic’s interest expense consisted of the following (in thousands):
 
                         
    Year Ended December 31,  
    2006     2005     2004  
 
Cash payments for interest
  $ 12,587     $ 11,421     $ 8,159  
Commitment and other fees paid
    566       185     $ 25  
Amortization of debt issuance costs
    805       1,062       970  
Accrued interest on senior notes
    3,384              
Other
    124       397       560  
                         
    $ 17,466     $ 13,065     $ 9,714  
                         
 
Losses on Extinguishment of Debt
 
In April of 2006, Basic recognized a loss on the early extinguishment of debt. Basic wrote off unamortized debt issuance costs of approximately $2.7 million, which related to the prepayment of the Term B Loan.
 
In 2005, Basic recognized a loss on the early extinguishment of debt. Basic wrote-off unamortized debt issuance costs of approximately $627,000.
 
6.   Income Taxes
 
Income tax provision (benefit) was allocated as follows (in thousands):
 
                         
    Years Ended December 31,  
    2006     2005     2004  
 
Income from continuing operations
  $ 54,742     $ 26,800     $ 7,984  
Discontinued operations
                (38 )
                         
    $ 54,742     $ 26,800     $ 7,946  
                         


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

Income tax expense attributable to income from continuing operations consists of the following (in thousands):
 
                         
    Years Ended December 31,  
    2006     2005     2004  
 
Current:
                       
Federal
  $ 50,499     $ 8,048     $  
State
    1,632       451        
                         
Total
  $ 52,131     $ 8,499     $  
                         
Deferred:
                       
Federal
  $ 3,594     $ 17,335     $ 7,563  
State
    (983 )     966       421  
                         
Total
  $ 2,611     $ 18,301     $ 7,984  
                         
 
Basic paid Federal income taxes of $40,200,000 during 2006 and $1,325,000 during 2005. No Federal income taxes were paid or received in 2004.
 
Reconciliation between the amount determined by applying the Federal statutory rate of 35% to the income from continuing operations with the provision for income taxes is as follows (in thousands):
 
                         
    Years Ended December 31,  
    2006     2005     2004  
 
Statutory Federal income tax
  $ 53,750     $ 25,053     $ 7,321  
Meals and entertainment
    430       324       265  
State taxes, net of Federal benefit
    778       1,415       421  
Change in tax rates
                 
Changes in estimates and other
    (216 )     8       (23 )
                         
    $ 54,742     $ 26,800     $ 7,984  
                         


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are as follows (in thousands):
 
                 
    December 31,  
    2006     2005  
 
Deferred tax assets:
               
Receivables allowance
  $ 1,461     $ 1,025  
Asset retirement obligation
    234       210  
Accrued liabilities
    6,659       5,181  
Operating loss carryforward
    1,412       1,856  
Deferred Compensation
    1,790       1,140  
                 
Total deferred tax assets
    11,556       9,412  
Deferred tax liabilities:
               
Property and equipment
    (73,926 )     (55,768 )
Goodwill and intangibles
    (2,611 )     (1,208 )
Interest rate derivative
          (186 )
                 
Total deferred tax liabilities
    (76,537 )     (57,162 )
                 
Net deferred tax liability
    (64,981 )     (47,750 )
                 
Recognized as:
               
Deferred tax assets — current
    8,432       6,020  
Deferred tax liabilities — non-current
    (73,413 )     (53,770 )
                 
Net deferred tax liability
  $ (64,981 )   $ (47,750 )
                 
 
Basic provides a valuation allowance when it is more likely than not that some portion of the deferred tax assets will not be realized. There was no valuation allowance necessary as of December 31, 2006 or 2005.
 
As of December 31, 2006, Basic had approximately $4.0 million of net operating loss carryforwards (“NOL”) for U.S. federal income tax purposes related to the preacquisition period of FESCO, which are subject to an annual limitation of approximately $900,000. The carryforwards begin to expire in 2017.
 
7.   Commitments and Contingencies
 
Environmental
 
Basic is subject to various federal, state and local environmental laws and regulations that establish standards and requirements for protection of the environment. Basic cannot predict the future impact of such standards and requirements which are subject to change and can have retroactive effectiveness. Basic continues to monitor the status of these laws and regulations. Management believes that the likelihood of the disposition of any of these items resulting in a material adverse impact to Basic’s financial position, liquidity, capital resources or future results of operations is remote.
 
Currently, Basic has not been fined, cited or notified of any environmental violations that would have a material adverse effect upon its financial position, liquidity or capital resources. However, management does recognize that by the very nature of its business, material costs could be incurred in the near term to bring Basic into total compliance. The amount of such future expenditures is not determinable due to several factors including the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions which may be required, the determination of Basic’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnification.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

 
Litigation
 
From time to time, Basic is a party to litigation or other legal proceedings that Basic considers to be a part of the ordinary course of business. Basic is not currently involved in any legal proceedings that it considers probable or reasonably possible, individually or in the aggregate, to result in a material adverse effect on its financial condition, results of operations or liquidity.
 
Operating Leases
 
Basic leases certain property and equipment under non-cancelable operating leases. The term of the operating leases generally range from 12 to 60 months with varying payment dates throughout each month.
 
As of December 31, 2006, the future minimum lease payments under non-cancelable operating leases are as follows (in thousands):
 
         
Year Ended December 31,
     
 
2007
  $ 2,551  
2008
    2,360  
2009
    2,098  
2010
    1,493  
2011
    1,200  
Thereafter
    3,904  
 
Rent expense approximated $13.9 million, $7.0 million, and $5.6 million for 2006, 2005 and 2004, respectively.
 
Basic leases rights for the use of various brine and fresh water wells and disposal wells ranging in terms from month-to-month up to 99 years. The above table reflects the future minimum lease payments if the lease contains a periodic rental. However, the majority of these leases require payments based on a royalty percentage or a volume usage.
 
Employment Agreements
 
Under the employment agreement with Mr. Huseman, Chief Executive Officer and president of Basic, effective December 31, 2006 through December 31, 2009, Mr. Huseman will be entitled to an annual salary of $400,000 and a minimum annual bonus of $50,000. Under this employment agreement, Mr. Huseman is eligible from time to time to receive grants of stock options and other long-term equity incentive compensation under our Amended and Restated 2003 Incentive Plan. In addition, upon a qualified termination of employment, Mr. Huseman would be entitled to three times his base salary plus his current annual incentive target bonus for the full year in which the termination of employment occurred. If employment is terminated for certain reasons within the six months preceding or the twelve months following the change of control of our Company, Mr. Huseman would be entitled to a lump sum severance payment equal to three times the sum of his base salary plus the higher of (i) his current incentive target bonus for the full year in which the termination of employment occurred or (ii) the highest annual incentive bonus received by him for any of the last three fiscal years.
 
Basic has entered into employment agreements with various other executive officers of Basic that range in term up through December 2007. Under these agreements, if the officer’s employment is terminated for certain reasons, he would be entitled to a lump sum severance payment equal to amounts ranging from 1.5 times to 0.75 times the sum of his base salary plus his current annual incentive target bonus for the full year in which the termination occurred . If employment is terminated for certain reasons within the six months preceding or the twelve months following the chance of control of our Company, he would be entitled to a lump sum severance payment equal to three times the sum of his base salary plus the higher of (i) his current incentive target bonus for the full year in


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

which the termination of employment occurred or (ii) the highest annual incentive bonus received by him for any of the last three fiscal years.
 
Self-Insured Risk Accruals
 
Basic is self-insured up to retention limits as it relates to workers’ compensation and medical and dental coverage of its employees. Basic, generally, maintains no physical property damage coverage on its workover rig fleet, with the exception of certain of its 24-hour workover rigs and newly manufactured rigs. Basic has deductibles per occurrence for workers’ compensation and medical and dental coverage of $150,000 and $150,000, respectively. Basic has lower deductibles per occurrence for automobile liability and general liability. Basic maintains accruals in the accompanying consolidated balance sheets related to self-insurance retentions by using third-party data and claims history.
 
At December 31, 2006 and December 31, 2005, self-insured risk accruals totaled approximately $12.6 million, net of $652,000 receivable for medical and dental coverage, and $9.5 million, net of $127,000 receivable for medical and dental coverage, respectively.
 
8.   Stockholders’ Equity
 
Common Stock
 
In February 2002, a group of related investors purchased a total of 3,000,000 shares of Basic’s common stock at a purchase price of $4 per share, for a total purchase price of $12 million. As part of the purchase, 600,000 common stock warrants were issued in connection with this transaction, the fair value of which was approximately $1.2 million (calculated using an option valuation model). The warrants allow the holder to purchase 600,000 shares of Basic’s common stock at $4 per share. The warrants were exercisable in whole or in part after June 30, 2002 and prior to February 13, 2007.
 
In June of 2002 Basic granted 3,750,000 common stock warrants to acquire a total of 3,750,000 shares of common stock at a price of $4 per share, exercisable in whole or in part from June 30, 2002 through June 30, 2007.
 
In February 2004, Basic granted certain officers and directors 837,500 restricted shares of common stock. The shares vest 25% per year for four years from the award date and are subject to other vesting and forfeiture provisions. The estimated fair value of the restricted shares was $5.8 million at the date of the grant and was recorded as deferred compensation, a component of stockholders’ equity. This amount is being charged to expense over the respective vesting period and totaled approximately $1.3 million, $1.6 million and $1.3 million for the years ended December 31, 2006, 2005 and 2004.
 
In December 2005, Basic issued 5,000,000 shares of common stock during the Company’s Initial Public Offering to a group of investors for $100 million or $20 per share. After deducting fees, this resulted in net proceeds to Basic totaling approximately $91.5 million.
 
On October 5, 2006, all outstanding warrants were exercised to purchase an aggregate of 4,350,000 shares of Basic’s common stock. In connection with the exercise of the warrants, Basic received an aggregate of $17.4 million from the Holders in satisfaction of the exercise price of the warrants (representing an exercise price of $4.00 per share of Basic’s common stock acquired).
 
During year ended 2006, Basic issued 293,350 shares of common stock from treasury stock for the exercise of stock options. Also, Basic issued 15,670 shares of newly-issued common stock for the exercise of stock options.
 
Preferred Stock
 
At December 31, 2006 and 2005, Basic had 5,000,000 shares of $.01 par value preferred stock authorized, of which none is designated.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

 
9.   Stockholders’ Agreement
 
Basic has a Stockholders’ Agreement, as amended on April 2, 2004 (“Stockholders’ Agreement”), which provides for rights relating to the shares of our stockholders and certain corporate governance matters.
 
The Stockholders’ Agreement provides for participation rights of the other stockholders to require affiliates of DLJ Merchant Banking to offer to include a specified percentage of their shares whenever affiliates of DLJ Merchant Banking sell their shares for value, other than a public offering or a sale in which all of the parties to the Stockholders’ Agreement agree to participate. The Stockholders’ Agreement also contains “drag-along” rights. The “drag-along” rights entitle the affiliated of DLJ Merchant Banking to require the other stockholders who are a party to this agreement to sell a portion of their shares of common stock and common stock equivalents in the sale in any proposed to sale of shares of common stock and common stock equivalents representing more than 50% of such equity interest held by the affiliates of DLJ Merchant Banking to a person or persons who are not an affiliate of them.
 
The Stockholders’ Agreement currently provides for demand and piggyback registration rights following the completion of our 2005 initial public offering of Basic’s common stock.
 
10.   Incentive Plan
 
In May 2003, Basic’s board of directors and stockholders approved the Basic 2003 Incentive Plan (as amended effective April 22, 2005) (the “Plan”), which provides for granting of incentive awards in the form of stock options, restricted stock, performance awards, bonus shares, phantom shares, cash awards and other stock-based awards to officers, employees, directors and consultants of Basic. The Plan assumed awards of the plans of Basic’s successors that were awarded and remained outstanding prior to adoption of the Plan. The Plan provides for the issuance of 5,000,000 shares. The Plan is administered by the Plan committee, and in the absence of a Plan committee, by the Board of Directors, which determines the awards, and the associated terms of the awards and interprets its provisions and adopts policies for implementing the Plan. The number of shares authorized under the Plan and the number of shares subject to an award under the Plan will be adjusted for stock splits, stock dividends, recapitalizations, mergers and other changes affecting the capital stock of Basic.
 
On March 15, 2006, the board of directors granted various employees and directors options to purchase 418,000 shares of common stock of Basic at an exercise price of $26.84 per share. All of the 418,000 options granted in 2006 vest over a five-year period and expire 10 years from the date they were granted. Option awards are generally granted with an exercise price equal to the market price of the Company’s stock at the date of grant.
 
The fair value of each option award is estimated on the date of grant using the Black-Scholes-Merton option-pricing model that uses the subjective assumptions noted in the following table. Since the Company has only been public since December 2005, expected volatility for options granted during 2006 is an implied volatility based upon a peer group. When the Company has sufficient historical data to calculate expected volatility, the Company will use its’ own historical data to calculate expected volatility. The expected term of options granted represents the period of time that options granted are expected to be outstanding. For options granted in 2006, the Company used the simplified method to calculate the expected term. The risk-free rate for periods within the contractual life of the options is based on the U.S. Treasury yield curve in effect at the time of grant. The estimates involve inherent uncertainties and the application of management judgment. In addition, we are required to estimate the expected forfeiture rate and only recognize expense for those options expected to vest. During the years ended December 31, 2006, 2005 and 2004, compensation expense related to share-based arrangements was approximately $3.4 million, $2.9 million and $1.6 million , respectively. For compensation expense recognized during the years ended


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

December 31, 2006, 2005 and 2004 Basic recognized a tax benefit of approximately $1,222,000, $1,082,000 and $606,000, respectively.
 
The fair value of each option award accounted for under SFAS No. 123R is estimated on the date of grant using the Black-Scholes-Merton option-pricing model that uses the assumptions noted in the following table:
 
                         
    Years Ended December 31,  
    2006     2005     2004  
 
Risk-free interest rate
    4.7 %     4.2% - 4.5 %     4.0% - 4.7 %
Expected term
    6.65       6.00 - 10.00       10.0  
Expected volatility
    47.0 %     0.0 %     0.0 %
Expected dividend yield
                 
 
Options granted under the Plan expire 10 years from the date they are granted, and generally vest over a three-to-five year service period.
 
The following table reflects the summary of stock options outstanding at December 31, 2006 and the changes during the twelve months then ended:
 
                                 
                Weighted
       
          Weighted
    Average
    Aggregate
 
    Number of
    Average
    Remaining
    Instrinsic
 
    Options
    Exercise
    Contractual
    Value
 
    Granted     Price     Term (Years)     (000’s)  
 
Non-statutory stock options:
                               
Outstanding, beginning of period
    2,445,800     $ 5.44                  
Options granted
    418,000     $ 26.84                  
Options forfeited
    (97,000 )   $ 10.46                  
Options exercised
    (309,020 )   $ 4.10                  
Options expired
        $                  
                                 
Outstanding, end of period
    2,457,780     $ 9.05       7.20     $ 39,228  
                                 
Exercisable, end of period
    1,142,613     $ 4.35       5.75     $ 23,199  
                                 
Vested or expected to vest, end of period
    2,439,080     $ 8.91       7.18     $ 39,228  
                                 
 
The weighted-average grant date fair value of share options granted during the years ended December 31, 2006, 2005 and 2004 was $14.47, $8.00 and $3.14, respectively. The total intrinsic value of share options exercised during the years ended December 31, 2006, 2005 and 2004 was approximately $7.1 million, $0 and $0, respectively.
 
A summary of the status of the Company’s non-vested share grants at December 31, 2006 and changes during the year ended December 31, 2006 is presented in the following table:
 
                 
          Weighted Average
 
    Number of
    Grant Date Fair
 
Nonvested Shares
  Shares     Value per Share  
 
Nonvested at beginning of period
    591,875     $ 6.98  
Granted during period
           
Vested during period
    (230,625 )     6.98  
Forfeited during period
           
                 
Nonvested at end of period
    361,250     $ 6.98  
                 


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

As of December 31, 2006, there was $8.8 million of total unrecognized compensation related to non-vested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 3.06 years. The total fair value of share-based awards vested during the years ended December 31, 2006, 2005 and 2004 was approximately $12.3 million, $5.3 million and $2.6 million, respectively.
 
Cash received from share option exercises under the incentive plan was approximately $671,000, $0 and $0 for the years ended December 31, 2006, 2005 and 2004, respectively. The actual tax benefit realized for the tax deductions from options exercised was $4.0 million, $0 and $0, respectively, for the years ended December 31, 2006, 2005 and 2004.
 
The Company has a history of issuing Treasury and newly-issued shares to satisfy share option exercises.
 
11.   Related Party Transactions
 
Basic had receivables from employees of approximately $94,000 and $65,000 as of December 31, 2006 and December 31, 2005, respectively. During 2006, Basic entered into a lease agreement with Darle Vuelta Cattle Co., LLC, an affiliate of the Chief Executive Officer, for approximately $69,000. The term of the lease is five years and will continue on a year-to-year basis unless terminated by either party.
 
12.   Profit Sharing Plan
 
Basic has a 401(k) profit sharing plan that covers substantially all employees with more than 90 days of service. Employees may contribute up to their base salary not to exceed the annual Federal maximum allowed for such plans. Basic makes a matching contribution proportional to each employee’s contribution. Employee contributions are fully vested at all times. Employer matching contributions vest incrementally, with full vesting occurring after five years of service. Employer contributions to the 401(k) plan approximated $2.5 million, $468,000 and $363,000 in 2006, 2005 and 2004, respectively.
 
13.   Deferred Compensation Plan
 
In April 2005, Basic established a deferred compensation plan for certain employees. Participants may defer up to 50% of their salary and 100% of any cash bonuses. Basic makes matching contributions of 100% of the first 3% of the participants’ deferred pay and 50% of the next 2% of the participants’ deferred pay to a maximum match of $8,800 per year. Employer matching contributions and earnings thereon are subject to a five-year vesting schedule with full vesting occurring after five years of service. Employer contributions to the deferred compensation plan approximated $199,000, $56,000, and $0 in 2006, 2005 and 2004, respectively.
 
14.   Earnings Per Share
 
Basic presents earnings per share information in accordance with the provisions of Statement of Financial Accounting Standards No. 128, “Earnings per Share” (“SFAS No. 128”). Under SFAS No. 128, basic earnings per common share are determined by dividing net earnings applicable to common stock by the weighted average number of common shares actually outstanding during the year. Diluted earnings per common share is based on the


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

increased number of shares that would be outstanding assuming conversion of dilutive outstanding securities using the “as if converted” method. The following table sets forth the computation of basic and diluted earnings per share:
 
                         
    Years Ended December 31,  
    2006     2005     2004  
 
Numerator (both basic and diluted):
                       
Income from continuing operations
  $ 98,830     $ 44,781     $ 12,932  
Discontinued operations, net of tax
                (71 )
                         
Net income available to common stockholders
  $ 98,830     $ 44,781     $ 12,861  
                         
Denominator:
                       
Denominator for basic earnings per share
    34,471,771       28,580,911       28,094,435  
Stock options
    1,054,040       789,991       389,975  
Unvested restricted stock
    244,153       638,442       837,500  
Common stock warrants
    2,823,029       3,159,035       1,333,310  
                         
Denominator for diluted earnings per share
    38,592,993       33,168,379       30,655,220  
                         
Basic earnings per common share:
                       
Income from continuing operations
  $ 2.87     $ 1.57     $ 0.46  
Discontinued operations, net of tax
                 
                         
Net income available to common stockholders
  $ 2.87     $ 1.57     $ 0.46  
                         
Diluted earnings per common share:
                       
Income from continuing operations
  $ 2.56     $ 1.35     $ 0.42  
Discontinued operations, net of tax
                 
                         
Net income available to common stockholders
  $ 2.56     $ 1.35     $ 0.42  
                         
 
15.   Assets Held for Sale and Discontinued Operations
 
In August, 2003 Basic’s management and board of directors made the decision to dispose of its fluid services operations in Alaska it acquired in the FESCO acquisition prior to closing of the acquisition. After this disposal Basic no longer had any operations in Alaska.
 
The following are the results of operations, since their acquisition in October 2003, from the discontinued operations (in thousands):
 
         
    Year Ended
 
    December 31, 2004  
 
Revenues
  $ 1,705  
Operating costs
    (1,814 )
Income taxes — deferred
    38  
         
Loss from discontinued operations, net of tax
  $ (71 )
         


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

16.   Business Segment Information
 
Basic’s reportable business segments are well servicing, fluid services, drilling and completion services and well site construction services. The following is a description of the segments:
 
Well Servicing:  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. Basic well servicing equipment and capabilities are essential to facilitate most other services performed on a well.
 
Fluid Services:  This segment utilizes a fleet of trucks and related assets, including specialized tank trucks, storage tanks, water wells, disposal facilities and related equipment. Basic employs these assets to provide, transport, store and dispose of a variety of fluids. These services are required in most workover, drilling and completion projects as well as part of daily producing well operations.
 
Drilling and Completion Services:  This segment utilizes a fleet of pressure pumping units, air compressor packages specially configured for underbalanced drilling operations, cased-hole wireline units and an array of specialized rental equipment and fishing tools. 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:  This segment utilizes a fleet of power units, dozers, trenchers, motor graders, backhoes and other heavy equipment. Basic employs these assets 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.
 
Basic’s management evaluates the performance of its operating segments based on operating revenues and segment profits. Corporate expenses include general corporate expenses associated with managing all reportable operating segments. Corporate assets consist principally of working capital and debt financing costs.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

 
The following table sets forth certain financial information with respect to Basic’s reportable segments (in thousands):
 
                                                 
                Drilling and
    Well Site
             
    Well
    Fluid
    Completion
    Construction
    Corporate
       
    Servicing     Services     Services     Services     and Other     Total  
 
Year ended December 31, 2006
                                               
Operating revenues
  $ 330,725     $ 194,636     $ 154,412     $ 50,375     $     $ 730,148  
Direct operating costs
    (186,428 )     (118,378 )     (74,981 )     (35,067 )           (414,854 )
                                                 
Segment profits
  $ 144,297     $ 76,258     $ 79,431     $ 15,308     $     $ 315,294  
                                                 
Depreciation and amortization
  $ 28,930     $ 16,090     $ 11,070     $ 3,602     $ 2,395     $ 62,087  
Capital expenditures, (excluding acquisitions)
  $ 48,727     $ 27,100     $ 18,646     $ 6,067     $ 4,034     $ 104,574  
Identifiable assets
  $ 243,678     $ 161,555     $ 129,471     $ 32,372     $ 229,184     $ 796,260  
Year ended December 31, 2005
                                               
Operating revenues
  $ 221,993     $ 132,280     $ 59,832     $ 45,647     $     $ 459,752  
Direct operating costs
    (137,392 )     (82,551 )     (30,900 )     (32,000 )           (282,843 )
                                                 
Segment profits
  $ 84,601     $ 49,729     $ 28,932     $ 13,647     $     $ 176,909  
                                                 
Depreciation and amortization
  $ 18,671     $ 9,415     $ 3,644     $ 2,808     $ 2,534     $ 37,072  
Capital expenditures, (excluding acquisitions)
  $ 42,838     $ 21,602     $ 8,361     $ 6,443     $ 3,851     $ 83,095  
Identifiable assets
  $ 169,487     $ 100,959     $ 45,850     $ 28,376     $ 152,621     $ 497,293  
Year ended December 31, 2004
                                               
Operating revenues
  $ 142,551     $ 98,683     $ 29,341     $ 40,927     $     $ 311,502  
Direct operating costs
    (98,058 )     (65,167 )     (17,481 )     (31,454 )           (212,160 )
                                                 
Segment profits
  $ 44,493     $ 33,516     $ 11,860     $ 9,473     $     $ 99,342  
                                                 
Depreciation and amortization
  $ 14,125     $ 8,316     $ 2,402     $ 1,857     $ 1,976     $ 28,676  
Capital expenditures, (excluding acquisitions)
  $ 27,918     $ 16,436     $ 3,670     $ 4,748     $ 2,902     $ 55,674  
Identifiable assets
  $ 126,208     $ 87,349     $ 24,246     $ 24,064     $ 105,993     $ 367,860  
 
The following table reconciles the segment profits reported above to the operating income as reported in the consolidated statements of operations (in thousands):
 
                         
    Year Ended December 31,  
    2006     2005     2004  
 
Segment profits
  $ 315,294     $ 176,909     $ 99,342  
General and administrative expenses
    (81,318 )     (55,411 )     (37,186 )
Depreciation and amortization
    (62,087 )     (37,072 )     (28,676 )
Gain (loss) on disposal of assets
    (277 )     222       (2,616 )
                         
Operating income
  $ 171,612     $ 84,648     $ 30,864  
                         


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

17.   Accrued Expenses
 
The accrued expenses are as follows (in thousands):
 
                 
    December 31,  
    2006     2005  
 
Compensation related
  $ 14,006     $ 10,576  
Workers’ compensation self-insured risk reserve
    8,497       7,461  
Health self-insured risk reserve
    5,289       2,200  
Accrual for receipts
    3,608       1,841  
Authority for expenditure accrual
    1,325       3,052  
Ad valorem taxes
    106       935  
Sales tax
    1,886       2,407  
Insurance obligations
    489       673  
Purchase order accrual
    41       96  
Professional fee accrual
    216       1,079  
Diesel tax accrual
          385  
Contingent earnout obligation
    2,189        
Retainers
    181       1,042  
Fuel accrual
    460       368  
Accrued interest
    3,620       391  
Contingent liability
          1,000  
Franchise Tax Payable
    1,789        
Other
    17       42  
                 
    $ 43,719     $ 33,548  
                 
 
18.   Supplemental Schedule of Cash Flow Information
 
The following table reflects non-cash financing and investing activity during:
 
                         
    Year Ended December 31,  
    2006     2005     2004  
    (In thousands)  
 
Capital leases issued for equipment
  $ 26,420     $ 10,334     $ 10,472  
Exercise of stock options
  $ 5,144     $     $  
Contingent earnout accrual
  $ 2,256     $     $  
Asset retirement obligation additions
  $ 767     $ 74     $ 21  
 
Basic paid income taxes of approximately $43.2 million, $1.3 million and $0 during the years ended December 31, 2006, 2005 and 2004, respectively.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

 
19.   Quarterly Financial Data (Unaudited)
 
The following table summarizes results for each of the four quarters in the years ended December 31, 2006 and 2005:
 
                                         
    First
    Second
    Third
    Fourth
       
    Quarter     Quarter     Quarter     Quarter     Year  
 
Year ended December 31, 2006:
                                       
Total revenues
  $ 154,306     $ 183,833     $ 194,555     $ 197,454     $ 730,148  
Segment profits
  $ 64,894     $ 80,969     $ 84,989     $ 84,442     $ 315,294  
Income from continuing operations
  $ 19,681     $ 24,487     $ 27,328     $ 27,334     $ 98,830  
Net income available to common stockholders
  $ 19,681     $ 24,487     $ 27,328     $ 27,334     $ 98,830  
Basic earnings per share of common stock(a):
                                       
Continuing operations
  $ 0.59     $ 0.73     $ 0.81     $ 0.72     $ 2.87  
Net income available to common stockholders
  $ 0.59     $ 0.73     $ 0.81     $ 0.72     $ 2.87  
Diluted earnings per share of common stock(a):
                                       
Continuing operations
  $ 0.53     $ 0.64     $ 0.71     $ 0.70     $ 2.56  
Net income available to common stockholders
  $ 0.53     $ 0.64     $ 0.71     $ 0.70     $ 2.56  
Weighted average common shares outstanding:
                                       
Basic
    33,262       33,434       33,537       37,766       34,472  
Diluted
    36,902       38,526       38,442       39,116       38,593  
Year ended December 31, 2005:
                                       
Total revenues
  $ 93,813     $ 109,818     $ 120,771     $ 135,350     $ 459,752  
Segment profits
  $ 33,416     $ 42,238     $ 45,791     $ 55,464     $ 176,909  
Income from continuing operations
  $ 5,801     $ 10,747     $ 12,335     $ 15,898     $ 44,781  
Net income available to common stockholders
  $ 5,801     $ 10,747     $ 12,335     $ 15,898     $ 44,781  
Basic earnings per share of common stock(a):
                                       
Continuing operations
  $ 0.21     $ 0.38     $ 0.44     $ 0.54     $ 1.57  
Net income available to common stockholders
  $ 0.21     $ 0.38     $ 0.44     $ 0.54     $ 1.57  
Diluted earnings per share of common stock(a):
                                       
Continuing operations
  $ 0.18     $ 0.33     $ 0.38     $ 0.46     $ 1.35  
Net income (loss) available to common stockholders
  $ 0.18     $ 0.33     $ 0.38     $ 0.46     $ 1.35  
Weighted average common shares outstanding:
                                       
Basic
    28,186       28,328       28,318       29,481       28,581  
Diluted
    32,157       32,783       32,802       34,436       33,168  
 
 
(a) The sum of individual quarterly net income per share may not agree to the total for the year to due each period’s computation based on the weighted average number of common shares outstanding during each period.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)

 
20.   Subsequent Events
 
  (a)   Acquisitions
 
On January 3, 2007, Basic acquired two barge-mounted workover rigs and related equipment from Parker Drilling Offshore USA, LLC for total consideration of $20.5 million cash. The acquired rigs will operate in the inland waters of Louisiana and Texas as part of Basic Marine Services.
 
On January 17, 2007, Basic acquired substantially all of the operating assets of Davis Tool Company, Inc. for total consideration of $4.9 million cash. This acquisition will operate in Basic’s drilling and completion line of business.
 
On March 6, 2007, Basic acquired all of the outstanding capital stock of JetStar Consolidated Holdings, Inc. for a total acquisition price, net of estimated working capital, of approximately $118 million. The total acquisition price is comprised of approximately 1.9 million shares of Basic common stock, $45 million in cash to JetStars’s shareholders, and $38 million for repayment of JetStar outstanding debt. This acquisition will operate in the Basic’s drilling and completion line of business.
 
On March 13, 2007, Basic signed a definitive agreement to acquire all of the outstanding capital stock of Sledge Drilling Holding Corp. (“Sledge”) for total consideration of approximately $51 million, including $10 million in shares of Basic common stock and repayment of Sledge’s outstanding debt, plus certain working capital adjustments at closing. The transaction is expected to close in the second quarter of 2007 but closing is subject to completion of due diligence by Basic and other customary closing conditions.
 
  (b)   Debt
 
On February 6, 2007, Basic amended and restated its existing credit agreement by entering into a Fourth Amended and Restated Credit Agreement with a syndicate of lenders. The amendments contained in the 2007 Credit Facility included:
 
  •  eliminating the $90 million class of Term B Loans;
 
  •  creating a new class of Revolving Loans, which increased the lender’s total revolving commitments from $150 million to $225 million
 
  •  increasing the “Incremental Revolving Commitments” under the 2007 Credit Facility from $75.0 million to an aggregate principal amount of $100 million;
 
  •  changing the applicable margins for Alternative Base Rate or Eurodollar revolving loans;
 
  •  amending our negative covenants relating to our ability to incur indebtedness and liens, to add tests based on a percentage of our consolidated tangible assets in addition to fixed dollar amounts, or to increase applicable dollar limits on baskets or other tests for permitted indebtedness or liens;
 
  •  amending our negative covenants relating to our ability to pay dividends, or repurchase or redeem our capital stock, in order to conform more closely with permitted payments under our senior notes; and
 
  •  eliminating certain restrictions on our ability to create or incur certain lease obligations.
 
  (c)   Employment Agreements
 
On January 23, 2007, Basic amended its employment agreement with Kenneth U. Huseman, President and Chief Executive Officer. The amendment eliminated a minimum annual bonus of $50,000 and increased his salary to $525,000 per year.


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Schedule II — Valuation and Qualifying Accounts
 
                                         
          Additions              
    Balance at
    Charged to
    Charged to
          Balance at
 
    Beginning of
    Costs and
    Other
          End of
 
Description
  Period     Expenses(a)     Accounts(b)     Deductions(c)     Period  
          (In thousands)                    
 
Year Ended December 31, 2006
                                       
Allowance for Bad Debt
  $ 2,775     $ 1,820     $     $ (632 )   $ 3,963  
Year Ended December 31, 2005
                                       
Allowance for Bad Debt
  $ 3,108     $ 1,651     $     $ (1,984 )   $ 2,775  
Year Ended December 31, 2004
                                       
Allowance for Bad Debt
  $ 1,958     $ 1,200     $     $ (50 )   $ 3,108  
 
 
(a) Charges relate to provisions for doubtful accounts
 
(b) Reflects the impact of acquisitions
 
(c) Deductions relate to the write-off of accounts receivable deemed uncollectible


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ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 
None.
 
ITEM 9A.   CONTROLS AND PROCEDURES
 
Disclosure Controls and Procedures
 
Based on their evaluation as of the end of the fiscal year ended December 31, 2006, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
 
Changes in Internal Control Over Financial Reporting
 
During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
Design and Evaluation of Internal Control over Financial Reporting
 
Management’s Report on Internal Control over Financial Reporting and the Report of the Independent Registered Public Accounting Firm are set forth in Part II, Item 8 of this report and are incorporated herein by reference.
 
ITEM 9B.   OTHER INFORMATION
 
None.
 
PART III
 
Pursuant to paragraph 3 of General Instruction G to Form 10-K, the information required by Item 10, to the extent not set forth in “Executive Officers and Other Key Employees” in Item 4, and Items 11 through 14 of Part III of this Report is incorporated by reference from our definitive proxy statement involving the election of directors and the approval of independent auditors, which is to be filed pursuant to Regulation 14A within 120 days after the end of our fiscal year ended December 31, 2006.
 
PART IV
 
ITEM 15.   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
 
(a) Financial Statements, Schedules and Exhibits (1) Financial Statements — Basic Energy Services, Inc. and Subsidiaries:
 
The Financial Statements listed in the Index to Consolidated Financial Statements are filed as part of this report on Form 10-K (see Part II, Item 8-Financial Statements and Supplementary Data).
 
(2) Financial Statement Schedules
 
With the exception of Schedule II — Valuation and Qualifying Accounts, all other consolidated financial statement schedules have been omitted because they are not required, are not applicable, or the required information has been included elsewhere within this Form 10-K.


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(3) Exhibits
 
         
Exhibit
   
No.
 
Description
 
  2 .1*   Agreement and Plan of Merger, dated as of January 8, 2007, by and among Basic Energy Services, Inc., JS Acquisition LLC and JetStar Consolidated Holdings, Inc. (Incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on March 8, 2007)
  2 .2*   Amendment to Merger Agreement, dated as of March 5, 2007, by and among Basic Energy Services, Inc., JS Acquisition LLC and JetStar Consolidated Holdings, Inc. (Incorporated by reference to Exhibit 2.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on March 8, 2007)
  3 .1*   Amended and Restated Certificate of Incorporation of the Company, dated September 22, 2005. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)
  3 .2*   Amended and Restated Bylaws of the Company, dated December 14, 2005. (Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on December 14, 2005)
  4 .1*   Specimen Stock Certificate representing common stock of the Company. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on November 4, 2005)
  4 .2*   Indenture dated April 12, 2006, among Basic Energy Services, Inc., the guarantors party thereto, and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006)
  4 .3*   Form of 7.125% Senior Note due 2016. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006)
  4 .4*   First Supplemental Indenture dated as of July 14, 2006 to Indenture dated as of April 12, 2006 among the Company, as Issuer, the Subsidiary Guarantors named therein and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on July 20, 2006)
  10 .1*†   Form of Indemnification Agreement. (Incorporated by reference to Exhibit 10.1 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)
  10 .2*   Second Amended and Restated Stockholders’ Agreement dated as of April 2, 2004 among the Company and the stockholders listed therein. (Incorporated by reference to Exhibit 10.7 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on August 12, 2005)
  10 .3*   Stock Purchase Agreement dated as of September 18, 2003, as amended on October 1, 2003, among the Company, FESCO Holdings, Inc. and the sellers named therein. (Incorporated by reference to Exhibit 10.8 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on August 12, 2005)
  10 .4*   Asset Purchase Agreement dated as of August 14, 2003 among the Company and PWI, Inc. (Incorporated by reference to Exhibit 10.9 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on August 12, 2005)
  10 .5*   Fourth Amended and Restated Credit Agreement dated as of October 3, 2003, amended and restated as of February 6, 2007, among Basic Energy Services, Inc., the subsidiary guarantors party thereto, Bank of America, N.A., as syndication agent, Capital One, National Association, as documentation agent, BNP Paribas, as documentation agent, UBS AG, Stamford Branch, as issuing bank, administrative agent and collateral agent, and the lenders party thereto. (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on February 12, 2007)
  10 .6*†   Second Amended and Restated 2003 Incentive Plan. (Incorporated by reference to Exhibit 10.11 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on August 12, 2005)
  10 .7*†   Form of Non-Qualified Option Grant Agreement (Executive Officer — Pre-March 1, 2005). (Incorporated by reference to Exhibit 10.12 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)


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Exhibit
   
No.
 
Description
 
  10 .8*†   Form of Non-Qualified Option Grant Agreement (Executive Officer — Post-March 1, 2005). (Incorporated by reference to Exhibit 10.13 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)
  10 .9*†   Form of Non-Qualified Option Grant Agreement (Non-Employee Director — Pre-March 1, 2005). (Incorporated by reference to Exhibit 10.14 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)
  10 .10*†   Form of Non-Qualified Option Grant Agreement (Non-Employee Director — Post-March 1, 2005). (Incorporated by reference to Exhibit 10.15 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)
  10 .11*†   Form of Restricted Stock Grant Agreement. (Incorporated by reference to Exhibit 10.16 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)
  10 .12*†   Form of Amendment to Nonqualified Stock Option Agreement, dated as of December 31, 2005, by and between the Company and the optionees party thereto. (Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on January 4, 2006)
  10 .13*†   Form of Nonqualified Stock Option Agreement (Director form effective March 2006). (Incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-32693), filed on May 12, 2006)
  10 .14*†   Form of Nonqualified Stock Option Agreement (Employee form effective March 2006). (Incorporated by reference to Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-32693), filed on May 12, 2006)
  10 .15*   Workover Unit Package Contract and Acceptance Agreement, dated as of May 17, 2005, between Basic Energy Services, L.P. and Taylor Rigs, LLC. (Incorporated by reference to Exhibit 10.17 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on November 4, 2005)
  10 .16*   Share Exchange Agreement, dated as of September 22, 2003, among BES Holding Co. and the Stockholders named therein. (Incorporated by reference to Exhibit 10.18 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)
  10 .17*   Form of Share Tender and Repurchase Agreement. (Incorporated by reference to Exhibit 10.19 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on November 4, 2005)
  10 .18*   Workover Unit Package Contract and Acceptance Agreement, dated as of November 10, 2005, between Basic Energy Services, L.P. and Taylor Rigs, LLC. (Incorporated by reference to Exhibit 10.20 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on November 16, 2005)
  10 .19*   Asset Purchase Agreement dated as of February 21, 2006 among Basic Energy Services, LP, Basic Energy Services GP, LLC, G&L Tool, Ltd., DLH Management, LLC and LJH, Ltd. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on March 2, 2006)
  10 .20*   Contingent Earn Out Agreement dated as of February 28, 2006 among Basic Energy Services, LP and G&L Tool, Ltd. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on March 2, 2006)
  10 .21*   Registration Rights Agreement dated April 12, 2006, among the Company, the guarantors party thereto and the initial purchasers party thereto. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006)
  10 .22*   Summary of 2006 salaries and other compensation for named executive officers and certain employees (Incorporated by reference to Item 1.01 of the Company’s Form 8-K filed on March 8, 2006)
  10 .23*   Fee Reimbursement Agreement, dated as of July 24, 2006, by and among the Company, Southwest Partners II, L.P., Southwest Partners, III, L.P. and Fortress Holdings, LLC. (Incorporated by reference to Exhibit 10.23 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-136019), filed on July 25, 2006)

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Exhibit
   
No.
 
Description
 
  10 .24*†   Employment Agreement of Kenneth V. Huseman, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on January 4, 2007)
  10 .25*†   Employment Agreement of Alan Krenek, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on January 4, 2007)
  10 .26*†   Employment Agreement of Charles W. Swift, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on January 4, 2007)
  10 .27*†   Employment Agreement of Dub William Harrison, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on January 4, 2007)
  10 .28*†   Employment Agreement of James E. Tyner, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.5 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on January 4, 2007)
  10 .29*†   Employment Agreement of Thomas Monroe Patterson, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.6 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on January 4, 2007)
  10 .30*†   Employment Agreement of Mark David Rankin, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.7 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on January 4, 2007)
  10 .31*†   First Amendment to Employment Agreement of Kenneth V. Huseman, effective as of January 23, 2007. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on January 29, 2007)
  10 .32*   Registration Rights Agreement, dated as of March 6, 2007, by and among Basic Energy Services, Inc. and the JetStar Stockholders’ Representative. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on March 8, 2007)
  21 .1   Subsidiaries of the Company
  23 .1   Consent of KPMG LLP
  31 .1   Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
  31 .2   Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
  32 .1   Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
  32 .2   Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
* Incorporated by reference
 
Management contract or compensatory plan or arrangement

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SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
BASIC ENERGY SERVICES, INC.
 
  By: 
/s/  Kenneth V. Huseman
Name: Kenneth V. Huseman
  Title:  President, Chief Executive Officer and
Director
 
Date: March 16, 2007
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
 
             
Signature
 
Date
   
 
/s/  Kenneth V. Huseman

Kenneth V. Huseman
  President, Chief Executive Officer and Director (Principal Executive Officer)   March 16, 2007
         
/s/  Alan Krenek

Alan Krenek
  Chief Financial Officer (Principal
Financial Officer and Principal
Accounting Officer)
  March 16, 2007
         
/s/  Steven A. Webster

Steven A. Webster
  Chairman of the Board   March 16, 2007
         
/s/  James S. D’Agostino, Jr.

James S. D’Agostino, Jr.
  Director   March 16, 2007
         
/s/  William E. Chiles

William E. Chiles
  Director   March 16, 2007
         
/s/  Robert F. Fulton

Robert F. Fulton
  Director   March 16, 2007
         
/s/  Sylvester P. Johnson, IV

Sylvester P. Johnson, IV
  Director   March 16, 2007
         
/s/  H.H. Wommack, III

H.H. Wommack, III
  Director   March 16, 2007
         
/s/  Thomas P. Moore, Jr.

Thomas P. Moore, Jr.
  Director   March 16, 2007


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EXHIBIT INDEX
 
         
Exhibit
   
No.
 
Description
 
  2 .1*   Agreement and Plan of Merger, dated as of January 8, 2007, by and among Basic Energy Services, Inc., JS Acquisition LLC and JetStar Consolidated Holdings, Inc. (Incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on March 8, 2007)
  2 .2*   Amendment to Merger Agreement, dated as of March 5, 2007, by and among Basic Energy Services, Inc., JS Acquisition LLC and JetStar Consolidated Holdings, Inc. (Incorporated by reference to Exhibit 2.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on March 8, 2007)
  3 .1*   Amended and Restated Certificate of Incorporation of the Company, dated September 22, 2005. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)
  3 .2*   Amended and Restated Bylaws of the Company, dated December 14, 2005. (Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on December 14, 2005)
  4 .1*   Specimen Stock Certificate representing common stock of the Company. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on November 4, 2005)
  4 .2*   Indenture dated April 12, 2006, among Basic Energy Services, Inc., the guarantors party thereto, and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006)
  4 .3*   Form of 7.125% Senior Note due 2016. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006)
  4 .4*   First Supplemental Indenture dated as of July 14, 2006 to Indenture dated as of April 12, 2006 among the Company, as Issuer, the Subsidiary Guarantors named therein and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on July 20, 2006)
  10 .1*†   Form of Indemnification Agreement. (Incorporated by reference to Exhibit 10.1 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)
  10 .2*   Second Amended and Restated Stockholders’ Agreement dated as of April 2, 2004 among the Company and the stockholders listed therein. (Incorporated by reference to Exhibit 10.7 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on August 12, 2005)
  10 .3*   Stock Purchase Agreement dated as of September 18, 2003, as amended on October 1, 2003, among the Company, FESCO Holdings, Inc. and the sellers named therein. (Incorporated by reference to Exhibit 10.8 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on August 12, 2005)
  10 .4*   Asset Purchase Agreement dated as of August 14, 2003 among the Company and PWI, Inc. (Incorporated by reference to Exhibit 10.9 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on August 12, 2005)
  10 .5*   Fourth Amended and Restated Credit Agreement dated as of October 3, 2003, amended and restated as of February 6, 2007, among Basic Energy Services, Inc., the subsidiary guarantors party thereto, Bank of America, N.A., as syndication agent, Capital One, National Association, as documentation agent, BNP Paribas, as documentation agent, UBS AG, Stamford Branch, as issuing bank, administrative agent and collateral agent, and the lenders party thereto. (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on February 12, 2007)
  10 .6*†   Second Amended and Restated 2003 Incentive Plan. (Incorporated by reference to Exhibit 10.11 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on August 12, 2005)
  10 .7*†   Form of Non-Qualified Option Grant Agreement (Executive Officer — Pre-March 1, 2005). (Incorporated by reference to Exhibit 10.12 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)
  10 .8*†   Form of Non-Qualified Option Grant Agreement (Executive Officer — Post-March 1, 2005). (Incorporated by reference to Exhibit 10.13 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)


Table of Contents

         
Exhibit
   
No.
 
Description
 
  10 .9*†   Form of Non-Qualified Option Grant Agreement (Non-Employee Director — Pre-March 1, 2005). (Incorporated by reference to Exhibit 10.14 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)
  10 .10*†   Form of Non-Qualified Option Grant Agreement (Non-Employee Director — Post-March 1, 2005). (Incorporated by reference to Exhibit 10.15 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)
  10 .11*†   Form of Restricted Stock Grant Agreement. (Incorporated by reference to Exhibit 10.16 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)
  10 .12*†   Form of Amendment to Nonqualified Stock Option Agreement, dated as of December 31, 2005, by and between the Company and the optionees party thereto. (Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on January 4, 2006)
  10 .13*†   Form of Nonqualified Stock Option Agreement (Director form effective March 2006). (Incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-32693), filed on May 12, 2006)
  10 .14*†   Form of Nonqualified Stock Option Agreement (Employee form effective March 2006). (Incorporated by reference to Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-32693), filed on May 12, 2006)
  10 .15*   Workover Unit Package Contract and Acceptance Agreement, dated as of May 17, 2005, between Basic Energy Services, L.P. and Taylor Rigs, LLC. (Incorporated by reference to Exhibit 10.17 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on November 4, 2005)
  10 .16*   Share Exchange Agreement, dated as of September 22, 2003, among BES Holding Co. and the Stockholders named therein. (Incorporated by reference to Exhibit 10.18 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)
  10 .17*   Form of Share Tender and Repurchase Agreement. (Incorporated by reference to Exhibit 10.19 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on November 4, 2005)
  10 .18*   Workover Unit Package Contract and Acceptance Agreement, dated as of November 10, 2005, between Basic Energy Services, L.P. and Taylor Rigs, LLC. (Incorporated by reference to Exhibit 10.20 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on November 16, 2005)
  10 .19*   Asset Purchase Agreement dated as of February 21, 2006 among Basic Energy Services, LP, Basic Energy Services GP, LLC, G&L Tool, Ltd., DLH Management, LLC and LJH, Ltd. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on March 2, 2006)
  10 .20*   Contingent Earn Out Agreement dated as of February 28, 2006 among Basic Energy Services, LP and G&L Tool, Ltd. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on March 2, 2006)
  10 .21*   Registration Rights Agreement dated April 12, 2006, among the Company, the guarantors party thereto and the initial purchasers party thereto. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006)
  10 .22*   Summary of 2006 salaries and other compensation for named executive officers and certain employees (Incorporated by reference to Item 1.01 of the Company’s Form 8-K filed on March 8, 2006)
  10 .23*   Fee Reimbursement Agreement, dated as of July 24, 2006, by and among the Company, Southwest Partners II, L.P., Southwest Partners, III, L.P. and Fortress Holdings, LLC. (Incorporated by reference to Exhibit 10.23 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-136019), filed on July 25, 2006)
  10 .24*†   Employment Agreement of Kenneth V. Huseman, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on January 4, 2007)
  10 .25*†   Employment Agreement of Alan Krenek, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on January 4, 2007)


Table of Contents

         
Exhibit
   
No.
 
Description
 
  10 .26*†   Employment Agreement of Charles W. Swift, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on January 4, 2007)
  10 .27*†   Employment Agreement of Dub William Harrison, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on January 4, 2007)
  10 .28*†   Employment Agreement of James E. Tyner, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.5 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on January 4, 2007)
  10 .29*†   Employment Agreement of Thomas Monroe Patterson, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.6 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on January 4, 2007)
  10 .30*†   Employment Agreement of Mark David Rankin, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.7 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on January 4, 2007)
  10 .31*†   First Amendment to Employment Agreement of Kenneth V. Huseman, effective as of January 23, 2007. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on January 29, 2007)
  10 .32*   Registration Rights Agreement, dated as of March 6, 2007, by and among Basic Energy Services, Inc. and the JetStar Stockholders’ Representative. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on March 8, 2007)
  21 .1   Subsidiaries of the Company
  23 .1   Consent of KPMG LLP
  31 .1   Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
  31 .2   Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
  32 .1   Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
  32 .2   Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
* Incorporated by reference
 
Management contract or compensatory plan or arrangement