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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, 2008
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 number 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.)
 
         
500 W. Illinois, Suite 100
Midland, Texas
    79701
(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 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 registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer o Accelerated filer þ Non-accelerated filer o Smaller reporting company o
(Do not check if a smaller reporting company)
 
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 $545,420,106 as of June 30, 2008, the last business day of the registrant’s most recently completed second fiscal quarter (based on a closing price of $31.50 per share and 24,015,323 shares held by non-affiliates).
 
There were 40,222,938 shares of the registrant’s Common Stock outstanding as of February 27, 2009.
 
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  
    16  
    22  
    22  
    22  
    24  
    24  
    27  
    28  
    46  
    47  
    84  
    84  
    84  
    84  
    85  
    85  
    89  
 EX-4.7
 EX-21.1
 EX-23.1
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2


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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 Item 1A of 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 data, 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 Baker Hughes Incorporated, the Association of Energy Service Companies (“AESC”), and the Energy Information Administration of the U.S. Department of Energy (“EIA”). Industry surveys and 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 and well site construction services, completion and remedial services and contract drilling. 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, Kansas and Louisiana and the Rocky Mountain states. We provide our services to a diverse group of over 2,000 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 12% of the overall available U.S. fleet, with our two larger competitors controlling approximately 27% and 17%, respectively, according to the AESC and other publicly available data.
 
Basic revised its business segments beginning in the first quarter of 2008, and in connection therewith restated the corresponding items of segment information for earlier periods. The new operating segments are Well Servicing, Fluid Services, Completion and Remedial Services, and Contract Drilling. These segments were selected based on changes in management’s resource allocation and performance assessment in making decisions regarding the Company. Contract Drilling was previously included in our Well Servicing segment. Well Site Construction Services is consolidated with our Fluid Services segment. These changes reflect Basic’s operating focus in compliance with Statement of Financial Accounting Standards (SFAS) No. 131, “Disclosures about Segments of an Enterprise and Related Information.” The following is a description of the segments:
 
  •  Well Servicing.  Our well servicing segment (34% of our revenues in 2008) currently operates our fleet of 414 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 (32% of our revenues in 2008) currently utilizes our fleet of 819 fluid service trucks and related assets, including specialized tank trucks, storage tanks, water wells, disposal facilities, construction and other related equipment. These assets provide, transport, store and dispose of a variety of fluids, as well as provide well site construction and maintenance services. These services are required in most workover, completion and remedial projects and are routinely used in daily producing well operations.
 
  •  Completion and Remedial Services.  Our completion and remedial services segment (30% of our revenues in 2008) currently operates our fleet of pressure pumping units, an array of specialized rental equipment and fishing tools, air compressor packages specially configured for underbalanced drilling operations, and cased-hole wireline units. The largest portion of this business segment consists of pressure pumping services focused on cementing, acidizing and fracturing services in niche markets. We entered the rental and fishing tool business through an acquisition in the first quarter of 2006.
 
  •  Contract Drilling.  Our contract drilling segment (4% of our revenues in 2008) currently operates nine drilling rigs and related equipment. We use these assets to penetrate the earth to a desired depth and initiate production from a well. We greatly increased our presence in this line of business through the Sledge Drilling acquisition in the second quarter of 2007.
 
Financial information about our segments is included in Note 15, Business Segment Information, of the Notes to Consolidated Financial Statements, included in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.


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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 414 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 drilling, maintenance, workover, completion and plugging and abandonment services.
 
Modern and Active Well Servicing Fleet.  We operate a modern and active fleet of well servicing rigs. We believe over 75% of the active U.S. well servicing rig fleet was built prior to 1985. Greater than 50% of our rigs at December 31, 2008 were either 2000 model year or newer, or have undergone major refurbishments during the last five years. As of December 31, 2008, we had taken delivery of 132 newbuild well servicing rigs since October 2004 as part of a 134-rig newbuild commitment, driven by our desire to maintain one of the most efficient, reliable and safest fleets in the industry. The remaining two newbuilds are scheduled to be delivered to us by the end of February 2009. 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 70 of our rigs since the beginning of 2004. 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, Kansas and Louisiana and the Rocky Mountain states. We operate in states that accounted for approximately 58% of the approximately 900,000 existing onshore oil and gas wells in the 48 contiguous states and approximately 73% of onshore oil production and 90% of onshore gas production in 2008. 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 2,000 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 121 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 division managers are responsible for their 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 division managers, our 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.


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Our Business Strategy
 
We intend to increase our shareholder value by pursuing the following strategies:
 
Establish and Maintain Leadership Position in Core Operating Areas.  We strive to establish and maintain market leadership positions within our core operating areas. To achieve this goal, we maintain close customer relationships, seek to expand the breadth of our services and offer high quality services and equipment that meet the scope of customer specifications and requirements. In addition, our significant presence in our core operating areas facilitates employee retention and attraction, a key factor for success in our business. Our significant presence in our core operating areas also provides us with brand recognition that we intend to utilize in creating leading positions in new operating areas.
 
Expand Within Our Regional Markets.  We intend to continue strengthening our presence within our existing geographic footprint through internal growth and acquisitions of businesses with strong customer relationships, well-maintained equipment and experienced and skilled personnel. 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, we have made 23 acquisitions including:
 
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 completion and remedial line of business;
 
2007
 
  •  JetStar Consolidated Holdings, Inc., a pressure pumping company operating in our completion and remedial line of business, and
 
  •  Sledge Drilling Holding Corp., a contract drilling company operating in our contract drilling line of business;
 
2008
 
  •  Azurite Services Company, Inc., Azurite Leasing Company, LLC and Freestone Disposal, L.P. (collectively “Azurite”), a fluid service business operating in our Ark-La-Tex and Mid-Continent regions.
 
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


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combination of asset acquisitions and the purchase of new equipment. In 2008, we completed five separate acquisitions for an aggregate purchase price of $110 million, net of cash acquired.
 
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. As oil and gas prices increased in recent years, oil and gas companies increased their drilling and workover activities. The increased activity resulted in increased domestic exploration and production spending year over year for the past four years. In the last part of 2008 there was a rapid decline in oil and gas prices which we believe has resulted in a significant decrease in budgeted 2009 domestic spending compared to 2008 actual spending.
 
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 2004:
 
                 
    Cushing WTI Spot
    Average Wellhead Price
 
Period
  Oil Price ($/bbl)     Natural Gas ($/mcf)  
 
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  
1/1/07 — 12/31/07
    72.34       6.38  
1/1/08 — 12/31/08
    99.67       8.07  
 
 
 
Source: U.S. Department of Energy.
 
Increased expenditures for exploration and production activities generally drives the increased demand for our services. Rising oil and gas prices in recent years and the corresponding increase in onshore oil exploration and production spending led to expanded drilling and well service activity, as the U.S. land-based drilling rig count increased approximately 22% during 2005, 17% during 2006, and 4% during 2007. With the rapid decline in oil and gas prices in the second half of 2008 there was a decrease in the land-based drilling rig count of approximately 3% during 2008, according to Baker Hughes. The decrease in oil and gas prices in recent months coupled with the buildup of drilling and workover rig counts in recent years is resulting in both lower utilization of those rigs and decreases in the rates being charged.
 
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.


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Our business is influenced substantially by both operating and capital expenditures by oil and gas companies. Because existing oil and gas wells require ongoing spending to maintain production, expenditures by oil and gas companies for the maintenance of existing wells are relatively stable and predictable. In contrast, capital expenditures by oil and gas companies for exploration and drilling are more directly influenced by current and expected oil and gas prices and generally reflect the volatility of commodity prices.
 
Overview of Our Segments and Services
 
Well Servicing Segment
 
Our well servicing segment encompasses a full range of services performed with a mobile well servicing rig, also commonly referred to as a workover rig, and ancillary equipment. Our rigs and personnel provide the means for hoisting equipment and tools into and out of the well bore, and our well servicing equipment and capabilities are essential to facilitate most other services performed on a well. Our well servicing segment services, which are performed to maintain and improve production throughout the productive life of an oil and gas well, include:
 
  •  maintenance work involving removal, repair and replacement of down-hole equipment and returning the well to production after these operations are completed;
 
  •  hoisting tools and equipment required by the operation into and out of the well, or removing equipment from the well bore, to facilitate specialized production enhancement and well repair operations performed by other oilfield service companies; and
 
  •  plugging and abandonment services when a well has reached the end of its productive life.
 
Regardless of the type of work being performed on the well, our personnel and rigs are often the first to arrive at the well site and the last to leave. We generally charge our customers an hourly rate for these services, which rate varies based on a number of considerations including market conditions in each region, the type of rig and ancillary equipment required, and the necessary personnel.
 
Our fleet included 414 well servicing rigs as of December 31, 2008, including 132 newbuilds since October 2004 and 70 rebuilds since the beginning of 2004. Our well servicing rigs operate from facilities in Texas, Wyoming, Oklahoma, North Dakota, New Mexico, Louisiana, Colorado, Utah and Montana. Our well servicing 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, which were refurbished and were placed into service in the second quarter of 2005. In January 2007, we acquired two additional inland barges equipped with rigs from 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, 2008. 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.
 
                                                     
        Market Area        
        Permian
    South
    Ark-La-
    Mid-
    Rocky
       
Rig Type
  Rated Capacity   Basin     Texas     Tex     Continent     Mountain     Total  
 
Swab
  N/A     3       1       6       4       0       14  
Light Duty
  <90 tons     5       2       0       17       1       25  
Medium Duty
  ³90<125 tons     133       38       29       58       54       312  
Heavy Duty
  ³125 tons     29       4       6       4       8       51  
24-Hour
  ³125 tons     2       3       0       2       1       8  
Inland Barge
  ³125 tons     0       0       4       0       0       4  
                                                     
Total
        172       48       45       85       64       414  
                                                     


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We operate a total of 414 well servicing rigs, the third largest fleet in the United States. Based on their most recent publicly available information, Key Energy Services is our largest competitor with an estimated total of 943 domestic rigs and Nabors is the second largest with an estimated 592 domestic rigs at year end. Our only other competitors operating more than 100 rigs is Complete Production Services with an estimated 267 domestic rigs and Forbes Energy Services with an estimated 169 domestic rigs. Excluding the rigs operated by Nabors in California where we do not compete, we have the second largest rig fleet in the United States.
 
The total number of rigs owned by us and the four other largest companies referenced above is approximately 2,385, or 69% of the available fleet owned by member companies of the AESC, the major trade association of well site service providers. The remaining 31% of the well servicing rigs are owned by more than 100 local and regional companies. The December 2008 monthly activity survey conducted by the AESC indicated that 68% of the rigs owned were active.
 
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 shut in producing wells temporarily when oil or gas prices are too low to justify additional expenditures, including maintenance.
 
Workover.  In addition to periodic maintenance, producing oil and gas wells occasionally require major repairs or modifications called workovers, which are typically more complex and more time consuming than maintenance operations. Workover services include extensions of existing wells to drain new formations either through perforating the well casing to expose additional productive zones not previously produced, deepening well bores to new zones or the drilling of lateral well bores to improve reservoir drainage patterns. Our workover rigs are also used to convert former producing wells to injection wells through which water or carbon dioxide is then pumped into the formation for enhanced oil recovery operations. Workovers also include major subsurface repairs such as repair or replacement of well casing, recovery or replacement of tubing and removal of foreign objects from the well bore. These extensive workover operations are normally performed by a workover rig with additional specialized auxiliary equipment, which may include rotary drilling equipment, mud pumps, mud tanks and fishing tools, depending upon the particular type of workover operation. Most of our well servicing rigs are designed to perform complex workover operations. A workover may require a few days to several weeks and generally require 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


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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, storage and construction services. These services are required in most workover, completion and remedial 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;
 
  •  operation of company-owned fresh water and brine source wells and of non-hazardous wastewater disposal wells; and
 
  •  preparation, construction and maintenance of access roads, drilling locations, and production facilities.
 
This segment utilizes our fleet of fluid service 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, 2008:
 
                                                 
    Market Area        
    Rocky
    Permian
    Ark-La-
    South
    Mid-
       
    Mountain     Basin     Tex     Texas     Continent     Total  
 
Fluid Service Trucks
    94       262       259       125       79       819  
Salt Water Disposal Wells
    0       19       24       8       10       61  
Fresh/Brine Water Stations
    0       37       0       2       0       39  
Fluid Storage Tanks
    268       499       1,119       230       224       2,340  
 
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, completion and remedial 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.


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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 outperform 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, completion and remedial 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 819 fluid service 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 service 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 operate, oil and gas wastes and salt water produced from oil and gas wells are required by law to be disposed of in authorized facilities, including permitted salt water disposal wells. Injection wells are licensed by state authorities and are completed in permeable formations below the fresh water table. We maintain separators at most of our disposal wells permitting us to salvage residual crude oil, which is later sold for our account.
 
Fresh and Brine Water Stations.  Our network of fresh and brine water stations, particularly in the Permian Basin, where surface water is generally not available, is 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


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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.
 
Construction Services.  We utilize 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. 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.
 
Completion and Remedial Services Segment
 
Our completion and remedial 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, nitrogen and pressure testing;
 
  •  rental and fishing tools;
 
  •  cased-hole wireline services; and
 
  •  underbalanced drilling in low pressure and fluid sensitive reservoirs.
 
This segment currently operates 142 pressure pumping units, with approximately 139,000 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, 2008, we also operated 46 air compressor packages, including foam circulation units, for underbalanced drilling and 15 wireline units for cased-hole measurement and pipe recovery services.
 
Just as a well servicing rig is required to perform various operations over the life cycle of a well, there is a similar need for equipment capable of pumping fluids into the well under varying degrees of pressure. During the drilling and completion phase, the well bore is lined with large diameter steel pipe called casing. Casing is cemented into place by circulating slurry into the annulus created between the pipe and the rock wall of the well bore. The cement slurry is forced into the well by pressure pumping equipment located on the surface. Cementing services are also utilized over the life of a well to repair leaks in the casing, to close perforations that are no longer productive and ultimately to “plug” the well at the end of its productive life.
 
A hydrocarbon reservoir is essentially an interval of rock that is saturated with oil and/or gas, usually in combination with water. Three primary factors determine the productivity of a well that intersects a hydrocarbon reservoir: porosity — the percentage of the reservoir volume represented by pore space in which the hydrocarbons reside, permeability — the natural propensity for the flow of hydrocarbons toward the well bore, and “skin” — the degree to which the portion of the reservoir in close proximity to the well bore has experienced reduced permeability as a result of exposure to drilling fluids or other contaminants. Well productivity can be increased by artificially improving either permeability or skin through stimulation methods.
 
Permeability can be increased through the use of fracturing methods. The reservoir is subjected to fluids pumped into it under high pressure. This pressure creates stress in the reservoir and causes the rock to fracture thereby creating additional channels through which hydrocarbons can flow. In most cases, sand or another form of proppant is pumped with the fluid as a means of holding open the newly created fractures.
 
The most common means of reducing near-well bore damage, or skin, is the injection of a highly reactive solvent (such as hydrochloric acid) solution into the area where the hydrocarbons enter the well. This solution has the effect of dissolving contaminants which have accumulated and are restricting flow. This process is generically known as acidizing.
 
As a well is drilled, long intervals of rock are left exposed and unprotected. In order to prevent the exposed rock from caving and to prevent fluids from entering or leaving the exposed sections, steel casing is lowered into the hole and cemented in place. Pressure pumping equipment is utilized to force 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


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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.
 
The following table sets forth the type, number and location of the completion and remedial services equipment that we operated at December 31, 2008:
 
                                         
    Market Area        
                Rocky
    Permian
       
    Ark-La-Tex     Mid-Continent     Mountain     Basin     Total  
 
Pressure Pumping Units
    21       118       3       0       142  
Coiled Tubing Units
    0       4       0       0       4  
Air/Foam Packages
    0       6       34       6       46  
Wireline Units
    0       15       0       0       15  
Rental and Fishing Tool Stores
    0       9       3       8       20  
 
Our pressure pumping business focuses primarily on lower horsepower cementing, acidizing and fracturing services markets. Currently, there are several 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 higher horsepower requirements. This has created an opportunity in the markets for pressure pumping services in mature areas with less complex characteristics and lower horsepower requirements. We, along with a number of smaller, regional companies, have concentrated our efforts on these markets. Two of our major well servicing competitors also participate 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.
 
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 downhole problems develop with drilling or servicing operations, or conditions require non-routine equipment, our customers will usually 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.
 
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


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fluids instead of conventional drilling fluid. The most common method of reducing the weight of 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.
 
Contract Drilling Segment
 
Our contract drilling segment employs drilling rigs and related equipment to penetrate the earth to a desired depth and initiate production.
 
We own and operate nine land drilling rigs, which are currently deployed in the Permian Basin of Texas and New Mexico. A land drilling rig generally consists of engines, a drawworks, a mast, pumps to circulate the drilling fluid (mud) under various pressures, blowout preventers, drill string, and related equipment. The engines power the different pieces of equipment, including a rotary table or top drives that turns the drill string, causing the drill bit to bore through the subsurface rock layers. These jobs are typically bid by “daywork” contracts, in which an agreed upon rate per day is charged to the customer, or “footage” contracts, in which an agreed upon rate per the number of feet drilled is charged to the customer. The demand for drilling services is highly dependent on the availability of new drilling locations available to well operators, as well as sensitivity to expectations relating to and changes in oil and gas prices.
 
Our drilling rig services grew significantly in 2007 with the acquisition of Sledge Drilling in April. We acquired six drilling rigs in this acquisition.
 
Properties
 
Our principal executive offices are located at 500 W. Illinois, Suite 100, Midland, Texas 79701. We currently conduct our business from 121 area offices, 62 of which we own and 59 of which we lease. Each office typically includes a yard, administrative office and maintenance facility. Of our 121 area offices, 76 are located in Texas, 11 are in Oklahoma, 10 are in New Mexico, seven are in Wyoming, four are in Colorado, four are in Louisiana, three are in North Dakota, two are in Montana, two are in Kansas, one is in Arkansas and one is in Utah.
 
Customers
 
We serve numerous major and independent oil and gas companies that are active in our core areas of operations. During 2008, no single customer comprised over 5% of our total 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 any material customers, 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 to 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


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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 damage 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. We believe our two largest competitors, Key Energy Services, Inc. and Nabors Well Services Co., combined own approximately 44% of the U.S. marketable well servicing rigs according to the most recent publicly available data including the Guiberson-AESC well service rig count. 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 operations to develop stronger relationships with our customers at the field level. We target areas that are attractive to independent oil and gas operators who in our opinion tend to be more aggressive in spending, less focused on price and more likely to award work based on performance. With the major oil and gas companies divesting mature U.S. properties, we expect our target customers’ well population to grow over time through acquisition of properties formerly operated by major oil and gas companies. We concentrate on providing services to a diverse group of large and small independent oil and gas companies. These independents typically are relationship driven, make decisions at the local level and are willing to pay higher rates for services. We have been successful using this business model and believe it will enable us to continue to grow our business and maintain or expand our operating margins.
 
Safety Program
 
Our business involves the operation of heavy and powerful equipment which can result in serious injuries to our employees and third parties and substantial damage to property. We have comprehensive safety and training programs designed to minimize accidents in the workplace 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”,


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issue regulations to implement and enforce these laws, which often require difficult and costly compliance measures. Failure to comply with these laws and regulations may result in the assessment of substantial administrative, civil and criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities. In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of that person. Strict adherence with these regulatory requirements increases our cost of doing business and consequently affects our profitability. We believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a materially adverse effect upon our capital expenditures, earnings or our competitive position.
 
The Comprehensive Environmental Response, Compensation and Liability Act, referred to as “CERCLA” or the Superfund law, and comparable state laws impose liability, without regard to fault on certain classes of persons that are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances that have been released at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the costs of some health studies. In addition, companies that incur liability frequently confront additional claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.
 
The federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, referred to as “RCRA”, generally does not regulate most wastes generated by the exploration and production of oil and natural gas because that act specifically excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and gas from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies as non-hazardous wastes as long as these wastes are not commingled with regulated hazardous wastes. Moreover, in the ordinary course of our operations, industrial wastes such as paint wastes and waste solvents as well as wastes generated in the course of our 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 EPA 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 storm water discharge permit coverage and updating storm water 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


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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 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, 2008, we employed approximately 5,000 people, with approximately 82% 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.
 
Additional Information
 
We make available free of charge on our website, www.basicenergyservices.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such information with, or furnish it to, the SEC.
 
The certifications by our Chief Executive Officer and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 are filed as exhibits to this Annual Report on Form 10-K. We have also filed with the


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New York Stock Exchange the most recent Annual CEO Certification as required by Section 303A.12(a) of the New York Stock Exchange Listed Company Manual.
 
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
 
Our business depends on domestic spending by the oil and gas industry, and this spending and our business has been, and may continue to be, adversely affected by industry and financial market 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, as well as the availability of capital for operating and capital expenditures, may cause them to 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.
 
Recent deterioration in the global economic environment has caused the oilfield services industry to cycle into a downturn, and the rate at which it may continue to slow, or return to former levels, is uncertain. Recent adverse changes in capital markets and declines in prices for oil and gas have caused many oil and gas producers to announce reductions in capital budgets for future periods. Limitations on the availability of capital, or higher costs of capital, for financing expenditures may cause these and other oil and gas producers to make additional reductions to capital budgets in the future even if commodity prices increase from current levels. These cuts in spending will curtail drilling programs as well as discretionary spending on well services, which may result in a reduction in the demand for our services, the rates we can charge and our utilization. In addition, certain of our customers could become unable to pay their suppliers, including us. Any of these conditions or events could adversely affect our operating results.
 
If oil and gas prices remain volatile, remain low or decline further it could have an adverse effect on 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. Continued low oil and gas prices, a further 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. Although oil prices exceeded $140 per barrel and natural gas prices exceeded $13 per mcf in 2008, prices fell to


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below $40 per barrel and $6 per mcf by the end of 2008. The Cushing WTI Spot Oil Price averaged $66.05, $72.34 and $99.67 per barrel in 2006, 2007 and 2008, respectively, and the average wellhead price for natural gas, as recorded by the Energy Information Agency, was $6.42, $6.38 and $8.07 per mcf for 2006, 2007 and 2008, respectively. The Cushing WTI Spot Oil Price average for December 2008 was $41.12 and the wellhead price for natural gas as provided by the Energy Information Agency was $5.87 for December 2008. The speed and severity of the decline in oil and gas prices during the fourth quarter of 2008 and the resulting low prices in the first quarter of 2009 could materially affect the demand for our services and the rates that we are able to charge.
 
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, 2007, we invested approximately $98.5 million in cash for capital expenditures, excluding acquisitions. For the year ended December 31, 2008, we invested approximately $91.9 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 senior credit facility. 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 and 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. The recent adverse changes in the capital markets could make it difficult to obtain capital or obtain it at attractive rates.
 
Changes in future market conditions could cause recorded goodwill to become impaired, resulting in substantial write-downs that would reduce our operating income.
 
We have actively pursued the acquisition of other businesses. These investments are made after careful analysis and due diligence of the potential business. After the acquisitions are made, unforeseen market conditions could arise which adversely affect the anticipated cash flows from the acquired businesses. Goodwill accounts for approximately 15% of our total assets. We evaluate goodwill amounts for impairment annually, or more often if conditions require. The annual impairment test is based on several factors requiring judgment. Primarily, a significant decrease in expected cash flows or an adverse change in equity market conditions may indicate potential impairment of recorded goodwill. Due to recent changes in the above mentioned factors, we are recognizing a $22.5 million impairment of goodwill related to our contract drilling reporting unit in 2008. If the current economic conditions continue to decline further, we may be required to recognize a goodwill impairment in future periods on our well servicing, fluid services, and completion and remedial reporting units.


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Competition within the well services industry may adversely affect our ability to market our services.
 
The well services industry is highly competitive and fragmented and includes numerous small companies capable of competing effectively in our markets on a local basis, as well as several large companies that possess substantially greater financial and other resources than we do. Our larger competitors’ greater resources could allow those competitors to compete more effectively than we can. The amount of equipment available may exceed demand, which could result in active price competition. Many contracts are awarded on a bid basis, which may further increase competition based primarily on price. In addition, recent market conditions have stimulated the reactivation of well servicing rigs and construction of new equipment, which could result in excess equipment and lower utilization rates in future periods.
 
We depend on several significant customers, and a loss of one or more significant customers could adversely affect our results of operations.
 
Our customers consist primarily of major and independent oil and gas companies. During 2007 and 2008, our top five customers accounted for 16% and 18%, 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.
 
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.
 
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 our 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. As such, not all of our property is insured. We are also self-insured up to retention limits with regard to workers’ compensation and medical and dental coverage. 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 the risks to which we are subject, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive. 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 regulations 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 the conduct of, or conditions caused by, prior operators or other third parties. Clean-up costs and other damages arising as a result of environmental laws and 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, 2008, our total debt was $480.3 million, including the aggregate principal amount due under our Senior Notes of $225 million, an outstanding revolver balance of $180 million and capital lease obligations in the aggregate amount of $75.3 million. For the year ended December 31, 2008, we made cash interest payments totaling $24.5 million.
 
Our current and future indebtedness could have important consequences. For example, it could:
 
  •  impair our ability to make investments and obtain additional financing for working capital, capital expenditures, acquisitions or other general corporate purposes;


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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 other 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 facility could elect to terminate their commitments there under 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 senior credit facility and the indenture governing our Senior Notes impose restrictions on us that may affect our ability to successfully operate our business.
 
Our senior credit facility and the indenture governing our Senior Notes include limitations on our ability to take various actions, such as:
 
  •  limitations on the incurrence of additional indebtedness;
 
  •  restrictions on mergers, sales or transfer of assets without the lenders’ consent; and
 
  •  limitation on dividends and distributions.
 
In addition, our senior credit facility requires us to maintain certain financial ratios and to satisfy certain financial conditions, several of which become more restrictive over time and may require us to reduce our debt or take some other action in order to comply with them. The failure to comply with any of these financial conditions, including the financial ratios or covenants, would cause a default under our senior credit facility. A default, if not waived, could result in acceleration of the outstanding indebtedness under our senior credit facility, in which case the debt would become immediately due and payable. In addition, a default or acceleration of indebtedness under our senior 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 senior credit facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — 2007 Credit Facility” for a discussion of our credit facility.
 
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 134-rig commitment, of which the two remaining rigs are scheduled to be delivered during February 2009. There are 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


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fleet at economic levels. In addition, the failure of our current supplier to timely deliver the remaining newbuild rigs could adversely affect our budgeted or projected financial and operational data.
 
One of our directors may have a conflict of interest because he is also currently an affiliate, director or officer of a private equity firm that makes investments in the energy sector. The resolution of this conflict of interest may not be in our or our stockholders’ best interests.
 
Steven A. Webster, the Chairman of our Board of Directors, is the Co-Managing Partner of Avista Capital Holdings, L.P., a private equity firm that makes investments in the energy sector. This relationship may create a conflict of interest because of his responsibilities to Avista and its owners. His duties as a partner in, or director or officer of, Avista or its affiliates may conflict with his duties as a director of our company regarding corporate opportunities and other matters. The resolution of this conflict may not always be in our or our stockholders’ best interest.
 
Risks Relating to Our Relationship with DLJ Merchant Banking
 
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 February 27, 2009, 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 44.9% 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;
 
  •  limitations on the ability of our stockholders to call special meetings; and
 
  •  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.


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Because we have no plans to pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us.
 
We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that the board of directors deems relevant. The terms of our existing senior credit facility restrict the payment of dividends without the prior written consent of the lenders. Investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our common stock.
 
ITEM 1B.   UNRESOLVED STAFF COMMENTS
 
None.
 
ITEM 3.   LEGAL PROCEEDINGS
 
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.
 
ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
None.
 
Executive Officers
 
Our executive officers as of December 31, 2008 and their respective ages and positions are as follows:
 
             
Name
 
Age
 
Position
 
Kenneth V. Huseman
    56     President, Chief Executive Officer and Director
Alan Krenek
    53     Senior Vice President, Chief Financial Officer, Treasurer and Secretary
Charles W. Swift
    60     Senior Vice President — Operations Support
T.M. “Roe” Patterson
    34     Senior Vice President — Rig and Truck Operations
James F. Newman
    44     Group Vice President — Completion and Remedial Services
David W. Sledge(1)
    54     Vice President — Contract Drilling
Mark D. Rankin
    55     Vice President — Risk Management
James E. Tyner
    58     Vice President — Human Resources
 
 
(1) Mr. Sledge resigned effective February 27, 2009.
 
Set forth below is the description of the backgrounds of our executive officers.
 
Kenneth V. Huseman (President — Chief Executive Officer and Director) has 30 years of well servicing experience. He has been our President and Chief Executive Officer and a Director 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 1978 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 21 years of related industry experience. He has been our Vice President, Chief Financial Officer and Treasurer since January 2005. He


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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. 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 and is a certified public accountant.
 
Charles W. Swift (Senior Vice President — Operations Support) has 36 years of related industry experience including 27 years specifically in the domestic well service business. He was named Senior Vice 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.
 
T. M. “Roe” Patterson (Senior Vice President — Rig and Truck Operations) has 14 years of related industry experience. He has been our Senior Vice President of Rig and Truck operations since September 2008, and has been the Vice President of various different groups within Basic since February 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 a Contracts/Sales Manager for the 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.
 
James F. Newman (Group Vice President — Completion and Remedial Services) has 24 years of related industry experience and has been our Group Vice President of Completion and Remedial Services since September 2008. Prior to joining Basic, he co-founded Triple N Services in 1986 and served as its President thru May 2008. He initially served Basic as an Area Manager in the plugging and abandonment operations. Mr. Newman is a registered Professional Engineer and is active in the Society of Professional Engineers. Mr. Newman graduated with a BSc in Petroleum Engineering from Colorado School of Mines.
 
David W. Sledge (Vice President — Contract Drilling) has 29 years of related industry experience. He has been our Vice President of Contract Drilling since April 2007. Prior to joining us he served as President and COO of Sledge Drilling Corporation from March 2006 to March 2007. He served as an Area Manager for Patterson — UTI from 2004 to 2006. He was involved in private investments from 1997 to 2004. He served with Gene Sledge Drilling Corp. in various capacities and was President at the time of its sale to Patterson — UTI in 1996. He presently serves on the Board of Directors for Comstock Resources Inc. Mr. Sledge graduated with a B.B.A. degree in Management from Baylor University. Mr. Sledge resigned effective as of February 27, 2009.
 
Mark D. Rankin (Vice President — Risk Management) has 31 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 1979, 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.


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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 is traded on the New York Stock Exchange under the symbol “BAS”. 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 each of the quarters in the years ended December 31, 2007 and 2008, respectively:
 
                 
    High     Low  
 
2007:
               
First Quarter
  $ 24.42     $ 21.65  
Second Quarter
  $ 27.77     $ 23.39  
Third Quarter
  $ 25.82     $ 19.25  
Fourth Quarter
  $ 23.28     $ 18.92  
2008:
               
First Quarter
  $ 22.39     $ 17.95  
Second Quarter
  $ 32.82     $ 22.61  
Third Quarter
  $ 31.25     $ 20.36  
Fourth Quarter
  $ 19.87     $ 8.04  
 
As of February 27, 2009, we had 40,222,938 shares of common stock outstanding held by approximately 198 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, 2008:
 
                         
                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)
    1,608,675     $ 11.11       815,675  
Equity compensation plans not approved by security holders
                 
                         
Total
    1,608,675     $ 11.11       815,675  
                         
 
 
(1) Consists of the Basic Energy Services, Inc. Third Amended and Restated 2003 Incentive Plan (as amended effective May 12, 2008).


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Issuer Purchases of Equity Securities
 
The following table provides information relating to our repurchase of shares of common stock during the three months ended December 31, 2008 (in thousands, except average price paid per share):
 
                                 
                      Approximate Dollar
 
                Total Number of
    Value of Shares
 
          Average
    Shares Purchased as
    that May Yet be
 
    Total Number of
    Price Paid
    Part of Publicly
    Purchased Under the
 
Period
  Shares Purchased     per Share     Announced Program     Program (1)  
 
October 1, 2008 to October 31, 2008
    228     $ 10.41       228     $ 47,628  
November 1, 2008 to November 30, 2008
    631     $ 9.61       631     $ 41,558  
December 1, 2008 to December 31, 2008
    38     $ 9.74       38     $ 41,184  
 
 
(1) On October 13, 2008, Basic announced that its Board of Directors had authorized the repurchase of up to $50.0 million of Basic’s shares of common stock from time to time in open market or private transactions, at Basic’s discretion. The stock repurchase program may be suspended or discontinued at any time.


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Performance Graph
 
The following is a line graph comparing cumulative, total shareholder return from December 9, 2005 (the date of first trading) through December 31, 2008 with (i) a general market index (the Russell 2000 Index) and (ii) a group of peers selected by the Company in the same line of business or industry as the Company. The peer group is comprised of the following companies: Key Energy Services, Inc., Complete Production Services, Inc., Tetra Technologies, Inc., and Pioneer Drilling Company.
 
The graph assumes investments of $100 on December 9, 2005 at the closing sale price, and the reinvestment of all dividends, if any.
 
The graph shall not be deemed incorporated by reference by any general statement incorporating by reference this report into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that the Company specifically incorporates this information by reference, and shall not otherwise be deemed filed under such Acts.
 
December 9, 2005 to December 31, 2008
 
(PERFORMANCE GRAPH)
 
Value of $100 Invested December 9, 2005 at December 30, 2005, December 29, 2006, December 31, 2007 and December 31, 2008
 
                               
      Basic Energy
    Peer
     
      Services     Group     Russell 2000
December 9, 2005
    $ 100.00       $ 100.00       $ 100.00  
December 30, 2005
    $ 92.79       $ 97.03       $ 98.43  
December 29, 2006
    $ 114.65       $ 108.25       $ 114.36  
December 31, 2007
    $ 102.09       $ 85.52       $ 111.22  
December 31, 2008
    $ 60.65       $ 32.87       $ 72.51  
                               
 
The foregoing graph is based on historical data and is not necessarily indicative of future performance. This graph shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to the Regulations 14A or 14C under the Securities Exchange Act of 1934 or to the liabilities of Section 18 under such act.


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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,  
    2008     2007     2006     2005     2004  
    (Dollars in thousands)  
 
Statement of Operations Data:
                                       
Revenues:
                                       
Well servicing
  $ 343,113     $ 342,697     $ 323,755     $ 221,993     $ 142,551  
Fluid services
    315,768       259,324       245,011       177,927       139,610  
Completion and remedial services
    304,326       240,692       154,412       59,832       29,341  
Contract drilling
    41,735       34,460       6,970              
                                         
Total revenues
    1,004,942       877,173       730,148       459,752       311,502  
                                         
Expenses:
                                       
Well servicing
    215,243       205,132       178,028       137,392       98,058  
Fluid services
    203,205       165,327       153,445       114,551       96,621  
Completion and remedial services
    165,574       125,948       74,981       30,900       17,481  
Contract drilling
    28,629       22,510       8,400              
General and administrative(a)
    115,319       99,042       81,318       55,411       37,186  
Depreciation and amortization
    118,607       93,048       62,087       37,072       28,676  
Loss (gain) on disposal of assets
    76       477       277       (222 )     2,616  
Goodwill impairment
    22,522                          
                                         
Total expenses
    869,175       711,484       558,536       375,104       280,638  
                                         
Operating income
    135,767       165,689       171,612       84,648       30,864  
Other income (expense):
                                       
Net interest expense
    (24,630 )     (25,136 )     (15,504 )     (12,660 )     (9,550 )
Gain (loss) on early extinguishment of debt
          (230 )     (2,705 )     (627 )      
Other income (expense)
    12,235       176       169       220       (398 )
                                         
Income from continuing operations before income taxes
    123,372       140,499       153,572       71,581       20,916  
Income tax expense
    (55,134 )     (52,766 )     (54,742 )     (26,800 )     (7,984 )
                                         
Income from continuing operations
    68,238       87,733       98,830       44,781       12,932  
Discontinued operations, net of tax
                            (71 )
                                         
Net income
    68,238       87,733       98,830       44,781       12,861  
                                         
Net income available to common stockholders
  $ 68,238     $ 87,733     $ 98,830     $ 44,781     $ 12,861  
                                         
Basic earnings (loss) per share of common stock:
  $ 1.67     $ 2.19     $ 2.87     $ 1.57     $ 0.46  
                                         
Diluted earnings (loss) per share of common stock:
  $ 1.64     $ 2.13     $ 2.56     $ 1.35     $ 0.42  
                                         


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    Year Ended December 31,  
    2008     2007     2006     2005     2004  
    (Dollars in thousands)  
 
Other Financial Data:
                                       
Cash flows from operating activities
  $ 212,827     $ 198,591     $ 145,678     $ 99,189     $ 46,539  
Cash flows from investing activities
    (197,302 )     (294,103 )     (241,351 )     (107,679 )     (73,587 )
Cash flows from financing activities
    3,669       136,088       114,193       21,188       21,498  
Capital expenditures:
                                       
Acquisitions, net of cash acquired
    110,913       199,673       135,568       25,378       19,284  
Property and equipment
    91,890       98,536       104,574       83,095       55,674  
 
 
(a) Includes approximately $4,149, $3,964, $3,429, $2,890, and $1,587 of non-cash stock compensation expense for the years ended December 31, 2008, 2007, 2006, 2005 and 2004, respectively.
 
                                         
    As of December 31,  
    2008     2007     2006     2005     2004  
    (Dollars in thousands)  
 
Balance Sheet Data:
                                       
Cash and cash equivalents
  $ 111,135     $ 91,941     $ 51,365     $ 32,845     $ 20,147  
Property and equipment, net
    740,879       636,924       475,431       309,075       233,451  
Total assets
    1,310,711       1,143,609       796,260       496,957       367,601  
Long-term debt
    454,260       406,306       250,742       119,241       170,915  
Stockholders’ equity
    595,004       524,821       379,250       258,575       121,786  
 
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, completion and remedial services and contract drilling services. Our results of operations reflect the impact of our acquisition strategy as a leading consolidator in the domestic land-based well services industry. 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 40 separate acquisitions from January 1, 2004 to December 31, 2008. Our weighted average number of well servicing rigs increased from 126 in 2001 to 414 in the fourth quarter of 2008, and our weighted average number of fluid service trucks increased from 156 to 804 in the same period. We added 98 trucks through the acquisition of Azurite Services Company, Inc., Azurite Leasing Company, LLC, and Freestone Disposal, LP (collectively “Azurite”) in the third quarter of 2008. We significantly increased our completion and remedial services segment, principally through the acquisition of JetStar Consolidated Holdings, Inc. in the first quarter of 2007. Our weighted average number of drilling rigs increased from two in the first quarter of 2006 to nine in the fourth quarter of 2008, principally through the acquisition of Sledge Drilling Holding Corp. in the second quarter of 2007. These acquisitions make changes in revenues, expenses and income not directly comparable between periods.
 
Basic revised its business segments beginning in the first quarter of 2008, and in connection therewith, restated the corresponding items of segment information for earlier periods. The new operating segments are Well Servicing, Fluid Services, Completion and Remedial Services, and Contract Drilling. These segments were selected based on changes in management’s resource allocation and performance assessment in making decisions regarding the Company. Contract Drilling was previously included in our Well Servicing segment. The Well Site Construction Services segment was consolidated into our Fluid Services segment. These changes reflect Basic’s operating focus in compliance with Statement of Financial Accounting Standards (SFAS) No. 131, “Disclosures about Segments of an Enterprise and Related Information.”

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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,  
    2008     2007     2006  
 
Revenues:
                                               
Well servicing
  $ 343.1       34 %   $ 342.7       39 %   $ 323.7       44 %
Fluid services
    315.8       32 %     259.3       29 %     245.0       34 %
Completion and remedial services
    304.3       30 %     240.7       28 %     154.4       21 %
Contract drilling
    41.7       4 %     34.5       4 %     7.0       1 %
                                                 
Total revenues
  $ 1,004.9       100 %   $ 877.2       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 “General Industry Overview” included in Items 1 and 2, Business and Properties, of this Annual Report on Form 10-K.
 
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, our revenues will vary based on changes in capital spending by our customers as oil and gas prices increase or decrease.
 
During 2006, our business activity levels increased due to the impact of higher oil and gas prices and the expansion of our equipment fleets. In 2007, natural gas prices declined as an excess supply of natural gas began to occur, mainly due to moderate U.S. weather patterns. Utilization for our services declined from 2006 levels as drilling activity flattened or declined in several of our markets and new equipment entered the marketplace balancing supply and demand for our services. However, pricing for our services improved in 2007 from 2006, mainly reflecting continued increases in labor costs, and offset a portion the effect of the lower utilization of our services on our total revenues. By the middle of 2008, oil and natural gas prices reached historic highs. However, in the second half of 2008 there were significant decreases in oil and natural gas prices, which caused significantly lower utilization of our services in the fourth quarter of 2008. For 2009, we expect oil and gas prices to remain substantially below the levels required to support aggressive capital spending programs by our customers and that their maintenance related spending will be deferred for as long as possible. The reduced spending by our customers will result in significantly lower demand for our services and increased price competition among the service providers in each of our segments. We anticipate that utilization, revenue and margins will be substantially below 2008 levels. We do not currently believe that the changes being experienced during the first quarter of 2009 and anticipated later in 2009 will affect the Company’s compliance with the financial covenants in its debt agreements.
 
We will continue to evaluate opportunities to grow our business through selective acquisitions and internal growth initiatives. 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 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


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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.
 
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;
 
  •  Completion and Remedial Services — segment profits as a percent of revenues; and
 
  •  Contract Drilling — rig operating days, revenue per drilling day and 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 “Segment Overview” below.
 
Recent Strategic Acquisitions and Expansions
 
During the period from 2006 through 2008, we grew significantly through acquisitions and capital expenditures. During 2006, we completed ten acquisitions, of which G&L Tool, Ltd. was considered significant for purposes of SFAS No. 141, “Business Combinations.” During 2007, we completed eight acquisitions, of which JetStar Consolidated Holdings, Inc. and Sledge Drilling Holding Corp. were considered significant for purposes of SFAS No. 141. During 2008, we completed five acquisitions, of which Azurite was considered significant for purposes of SFAS No. 141.
 
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., JetStar Consolidated Holdings, Inc., Sledge Drilling Holding Corp., and Azurite in Note 3 of our historical consolidated financial statements included in this report.
 
Selected 2006 Acquisitions
 
During 2006, we made several acquisitions that complemented our existing business segments and provided an entry into the rental and fishing 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. (“Lebus”) for an acquisition price of $26 million, subject to adjustments. This acquisition significantly expanded our fluid services segment 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. (“G&L”) for total consideration of $58.5 million in cash. This acquisition provided an entry into the rental and fishing tool market and operates within our completion and remedial 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. (“Chaparral”) for total consideration of $19 million in cash, subject to


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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.
 
Selected 2007 Acquisitions
 
During 2007, we made several acquisitions that complemented our existing business segments. These included, among others:
 
Parker Drilling Offshore USA, LLC
 
On January 3, 2007, we acquired two barge-mounted workover rigs and related equipment from Parker Drilling Offshore USA, LLC for total consideration of $20.5 million in cash. The acquired rigs operate in the inland waters of Louisiana and Texas as a part of Basic Marine Services.
 
JetStar Consolidated Holdings, Inc.
 
On March 6, 2007, we acquired all of the outstanding capital stock of JetStar Consolidated Holdings, Inc. (“JetStar”) for an aggregate purchase price of approximately $127.3 million, including $86.3 million in cash, of which approximately $37.6 million was used for the retirement of JetStar’s outstanding debt. As part of the purchase price, we issued 1,794,759 shares of common stock, at a fair value of $22.86 per share for a total fair value of approximately $41 million. This acquisition operates in our completion and remedial business segment.
 
Sledge Drilling Holding Corp.
 
On April 2, 2007, we acquired all of the outstanding capital stock of Sledge Drilling Holding Corp. (“Sledge”) for an aggregate purchase price of approximately $60.8 million, including $50.6 million in cash, of which approximately $19 million was used for the repayment of Sledge’s outstanding debt. As part of the purchase price, we issued 430,191 shares of common stock at a fair value of $23.63 per share for a total fair value of approximately $10.2 million. This acquisition allowed us to expand our drilling operations in the Permian Basin and operates in our contract drilling segment.
 
Wildhorse Services, Inc.
 
On June 5, 2007, we acquired all of the outstanding capital stock of Wildhorse Services, Inc. (“Wildhorse”) for an aggregate purchase price of approximately $17.3 million, net of cash acquired. This acquisition allowed us to expand our rental and fishing tool operations in northwestern Oklahoma and the Texas panhandle area. This acquisition operates in our completion and remedial line of business.
 
Selected 2008 Acquisitions
 
During 2008, we made several acquisitions that complemented our existing business segments. These included, among others:
 
Xterra Fishing and Rental Tools Co
 
On January 28, 2008, we acquired all of the outstanding capital stock of Xterra Fishing and Rental Tools Co. (“Xterra”) for total consideration of $21.1 million cash. This acquisition operates in our completion and remedial services line of business.
 
Azurite Services Company, Inc, Azurite Leasing Company, LLC and Freestone Disposal, L.P.
 
On September 26, 2008, we acquired substantially all of the operating assets of Azurite for $60.2 million in cash. This acquisition operates in our fluid services line of business.


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Segment Overview
 
Well Servicing
 
In 2008, our well servicing segment represented 34% 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 well servicing rig 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. We measure the activity level of our well servicing rigs on a weekly basis by calculating a rig utilization rate which is based on a 55-hour work week per rig.
 
Our well servicing rig fleet increased from a weighted average number of 325 rigs in the first quarter of 2006 to 414 in the fourth quarter of 2008 through a combination of newbuild purchases, acquisitions, and other individual equipment purchases.
 
The following is an analysis of our well servicing segment for each of the quarters and years in the years ended December 31, 2006, 2007 and 2008:
 
                                                 
    Weighted
                               
    Average
          Rig
          Profits
       
    Number of
    Rig
    Utilization
    Revenue Per
    Per Rig
    Segment
 
    Rigs     Hours     Rate     Rig Hour     Hour     Profits%  
 
2006:
                                               
First Quarter
    325       208,700       89.8 %   $ 349     $ 157       44.9 %
Second Quarter
    337       219,300       91.0 %   $ 365     $ 165       45.2 %
Third Quarter
    351       226,300       90.2 %   $ 379     $ 175       46.1 %
Fourth Quarter
    360       213,900       83.1 %   $ 398     $ 174       43.8 %
Full Year
    344       868,200       88.2 %   $ 373     $ 168       45.0 %
2007:
                                               
First Quarter
    364       210,800       81.0 %   $ 411     $ 174       42.2 %
Second Quarter
    371       207,700       78.3 %   $ 415     $ 163       39.5 %
Third Quarter
    383       212,100       77.7 %   $ 414     $ 166       40.0 %
Fourth Quarter
    386       200,600       72.7 %   $ 409     $ 159       38.8 %
Full Year
    376       831,200       77.3 %   $ 412     $ 166       40.1 %
2008:
                                               
First Quarter
    392       202,500       72.2 %   $ 398     $ 158       39.8 %
Second Quarter
    403       222,300       77.1 %   $ 400     $ 152       37.9 %
Third Quarter
    412       233,000       79.1 %   $ 418     $ 156       37.3 %
Fourth Quarter
    414       182,400       61.6 %   $ 418     $ 141       33.8 %
Full Year
    405       840,200       72.5 %   $ 408     $ 152       37.3 %
 
We gauge activity levels in our well servicing rig operations based on rig utilization rate, revenue per rig hour and profits per rig hour.
 
Fluid Services
 
In 2008, our fluid services segment represented 32% 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. Revenues also include well site construction and maintenance services. 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


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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. Revenues from our well site constructions services 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. We typically price fluid services by the job, by the hour or by the quantities sold, disposed of or hauled.
 
The following is an analysis of our fluid services segment for each of the quarters and years in the years ended December 31, 2006, 2007 and 2008 (dollars in thousands):
 
                                 
                Segment
       
    Weighted
          Profits
       
    Average
          Per
       
    Number of
    Revenue Per
    Fluid
       
    Fluid Service
    Fluid Service
    Service
    Segment
 
    Trucks     Truck     Truck     Profits%  
 
2006:
                               
First Quarter
    529     $ 101     $ 37       36.4 %
Second Quarter
    568     $ 109     $ 42       38.2 %
Third Quarter
    614     $ 105     $ 38       36.7 %
Fourth Quarter
    640     $ 103     $ 39       38.0 %
Full Year
    588     $ 417     $ 156       37.4 %
2007:
                               
First Quarter
    652     $ 98     $ 37       37.5 %
Second Quarter
    657     $ 96     $ 35       36.1 %
Third Quarter
    653     $ 97     $ 35       35.7 %
Fourth Quarter
    656     $ 104     $ 37       35.7 %
Full Year
    655     $ 396     $ 144       36.2 %
2008:
                               
First Quarter
    644     $ 111     $ 39       35.0 %
Second Quarter
    663     $ 109     $ 36       33.1 %
Third Quarter
    683     $ 121     $ 43       35.8 %
Fourth Quarter
    804     $ 111     $ 42       38.1 %
Full Year
    699     $ 452     $ 161       35.6 %
 
We gauge activity levels in our fluid services segment based on revenue and segment profits per fluid service truck.
 
Completion and Remedial Services
 
In 2008, our completion and remedial services segment represented 30% of our revenues. Revenues from our completion and remedial 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 completion and remedial services segment includes pressure pumping, rental and fishing tool operations, cased-hole wireline services and underbalanced drilling.
 
Our pressure pumping operations concentrate on providing single truck, lower-horsepower cementing, acidizing and fracturing services in selected markets. On March 6, 2007, we acquired all of the outstanding capital stock of JetStar Consolidated Holdings, Inc. This acquisition allowed us to enter into the southwest Kansas market and increased our presence in North Texas. Our total hydraulic horsepower capacity for our pressure pumping operations was approximately 139,000 horsepower at December 31, 2008 compared to 120,000 horsepower at December 31, 2007 and 58,000 horsepower at December 31, 2006.


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We entered the rental and fishing tool business through our acquisition of G&L in the first quarter of 2006. This acquisition consisted of 16 rental and fishing tool stores in the North Texas, West Texas, and Oklahoma markets. We have since further expanded this business line with several acquisitions and had 20 rental and fishing tool stores as of December 31, 2008.
 
We entered the wireline business in 2004 with 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 “Overview of Our Segments and Services — Completion and Remedial Services Segment” included in Items 1 and 2, Business and Properties, of this Annual Report on Form 10-K.
 
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 completion and remedial services segment for each of the quarters and years in the years ended December 31, 2006, 2007 and 2008 (dollars in thousands):
 
                 
          Segment
 
    Revenues     Profits%  
 
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 %
2007:
               
First Quarter
  $ 46,137       49.9 %
Second Quarter
  $ 63,735       47.6 %
Third Quarter
  $ 66,304       47.6 %
Fourth Quarter
  $ 64,515       46.2 %
Full Year
  $ 240,692       47.7 %
2008:
               
First Quarter
  $ 68,458       47.7 %
Second Quarter
  $ 79,579       46.4 %
Third Quarter
  $ 85,541       45.3 %
Fourth Quarter
  $ 70,748       43.0 %
Full Year
  $ 304,326       45.6 %
 
We gauge the performance of our completion and remedial services segment based on the segment’s operating revenues and segment profits.
 
Contract Drilling
 
In 2008, our contract drilling segment represented 4% of our revenues. Revenues from our contract drilling segment are derived primarily from the drilling of new wells.
 
Within this segment, we typically charge our drilling rig customers at a daywork daily rate, or footage at an established rate per number of feet drilled. Depending on the type of job, we may also charge by the project. We measure the activity level of our drilling rigs on a weekly basis by calculating a rig utilization rate which is based on a seven day work week per rig.
 
Our contract drilling rig fleet grew from two during the first quarter of 2006 to nine by the fourth quarter of 2008, due to the Sledge acquisition in April 2007.


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The following is an analysis of our contract drilling segment for each of the quarters and years in the years ended December 31, 2006, 2007, and 2008 (dollars in thousands):
 
                                         
    Weighted
                         
    Average
    Rig
                   
    Number of
    Operating
    Revenue
    Profits (Loss)
    Segment
 
    Rigs     Days     Per Day     Per Day     Profits%  
 
2006:
                                       
First Quarter
    2       12       N.M.       N.M.       N.M.  
Second Quarter
    2       104     $ 11,700     $ (4,900 )     −45.2 %
Third Quarter
    2       160     $ 14,700     $ 1,600       10.9 %
Fourth Quarter
    3       208     $ 13,300     $ (1,600 )     −11.7 %
Full Year
    2       484     $ 14,400     $ (3,000 )     −20.5 %
2007:
                                       
First Quarter
    3       168     $ 11,500     $ (5,200 )     −44.9 %
Second Quarter
    8       594     $ 17,200     $ 6,900       39.5 %
Third Quarter
    9       723     $ 15,700     $ 6,700       42.4 %
Fourth Quarter
    10       748     $ 14,600     $ 5,300       36.3 %
Full Year
    8       2,233     $ 15,400     $ 5,400       34.7 %
2008:
                                       
First Quarter
    9       645     $ 14,700     $ 3,800       25.7 %
Second Quarter
    9       699     $ 14,800     $ 4,000       27.2 %
Third Quarter
    9       767     $ 15,600     $ 5,600       35.6 %
Fourth Quarter
    9       666     $ 14,900     $ 5,400       36.2 %
Full Year
    9       2,777     $ 15,000     $ 4,700       31.4 %
 
We gauge activity levels in our drilling operations based on rig operating days, revenue per day, and profits per drilling day. The results of the first quarter 2006 are not considered meaningful, due to the start-up nature of the drilling operations, and the fact that only twelve operating days were completed in this quarter.
 
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. 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 our safety record.
 
Critical Accounting Policies and Estimates
 
Our consolidated financial statements are impacted by the accounting policies used and the estimates and assumptions made by management during their preparation. A complete summary of these policies is included in Note 2 of the notes to our historical consolidated financial statements. The following is a discussion of our critical accounting policies and estimates.
 
Critical Accounting Policies
 
We have identified below accounting policies that are of particular importance in the presentation of our financial position, results of operations and cash flows and which require the application of significant judgment by management.
 
Property and Equipment.  Property and equipment are stated at cost, or at estimated fair value at acquisition date if acquired in a business combination. Expenditures for repairs and maintenance are charged to expense as


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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 $375,000 and $180,000 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 SFAS 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 the 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.
 
Impairment of Goodwill.  Our goodwill is considered to have an indefinite useful economic life and is not amortized. We assess impairment of our goodwill annually as of December 31 or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. SFAS No. 142, “Goodwill and Other Intangible Assets” (“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


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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.
 
In step one of the annual impairment test and due to the adverse equity market conditions affecting the Company’s common stock price and the declines in oil and natural gas prices in the fourth quarter of 2008 and continuing into 2009, the Company tested its four reporting units, well servicing, fluid services, completion and remedial services, and contract drilling, for impairment. To estimate the fair value of the reporting units the Company used a weighting of the discounted cash flow method, the guideline transaction method, and the public company guideline method. The Company weighted the discounted cash flow method 85% in its analysis and the other two methods combined 15% due to differences between the Company’s reporting units and the peer companies size, profitability and diversity of operations. In order to validate the reasonableness of the estimated fair values obtained for the reporting units, a reconciliation of fair value to market capitalization was performed. The control premium used in the reconciliation was derived from a market transaction data study along with historical control premiums from other Basic acquisitions. The measurement date for the stock price for the reconciliation was the closing price on December 31, 2008.
 
Based on the results of step one, impairment was indicated in the contract drilling reporting unit but not in the other three reporting units. As a result the Company tested the contract drilling reporting unit’s long-lived assets for impairment under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS No. 144”), which indicated no impairment. The Company performed step two for the contract drilling unit by allocating the estimated fair value to the tangible and intangible assets and liabilities, which indicated that the entire value of the goodwill in contract drilling of $22.5 million was impaired. This non-cash charge eliminates the goodwill recorded in connection with the Sledge acquisition in 2007. The goodwill associated with this acquisition has no tax basis, and accordingly, there is no tax benefit derived from recording the impairment charge. Further declines in the Company’s stock price and general market conditions may be considered as a triggering event for the first quarter of 2009. If this is the case, the Company will analyze its goodwill as of March 31, 2009 and potentially record further goodwill impairments in its well servicing, fluid services and/or completion and remedial services reporting units.
 
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-insured 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 litigation 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 the 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. We test annually for impairment of 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.


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Stock-Based Compensation.  On January 1, 2006, we adopted the fair value recognition provisions of SFAS 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 SFAS 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, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”) requires us to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets and to capitalize an equal amount as a cost of the asset, depreciating it over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each quarter to reflect the passage of time, changes in the estimated future cash flows underlying the obligation, acquisition or construction of assets, and settlement of obligations.
 
Results of Operations
 
The results of operations between periods will not be comparable, primarily due to the significant number of acquisitions made and their relative timing in the year acquired. See Note 3 of the notes to our historical consolidated financial statements for more detail.
 
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
 
Revenues.  Revenues increased by 15% to $1.0 billion in 2008 from $877.2 million in 2007. This increase was primarily due to acquisitions in the completion and remedial services and fluid services segments, and to the internal expansion of our business segments.
 
Well servicing revenues increased by less than 1% to $343.1 million in 2008 compared to $342.7 million in 2007. Revenue remained relatively flat due to the increase in rig hours to 840,200 in 2008 as compared to 831,200 in 2007 being offset by a decrease in revenue per rig hour to $408 in 2008 from $412 in 2007. Similarly, an increase in the weighted average number of rigs was offset by lower utilization rates. Our weighted average number of rigs increased to 405 in 2008 from 376 in 2007. The increase was due to the addition of 22 newbuild rigs, 13 rigs from acquisitions and the conversion of one drilling rig to workover mode, offset by the retirement of 9 rigs in 2008. The rig utilization rate for our well servicing rigs declined to 73% in 2008 compared to 77% in 2007.
 
Fluid services revenues increased by 22% to $315.8 million in 2008 compared to $259.3 million in 2007. This increase was primarily due to the Azurite acquisition and internal growth. The Azurite acquisition added 98 trucks, 632 frac tanks and six disposal wells, which increased revenues by approximately $10.9 million in 2008. Our weighted average number of fluid service trucks increased to 699 in 2008 compared to 655 in 2007, an increase of approximately 7%. During 2008, our average revenue per fluid service truck was approximately $452,000 as compared to $396,000 in 2007.


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Completion and remedial services revenues increased by 26% to $304.3 million in 2008 as compared to $240.7 million in 2007. The increase in revenue between these periods was primarily the result of the acquisition of JetStar in March 2007, Xterra in January 2008 and Triple N Services, Inc. (“Triple N”) in May 2008. The yards associated with the JetStar acquisition added approximately $20.9 million more in revenue in 2008 compared to 2007, the Xterra yards added $17.7 million in revenues for 2008 and the Triple N yards added $4.7 million in revenues for 2008. There was also improved utilization for our services in 2008 due to higher oil and natural gas prices for the majority of 2008.
 
Contract drilling revenues increased by 21% to $41.7 million in 2008 compared to $34.5 million in 2007. The increase was due mainly to the acquisition of Sledge in April 2007, which added approximately $3.9 million more in revenues in 2008 compared to 2007. There was also an increase in rig operating days to 2,777 in 2008 compared to 2,233 in 2007, an increase of 24%. Revenue per drilling day was $15,000 in 2008 compared to $15,400 in 2007, a decrease of 3%.
 
Direct Operating Expenses.  Direct operating expenses, which primarily consist of labor, including workers’ compensation and health insurance, and maintenance and repair costs, increased by 18% to $612.6 million in 2008 from $518.9 million in 2007. This increase was primarily due to the acquisitions we completed in 2008, the expansion of our well servicing rig and fluid service truck fleets, and increases in personnel and related benefit costs. Direct operating expenses increased to 61.0% of revenues in 2008 from 59.2% in 2007.
 
Direct operating expenses for the well servicing segment increased by 5% to $215.2 million in 2008 as compared to $205.1 million in 2007 due primarily to the expansion of our well servicing rig fleet. Segment profits decreased to 37.3% of revenues in 2008 compared to 40.1% in 2007, which reflects higher fuel costs in 2008 and higher labor costs since we generally retain our rig crews during times of lower utilization.
 
Direct operating expenses for the fluid services segment increased by 23% to $203.2 million in 2008 as compared to $165.3 million in 2007 due primarily to the expansion of our fluid services fleet. The Azurite acquisition added approximately $7.2 million in operating expense in 2008. Segment profits decreased slightly to 35.6% of revenues in 2008 compared to 36.2% in 2007, mainly due to higher fuel costs.
 
Direct operating expenses for the completion and remedial services segment increased by 31% to $165.6 million in 2008 as compared to $125.9 million in 2007 due primarily to the expansion of our services and equipment, including the JetStar, Xterra and Triple N acquisitions, and higher operating costs. JetStar operating expenses were approximately $18.3 million more in 2008 than in 2007, Xterra operating expenses were $7.6 million in 2008 and Triple N operating expenses were $2.1 million in 2008. Our segment profits decreased to 45.6% of revenues in 2008 from 47.7% in 2007, as we experienced higher fuel costs and increases in costs of the materials used in our pressure pumping operations.
 
Direct operating expenses for the contract drilling segment increased by 27% to $28.6 million in 2008 as compared to $22.5 million in 2007. The Sledge acquisition added approximately $6.6 million of operating expenses. Our segment profits decreased to 31.4% of revenues in 2008 from 34.7% in 2007, as we experienced increased fuel and transportation expense.
 
General and Administrative Expenses.  General and administrative expenses increased by 16% to $115.3 million in 2008 from $99.0 million in 2007, which included $4.1 million and $4.0 million of stock-based compensation expense in 2008 and 2007, 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 $118.6 million in 2008, as compared to $93.0 million in 2007, reflecting the increase in the size of and investment in our asset base. We invested $110.9 million for acquisitions, $50.7 million for capital leases and an additional $91.9 million for capital expenditures in 2008.
 
Goodwill Impairment.  In the fourth quarter of 2008, we recorded a non-cash charge totaling $22.5 million to impair the contract drilling goodwill.


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Interest Expense.  Interest expense decreased by 2% to $26.8 million in 2008 from $27.4 million in 2007. The decrease was due primarily to lower interest rates on our revolving line of credit, which was offset by an increase in interest expense due to the $30.0 million draw down on our revolver in September 2008.
 
Other Income and Expense.  Other income and expense included $18.2 million of merger costs associated with the terminated merger agreement with Grey Wolf, Inc., offset by termination payments received from Grey Wolf, Inc. for $30.0 million.
 
Income Tax Expense.  Income tax expense was $55.1 million in 2008, as compared to $52.8 million in 2007. Our effective tax rate was approximately 45% in 2008 and 38% in 2007.
 
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
 
Revenues.  Revenues increased by 20% to $877.2 million in 2007 from $730.1 million in 2006. This increase was primarily due to acquisitions in the completion and remedial services and well servicing segments, and to the internal expansion of our business segments, mainly well servicing.
 
Well servicing revenues increased by 6% to $342.7 million in 2007 compared to $323.8 million in 2006. The increase was mainly due to internal growth of this segment as we added 45 newbuild rigs to our fleet in 2007. Our weighted average number of well servicing rigs increased to 376 in 2007 compared to 344 in 2006, an increase of approximately 9%. The rig utilization rate for our well servicing rigs declined to 77% in 2007 compared to 88% in 2006. This decline was due to stabilization of industry markets after experiencing significant growth throughout 2005 and 2006. The effect on revenue from this lower rig utilization rate was partially offset by an increase of 10% in our revenue per rig hour from 2006, which increased to $412 per rig hour, and the expansion of our well servicing fleet.
 
Fluid services revenues increased by 6% to $259.3 million in 2007 compared to $245.0 million in 2006. This increase was primarily due to our internal growth and acquisitions. The Steve Carter Inc. and Hughes Services Inc. acquisition added 22 trucks to our fleet and increased revenues by approximately $2.2 million for the fourth quarter of 2007. Our weighted average number of fluid service trucks increased to 655 in 2007 compared to 588 in 2006, an increase of approximately 11%. During 2007, our average revenue per fluid service truck was approximately $396,000 as compared to $417,000 in 2006.
 
Completion and remedial services revenues increased by 56% to $240.7 million in 2007 as compared to $154.4 million in 2006. The increase in revenue between these periods was primarily the result of the acquisition of JetStar in March 2007, which added revenues of $57.1 million, and improved pricing and utilization of our services.
 
Contract drilling revenues increased by 394% to $34.5 million in 2007 compared to $7.0 million in 2006. The increase was due mainly to the acquisition of Sledge, which added revenues of $23.9 million. Revenue per drilling day was $15,400 in 2007 compared to $14,400 in 2006, an increase of 7%.
 
Direct Operating Expenses.  Direct operating expenses, which primarily consist of labor, including worker’s compensation and health insurance, and maintenance and repair costs, increased by 25% to $518.9 million in 2007 from $414.9 million in 2006. This increase was primarily due to the acquisitions we completed in 2007, the expansion of our well servicing rig and fluid service truck fleets, and increases in personnel and related benefit costs. Direct operating expenses increased to 59.2% of revenues in 2007 from 56.8% in 2006.
 
Direct operating expenses for the well servicing segment increased by 15% to $205.1 million in 2007 as compared to $178.0 million in 2006 due primarily to the expansion of our well servicing rig fleet. Segment profits decreased to 40.1% of revenues in 2007 compared to 45.0% in 2006, which reflects higher labor costs as we retained our rig crews during times of lower utilization.
 
Direct operating expenses for the fluid services segment increased by 8% to $165.3 million in 2007 as compared to $153.4 million in 2006 due primarily to the expansion of our fluid services fleet and higher labor costs. Segment profits decreased to 36.2% of revenues in 2007 compared to 37.4% in 2006.
 
Direct operating expenses for the completion and remedial services segment increased by 68% to $125.9 million in 2007 as compared to $75.0 million in 2006 due primarily to the expansion of our services and equipment, including the JetStar acquisition, and higher operating costs. JetStar operating expenses were approximately $34.1 million in


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2007. Our segment profits decreased to 47.7% of revenues in 2007 from 51.4% in 2006, as we experienced higher labor costs and increases in costs of the materials used in our pressure pumping operations.
 
Direct operating expenses for the contract drilling segment increased by 168% to $22.5 million in 2007 as compared to $8.4 million in 2006. The increase was primarily due to the acquisition of Sledge, which added $11.7 million of operating expenses.
 
General and Administrative Expenses.  General and administrative expenses increased by 22% to $99.0 million in 2007 from $81.3 million in 2006, which included $4.0 million and $3.4 million of stock-based compensation expense in 2007 and 2006, 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 $93.0 million in 2007 as compared to $62.1 million in 2006, reflecting the increase in the size of and investment in our asset base, particularly due to the Sledge and JetStar acquisitions. We invested $252 million for acquisitions, $26.8 million for capital leases and an additional $98.5 million for capital expenditures in 2007.
 
Interest Expense.  Interest expense increased by 57% to $27.4 million in 2007 from $17.5 million in 2006. The increase was due to an increase in the amount of long-term debt during the period. In 2007, we used $150 million of our credit revolver for the acquisitions of Sledge, JetStar and Wildhorse.
 
Income Tax Expense.  Income tax expense was $52.8 million in 2007 as compared to $54.7 million in 2006. Our effective tax rate was approximately 38% in 2007 and 36% in 2006.
 
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 our previous 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.
 
Liquidity and Capital Resources
 
Currently, our primary capital resources are net cash flows from our operations, utilization of capital leases as allowed under our Fourth Amended and Restated Credit Agreement (the “2007 Credit Facility”) and availability under our 2007 Credit Facility, under which approximately $28.8 million of borrowing capacity was available at December 31, 2008. As of December 31, 2008, we had cash and cash equivalents of $111.1 million compared to $91.9 million as of December 31, 2007. 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 $212.8 million for the year ended December 31, 2008 as compared to $198.6 million in 2007 and $145.7 million in 2006. The increase in 2008 was due primarily to higher revenues being partially offset by an increase in accounts receivable and other working capital changes. The increase in operating cash flows in 2007 compared to 2006 was primarily due to higher revenue and working capital changes.
 
Capital Expenditures
 
Capital expenditures are the main component of our investing activities. Cash capital expenditures (including for acquisitions) for 2008 were $202.8 million as compared to $298.2 million in 2007, and $240.1 million in 2006. In 2008, 2007 and 2006, the majority of our capital expenditures were for business acquisitions. We also added assets through our capital lease program of approximately $50.7 million, $26.8 million and $26.4 million in 2008, 2007 and 2006, respectively.
 
For 2009, we currently have planned approximately $40 million in cash capital expenditures and $22 million in new capital leases, none of which is planned for acquisitions. We do not budget acquisitions in the normal course of business. The $40 million of cash 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


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and (3) replacement of existing equipment. We regularly engage in discussions related to potential acquisitions related to the well services industry.
 
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 $84.7 million at December 31, 2008, the availability under our 2007 Credit Facility of $28.8 million at December 31, 2008 and a cash balance of $111.1 million at December 31, 2008. In 2008, we financed activities in excess of cash flow from operations primarily through the use of bank debt and capital leases.
 
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 long-term debt, (3) our capital leases, (4) our operating leases, (5) our asset retirement obligations, and (6) our other long-term liabilities. The following table outlines our contractual obligations as of December 31, 2008 (in thousands):
 
                                         
    Obligations Due in Periods Ended
       
    December 31,        
Contractual Obligations
  Total     2009     2010-2011     2012-2013     Thereafter  
 
Long-term debt (excluding capital leases)
  $ 405,000     $     $ 180,000     $     $ 225,000  
Interest on long-term debt
    134,166       24,851       40,515       32,062       36,738  
Capital leases
    75,323       26,063       36,292       12,968        
Operating leases
    22,322       4,543       7,845       4,714       5,220  
Asset retirement obligations
    1,797             565       48       1,184  
Other long-term liabilities
    4,557       1,908       1,311       985       353  
                                         
Total
  $ 643,165     $ 57,365     $ 266,528     $ 50,777     $ 268,495  
                                         
 
Our long-term debt, excluding capital leases, consists primarily of revolver indebtedness outstanding under our 2007 Credit Facility. Interest on long-term debt relates to our future contractual interest obligation on our $225 million 7.125% Senior Notes due 2016 and $180 million outstanding under our 2007 Credit Facility. Interest on our 2007 Credit Facility is payable based upon the amount outstanding at December 31, 2008, at an interest rate of LIBOR plus 125 basis points. 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, 2008, we had a maximum potential obligation of $22.0 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 targets are exceeded. See Note 3 of the notes to our historical consolidated financial statements for additional detail.
 
At December 31, 2008, of the $225 million in financial commitments under the revolving line of credit under our 2007 Credit Facility, there was only $28.8 million of available capacity due to the outstanding balance of $180 million and the $16.2 million of outstanding standby letters of credit. The 2007 Credit Facility includes provisions allowing us to request an increase in commitments of up to $100 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.
 
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 million 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


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outstanding balance under our previous senior 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 accrues 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. The Senior Notes mature on April 15, 2016. The Senior Notes and the 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 are effectively subordinated to our and the guarantors’ secured obligations, including our senior credit facility, 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.
 
2007 Credit Facility
 
On February 6, 2007, we amended and restated our existing credit agreement by entering into the 2007 Credit Facility. At December 31, 2008, we had $180 million outstanding under this 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 lenders’ total revolving commitments from $150 million to $225 million;


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  •  increasing the “Incremental Revolving Commitments” 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 the 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 the 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 million aggregate principal amount subject to meeting certain tangible value requirements and subject to lender participation at the time of the request. 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 $0.7 million in debt issuance costs in connection with the 2007 Credit Facility.
 
At our option, borrowings under the Revolver bear interest at either (1) the “Alternative Base Rate” (i.e., the higher of the bank’s prime rate or the federal funds rate plus .50% per year) plus 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%.
 
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 3.25 to 1.00, and
 
  •  a minimum interest coverage ratio of 3.00 to 1.00.


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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 is material individually. As of December 31, 2008, we had total capital leases of approximately $75.3 million.
 
Losses on Extinguishment of Debt
 
In February 2007 and April 2006, we recognized a loss on the early extinguishment of debt. In February 2007, we wrote off unamortized debt issuance costs of approximately $0.2 million, which related to our previous senior credit facility. In April 2006, we wrote off unamortized debt issuance costs of approximately $2.7 million, which related to the prepayment of the Term B Loan under our previous senior credit facility.
 
Credit Rating Agencies
 
Our Senior Notes are currently rated BB- and B1 by Standard and Poor’s and Moody’s, respectively. Our 2007 Credit Facility maintains ratings of BB+ and Ba1 from Standard and Poor’s and Moody’s, respectively.
 
Preferred Stock
 
At December 31, 2008 and December 31, 2007, Basic had 5,000,000 shares of $.01 par value preferred stock authorized, of which none was designated, issued or outstanding.
 
Other Matters
 
Off-Balance Sheet Arrangements
 
We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition or results of operations.
 
Net Operating Losses
 
As of December 31, 2008, we had approximately $2.3 million of NOL carryforwards related to the pre-acquisition period of FESCO Holdings, Inc., which is subject to an annual limitation of approximately $892,000. The carryforwards begin to expire in 2017.
 
Recent Accounting Pronouncements
 
In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, Fair Value Measurements (SFAS 157), which became effective for financial assets and liabilities of the Company on January 1, 2008 and non-financial assets and liabilities of the Company on January 1, 2009. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS 157 does not require any new fair value measurements but would apply to assets and liabilities that are required to be recorded at fair value under other accounting standards. The impact, if any, to the Company from the adoption of SFAS 157 in 2009 will depend on the Company’s assets and liabilities at that time that are required to be measured at fair value.
 
In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS 159), which became effective for the Company on January 1, 2008. This standard permits companies to choose to measure many financial instruments and certain other items at fair value and report unrealized gains and losses in earnings. Such accounting is optional and is generally to be applied instrument by instrument.
 
In December 2007, the FASB issued SFAS No. 141R, Business Combinations (SFAS 141R), which became effective for the Company on January 1, 2009. This Statement requires an acquirer to recognize the assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date be measured at their fair values as of that date. An acquirer is required to recognize assets or liabilities arising from all other contingencies (contractual contingencies) as of the acquisition date, measured at their acquisition-date fair values, only if it is more likely than not that they meet the definition of an asset or a liability in FASB Concepts Statement


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No. 6, “Elements of Financial Statements.” Any acquisition related costs are to be expensed instead of capitalized. The impact to the Company from the adoption of SFAS 141R in 2009 will depend on acquisitions at the time.
 
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements (SFAS 160), which became effective for the Company on January 1, 2009. This standard establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. The Statement also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. The Company does not anticipate that this pronouncement will have a material impact on its results of operations or consolidated financial position.
 
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (SFAS 161), which became effective for the Company on January 1, 2009. This standard improves financial reporting for derivative instruments and hedging activities by requiring enhanced disclosures to expand on these instruments’ effects on a company’s financial position, financial performance and cash flows. The Company does not anticipate that this pronouncement will have a material impact on its results of operations or consolidated financial position.
 
In April 2008, the FASB issued FSP SFAS No. 142-3, Determination of Useful Life of Intangible Assets (“FSP 142-3”). FSP 142-3 amends the factors that should be considered in developing the renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS 142. FSP 142-3 is effective for fiscal years beginning after December 15, 2008. Earlier adoption is not permitted. We are currently evaluating the potential impact the adoption of FSP 142-3 will have on our consolidated financial statements.
 
In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles (SFAS 162), which becomes effective for the Company 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” This standard identifies the sources of accounting principles and the framework for selecting the principles used in preparation of financial statements that are presented in conformity with generally accepted accounting principles (GAAP). The Company does not anticipate that this pronouncement will have a material impact on its results of operations or consolidated financial position.
 
In June 2008, the FASB issued Staff Position EITF 03-6-1Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-6-1 addresses whether instruments granted in share based payment transactions are participating securities prior to vesting and, therefore, need to be included in earnings allocation in computing earnings per share (“EPS”) under the two-class method described in paragraphs 60 and 61 of SFAS No. 128, “Earnings Per Share”. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008 and requires retrospective adjustment for all comparable prior periods presented. The Company does not anticipate that the adoption of FSP EITF 03-6-1 will have a material impact on its EPS disclosures.
 
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, 2008, we had $180 million outstanding under the revolving portion of our 2007 Credit Facility subject to variable interest rate risk. The impact of a 1% increase in interest rates on this amount of debt would result in increased interest expense of approximately $1.8 million annually and a decrease in net income of approximately $996,000.


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ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
Basic Energy Services, Inc.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 
         
    Page
 
    48  
    49  
    51  
    52  
    53  
    54  
    55  


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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, 2008, 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, 2008, 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 substantially all of the assets of Azurite Services Company, Inc., Azurite Leasing Company, LLC and Freestone Disposal, L.P. (collectively “Azurite”) during 2008, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008 any internal control evaluation over financial reporting the associated total assets of approximately $60.2 million and total revenues of approximately $10.9 million included in the consolidated financial statements of Basic Energy Services Inc. and subsidiaries as of and for the year ended December 31, 2008.
 
KPMG LLP, the independent registered public accounting firm that audited the Company’s consolidated financial statements included in this report, has issued an audit report on the effectiveness of internal control over financial reporting.
 
     
     
     
     
/s/  Kenneth V. Huseman

Kenneth V. Huseman
Chief Executive Officer
 
/s/  Alan Krenek
Alan Krenek
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 Basic Energy Services, Inc’s (the Company) internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). 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, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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, Basic Energy Services, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
 
The Company acquired substantially all of the assets of Azurite Services Company, Inc., Azurite Leasing Company, LLC, and Freestone Disposal, L.P. (collectively, “Azurite”) during 2008, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008, Azurite’s internal control over financial reporting associated with total assets of $60.2 million and total revenues of $10.9 million included in the consolidated financial statements of Basic Energy Services, Inc. and subsidiaries as of and for the year ended December 31, 2008. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of Azurite.
 
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. and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2008, and our report dated March 6, 2009 expressed an unqualified opinion on those consolidated financial statements.
 
KPMG LLP
 
Dallas, Texas
March 6, 2009


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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 (the Company) as of December 31, 2008 and 2007, and the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2008. 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, 2008 and 2007, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008, 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.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Basic Energy Services, Inc.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 6, 2009 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
 
KPMG LLP
 
Dallas, Texas
March 6, 2009


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Basic Energy Services, Inc.
 
Consolidated Balance Sheets
 
                 
    December 31,  
    2008     2007  
    (In thousands, except
 
    share data)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 111,135     $ 91,941  
Trade accounts receivable, net of allowance of $5,838 and $6,090, respectively
    172,930       138,384  
Accounts receivable — related parties
    148       91  
Federal income tax receivable
    3,324       1,130  
Inventories
    11,937       11,034  
Prepaid expenses
    6,838       6,999  
Other current assets
    6,508       6,353  
Deferred tax assets
    11,081       10,593  
                 
Total current assets
    323,901       266,525  
                 
Property and equipment, net
    740,879       636,924  
Deferred debt costs, net of amortization
    5,132       6,100  
Goodwill
    202,749       204,963  
Other intangible assets
    36,004       26,975  
Other assets
    2,046       2,122  
                 
Total assets
  $ 1,310,711     $ 1,143,609  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
               
Accounts payable
  $ 28,291     $ 22,146  
Accrued expenses
    47,139       51,003  
Current portion of long-term debt
    26,063       17,413  
Other current liabilities
    658       1,474  
                 
Total current liabilities
    102,151       92,036  
                 
Long-term debt
    454,260       406,306  
Deferred tax liabilities
    149,591       114,604  
Other long-term liabilities
    9,705       5,842  
Commitments and contingencies
               
Stockholders’ equity:
               
Preferred stock; $.01 par value; 5,000,000 shares authorized; none designated or issued at December 31, 2008 and December 31, 2007, respectively
           
Common stock; $.01 par value; 80,000,000 shares authorized; 41,734,485 shares issued and 40,851,862 shares outstanding at December 31, 2008; and 40,925,530 shares issued and 40,896,217 shares outstanding at December 31, 2007
    417       409  
Additional paid-in capital
    325,785       314,705  
Retained earnings
    277,173       209,707  
Treasury stock, 882,623 and 29,313 shares at December 31, 2008 and 2007, respectively
    (8,371 )      
                 
Total stockholders’ equity
    595,004       524,821  
                 
Total liabilities and stockholders’ equity
  $ 1,310,711     $ 1,143,609  
                 
 
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  
    2008     2007     2006  
    (Dollars in thousands, except per share amounts)  
 
Revenues:
                       
Well servicing
  $ 343,113     $ 342,697     $ 323,755  
Fluid services
    315,768       259,324       245,011  
Completion and remedial services
    304,326       240,692       154,412  
Contract drilling
    41,735       34,460       6,970  
                         
Total revenues
    1,004,942       877,173       730,148  
                         
Expenses:
                       
Well servicing
    215,243       205,132       178,028  
Fluid services
    203,205       165,327       153,445  
Completion and remedial services
    165,574       125,948       74,981  
Contract drilling
    28,629       22,510       8,400  
General and administrative, including stock-based compensation of $4,149, $3,964 and $3,429 in 2008, 2007 and 2006, respectively
    115,319       99,042       81,318  
Depreciation and amortization
    118,607       93,048       62,087  
Loss on disposal of assets
    76       477       277  
Goodwill impairment
    22,522              
                         
Total expenses
    869,175       711,484       558,536  
                         
Operating income
    135,767       165,689       171,612  
Other income (expense):
                       
Interest expense
    (26,766 )     (27,416 )     (17,466 )
Interest income
    2,136       2,280       1,962  
Loss on early extinguishment of debt
          (230 )     (2,705 )
Other income
    12,235       176       169  
                         
Income from continuing operations before income taxes
    123,372       140,499       153,572  
Income tax expense
    (55,134 )     (52,766 )     (54,742 )
                         
Net income
    68,238       87,733       98,830  
Basic earnings per share of common stock:
                       
                         
Net income available to common stockholders
  $ 1.67     $ 2.19     $ 2.87  
                         
Diluted earnings per share of common stock:
                       
                         
Net income available to common stockholders
  $ 1.64     $ 2.13     $ 2.56  
                         
Comprehensive income:
                       
Net income
  $ 68,238     $ 87,733     $ 98,830  
Unrealized gains on hedging activities
                51  
Less: reclassification adjustment for gain included in net income
                (287 )
                         
Comprehensive income:
  $ 68,238     $ 87,733     $ 98,594  
                         
 
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, 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  
Issuance of restricted stock
    229,100       2       (2 )                              
Amortization of share based compensation
                3,873                               3,873  
Stock issued as compensation to Chairman of the Board
    4,000             91                               91  
Stock issued in JetStar Consolidated Holdings, Inc. acquisition
    1,794,759       18       41,011                               41,029  
Stock issued in Sledge Drilling Holding Corp acquisition
    430,191       4       10,161                               10,165  
Purchase of treasury stock
                              (462 )                 (462 )
Exercise of stock options
    169,875       2       3,044             462       (366 )           3,142  
Net income
                                    87,733             87,733  
                                                                 
Balance — December 31, 2007
    40,925,530       409       314,705                   209,707             524,821  
Issuances of restricted stock
    361,700       4       (25 )           21                    
Amortization of share based compensation
                4,064                               4,064  
Treasury stock issued as compensation to Chairman of the Board
                            89       (4 )           85  
Purchase of treasury stock
                            (9,994 )                 (9,994 )
Exercise of stock options
    447,255       4       7,041             1,513       (768 )           7,790  
Net income
                                  68,238             68,238  
                                                                 
Balance — December 31, 2008
    41,734,485     $ 417     $ 325,785     $     $ (8,371 )   $ 277,173     $     $ 595,004  
                                                                 
 
See accompanying notes to consolidated financial statements.


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Basic Energy Services, Inc.
 
Consolidated Statements of Cash Flows
 
                         
    Years Ended December 31,  
    2008     2007     2006  
    (In thousands)  
 
Cash flows from operating activities:
                       
Net income
  $ 68,238     $ 87,733     $ 98,830  
Adjustments to reconcile net income to net cash provided by operating activities
                       
Depreciation and amortization
    118,607       93,048       62,087  
Goodwill impairment
    22,522              
Accretion on asset retirement obligation
    131       115       78  
Change in allowance for doubtful accounts
    (252 )     2,127       1,188  
Amortization of deferred financing costs
    968       962       804  
Non-cash compensation
    4,149       3,964       3,429  
Loss on early extinguishment of debt
          230       2,705  
Loss on disposal of assets
    76       477       277  
Deferred income taxes
    30,165       15,285       2,611  
Changes in operating assets and liabilities, net of acquisitions:
                       
Accounts receivable
    (32,411 )     4,396       (32,933 )
Inventories
    (558 )     (328 )     (714 )
Prepaid expenses and other current assets
    2,348       6,325       (6,771 )
Other assets
    47       (753 )     (450 )
Accounts payable
    4,759       (1,237 )     5,128  
Excess tax benefits from exercise of employee stock options
    (5,062 )     (2,169 )     (4,022 )
Income tax payable
    2,963       (11,262 )     6,344  
Other liabilities
    1,217       (332 )     (171 )
Accrued expenses
    (5,080 )     10       7,258  
                         
Net cash provided by operating activities
    212,827       198,591       145,678  
                         
Cash flows from investing activities:
                       
Purchase of property and equipment
    (91,890 )     (98,536 )     (104,574 )
Proceeds from sale of assets
    8,184       6,815       5,560  
Payments for other long-term assets
    (2,683 )     (2,709 )     (6,769 )
Payments for businesses, net of cash acquired
    (110,913 )     (199,673 )     (135,568 )
                         
Net cash used in investing activities
    (197,302 )     (294,103 )     (241,351 )
                         
Cash flows from financing activities:
                       
Proceeds from debt
    30,000       150,000       305,546  
Payments of debt
    (24,126 )     (15,838 )     (204,793 )
Purchase of treasury stock
    (9,994 )     (462 )     (3,218 )
Offering costs related to initial public offering
                (227 )
Excess tax benefits from exercise of employee stock options
    5,062       2,169       4,022  
Tax withholding from exercise of stock options
    (4,174 )     (1,290 )     (1,310 )
Exercise of employee stock options
    6,901       2,265       1,984  
Proceeds from exercise stock warrants
                17,401  
Deferred loan costs and other financing activities
          (756 )     (5,212 )
                         
Net cash provided by financing activities
    3,669       136,088       114,193  
                         
Net increase (decrease) in cash and equivalents
    19,194       40,576       18,520  
Cash and cash equivalents — beginning of year
    91,941       51,365       32,845  
                         
Cash and cash equivalents — end of year
  $ 111,135     $ 91,941     $ 51,365  
                         
 
See accompanying notes to consolidated financial statements.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements
December 31, 2008, 2007, and 2006
 
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, completion and remedial services and contract drilling. 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, Kansas, Arkansas and Louisiana, and the Rocky Mountain states.
 
Basic revised its reportable business segments beginning in the first quarter of 2008, and in connection therewith restated the corresponding items of segment information for earlier periods. The new operating segments are Well Servicing, Fluid Services, Completion and Remedial Services, and Contract Drilling. These segments were selected based on changes in management’s resource allocation and performance assessment in making decisions regarding the Company. Contract Drilling was previously included in our Well Servicing segment. Well Site Construction Services is consolidated with our Fluid Services segment. These changes reflect Basic’s operating focus in compliance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.”
 
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, Risks 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, goodwill and intangible assets
 
  •  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
 
Oil and gas prices decreased significantly in the second half of 2008 which resulted in lower utilization of the Company’s services in the fourth quarter of 2008. For 2009, the Company expects oil and gas prices to remain substantially below the levels required to support aggressive capital spending programs by its customers and that maintenance related spending by customers will be deferred as long as possible. The Company expects the reduced spending level by its customers will result in lower demand for its services and increased price competition among


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
service providers in all segments of its business which will negatively affect the Company’s revenue and gross margins.
 
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 or by the day of service performed.
 
Fluid Services — Fluid services consist 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.
 
Completion and Remedial Services (formerly 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 completion and remedial 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.
 
Contract Drilling — 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 these jobs by “daywork” contracts, in which an agreed upon rate per day is charged to the customer, or “footage” contracts, in which an agreed upon rate per the number of feet drilled is charged to the customer.
 
Taxes assessed on sales transactions are presented on a net basis and are not included in revenue.
 
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


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
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  
Contract drilling 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  
 
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. These assets are normally sold within a short period of time through a third party auctioneer.
 
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 were approximately $7.6 million net of accumulated amortization of $2.4 million, and $7.6 million net of accumulated amortization of $1.5 million at December 31, 2008 and December 31, 2007, respectively. Amortization of deferred debt costs totaled approximately $968,000, $962,000 and $804,000 for the years ended December 31, 2008, 2007 and 2006, respectively.
 
In 2006, Basic recognized a loss on early extinguishment of debt related to deferred debt costs. (See note 5)


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
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.
 
In step one of the annual impairment test and due to the adverse equity market conditions affecting the Company’s common stock price and the declines in oil and natural gas prices in the fourth quarter of 2008 and continuing into 2009, the Company tested its four reporting units, well servicing, fluid services, completion and remedial services, and contract drilling, for impairment. To estimate the fair value of the reporting units, the Company used a weighting of the discounted cash flow method, the guideline transaction method, and the public company guideline company method. The Company weighted the discounted cash flow method 85% in its analysis and the other two methods combined 15% due to differences between the Company’s reporting units and the peer companies size, profitability and diversity of operations. In order to validate the reasonableness of the estimated fair values obtained for the reporting units, a reconciliation of fair value to market cap was performed. The control premium used in the reconciliation was derived from a market transaction data study along with historical control premiums from the Company’s other acquisitions. The measurement date for the stock price for the reconciliation was the closing price on December 31, 2008.
 
Based on the results of step one, impairment was indicated in the contract drilling reporting unit but not in the other three reporting units. As a result, the Company tested the contract drilling reporting unit’s long-lived assets for impairment under SFAS No. 144, which indicated no impairment. The Company performed step two for the contract drilling unit by allocating the estimated fair value to the tangible and intangible assets and liabilities, which indicated that the entire value of the goodwill in contract drilling of $22.5 million was impaired. This non-cash charge eliminates the goodwill recorded in connection with the Sledge acquisition in 2007. The goodwill associated with this acquisition has no tax basis, and accordingly, there is no tax benefit derived from recording the impairment charge. Further declines in the Company’s stock price and general market conditions may be considered as a triggering event for the first quarter of 2009. If this is the case, the Company will analyze its goodwill as of March 31, 2009 and potentially record further goodwill impairments in its well servicing, fluid services and/or completion and remedial services reporting units.
 
Intangible assets subject to amortization under SFAS No. 142 consist of customer relationships and non-compete agreements. The gross carrying amount of customer relationships subject to amortization was $35.4 million and $23.8 million as of December 31, 2008 and 2007, respectively. The gross carrying amount of non-compete agreements subject to amortization totaled approximately $4.4 million and $5.2 million at December 31, 2008 and 2007, respectively. Accumulated amortization related to these intangible assets totaled approximately $3.8 and $2.1 million at December 31, 2008 and 2007, respectively. Amortization expense for the years ended December 31, 2008, 2007 and 2006 was approximately $2.8 million, $773,000, and $650,000, respectively. Amortization expense


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
for the next five succeeding years is estimated to be approximately $3.2 million, $3.1 million, $3.0 million, $2.6 million, and $2.4 million in 2009, 2010, 2011, 2012, and 2013, respectively.
 
         
Amortizable Intangible Assets at December 31, 2008 (in thousands):
       
Customer Relationships
  $ 35,441  
Accumulated Amortization Customer Relationships
    (1,879 )
Non-Compete Agreements
    4,392  
Accumulated Amortization Non-Compete Agreements
    (1,950 )
         
Total Amortizable Intangible Assets
  $ 36,004  
         
 
Customer relationships are amortized over a 15 year life. Non-Compete Agreements are amortized over a five year life.
 
Basic has identified its reporting units to be well servicing, fluid services, completion and remedial services and contract drilling. The goodwill allocated to such reporting units as of December 31, 2008 was $29.9 million, $49.3 million, $123.5 million, and $0, respectively. The change in the carrying amount of goodwill for the year ended December 31, 2008 of $2.2 million relates to goodwill from acquisitions and payments pursuant to contingent earn-out agreements and impairments, with approximately $3.1 million, $6.1 million and $12.0 million of goodwill additions relating to the well servicing, fluid services, and completion and remedial units, respectively. There was a decrease in the carrying amount of goodwill for the year ended December 31, 2008 of $23.4 million related to contract drilling. The decrease in the carrying amount of goodwill for contract drilling is due primarily to the impairment of $22.5 million. Other intangibles net of accumulated amortization allocated to reporting units as of December 31, 2008 was $454,000, $3.3 million, $26.3 million and $5.9 million for well servicing, fluid services, completion and remedial services, and contract drilling, 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 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 no longer includes 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


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
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.
 
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 2008, 2007, or 2006.
 
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. 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, 2008 and 2007 (in thousands):
 
         
Balance, December 31, 2006
  $ 1,336  
Additional asset retirement obligations recognized through acquisitions
    101  
Accretion expense
    115  
         
Balance, December 31, 2007
  $ 1,552  
Additional asset retirement obligations recognized through acquisitions
    143  
Accretion expense
    131  
Settlements
    (30 )
         
Balance, December 31, 2008
  $ 1,796  
         
 
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.
 
Recent Accounting Pronouncements
 
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS 157), which became effective for financial assets and liabilities of the Company on January 1, 2008 and non-financial assets and liabilities of the Company on January 1, 2009. This standard defines fair value, establishes a framework for


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
measuring fair value and expands disclosures about fair value measurements. SFAS 157 does not require any new fair value measurements but would apply to assets and liabilities that are required to be recorded at fair value under other accounting standards. The impact, if any, to the Company from the adoption of SFAS 157 in 2009 will depend on the Company’s assets and liabilities at that time that are required to be measured at fair value.
 
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS 159), which became effective for the Company on January 1, 2008. This standard permits companies to choose to measure many financial instruments and certain other items at fair value and report unrealized gains and losses in earnings. Such accounting is optional and is generally to be applied instrument by instrument.
 
In December 2007, the FASB issued SFAS No. 141R, Business Combinations (SFAS 141R), which becomes effective for the Company on January 1, 2009. This Statement requires an acquirer to recognize the assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date be measured at their fair values as of that date. An acquirer is required to recognize assets or liabilities arising from all other contingencies (contractual contingencies) as of the acquisition date, measured at their acquisition-date fair values, only if it is more likely than not that they meet the definition of an asset or a liability in FASB Concepts Statement No. 6, Elements of Financial Statements. Any acquisition related costs are to be expensed instead of capitalized. The impact to the Company from the adoption of SFAS 141R in 2009 will depend on acquisitions at the time.
 
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements (SFAS 160), which becomes effective for the Company on January 1, 2009. This standard establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. The Statement also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. The Company does not anticipate that this pronouncement will have a material impact on its results of operations or consolidated financial position.
 
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (SFAS 161), which became effective for the Company on January 1, 2009. This standard improves financial reporting for derivative instruments and hedging activities requiring enhanced disclosures to expand on these instruments’ effects on the Company’s financial position, financial performance and cash flows. The Company does not anticipate that this pronouncement will have a material impact on its results of operations or consolidated financial position.
 
In April 2008, the FASB issued FSP SFAS No. 142-3, Determination of Useful Life of Intangible Assets (“FSP 142-3”). FSP 142-3 amends the factors that should be considered in developing the renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS 142. FSP 142-3 is effective for fiscal years beginning after December 15, 2008. Earlier adoption is not permitted. We are currently evaluating the potential impact the adoption of FSP 142-3 will have on our consolidated financial statements.
 
In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles (SFAS 162), which becomes effective for the Company 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles. This standard identifies the sources of accounting principles and the framework for selecting the principles used in preparation of financial statements that are presented in conformity with generally accepted accounting principles (GAAP). The Company does not anticipate that this pronouncement will have a material impact on its results of operations or consolidated financial position.
 
In June 2008, the FASB issued Staff Position EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-6-1 addresses


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
whether instruments granted in share based payment transactions are participating securities prior to vesting and, therefore, need to be included in earnings allocation in computing earnings per share (“EPS”) under the two-class method described in paragraphs 60 and 61 of SFAS No. 128, “Earnings Per Share”. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008 and requires retrospective adjustment for all comparable prior periods presented. The Company does not anticipate that the adoption of FSP EITF 03-6-1 will have a material impact on its EPS disclosures.
 
3.   Acquisitions
 
In 2008, 2007 and 2006, 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)  
 
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  
                 
Parker Drilling Offshore USA, LLC
    January 3, 2007       20,594  
Davis Tool Company, Inc. 
    January 17, 2007       4,164  
JetStar Consolidated Holdings, Inc. 
    March 6, 2007       86,316  
Sledge Drilling Holding Corp. 
    April 2, 2007       50,632  
Eagle Frac Tank Rentals, LP
    May 30, 2007       3,813  
Wildhorse Services, Inc. 
    June 1, 2007       17,283  
Bilco Machine, Inc. 
    June 21, 2007       600  
Steve Carter Inc. and Hughes Services Inc. 
    September 26, 2007       19,041  
                 
Total 2007
          $ 202,443  
                 
Xterra Fishing and Rental Tools Co. 
    January 28, 2008     $ 21,110  
Lackey Construction, LLC
    January 30, 2008       4,328  
B&S Disposal, LLC and B&S Equipment, Ltd
    April 30, 2008       7,067  
Triple N Services, Inc. 
    May 27, 2008       17,315  
Azurite Services Company, Inc., Azurite Leasing Company, LLC and Freestone Disposal, L.P. (collectively, “Azurite”)
    September 26, 2008       60,155  
                 
Total 2008
          $ 109,975  
                 


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
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, JetStar Consolidated Holdings, Inc. and Sledge Drilling Holding Corp. in 2007 and Azurite in 2008 have been deemed significant and are 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. 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.
 
JetStar Consolidated Holdings, Inc.
 
On March 6, 2007, Basic acquired all of the capital stock of JetStar Consolidated Holdings, Inc. (“JetStar”). The results of JetStar’s operations have been included in the financial statements since that date. The aggregate purchase price was approximately $127.3 million, including $86.3 million in cash which included the retirement of JetStar’s outstanding debt. Basic issued 1,794,759 shares of common stock, at a fair value of $22.86 per share for a total fair value of approximately $41 million. The value of the 1,794,759 shares issued was determined based on the average market price of Basic’s common shares over the 2-day period before and after the date the number of shares were determined. This acquisition allowed us to enter into the Kansas market and increased our presence in North Texas. JetStar will operate in Basic’s completion and remedial segment. The following table summarizes the final fair value of the assets acquired and liabilities assumed at the date of acquisition for JetStar (in thousands):
 
         
Current Assets
  $ 12,547  
Property and Equipment
    58,785  
Amortizable Intangible Assets(1)
    17,857  
Goodwill(2)
    61,720  
         
Total Assets Acquired
    150,909  
         
Current Liabilities
    (4,581 )
Deferred Income Taxes
    (18,649 )
Current and Long Term Debt(3)
    (37,563 )
         
Total Liabilities Assumed
    (60,793 )
         
Net Assets Acquired
  $ 90,116  
         
 
 
(1) Consists of Customer Relationship of $17,543, amortizable over 15 years, and Non-Compete Agreements of $314, amortizable over 5 years.
 
(2) Approximately $25,955 is expected to be deductible for tax purposes
 
(3) Total balance was paid by Basic on the closing date


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
 
Sledge Drilling Holding Corp.
 
On April 2, 2007, Basic acquired all of the capital stock of Sledge Drilling Holding Corp. (“Sledge”). The results of Sledge’s operations have been included in the financial statements since that date. The aggregate purchase price was approximately $60.8 million, including $50.6 million in cash which included the retirement of Sledge’s outstanding debt. Basic issued 430,191 shares of common stock at a fair value of $23.63 per share for a total fair value of approximately $10.2 million. The value of the 430,191 shares issued was determined based on the average market price of Basic’s common shares over the 2-day period before and after the date the number shares were determined. This acquisition allowed Basic to expand its drilling operations in the Permian Basin. The following table summarizes the final fair value of the assets acquired and liabilities assumed at the date of acquisition for Sledge (in thousands):
 
         
Current Assets
  $ 6,807  
Property and Equipment
    30,638  
Intangible Assets(1)
    6,365  
Goodwill(2)
    22,522  
         
Total Assets Acquired
    66,332  
         
Current Liabilities
    (587 )
Deferred Income Taxes
    (3,804 )
Current and Long Term Debt(3)
    (19,093 )
         
Total Liabilities Assumed
    (23,484 )
         
Net Assets Acquired
  $ 42,848  
         
 
 
(1) Consists of Customer Relationship of $6,269, amortizable over 15 years, and Non-Compete Agreements of $96, amortizable over 5 years.
 
(2) None of which is expected to be deducted for tax purposes
 
(3) Total balance was paid by Basic on the closing date
 
Azurite
 
On September 26, 2008, Basic acquired substantially all of the assets of Azurite Services Company, Inc., Azurite Leasing Company, LLC, and Freestone Disposal, L.P. (collectively, “Azurite”) for $60.2 million in cash. This acquisition operates in our fluid services line of business and allowed us to expand our operations in the east Texas markets. The following table summarizes the preliminary estimated fair value of the assets acquired and liabilities assumed at the date of acquisition for Azurite (in thousands):
 
         
Property and Equipment
  $ 53,127  
Intangible Assets(1)
    1,862  
Goodwill(2)
    5,166  
         
Total Assets Acquired
  $ 60,155  
         
 
 
(1) Consists of customer relationship of $1,832, amortizable over 15 years, and non-compete agreements of $30, amortizable over five years.
 
(2) All of which is expected to be deductible for tax purposes.
 
Revisions to the fair values, which may be significant, will be recorded by the Company as further adjustments to the purchase price allocations.


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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 JetStar, Sledge, and Azurite acquisitions had been completed on January 1, 2007. Pro forma amounts are based on the 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,  
    2008     2007  
 
Revenues
  $ 1,040,160     $ 933,697  
Net income
  $ 70,680     $ 92,064  
Earnings per common share — basic
  $ 1.73     $ 2.28  
Earnings per common share — diluted
  $ 1.70     $ 2.22  
 
Basic does not believe the pro-forma effect of the remainder of the acquisitions completed in 2007 or 2008 is material, either individually or when aggregated, to the reported results of operations.
 
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. Contingent earn-out payments that are based on continued employment with the Company are recorded as compensation expense, in accordance with EITF No. 95-8, “Accounting for Contingent Consideration Paid to the Shareholders of an Acquired Enterprise in Purchase Business Combinations.” All other 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 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, 2008 (in thousands):
 
                         
          Maximum
       
          exposure of
       
    Termination date of
    contingent
    Amount paid or
 
    contingent earn-out
    earn-out
    accrued through
 
Acquisition
  arrangement     arrangement     December 31, 2008  
 
Rolling Plains
    April 30, 2009       *   $ 6,732  
Chaparral Services, Inc. 
    August 31, 2011     $ 1,000        
G&L Tool, Ltd. 
    February 28, 2011       21,000       5,093  
                         
            $ 22,000     $ 11,825  
                         
 
 
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,
 
    2008     2007  
 
Land
  $ 4,689     $ 3,475  
Buildings and improvements
    29,913       21,655  
Well service units and equipment
    379,167       328,468  
Fluid services equipment
    136,814       91,830  
Brine and fresh water stations
    10,203       8,964  
Frac/test tanks
    128,845       85,649  
Pressure pumping equipment
    156,406       132,746  
Construction equipment
    22,483       28,798  
Contract drilling equipment
    60,340       59,231  
Disposal facilities
    49,878       27,790  
Vehicles
    41,129       36,440  
Rental equipment
    36,898       33,381  
Aircraft
    4,119       4,119  
Other
    21,758       15,858  
                 
      1,082,642       878,404  
Less accumulated depreciation and amortization
    341,763       241,480  
                 
Property and equipment, net
  $ 740,879     $ 636,924  
                 
 
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,
 
    2008     2007  
 
Light vehicles
  $ 30,141     $ 25,768  
Well service units and equipment
    1,194       1,016  
Fluid services equipment
    56,010       34,668  
Pressure pumping equipment
    20,492       4,540  
Construction equipment
    3,679       4,440  
Software
    9,464       6,308  
Other
    705        
                 
      121,685       76,740  
Less accumulated amortization
    37,370       22,660  
                 
    $ 84,315     $ 54,080  
                 
 
Amortization of assets held under capital leases of approximately $14.7 million, $8.9 million and $5.3 million for the years ended December 31, 2008, 2007 and 2006, 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,
 
    2008     2007  
 
2007 Credit Facility
  $ 180,000     $ 150,000  
7.125% Senior Notes
    225,000       225,000  
Capital leases and other notes
    75,323       48,719  
                 
      480,323       423,719  
Less current portion
    26,063       17,413  
                 
    $ 454,260     $ 406,306  
                 
 
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 Company’s $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. 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 the Senior Notes, 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 Senior Notes redeemed, 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 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, make certain other payments 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, 2008.
 
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.
 
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.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
2007 Credit Facility
 
On February 6, 2007, Basic entered into a $225 million Fourth Amended and Restated Credit Agreement with a syndicate of lenders (the “2007 Credit Facility”), which refinanced all of the existing credit facilities. Under the 2007 Credit Facility, Basic Energy Services, Inc. is the sole borrower and each of its 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 million aggregate principal amount subject to meeting certain tangible value requirements and subject to lender participation at the time of the request. 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. Basic incurred approximately $0.7 million in debt issuance costs in connection with the 2007 Credit Facility.
 
At Basic’s 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 December 31, 2008, Basic, under its Revolver, had outstanding $180 million of borrowings and $16.2 million of letters of credit and no amounts outstanding in swing-line loans. At December 31, 2008, Basic had availability under its Revolver of $28.8 million.
 
Pursuant to the 2007 Credit Facility, Basic must apply proceeds from certain specified events to reduce principal outstanding borrowings under the Revolver, from (a) assets sales greater than $2.0 million individually or $7.5 million in the aggregate on an annual basis, (b) 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 (c) 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, which include (a) limitations on the incurrence of additional indebtedness, (b) restrictions on mergers, sales or transfer of assets without the lenders’ consent (c) limitations on dividends and distributions and (d) various financial covenants, including (1) a maximum leverage ratio of 3.25 to 1.00, and (2) a minimum interest coverage ratio of 3.00 to 1.00. At December 31, 2008, Basic was in compliance with its covenants.
 
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.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
As of December 31, 2008 the aggregate maturities of debt, including capital leases, for the next five years and thereafter are as follows (in thousands):
 
                 
    Debt     Capital Leases  
 
2009
  $     $ 26,063  
2010
    180,000       21,985  
2011
          14,307  
2012
          10,450  
2013
          2,518  
Thereafter
    225,000        
                 
    $ 405,000     $ 75,323  
                 
 
Basic’s interest expense consisted of the following (in thousands):
 
                         
    Years Ended December 31,  
    2008     2007     2006  
 
Cash payments for interest
  $ 24,484     $ 25,594     $ 12,587  
Commitment and other fees paid
    211       249       566  
Amortization of debt issuance costs
    968       962       804  
Accrued interest
    1,157       540       3,384  
Other
    (54 )     71       125  
                         
    $ 26,766     $ 27,416     $ 17,466  
                         
 
Losses on Extinguishment of Debt
 
In February 2007 and April 2006, Basic recognized a loss on the early extinguishment of debt. In February 2007, Basic wrote off unamortized debt issuance costs of approximately $0.2 million, which related to the 2005 credit facility. In April 2006, Basic wrote off unamortized debt issuance costs of approximately $2.7 million, which related to the prepayment of the Term B Loan.
 
6.   Income Taxes
 
Income tax expense consists of the following (in thousands):
 
                         
    Years Ended December 31,  
    2008     2007     2006  
 
Current:
                       
Federal
  $ 20,533     $ 33,157     $ 50,499  
State
    4,436       5,160       1,632  
                         
Total
  $ 24,969     $ 38,317     $ 52,131  
                         
Deferred:
                       
Federal
  $ 28,792     $ 14,207     $ 3,594  
State
    1,373       242       (983 )
                         
Total
  $ 30,165     $ 14,449     $ 2,611  
                         
Total income tax expense
  $ 55,134     $ 52,766     $ 54,742  
                         


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
Basic paid Federal income taxes of $22.0 million during 2008, $44.1 million during 2007 and $40.2 million during 2006.
 
Reconciliation between the amount determined by applying the Federal statutory rate of 35% to income from continuing operations with the provision for income taxes is as follows (in thousands):
 
                         
    Years Ended December 31,  
    2008     2007     2006  
 
Statutory federal income tax
  $ 43,180     $ 49,174     $ 53,750  
Meals and entertainment
    542       532       430  
State taxes, net of federal benefit
    4,726       4,062       778  
Impairment of non-deductible goodwill
    7,883              
Changes in estimates and other
    (1,197 )     (1,002 )     (216 )
                         
    $ 55,134     $ 52,766     $ 54,742  
                         
 
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,  
    2008     2007  
 
Deferred tax assets:
               
Receivables allowance
  $ 2,151     $ 2,314  
Inventory
    42       41  
Asset retirement obligation
    331       283  
Accrued liabilities
    8,696       8,044  
Operating loss carryforward
    788       1,100  
Deferred compensation
    3,497       2,648  
                 
Total deferred tax assets
    15,505       14,430  
Deferred tax liabilities:
               
Property and equipment
    (135,354 )     (104,476 )
Goodwill and intangibles
    (18,541 )     (13,846 )
Prepaid expenses
    (120 )     (119 )
                 
Total deferred tax liabilities
    (154,015 )     (118,441 )
                 
Net deferred tax liability
  $ (138,510 )   $ (104,011 )
                 
Recognized as:
               
Deferred tax assets — current
    11,081       10,593  
Deferred tax liabilities — non-current
    (149,591 )     (114,604 )
                 
Net deferred tax liability
  $ (138,510 )   $ (104,011 )
                 
 
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, 2008 or 2007.
 
Effective January 1, 2007, Basic adopted the provisions of the FASB issued Interpretation No. 48 (“FIN 48”), Accounting for Uncertainty in Income Taxes. Our adoption of FIN 48 in January 2007 did not result in any change to retained earnings or any additional unrecognized tax benefit. Interest is recorded in interest expense and penalties are recorded in income tax expense. We had no interest or penalties related to an uncertain tax positions during 2008. Basic files federal income tax returns and state income tax returns in Texas and other state tax jurisdictions. In


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
general, the Company’s tax returns for fiscal years after 2003 currently remain subject to examination by appropriate taxing authorities. None of the Company’s income tax returns are under examination at this time.
 
As of December 31, 2008, Basic had approximately $2.3 million of net operating loss carryforwards (“NOL”) for U.S. federal income tax purposes related to the preacquisition period of FESCO (acquired in 2003), which are subject to an annual limitation of approximately $892,000. 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.
 
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, 2008, the future minimum lease payments under non-cancelable operating leases are as follows (in thousands):
 
         
Year Ended December 31,
     
 
2009
  $ 4,543  
2010
    4,257  
2011
    3,588  
2012
    2,550  
2013
    2,164  
Thereafter
    5,220  
 
Rent expense approximated $20.3 million, $17.4 million, and $13.9 million for 2008, 2007 and 2006, respectively.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
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, amended February 27, 2008, Mr. Huseman will be entitled to an annual salary of $550,000. 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 2009. 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 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 $375,000 and $180,000, 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. In 2008 Basic classified the worker’s compensation self-insured risk reserve between short-term and long-term, with $4.0 million being allocated to short-term and $5.0 million being allocated to long-term.
 
At December 31, 2008 and December 31, 2007, self-insured risk accruals totaled approximately $15.4 million, net of $992,000 receivable for medical and dental coverage, and $15.1 million, net of $0 receivable for medical and dental coverage, respectively.
 
8.   Stockholders’ Equity
 
Common Stock
 
At December 31, 2008 and 2007, Basic had 80,000,000 shares of Basic’s common stock, par value $.01 per share, authorized.
 
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


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
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 allowed 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. This amount is being charged to expense over the respective vesting period and totaled approximately $182,000, $1.2 million and $1.3 million for the years ended December 31, 2008, 2007 and 2006.
 
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).
 
In March and April 2007, Basic issued 1,794,759 and 430,191 shares of common stock in connection with the acquisitions of JetStar Consolidated Holding, Inc. and Sledge Drilling Holding Corp., respectively. (See note 3)
 
In March 2007, Basic granted various employees 217,100 unvested shares of common stock which vest over a five year period. Also, in March 2007, Basic granted the Chairman of the Board 4,000 shares of common stock. In July 2007, Basic granted a vice president 12,000 shares of restricted common stock which vest over a four year period.
 
In March 2008, Basic granted various employees 361,700 unvested shares of common stock which vest over a five-year period. Also, in March 2008, Basic granted the Chairman of the Board 4,000 shares of common stock which vested immediately in lieu of annual cash director fees. In October 2008, Basic granted a vice president 5,000 shares of restricted common stock which vest over a three year period.
 
During the year ended 2008, Basic issued 138,675 shares of common stock from treasury stock for the exercise of stock options. Also, Basic issued 447,255 shares of newly-issued common stock for the exercise of stock options.
 
Treasury Stock
 
On October 13, 2008, Basic announced that its Board of Directors authorized the repurchase of up to $50.0 million of Basic’s shares of common stock from time to time in open market or private transactions, at Basic’s discretion. The number of shares purchased and the timing of purchases is based on several factors, including the price of the common stock, general market conditions, available cash and alternative investment opportunities. As of December 31, 2008, Basic repurchased 897,558 shares at a total price of $8.8 million (an average of $9.82 per share), inclusive of commissions and fees.
 
Basic also acquired treasury shares through net share settlements for payment of payroll taxes upon the vesting of restricted stock. We repurchased a total of 52,877 and 20,388 shares through net share settlements during 2008 and 2007, respectively.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
Preferred Stock
 
At December 31, 2008 and 2007, Basic had 5,000,000 shares of preferred stock, par value $.01 per share, authorized, of which none was designated, issued or outstanding.
 
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 in a transaction or series of transactions involving 10% or more of the then-outstanding shares of Basic’s common stock, 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 also provides for demand and piggyback registration rights to parties who continue to hold “Registrable Securities” as defined in the agreement.
 
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 the awards of the plans of Basic’s predecessors that were awarded and remained outstanding prior to adoption of the Plan. The Plan provides for the issuance of 5,000,000 shares. Of these shares, approximately 816,000 shares are available for grant as of December 31, 2008. 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. These option awards were granted with an exercise price equal to the market price of the Company’s stock at the date of grant. On March 15, 2007, the board of directors granted various employees options to purchase 92,000 shares of common stock of Basic at an exercise price of $22.66 per share. All of the 92,000 options granted in 2007 vest over a five-year period and expire 10 years from the date they were granted. These option awards were granted with an exercise price equal to the market price of the Company’s stock at the date of grant. There were no options granted during 2008.
 
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 a volatility based upon a peer group. Expected volatility for options granted during 2007 is a combination of the Company’s historical data and volatility based upon a peer group. The expected term of options granted represents the period of time that options granted are expected to be outstanding. For options granted in 2007 and 2006, the Company used the simplified method to calculate the expected term. For options granted in 2007 and 2006, the risk-free rate for periods within the


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
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, 2008, 2007 and 2006, compensation expense related to share-based arrangements was approximately $4.1 million, $3.9 million and $3.4 million, respectively. For compensation expense recognized during the years ended December 31, 2008, 2007 and 2006 Basic recognized a tax benefit of approximately $1.9 million, $1.5 million and $1.2 million, 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,  
    2007     2006  
 
Risk-free interest rate
    4.5 %     4.7 %
Expected term
    6.65       6.65  
Expected volatility
    45.3 %     47.0 %
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, 2008 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
    2,257,355     $ 9.58                  
Options granted
        $                  
Options forfeited
    (53,750 )   $ 15.29                  
Options exercised
    (585,930 )   $ 4.65                  
Options expired
    (9,000 )   $ 21.32                  
                                 
Outstanding, end of period
    1,608,675     $ 11.11       5.76     $ 8,714  
                                 
Exercisable, end of period
    957,925     $ 7.44       5.03     $ 6,782  
                                 
Vested or expected to vest, end of period
    1,584,425     $ 10.88       5.73     $ 8,714  
                                 
 
The weighted-average grant date fair value of share options granted during the years ended December 31, 2007 and 2006 was $11.85 and $14.47, respectively. The total intrinsic value of share options exercised during the years ended December 31, 2008, 2007 and 2006 was approximately $12.2 million, $3.6 million and $7.1 million, respectively.
 
On March 11, 2008, the Compensation Committee of our Board of Directors approved grants of performance-based stock awards to certain members of management. The performance-based awards consist of the Company achieving certain earnings per share growth targets and certain return on capital employed performance, over the performance period from January 1, 2006 through December 31, 2008 as compared to other members of a defined peer group. The number of shares to be issued will range from 0% to 150% of the target number of shares of 101,500 depending on the performance noted above. Any shares earned at the end of the performance period will then remain subject to vesting over a three-year period, with the first shares vesting March 15, 2010.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
A summary of the status of the Company’s non-vested share grants at December 31, 2008 and changes during the year ended December 31, 2008 is presented in the following table:
 
                 
          Weighted Average
 
    Number of
    Grant Date Fair
 
Nonvested Shares
  Shares     Value Per Share  
 
Nonvested at beginning of period
    378,000     $ 15.74  
Granted during period
    456,975       20.85  
Vested during period
    (178,300 )     7.90  
Forfeited during period
    (57,350 )     21.55  
                 
Nonvested at end of period
    599,325     $ 21.41  
                 
 
As of December 31, 2008, there was $11.9 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 2.65 years. The total fair value of share-based awards vested during the years ended December 31, 2008, 2007 and 2006 was approximately $10.3 million, $11.3 million and $12.3 million, respectively. The actual tax benefit realized for the tax deduction from vested share-based awards was $1.5 million, $1.6 million and $2.1 million, respectively for the years ended December 31, 2008, 2007 and 2006.
 
Cash received from share option exercises under the incentive plan was approximately $2.7 million, $975,000 and $674,000 for the years ended December 31, 2008, 2007 and 2006, respectively. The actual tax benefit realized for the tax deductions from options exercised was $5.6 million, $1.4 million and $4.0 million, respectively, for the years ended December 31, 2008, 2007 and 2006.
 
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 $148,000 and $91,000 as of December 31, 2008 and December 31, 2007, 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. 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 $4.1 million, $3.0 million, and $2.5 million in 2008, 2007 and 2006, 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 $9,200 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 net of earnings approximated a $563,000 gain in 2008 and a $216,000, and $199,000 expense in 2007 and 2006, respectively.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
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 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 (in thousands, except share data):
 
                         
    Years Ended December 31,  
    2008     2007     2006  
 
Numerator (both basic and diluted):
                       
Net income available to common stockholders
  $ 68,238     $ 87,733     $ 98,830  
                         
Denominator:
                       
Denominator for basic earnings per share
    40,754,890       40,013,054       34,471,771  
Stock options
    682,958       831,026       1,054,040  
Unvested restricted stock
    225,842       268,324       244,153  
Common stock warrants
                2,823,029  
                         
Denominator for diluted earnings per share
    41,663,690       41,112,404       38,592,993  
                         
Basic earnings per common share:
                       
Net income available to common stockholders
  $ 1.67     $ 2.19     $ 2.87  
                         
Diluted earnings per common share:
                       
Net income available to common stockholders
  $ 1.64     $ 2.13     $ 2.56  
                         
 
The number of antidilutive shares at December 31, 2008, 2007 and 2006 was 413,000, 442,000 and 401,000, respectively.
 
15.   Business Segment Information
 
Basic revised its reportable business segments beginning in the first quarter of 2008 and in connection therewith restated the corresponding items of segment information for earlier periods. The new operating segments are Well Servicing, Fluid Services, Completion and Remedial Services, and Contract Drilling. These segments have been selected based on changes in management’s resource allocation and performance assessment in making decisions regarding the Company. Contract Drilling was previously included in our Well Servicing segment. Well Site Construction Services is now consolidated with our Fluid Services segment. These changes reflect Basic’s operating focus in compliance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.” 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, completion and


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
remedial projects as well as part of daily producing well operations. Also included in this segment is our construction services which provide services for the construction and maintenance of oil and gas production infrastructures.
 
Completion and Remedial 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.
 
Contract Drilling:  This segment utilizes shallow and medium depth rigs and associated equipment for drilling wells to a specified depth for customers on a contract basis.
 
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.
 
The following table sets forth certain financial information with respect to Basic’s reportable segments (in thousands):
 
                                                 
                Completion and
                   
    Well
    Fluid
    Remedial
    Contract
    Corporate
       
    Servicing     Services     Services     Drilling     and Other     Total  
 
Year ended December 31, 2008
                                               
Operating revenues
  $ 343,113     $ 315,768     $ 304,326     $ 41,735     $     $ 1,004,942  
Direct operating costs
    (215,243 )     (203,205 )     (165,574 )     (28,629 )           (612,651 )
                                                 
Segment profits
  $ 127,870     $ 112,563     $ 138,752     $ 13,106     $     $ 392,291  
                                                 
Depreciation and amortization
  $ 45,298     $ 33,629     $ 27,473     $ 6,816     $ 5,391     $ 118,607  
Capital expenditures, (excluding acquisitions)
  $ 35,094     $ 26,054     $ 21,285     $ 5,281     $ 4,176     $ 91,890  
Identifiable assets
  $ 310,964     $ 262,377     $ 334,120     $ 47,027     $ 356,223     $ 1,310,711  
Year ended December 31, 2007
                                               
Operating revenues
  $ 342,697     $ 259,324     $ 240,692     $ 34,460     $     $ 877,173  
Direct operating costs
    (205,132 )     (165,327 )     (125,948 )     (22,510 )           (518,917 )
                                                 
Segment profits
  $ 137,565     $ 93,997     $ 114,744     $ 11,950     $     $ 358,256  
                                                 
Depreciation and amortization
  $ 37,586     $ 23,858     $ 21,138     $ 6,433     $ 4,033     $ 93,048  
Capital expenditures, (excluding acquisitions)
  $ 39,803     $ 25,266     $ 22,384     $ 6,813     $ 4,270     $ 98,536  
Identifiable assets
  $ 284,058     $ 207,380     $ 284,321     $ 73,787     $ 294,063     $ 1,143,609  
Year ended December 31, 2006
                                               
Operating revenues
  $ 323,755     $ 245,011     $ 154,412     $ 6,970     $     $ 730,148  
Direct operating costs
    (178,028 )     (153,445 )     (74,981 )     (8,400 )           (414,854 )
                                                 
Segment profits
  $ 145,727     $ 91,566     $ 79,431     $ (1,430 )   $     $ 315,294  
                                                 
Depreciation and amortization
  $ 26,992     $ 19,692     $ 11,070     $ 1,938     $ 2,395     $ 62,087  
Capital expenditures, (excluding acquisitions)
  $ 29,677     $ 33,167     $ 18,646     $ 19,050     $ 4,034     $ 104,574  
Identifiable assets
  $ 226,566     $ 193,927     $ 129,471     $ 17,112     $ 229,184     $ 796,260  


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
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,  
    2008     2007     2006  
 
Segment profits
  $ 392,291     $ 358,256     $ 315,294  
General and administrative expenses
    (115,319 )     (99,042 )     (81,318 )
Depreciation and amortization
    (118,607 )     (93,048 )     (62,087 )
Gain (loss) on disposal of assets
    (76 )     (477 )     (277 )
Goodwill Impairment (Contract drilling segment)
    (22,522 )            
                         
Operating income
  $ 135,767     $ 165,689     $ 171,612  
                         
 
16.   Accrued Expenses
 
The accrued expenses are as follows (in thousands):
 
                 
    December 31,  
    2008     2007  
 
Compensation related
  $ 19,832     $ 16,790  
Workers’ compensation self-insured risk reserve
    4,248       9,326  
Health self-insured risk reserve
    6,690       6,054  
Accrual for receipts
    4,976       3,955  
Authority for expenditure accrual
    543       211  
Ad valorem taxes
    137       73  
Sales tax
    588       1,140  
Insurance obligations
    2,474       995  
Purchase order accrual
    38       45  
Professional fee accrual
    185       424  
Contingent earnout obligation
    1,438       1,158  
Retainers
          172  
Fuel accrual
    897       1,692  
Accrued interest
    5,083       3,926  
Contingent liability
          1,296  
Franchise Tax Payable
          3,704  
Other
    10       42  
                 
    $ 47,139     $ 51,003  
                 


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
17.   Supplemental Schedule of Cash Flow Information
 
The following table reflects non-cash financing and investing activity during:
 
                         
    Year Ended December 31,  
    2008     2007     2006  
    (In thousands)  
 
Capital leases issued for equipment
  $ 50,730     $ 26,814     $ 26,420  
Value of shares that may be issued
  $     $ 2,194     $  
Contingent earnout accrual
  $ 183     $ 1,032     $ 2,256  
Asset retirement obligation additions
  $ 143     $ 101     $ 767  
Value of common stock issued in business combinations
  $     $ 51,193     $  
 
Basic paid income taxes of approximately $27.2 million, $44.1 million and $43.2 million during the years ended December 31, 2008, 2007 and 2006, respectively.


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BASIC ENERGY SERVICES, INC.
 
Notes to Consolidated Financial Statements — (Continued)
 
18.   Quarterly Financial Data (Unaudited)
 
The following table summarizes results for each of the four quarters in the years ended December 31, 2008 and 2007:
 
                                         
    First
    Second
    Third
    Fourth
       
    Quarter     Quarter     Quarter     Quarter     Year  
 
Year ended December 31, 2008:
                                       
Total revenues
  $ 229,873     $ 251,522     $ 277,575     $ 245,972     $ 1,004,942  
Segment profits
  $ 92,126     $ 97,495     $ 108,980     $ 93,690     $ 392,291  
Income from continuing operations
  $ 19,656     $ 18,713     $ 25,942     $ 3,927     $ 68,238  
Net income available to common stockholders
  $ 19,656     $ 18,713     $ 25,942     $ 3,927     $ 68,238  
Basic earnings per share of common stock(a):
                                       
Net income available to common stockholders
  $ 0.48     $ 0.46     $ 0.63     $ 0.10     $ 1.67  
Diluted earnings per share of common stock(a):
                                       
Net income (loss) available to common stockholders
  $ 0.47     $ 0.45     $ 0.62     $ 0.10     $ 1.64  
Weighted average common shares outstanding:
                                       
Basic
    40,577       40,721       40,988       40,731       40,755  
Diluted
    41,464       41,659       41,787       41,100       41,664  
Year ended December 31, 2007:
                                       
Total revenues
  $ 198,930     $ 223,256     $ 229,232     $ 225,755     $ 877,173  
Segment profits
  $ 82,785     $ 91,235     $ 94,280     $ 89,956     $ 358,256  
Income from continuing operations
  $ 22,073     $ 21,692     $ 24,426     $ 19,541     $ 87,733  
Net income available to common stockholders
  $ 22,073     $ 21,692     $ 24,426     $ 19,541     $ 87,733  
Basic earnings per share of common stock(a):
                                       
Net income available to common stockholders
  $ 0.57     $ 0.54     $ 0.60     $ 0.48     $ 2.19  
Diluted earnings per share of common stock(a):
                                       
Net income available to common stockholders
  $ 0.56     $ 0.52     $ 0.59     $ 0.47     $ 2.13  
Weighted average common shares outstanding:
                                       
Basic
    38,521       40,493       40,516       40,517       40,013  
Diluted
    39,661       41,621       41,591       41,551       41,112  
 
 
(a) The sum of individual quarterly net income per share may not agree to the total for the year due to each period’s computation being based on the weighted average number of common shares outstanding during each period.
 
19.   Subsequent Events
 
On October 13, 2008, Basic announced that its Board of Directors had authorized the repurchase of up to $50.0 million of Basic’s common shares from time to time in open market or private transactions, at Basic’s discretion. From January 1, 2009 through February 27, 2009, Basic has repurchased 622,700 common shares at a total price of $4.9 million (an average of $7.92 per share).


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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, 2008
                                       
Allowance for Bad Debt
  $ 6,090     $ 2,331     $     $ (2,583 )   $ 5,838  
Year Ended December 31, 2007
                                       
Allowance for Bad Debt
  $ 3,963     $ 3,251     $     $ (1,124 )   $ 6,090  
Year Ended December 31, 2006
                                       
Allowance for Bad Debt
  $ 2,775     $ 1,909     $     $ (721 )   $ 3,963  
 
 
(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, 2008, 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 and effective to ensure that information required to be disclosed in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
 
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, 2008.


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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.
 
(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. (the “Company”), 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, effective as of December 17, 2007. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on December 18, 2007)
  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. (Included in the Indenture filed as Exhibit 4.1 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)
  4 .5*   Second Supplemental Indenture dated as of April 26, 2007 and effective as of March 7, 2007 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 May 1, 2007)
  4 .6*   Third Supplement Indenture dated as of April 26, 2007 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 4.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on May 1, 2007)
  4 .7   Fourth Supplemental Indenture dated as of February 9, 2009 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Mellon Trust Company, N.A., as Trustee


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Exhibit
   
No.
 
Description
 
  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*†   Third Amended and Restated 2003 Incentive Plan. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on May 29, 2008)
  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)
  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 10.1 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 10.13 of the Company’s Annual Report on Form 10-K (SEC File No. 001-32693), filed on March 7, 2008)
  10 .14*†   Form of Nonqualified Stock Option Agreement (Employee form effective March 2006). (Incorporated by reference to Exhibit 10.14 of the Company’s Annual Report on Form 10-K (SEC File No. 001-32693), filed on March 7, 2008)
  10 .15*†   Form of Restricted Stock Grant Agreement (Officers and Employees — Post-March 1, 2007). (Incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-32693), filed on May 10, 2007)
  10 .16*†   Form of Restricted Stock Grant Agreement (Non-Employee Directors — Post-March 1, 2007). (Incorporated by reference to Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-32693), filed on May 10, 2007)

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Exhibit
   
No.
 
Description
 
  10 .17*†   Form of Non-Qualified Stock Option Grant Agreement (Post-March 1, 2007). (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 10, 2007)
  10 .18*†   Form of Performance-Based Award Agreement (Officers and Employees). (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 17, 2008)
  10 .19*†   Form of Restricted Stock Grant Agreement (Officers and Employees). (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-32693), filed on May 8, 2008)
  10 .20*†   Form of Restricted Stock Grant Agreement (Non-Employee Directors). (Incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-32693), filed on May 8, 2008)
  10 .21*   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 .22*   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 .23*   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 .24*   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 .25*   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 .26*   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 .27*   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 .28*†   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 .29*†   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 .30*†   Amended and Restated Employment Agreement of Charles W. Swift, effective as of November 21, 2008. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on November 24, 2008)
  10 .31*†   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 .32*†   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)

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Exhibit
   
No.
 
Description
 
  10 .33*†   Amended and Restated Employment Agreement of Thomas Monroe Patterson, effective as of November 21, 2008. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on November 24, 2008)
  10 .34*†   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 .35*†   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 .36*   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)
  10 .37*   Registration Rights Agreement, dated as of April 2, 2007, by and among the Company and the Holders named therein. (Incorporated by reference to Exhibit 10.1 of the Company’s current Report on Form 8-K (SEC File No. 001-32693), filed on April 5, 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

88


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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 6, 2009
 
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 6, 2009
         
/s/  Alan Krenek

Alan Krenek
  Senior Vice President,
Chief Financial Officer,
Treasurer and Secretary
(Principal Financial Officer
and Principal Accounting Officer)
  March 6, 2009
         
/s/  Steven A. Webster

Steven A. Webster
  Chairman of the Board   March 6, 2009
         
/s/  James S. D’Agostino, Jr.

James S. D’Agostino, Jr.
  Director   March 6, 2009
         
/s/  William E. Chiles

William E. Chiles
  Director   March 6, 2009
         
/s/  Robert F. Fulton

Robert F. Fulton
  Director   March 6, 2009
         
/s/  Sylvester P. Johnson, IV

Sylvester P. Johnson, IV
  Director   March 6, 2009
         
/s/  H.H. Wommack, III

H.H. Wommack, III
  Director   March 6, 2009
         
/s/  Thomas P. Moore, Jr.

Thomas P. Moore, Jr.
  Director   March 6, 2009


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Table of Contents

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. (the “Company”), 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, effective as of December 17, 2007. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on December 18, 2007)
  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. (Included in the Indenture filed as Exhibit 4.1 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)
  4 .5*   Second Supplemental Indenture dated as of April 26, 2007 and effective as of March 7, 2007 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 May 1, 2007)
  4 .6*   Third Supplement Indenture dated as of April 26, 2007 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 4.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on May 1, 2007)
  4 .7   Fourth Supplemental Indenture dated as of February 9, 2009 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Mellon Trust Company, N.A., as Trustee
  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)


Table of Contents

         
Exhibit
   
No.
 
Description
 
  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*†   Third Amended and Restated 2003 Incentive Plan. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on May 29, 2008)
  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)
  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 10.1 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 10.13 of the Company’s Annual Report on Form 10-K (SEC File No. 001-32693), filed on March 7, 2008)
  10 .14*†   Form of Nonqualified Stock Option Agreement (Employee form effective March 2006). (Incorporated by reference to Exhibit 10.14 of the Company’s Annual Report on Form 10-K (SEC File No. 001-32693), filed on March 7, 2008)
  10 .15*†   Form of Restricted Stock Grant Agreement (Officers and Employees — Post-March 1, 2007). (Incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-32693), filed on May 10, 2007)
  10 .16*†   Form of Restricted Stock Grant Agreement (Non-Employee Directors — Post-March 1, 2007). (Incorporated by reference to Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-32693), filed on May 10, 2007)
  10 .17*†   Form of Non-Qualified Stock Option Grant Agreement (Post-March 1, 2007). (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 10, 2007)
  10 .18*†   Form of Performance-Based Award Agreement (Officers and Employees). (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 17, 2008)
  10 .19*†   Form of Restricted Stock Grant Agreement (Officers and Employees). (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-32693), filed on May 8, 2008)
  10 .20*†   Form of Restricted Stock Grant Agreement (Non-Employee Directors). (Incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-32693), filed on May 8. 2008)
  10 .21*   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)


Table of Contents

         
Exhibit
   
No.
 
Description
 
  10 .22*   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 .23*   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 .24*   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 .25*   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 .26*   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 .27*   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 .28*†   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 .29*†   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 .30*†   Amended and Restated Employment Agreement of Charles W. Swift, effective as of November 21, 2008. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on November 24, 2008)
  10 .31*†   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 .32*†   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 .33*†   Amended and Restated Employment Agreement of Thomas Monroe Patterson, effective as of November 21, 2008. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (SEC File No. 001-32693), filed on November 24, 2008)
  10 .34*†   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 .35*†   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 .36*   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)
  10 .37*   Registration Rights Agreement, dated as of April 2, 2007, by and among the Company and the Holders named therein. (Incorporated by reference to Exhibit 10.1 of the Company’s current Report on Form 8-K (SEC File No. 001-32693), filed on April 5, 2007)
  21 .1   Subsidiaries of the Company
  23 .1   Consent of KPMG LLP


Table of Contents

         
Exhibit
   
No.
 
Description
 
  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