DEFA14A

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): May 8, 2008

Basic Energy Services, Inc.

(Exact name of registrant as specified in its charter)

Delaware	1-32693	54-2091194
(State or other jurisdiction of incorporation )	(Commission File Number)	(IRS Employer Identification No.)
500 W. Illinois, Suite 100
Midland, Texas (Address of principal executive offices)		79701 (Zip Code)

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

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2 below):

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

þ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01 Other Events.

ANNUAL REPORT UPDATE RELATING TO BUSINESS SEGMENTS

     Basic Energy Services, Inc. (“Basic” or the “Company”) is filing this Current Report on Form 8-K to update certain historical information included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007 filed with the Securities and Exchange Commission on March 7, 2008, as amended (the “Form 10-K”). In particular, the Company is updating historical results to reflect the reorganization of its business segments.

     As reported in the Form 10-K, the Company revised its business segments effective January 1, 2008 based on changes in management’s resource allocation and performance assessment in making decisions regarding the Company. As a result, the Company now reports its segments as follows:

• Well Servicing

• Contract Drilling

• Fluid Services

• Completion and Remedial Services

     Contract Drilling was previously included in our Well Servicing segment. Well Site Construction Services, which had previously been reported separately, has been consolidated with our Fluid Services segment.

     The following items of the Form 10-K are being adjusted retrospectively to reflect the Company’s reorganization of its reporting segments:

• Business and Properties (Part I, Items 1 and 2)(filed as Exhibit 99.1 hereto and incorporated herein by reference);

• Selected Financial Data (Part II, Item 6)(filed as Exhibit 99.2 hereto and incorporated herein by reference);

• Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) (Part II, Item 7)(filed as Exhibit 99.3 hereto and incorporated herein by reference); and

• Financial Statements and Supplementary Data (Part II, Item 8)(filed as Exhibit 99.4 hereto and incorporated herein by reference).

     These new presentations have no effect on the Company’s reported total net income for any reporting period. The revised sections of the Form 10-K included in this Current Report on Form 8-K have not been otherwise updated for events occurring after the date of the consolidated financial statements, which were originally presented in the Form 10-K. This Current Report on Form 8-K should be read in conjunction with the Form 10-K (except for Part I, Items 1 and 2 and Part II, Items 6, 7, and 8) and the Company’s other periodic reports on Form 10-Q and Form 8-K.

Forward Looking Statements

     This release includes forward-looking statements and projections made in reliance on the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Basic has made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable, and complete. However, a variety of factors could cause actual results to differ materially from the projections, anticipated results or other expectations expressed in this release, including (i) Basic’s ability to successfully execute, manage and integrate acquisitions, including the merger with Grey Wolf, Inc. (“Grey Wolf”), (ii) changes in demand for services and any related material impact on our pricing and utilizations rates and (iii) changes in our expenses, including labor or fuel costs. Additional important risk factors that could cause actual results to differ materially from expectations are disclosed in Item 1A of Basic’s Form 10-K and Form 10-Q’s filed with the SEC by Grey Wolf and Basic. While Basic makes these statements and projections in good faith, neither Basic nor its management can guarantee that the transactions will be consummated or that anticipated future results will be achieved. Basic assumes no obligation to publicly update or revise any forward-looking statements made herein or any other forward-looking statements made by Basic, whether as a result of new information, future events, or otherwise

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Additional Information and Where to Find It

     In connection with the proposed mergers, a registration statement of Horsepower Holdings, Inc. (“Holdings”), which will include proxy statements of Basic and Grey Wolf and other materials, will be filed with the Securities and Exchange Commission. INVESTORS AND SECURITY HOLDERS ARE URGED TO CAREFULLY READ THE REGISTRATION STATEMENT AND THE PROXY STATEMENT/PROSPECTUS AND THESE OTHER MATERIALS REGARDING THE PROPOSED TRANSACTION WHEN THEY BECOME AVAILABLE, BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT BASIC, GREY WOLF, HOLDINGS AND THE PROPOSED TRANSACTION. Investors and security holders may obtain a free copy of the registration statement and the proxy statement/prospectus when they are available and other documents containing information about Basic and Grey Wolf, without charge, at the SEC’s web site at www.sec.gov, Basic’s web site at www.basicenergyservices.com, and Grey Wolf’s web site at www.gwdrilling.com. Copies of the registration statement and the proxy statement/prospectus and the SEC filings that will be incorporated by reference therein may also be obtained for free by directing a request to either Investor Relations, Basic Energy Services, Inc., 432-620-5510 or to Investor Relations, Grey Wolf, Inc., 713-435-6100.

Participants in the Solicitation

     Basic and Grey Wolf and their respective directors, officers and certain other members of management may be deemed to be participants in the solicitation of proxies from their respective stockholders in respect of the mergers. Information about these persons can be found Grey Wolf’s proxy statement relating to its 2008 annual meetings of stockholders as filed with the SEC on April 8, 2008. Information concerning beneficial ownership of Basic stock by its directors and certain of its executive officers is included in its Form 10–K/A filed on April 29, 2008 and subsequent statements of changes in beneficial ownership on file with the SEC. Additional information about the interests of such persons in the solicitation of proxies in respect of the merger will be included in the registration statement and the joint proxy statement/prospectus to be filed with the SEC in connection with the proposed transaction.

Item 9.01 Financial Statements and Exhibits.

     (d) Exhibits.

23.1	Consent of Independent Registered Public Accounting Firm
99.1	Business and Properties, revised only to reflect the change in reportable segments
99.2	Selected Financial Data, revised only to reflect the change in reportable segments
99.3	MD&A, revised only to reflect the change in reportable segments
99.4	Financial Statements, revised only to reflect the change in reportable segments

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SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	Basic Energy Services, Inc.
Date: May 8, 2008	By:	/s/ Alan Krenek
		Alan Krenek
		Senior Vice President, Chief Financial Officer, Treasurer and Secretary

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EXHIBIT INDEX

Exhibit No.	Description
23.1	Consent of Independent Registered Public Accounting Firm
99.1	Business and Properties, revised only to reflect the change in reportable segments
99.2	Selected Financial Data, revised only to reflect the change in reportable segments
99.3	MD&A, revised only to reflect the change in reportable segments
99.4	Financial Statements, revised only to reflect the change in reportable segments

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors
Basic Energy Services, Inc.:

We consent to the incorporation by reference in the registration statement (No. 333-130509) on Form S-8 of Basic Energy Services, Inc. of our reports dated March 7, 2008 (except for the updated disclosures pertaining to the resegmenting and the updated subsequent event occurring in 2008 as described in Notes 1 ,2, 4, 15 and 19 as to which the date is May 7, 2008), with respect to the consolidated balance sheets of Basic Energy Services, Inc. as of December 31, 2007 and 2006, 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, 2007, and all related financial statement schedules, and the effectiveness of internal control over financial reporting as of December 31, 2007, which reports appear in this Current Report on Form 8-K of Basic Energy Services, Inc. Our report refers to a change in accounting for share-based payments effective January 1, 2006.

Our report dated March 7, 2008, on the effectiveness of internal control over financial reporting as of December 31, 2007, contains an explanatory paragraph that states the Company acquired JetStar Consolidated Holdings, Inc., Sledge Drilling Holding Corp., and Wildhorse Services, Inc. (collectively the 2007 Excluded Acquisitions) during 2007, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007, the 2007 Excluded Acquisitions’ internal control over financial reporting associated with total assets of $236.1 million and total revenues of $85.8 million included in the consolidated financial statements of Basic Energy Services, Inc. and subsidiaries as of and for the year ended December 31, 2007. Our audit of internal control over financial reporting of Basic Energy Services, Inc. also excluded an evaluation of the internal control over financial reporting of the 2007 Excluded Acquisitions.

KPMG LLP

Dallas, Texas
May 7, 2008

EX-99.1

Exhibit 99.1

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, contract drilling, completion and remedial services and well site construction services. These services are fundamental to establishing and maintaining the flow of oil and gas throughout the productive life of a well. Our broad range of services enables us to meet multiple needs of our customers at the well site. Our operations are managed regionally and are concentrated in the major United States onshore oil and gas producing regions in Texas, New Mexico, Oklahoma, Arkansas, 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 over 14% of the overall available U.S. fleet, with our two larger competitors controlling approximately 33% and 20%, respectively, according to the Association of Energy Services Companies (“AESC”) and other publicly available data.

     Basic revised its business segments beginning in the first quarter of 2008. 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.” The following is a description of the segments:

• Well Servicing.  Our well servicing segment (39% of our revenues in 2007) currently operates our fleet of 387 well servicing rigs and related equipment. This business segment encompasses a full range of services performed with a mobile well servicing rig, including the, installation and removal of downhole equipment, and elimination of obstructions in the well bore to facilitate the flow of oil and gas. These services are performed to establish, maintain and improve production throughout the productive life of an oil and gas well and to plug and abandon a well at the end of its productive life. Our well servicing equipment and capabilities are essential to facilitate most other services performed on a well.

• Fluid Services.  Our fluid services segment (29% of our revenues in 2007) currently utilizes our fleet of 645 fluid services trucks and related assets, including specialized tank trucks, storage tanks, water wells, disposal facilities and related equipment. These assets provide, transport, store and dispose of a variety of fluids. These services are required in most workover, completion and remedial projects and are routinely used in daily producing well operations.

• Completion and Remedial Services.  Our completion and remedial services segment (28% of our revenues in 2007) 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 2007) currently operates ten 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 the previously filed Annual Report on Form 10-K.

Our Competitive Strengths

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

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     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 387 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 Fleet.  We operate a modern and active fleet of well servicing rigs. We believe over 80% of the active U.S. well servicing rig fleet was built prior to 1985. Greater than 50% of our rigs at December 31, 2007 were either 2000 model year or newer, or have undergone major refurbishments during the last five years. As of December 31, 2007, we have taken delivery of 110 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 remainder of these newbuilds are scheduled to be delivered to us by the end of December 2008. 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 81 of our rigs since the beginning of 2000. Approximately 98% of our fleet was active or available for work and the remainder was stacked or awaiting refurbishment at December 31, 2007. 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 59% of the approximately 900,000 existing onshore oil and gas wells in the 48 contiguous states and approximately 76% of onshore oil production and 91% of onshore gas production in 2007. 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 101 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 ten 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 ten 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.

Our Business Strategy

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

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     Establish and Maintain Leadership Position in Core Operating Areas.  We strive to establish and maintain market leadership positions within our core operating areas. To achieve this goal, we maintain close customer relationships, seek to expand the breadth of our services and offer high quality services and equipment that meet the scope of customer specifications and requirements. In addition, our significant presence in our core operating areas facilitates employee retention and attraction, a key factor for success in our business. Our significant presence in our core operating areas also provides us with brand recognition that we intend to utilize in creating leading positions in new operating areas.

     Expand Within Our Regional Markets.  We intend to continue strengthening our presence within our existing geographic footprint through internal growth and acquisitions of businesses with strong customer relationships, well-maintained equipment and experienced and skilled personnel. Our larger competitors have only pursued acquisitions of small to mid-size regional businesses or assets in recent years on a limited basis, due to the small relative scale and financial impact of these potential acquisitions. In contrast, we have successfully pursued these types of acquisitions, which remain attractive to us and make a meaningful impact on our overall operations. We typically enter into new markets through the acquisition of businesses with strong management teams that will allow us to expand within these markets. Management of acquired companies often remain with us and retain key positions within our organization, which enhances our attractiveness as an acquisition partner. We have a record of successfully implementing this strategy. During the past three years, our acquisitions have included:

     2005

• Oilwell Fracturing Services, Inc., a pressure pumping services company operating in our Mid-Continent region;

     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.

     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.

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     Pursue Growth Through Selective Capital Deployment.  We intend to continue growing our business through selective acquisitions, continuing a newbuild program and/or upgrading our existing assets. Our capital investment decisions are determined by an analysis of the projected return on capital employed of each of those alternatives. Acquisitions are evaluated for “fit” with our area and regional operations management and are thoroughly reviewed by corporate level financial, equipment, safety and environmental specialists to ensure consideration is given to identified risks. We also evaluate the cost to acquire existing assets from a third party, the capital required to build new equipment and the point in the oil and gas commodity price cycle. Based on these factors, we make capital investment decisions that we believe will support our long-term growth strategy, and these decisions may involve a combination of asset acquisitions and the purchase of new equipment. In 2007, we completed eight separate acquisitions for an aggregate purchase price of $252 million, net of cash acquired, and took delivery of 45 new well servicing rigs.

General Industry Overview

     Demand for services offered by our industry is a function of our customers’ willingness to make operating and capital expenditures to explore for, develop and produce hydrocarbons in the U.S., which in turn is affected by current and expected levels of oil and gas prices. As oil and gas prices rebounded beginning in early 1999, oil and gas companies have increased their drilling and workover activities. The increased activity resulted in increased domestic exploration and production spending compared to the prior year of 17% in 2006, according to the Lehman Brothers 2007 E&P Spending Survey. Domestic spending increased 4% in 2007 and is estimated to increase 4% in 2008, according to the Lehman Brothers 2008 E&P Spending Survey.

     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 2003:

	Cushing WTI Spot		Average Wellhead Price
Period	Oil Price ($/bbl)		Natural Gas ($/mcf)
1/1/03 — 12/31/03		31.08		4.98
1/1/04 — 12/31/04		41.51		5.49
1/1/05 — 12/31/05		56.64		7.51
1/1/06 — 12/31/06		66.05		6.42
1/1/07 — 12/31/07		72.34		6.38

Source: U.S. Department of Energy.

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     Increased expenditures for exploration and production activities generally drives the increased demand for our services. Rising oil and gas prices since early 1999 and the corresponding increase in onshore oil exploration and production spending have led to expanded drilling and well service activity, as the U.S. land-based drilling rig count increased approximately 22% from year-end 2004 to year-end 2005, 17% from year-end 2005 to year-end 2006, and 4% from year-end 2006 to year-end 2007. In addition, the U.S. land-based workover rig count increased approximately 17% from year-end 2004 to year-end 2005, decreased 1% from year-end 2005 to year-end 2006 and increased 3% from year-end 2006 to year-end 2007, according to Baker Hughes.

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

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

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

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

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.

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     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 387 well servicing as of December 31, 2007, including 110 newbuilds since October 2004 and 81 rebuilds since the beginning of 2000. 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, have been refurbished and were placed into service in the second quarter of 2005. In January 2007, we acquired two additional inland barges equipped with rigs 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 that we operated at December 31, 2007. 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-		Northern		Southern
Rig Type	Rated Capacity		Basin		Texas		Tex		Continent		Rockies		Rockies		Stacked		Total
Swab		N/A		1		1		7		5		0		0		0		14
Light Duty	<90 tons			6		2		0		16		0		0		1		25
Medium Duty	³90-<125 tons			121		37		32		46		23		22		2		283
Heavy Duty	³125 tons			30		5		5		6		4		5		1		56
24-Hour	³125 tons			1		3		0		1		0		0		0		5
Inland Barge	³125 tons			0		0		4		0		0		0		0		4
Total				159		48		48		74		27		27		4		387

     We operate a total of 387 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 a total of 925 rigs and Nabors is the second largest with 564 rigs at year end. Our only other competitor operating more than 100 rigs is Complete Production Services with 225 rigs. Excluding the rigs operated by Nabors in California where we do not compete, we have the second largest rig fleet.

     The total number of rigs owned by those four largest companies referenced above total 2,101, or 74% of the available fleet owned by member companies of the AESC, the major trade association of well site service providers. The remaining 26% of the well servicing rigs are owned by more than 100 local and regional companies. The most recent monthly activity conducted by the AESC indicated that 73% of the rigs owned were active.

     We have suspected for several years that the AESC survey was failing to capture a substantial number of well servicing companies and rigs as oil and gas prices and demand since 2004 have caused numerous small company start-ups and several large E&P companies to purchase their own rigs to ensure availability. In mid-2007, we co-sponsored a comprehensive survey of well servicing rig ownership and manufacturers to provide a more accurate assessment of the size of the competitive well servicing rig fleet.

     The results of that survey performed by Energy Sector Analytics, LLC, and made available to the sponsors in December included responses by 145 companies, including six E&P companies. The survey indicated a total competitive fleet of 3,477 rigs with 3,332 of those rigs working at the survey date, a utilization rate of 95%. Based on that survey, we operate approximately 11% of the available fleet and the four largest companies combine to operate 62% of the total.

     The Energy Sector Analytics survey also addressed the amount of new rig capacity coming to market in 2008. Survey participants indicated plans to add 162 new rigs in 2008, offset by 77 retirements, for a net increase in the available fleet of 85 rigs, or 2.4%.

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

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

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

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

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

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

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  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 services trucks and related assets, including specialized tank trucks, portable storage tanks, water wells, disposal facilities and related equipment. The following table sets forth the type, number and location of the fluid services equipment that we operated at December 31, 2007:

	Market Area
	Northern		Permian		Ark-La-		South		Mid-
	Rockies		Basin		Tex		Texas		Continent		Total
Fluid Services Trucks		87		222		186		108		42		645
Salt Water Disposal Wells		0		19		18		9		7		53
Fresh/Brine Water Stations		0		30		0		0		0		30
Fluid Storage Tanks		277		454		644		249		72		1,696

     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.

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

     Workover, 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.

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     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 645 fluid services trucks equipped with a fluid hauling capacity of up to 150 barrels. Each fluid service truck is equipped to pump fluids from or into wells, pits, tanks and other storage facilities. The majority of our fluid service trucks are also used to transport water to fill frac tanks on well locations, including frac tanks provided by us and others, to transport produced salt water to disposal wells, including injection wells owned and operated by us, and to transport drilling and completion fluids to and from well locations. In conjunction with the rental of our frac tanks, we generally use our fluid service trucks to transport water for use in fracturing operations. Following completion of fracturing operations, our fluid service trucks are used to transport the flowback produced as a result of the fracturing operations from the well site to disposal wells. Fluid services trucks are generally provided to oilfield operators within a 50-mile radius of our nearest yard.

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

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

     Fluid Storage Tanks.  Our fluid storage tanks can store up to 500 barrels of fluid and are used by oilfield operators to store various fluids at the well site, including fresh water, brine and acid for frac jobs, flowback, temporary production and mud storage. We transport the tanks on our trucks to well locations that are usually within a 50-mile radius of our nearest yard. Frac tanks are used during all phases of the life of a producing well. We generally rent fluid services tanks at daily rates for a minimum of three days. A typical fracturing operation can be completed within four days using 5 to 50 frac tanks.

     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. We also own a substantial quantity of wooden mats in our Gulf Coast operations to support the well site construction requirements in that marshy environment. 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 and pressure testing;

• rental and fishing tools;

• cased-hole wireline services; and

• underbalanced drilling in low pressure and fluid sensitive reservoirs.

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     This segment currently operates 118 pressure pumping units, with approximately 120,000 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, 2007, we also operated 42 air compressor packages, including foam circulation units, for underbalanced drilling and 12 wireline units for cased-hole measurement and pipe recovery services.

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

     A hydrocarbon reservoir is essentially an interval of rock that is saturated with oil and/or gas, usually in combination with water. Three primary factors determine the productivity of a well that intersects a hydrocarbon reservoir: porosity — the percentage of the reservoir volume represented by pore space in which the hydrocarbons reside, permeability — the natural propensity for the flow of hydrocarbons toward the well bore, and “skin” — the degree to which the portion of the reservoir in close proximity to the well bore has experienced reduced permeability as a result of exposure to drilling fluids or other contaminants. Well productivity can be increased by artificially improving either permeability or skin through stimulation methods.

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

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

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

     The following table sets forth the type, number and location of the completion and remedial services equipment that we operated at December 31, 2007:

	Market Area
					Northern		Southern		Permian
	Ark-La-Tex		Mid-Continent		Rockies		Rockies		Basin		Total
Pressure Pumping Units		22		93		3		0		0		118
Coiled Tubing Units		0		3		0		0		0		3
Air/Foam Packages		0		5		0		34		3		42
Wireline Units		0		12		0		0		0		12
Rental and Fishing Tool Stores		0		9		1		0		8		18

     Our pressure pumping business focuses primarily on lower horsepower cementing, acidizing and fracturing services in 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

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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 participates in the pressure pumping business, but primarily outside our core areas of operations for pumping services.

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

     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 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 ten land drilling rigs 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.

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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 currently located at 500 W. Illinois, Suite 100, Midland, Texas 79701. We currently conduct our business from 101 area offices, 51 of which we own and 50 of which we lease. Each office typically includes a yard, administrative office and maintenance facility. Of our 101 area offices, 63 are located in Texas, nine are in Oklahoma, nine are in New Mexico, five are in Wyoming, four are in Colorado, three are in Louisiana, two are in Montana, two are in North Dakota, 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 2007, no one customer comprised over 4% 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 a single material customer, or a few of them, such loss could have an adverse effect on our business until the equipment is redeployed.

Operating Risks and Insurance

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

• personal injury or loss of life;

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

• suspension of operations.

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

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

     Despite our efforts to maintain high safety standards, we from time to time have suffered accidents in the past and anticipate that we could experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability and our relationships with customers, employees and regulatory agencies. Any significant increase in the frequency or severity of these incidents, or the general level of compensation awards, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations.

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

Competition

     Our competition includes small regional contractors as well as larger companies with international operations. Our two largest competitors, Key Energy Services, Inc. and Nabors Well Services Co., combined own approximately 53% of the U.S. marketable well servicing rigs. Both of these competitors are public companies or subsidiaries of public companies that operate in most of the large oil and gas producing regions in the U.S. These competitors have centralized management teams that direct their operations and decision-making primarily from corporate and regional headquarters. In addition, because of their size, these companies market a large portion of their work to the major oil and gas companies.

     We differentiate ourselves from our major competition by our operating philosophy. We operate a decentralized organization, where local management teams are largely responsible for sales and 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

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target customers’ well population to grow over time through acquisition of properties formerly operated by major oil and gas companies. We concentrate on providing services to a diverse group of large and small independent oil and gas companies. These independents typically are relationship driven, make decisions at the local level and are willing to pay higher rates for services. We have been successful using this business model and believe it will enable us to continue to grow our business and maintain or expand our operating margins.

Safety Program

     Our business involves the operation of heavy and powerful equipment which can result in serious injuries to our employees and third parties and substantial damage to property. We have comprehensive safety and training programs designed to minimize accidents in the work place and improve the efficiency of our operations. In addition, many of our larger customers now place greater emphasis on safety and quality management programs of their contractors. We believe that these factors will gain further importance in the future. We have directed substantial resources toward employee safety and quality management training programs as well as our employee review process. While our efforts in these areas are not unique, we believe many competitors, and particularly smaller contractors, have not undertaken similar training programs for their employees.

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

Environmental Regulation

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

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

     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

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such as paint wastes and waste solvents as well as wastes generated in the course of us providing well services may be regulated as hazardous waste under RCRA or hazardous substances under CERCLA.

     We currently own or lease, and have in the past owned or leased, a number of properties that have been used for many years as service yards in support of oil and natural gas exploration and production activities. Although we have utilized operating and disposal practices that were standard in the industry at the time, there is the possibility that repair and maintenance activities on rigs and equipment stored in these service yards, as well as well bore fluids stored at these yards, may have resulted in the disposal or release of hydrocarbons or other wastes on or under these yards or other locations where these wastes have been taken for disposal. In addition, we own or lease properties that in the past were operated by third parties whose operations were not under our control. These properties and the hydrocarbons or wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination. We believe that we are in substantial compliance with the requirements of CERCLA and RCRA.

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

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

     Our underground injection operations are subject to the federal Safe Drinking Water Act, as well as analogous state and local laws and regulations. Under Part C of the Safe Drinking Water Act, the EPA established the Underground Injection Control program, which established the minimum program requirements for state and local programs regulating underground injection activities. The Underground Injection Control program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. The substantial majority of our saltwater disposal wells are located in the State of Texas and regulated by the Texas Railroad Commission, also known as the “RRC”. We also operate salt water disposal wells in Oklahoma and Wyoming and are subject to similar regulatory controls in those states. Regulations in these states require us to obtain a permit from the applicable regulatory agencies to operate each of our underground injection wells. We believe that we have obtained the necessary permits from these agencies for each of our underground injection wells and that we are in substantial compliance with permit conditions and commission rules. Nevertheless, these regulatory agencies have the general authority to suspend or modify one or more of these permits if continued operation of one of our underground injection wells is likely to result in pollution of freshwater, substantial violation of permit conditions or applicable rules, or leaks to the environment. Although we monitor the injection process of our wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third parties for property damages and personal injuries. In addition, our sales of residual crude oil 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

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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, 2007, we employed approximately 4,500 people, with approximately 83% 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.

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EX-99.2

Exhibit 99.2

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,
	2007			2006			2005			2004			2003
	(Dollars in thousands, except per share data)
Statement of Operations Data:
Revenues:
Well servicing	$	342,697		$	323,755		$	221,993		$	142,551		$	104,097
Fluid services		259,324			245,011			177,927			139,610			61,994
Completion and remedial services		240,692			154,412			59,832			29,341			14,808
Contract drilling		34,460			6,970			—			—			—
Total revenues		877,173			730,148			459,752			311,502			180,899
Expenses:
Well servicing		205,132			178,028			137,392			98,058			73,244
Fluid services		165,327			153,445			114,551			96,621			41,006
Completion and remedial services		125,948			74,981			30,900			17,481			9,363
Contract drilling		22,510			8,400			—			—			—
General and administration(a)		99,042			81,318			55,411			37,186			22,722
Depreciation and amortization		93,048			62,087			37,072			28,676			18,213
Loss (gain) on disposal of assets		477			277			(222	)		2,616			391
Total expenses		711,484			558,536			375,104			280,638			164,939
Operating income		165,689			171,612			84,648			30,864			15,960
Other income (expense):
Net interest expense		(25,136	)		(15,504	)		(12,660	)		(9,550	)		(5,174	)
Gain (loss) on early extinguishment of debt		(230	)		(2,705	)		(627	)		—			(5,197	)
Other income (expense)		176			169			220			(398	)		146
Income (loss) from continuing operations before income taxes		140,499			153,572			71,581			20,916			5,735
Income tax (expense) benefit		(52,766	)		(54,742	)		(26,800	)		(7,984	)		(2,772	)
Income (loss) from continuing operations		87,733			98,830			44,781			12,932			2,963
Discontinued operations, net of tax		—			—			—			(71	)		22
Cumulative effect of accounting change, net of tax		—			—			—			—			(151	)
Net income (loss)		87,733			98,830			44,781			12,861			2,834
Preferred stock dividend		—			—			—			—			(1,525	)
Accretion of preferred stock discount		—			—			—			—			(3,424	)
Net income (loss) available to common stockholders	$	87,733		$	98,830		$	44,781		$	12,861		$	(2,115	)
Basic earnings (loss) per share of common stock:	$	2.19		$	2.87		$	1.57		$	0.46		$	(0.09	)
Diluted earnings (loss) per share of common stock:	$	2.13		$	2.56		$	1.35		$	0.42		$	(0.09	)
Other Financial Data:
Cash flows from operating activities		198,591			145,678			99,189			46,539			29,815
Cash flows from investing activities		(294,103	)		(241,351	)		(107,679	)		(73,587	)		(84,903	)
Cash flows from financing activities		136,088			114,193			21,188			21,498			79,859
Capital expenditures:
Acquistions, net of cash acquired		199,673			135,568			25,378			19,284			61,885
Property and equipment		98,536			104,574			83,095			55,674			23,501

(a) Includes approximately $3,964,000, $3,429,000, $2,890,000, $1,587,000, and $994,000 of non-cash stock compensation expense of ended December 31, 2007, 2006, 2005, 2004 and 2003, respectively.

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	As of December 31,
	2007		2006		2005		2004		2003
	(Dollars in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	91,941	$	51,365	$	32,845	$	20,147	$	25,697
Property and equipment, net		636,924		475,431		309,075		233,451		188,243
Total assets		1,143,609		796,260		496,957		367,601		302,653
Long-term debt		406,306		250,742		119,241		170,915		142,116
Stockholders’ equity (deficit)		524,821		379,250		258,575		121,786		107,295

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EX-99.3

Exhibit 99.3

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 43 separate acquisitions from January 1, 2003 to December 31, 2007. Our weighted average number of well servicing rigs has increased from 126 in 2001 to 386 in the fourth quarter of 2007, and our weighted average number of fluid service trucks has increased from 156 to 656 in the same period. In 2007, we significantly increased our completion and remedial services segment, principally through the acquisition of JetStar Consolidated Holdings, Inc. Our weighted average number drilling rigs has increased from two in the first quarter of 2006 to 10 in the fourth quarter of 2007, principally through the acquisition of Sledge Drilling Holding Corp. 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. 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.”

     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,
	2007				2006				2005
Revenues:
Well servicing	$	342.7	39	%	$	323.7	44	%	$	222.0	48	%
Fluid services		259.3	29	%		245.0	34	%		178.0	39	%
Completion and remedial services		240.7	28	%		154.4	21	%		59.8	13	%
Contract drilling		34.5	4	%		7.0	1	%		—	0	%
Total revenues	$	877.2	100	%	$	730.1	100	%	$	459.8	100	%

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

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

     During 2005 and 2006, our business activity levels increased due to the impact of higher oil and gas prices and the expansion of our equipment fleets. Natural gas prices reached historical highs in 2006 which stimulated

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increased drilling activity by our customers. 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. In 2008, we expect that the utilization of our services and pricing for these services will be comparable to 2007 assuming oil and gas prices and U.S. drilling activity remain at or near current levels.

     We intend to continue growing our business through selective acquisitions, continuing a newbuild program and/or upgrading our existing assets. Our capital investment decisions are determined by an analysis of the projected return on capital employed of each of those alternatives, which is substantially driven by the cost to acquire existing assets from a third party, the capital required to build new equipment and the point in the oil and gas commodity price cycle. Based on these factors, we make capital investment decisions that we believe will support our long-term growth strategy. While we believe our costs of integration for prior acquisitions have been reflected in our historical results of operations, integration of acquisitions may result in unforeseen operational difficulties or require a disproportionate amount of our management’s attention. As discussed below in “— Liquidity and Capital Resources,” we also must meet certain financial covenants in order to borrow money under our existing credit agreement to fund future acquisitions

     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 below in “— Segment Overview.”

Recent Strategic Acquisitions and Expansions

     During the period from 2005 through 2007, we grew significantly through acquisitions and capital expenditures. During 2005, we directed our focus for growth primarily on the integration and expansion of our existing businesses through capital expenditures and to a lesser extent, acquisitions. During 2006, we completed ten acquisitions, of which G&L Tool, Ltd. was considered significant for purposes of Statement of Financial Accounting Standards No. 141 (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.

     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., and Sledge Drilling Holding Corp. in note 3 of our historical consolidated financial statements included in this report.

  Selected 2005 Acquisitions

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

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  MD Well Service, Inc.

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

  Oilwell Fracturing Services, Inc.

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

  Selected 2006 Acquisitions

     During 2006, we made several acquisitions that complemented our existing 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. 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. for total consideration of $58.5 million 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. for total consideration of $19 million cash, subject to adjustments. This acquisition expanded our well servicing and fluid services capabilities in the eastern New Mexico portion of the Permian Basin. The cash used to acquire Chaparral was primarily from operating cash.

  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 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

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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.

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Segment Overview

  Well Servicing

     In 2007, our well servicing segment represented 39% 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 has increased from a weighted average number of 291 rigs in the first quarter of 2005 to 386 in the fourth quarter of 2007 through a combination of newbuild purchases and the remainder through acquisitions and other individual equipment purchases.

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     The following is an analysis of our well servicing segment for each of the quarters and years in the years ended December 31, 2005, 2006 and 2007:

	Weighted
	Average				Rig					Profits
	Number of		Rig		Utilization			Revenue Per		Per Rig		Segment
	Rigs		Hours		Rate			Rig Hour		Hour		Profits%
2005:
First Quarter		291		175,300		84.3	%	$	255	$	94		37.1	%
Second Quarter		303		192,400		88.8	%	$	280	$	107		38.2	%
Third Quarter		311		198,000		89.0	%	$	299	$	108		36.0	%
Fourth Quarter		316		195,000		86.3	%	$	329	$	134		40.7	%
Full Year		305		760,700		87.1	%	$	292	$	111		38.1	%
2006:
First Quarter		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	%

     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 2007, our fluid services segment represented 29% of our revenues. Revenues in our fluid services segment are earned from the sale, transportation, storage and disposal of fluids used in the drilling, production and maintenance of oil and gas wells. 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 demand but typically produce lower relative segment profits than other parts of our fluid services segment. Fluid services for completion and workover projects typically require fresh or brine water for making drilling mud, circulating fluids or frac fluids used during a job, and all of these fluids require storage tanks and hauling and disposal. Because we can provide a full complement of fluid sales, trucking, storage and disposal required on most drilling and workover projects, the add-on services associated with drilling and workover activity enable us to generate higher segment profits contributions. The higher segment profits are due to the relatively small incremental labor costs associated with providing these services in addition to our base fluid services segment. We typically price fluid services by the job, by the hour or by the quantities sold, disposed of or hauled.

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     The following is an analysis of our fluid services segment for each of the quarters and years in the years ended December 31, 2005, 2006 and 2007 (dollars in thousands):

					Segment
	Weighted				Profits
	Average				Per
	Number of		Revenue Per		Fluid
	Fluid Service		Fluid Service		Service		Segment
	Trucks		Truck		Truck		Profits%
2005:
First Quarter		435	$	88	$	27		31.1	%
Second Quarter		447	$	95	$	34		35.4	%
Third Quarter		465	$	98	$	36		36.8	%
Fourth Quarter		472	$	109	$	42		38.1	%
Full Year		455	$	391	$	139		35.6	%
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	%

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

  Completion and Remedial Services

     In 2007, our completion and remedial services segment represented 28% 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 120,000 horsepower at December 31, 2007 compared to 58,000 horsepower at December 31, 2006.

     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 have 18 rental and fishing tool stores as of December 31, 2007.

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

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

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     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, 2005, 2006 and 2007 (dollars in thousands):

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

     We gauge the performance of our completion and remedial services segment based on the segment’s operating revenues and segment profits.

  Contract Drilling

     In 2007, 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 four during the first quarter of 2007 to 10 by the fourth quarter, due to the Sledge Drilling acquisition.

     The following is an analysis of our well site construction services segment for each of the quarters and years in the years ended December 31, 2006 and 2007 (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	%

     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.

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Operating Cost Overview

     Our operating costs are comprised primarily of labor, including workers’ compensation and health insurance, repair and maintenance, fuel and insurance. A majority of our employees are paid on an hourly basis. With a reduced pool of workers in the industry, it is possible that we will have to raise wage rates to attract workers from other fields and retain or expand our current work force. Typically, we have been able to increase service rates to our customers to compensate for wage rate increases. We also incur costs to employ personnel to sell and supervise our services and perform maintenance on our fleet. These costs are not directly tied to our level of business activity. Compensation for our administrative personnel in local operating yards and in our corporate office is accounted for as general and administrative expenses. Repair and maintenance is performed by our crews, company maintenance personnel and outside service providers. Insurance is generally a fixed cost regardless of utilization and relates to the number of rigs, trucks and other equipment in our fleet, employee payroll and 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 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 $250,000 and $175,000 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.

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

     Income Taxes.  We account for income taxes based upon Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (“SFAS No. 109”). Under SFAS No. 109, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in the period that includes the statutory enactment date. A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized.

  Critical Accounting Estimates

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

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

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

     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.

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

     Litigation and Self-Insured Risk Reserves.  We estimate our reserves related to litigation and self-insure risk based on the facts and circumstances specific to the litigation and self-insured risk claims and our past experience with similar claims. The actual outcome of 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

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assumptions developed using third-party data and historical data to project future losses. Loss estimates in the calculation of these accruals are adjusted based upon actual claim settlements and reported claims.

     Fair Value of Assets Acquired and Liabilities Assumed.  We estimate the fair value of assets acquired and liabilities assumed in business combinations, which involves the use of various assumptions. These estimates may be affected by such factors as changing market conditions, technological advances in industry or changes in regulations governing the industry. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair value of property and equipment, intangible assets and the resulting amount of goodwill, if any. 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.

     Stock-Based Compensation.  On January 1, 2006, we adopted the fair value recognition provisions of Statement of Financial Accounting Standards No. 123R, “Share-Based Payment” (“SFAS No. 123R”). Prior to January 1, 2006, we accounted for share-based payments under the recognition and measurement provisions of Accounting Principles Board Opinion No. 25, “Accounting for stock Issued to Employees” (“APB No. 25”) which was permitted by Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123).

     We adopted SFAS No. 123R using both the modified prospective method and the prospective method as applicable to the specific awards granted. The modified prospective method was applied to awards granted subsequent to the Company becoming a public company. Awards granted prior to the Company becoming public and which were accounted for under APB No. 25 were adopted by using the prospective method. The results of prior periods have not been restated. Compensation expense of the unvested portion of awards granted as a private company and outstanding as of January 1, 2006 will continue to be based upon the intrinsic value method calculated under APB No. 25.

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

     Income Taxes.  The amount and availability of our loss carryforwards (and certain other tax attributes) are subject to a variety of interpretations and restrictive tests. The utilization of such carryforwards could be limited or lost upon certain changes in ownership and the passage of time. Accordingly, although we believe substantial loss carryforwards are available to us, no assurance can be given concerning the realization of such loss carryforwards, or whether or not such loss carryforwards will be available in the future.

     Asset Retirement Obligations.  Statement of Financial Accounting Standards 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.

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  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 is 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 workers 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 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 is primarily due to the acquisition of Sledge, which added $11.7 million of operating expenses.

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     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 or senior credit facility. In connection with the payment on the Term B Loan, we recognized a loss on the early extinguishment of debt and wrote-off unamortized debt issuance costs of approximately $2.7 million.

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

     Revenues.  Revenues increased by 59% to $730.1 million in 2006 from $459.8 million in 2005. This increase was primarily due to the internal expansion of our business segments, particularly well servicing and fluid services, and in part due to acquisitions. The pricing and utilization of our services, and thus related revenues, improved due to the increase in well maintenance and drilling activity caused by continued relatively high oil and gas prices.

     Well servicing revenues increased by 46% to $323.8 million in 2006 compared to $222.0 million in 2005. The increase was due mainly to our internal growth of this segment as well as an increase in our revenue per rig hour of approximately 28%, from $292 per hour to $373 per hour. Our weighted average number of well servicing rigs increased to 344 in 2006 compared to 305 in 2005, an increase of approximately 13%. In addition, the utilization rate of our rig fleet increased to 88.2% in 2006 compared to 87.1% in 2005.

     Fluid services revenues increased by 38% to $245.0 million in 2006 compared to $177.9 million in 2005. This increase was primarily due to our internal growth and acquisitions. Our weighted average number of fluid service trucks increased to 588 in 2006 compared to 455 in 2005, an increase of approximately 29%. The increase in weighted average number of fluid service trucks is primarily due to the internal expansion as wells as the trucks added from the LeBus acquisition. During 2006, our average revenue per fluid service truck was approximately $417,000 as compared to $391,000 in 2005. The increase in average revenue per fluid service truck reflects the expansion of our frac tank fleet and saltwater disposal operations, as well as increases in prices charged for our services.

     Completion and remedial services revenues increased by 158% to $154.4 million in 2006 as compared to $59.8 million in 2005. The increase in revenue between these periods was primarily the result of internal expansion, the acquisition of Oilwell Fracturing Services in October 2005, the acquisition of G&L during February 2006 and improved pricing and utilization of our services.

     Contract drilling revenues were $7.0 million as we entered this line of business in the first quarter of 2006.

     Direct Operating Expenses.  Direct operating expenses, which primarily consist of labor, including workers compensation and health insurance, and maintenance and repair costs, increased by 47% to $414.9 million in 2006 from $282.8 million in 2005 as a result of additional rigs and trucks, increase in labor costs and higher utilization of our equipment. Direct operating expenses decreased to 57% of revenues in 2006 from 62% in 2005, as fixed

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operating costs such as field supervision, insurance and vehicle expenses were spread over a higher revenue base. We also benefited from higher utilization and increased pricing of our services.

     Direct operating expenses for the well servicing segment increased by 30% to $178.0 million in 2006 as compared to $137.4 million in 2005 due primarily due to the internal growth of this segment. Segment profits increased to 45.0% of revenues in 2006 compared to 38.1% in 2005, due to improved pricing for our services and higher utilization of our equipment.

     Direct operating expenses for the fluid services segment increased by 34% to $153.4 million in 2006 as compared to $114.6 million in 2005 due primarily to increased activity and expansion of our fluid services fleet. Segment profits increased to 37.4% of revenues in 2006 compared to 35.6% in 2005.

     Direct operating expenses for the completion and remedial services segment increased by 143% to $75.0 million in 2006 as compared to $30.9 million in 2005 due primarily to increased activity and expansion of our services and equipment, including the G&L acquisition. Our segment profits increased to 51.4% of revenues in 2006 from 48.4% in 2005.

     Direct operating expenses for the contract drilling segment were $8.4 million.

     General and Administrative Expenses.  General and administrative expenses increased by 47% to $81.3 million in 2006 from $55.4 million in 2005, which included $3.4 million and $2.9 million of stock-based compensation expense in 2006 and 2005, respectively. The increase primarily reflects higher salary and office expenses related to the expansion of our business as well as additional staffing and other costs to enhance internal controls as a public company.

     Depreciation and Amortization Expenses.  Depreciation and amortization expenses were $62.1 million in 2006 as compared to $37.1 million in 2005, reflecting the increase in the size of and investment in our asset base. We invested $135.6 million for acquisitions in 2006 and an additional $131.0 million for capital expenditures in 2006 (including capital leases).

     Interest Expense.  Interest expense increased by 33% to $17.5 million in 2006 from $13.1 million in 2005. The increase was due to an increase in the amount of long-term debt during the period. In April 2006, Basic issued $225.0 million in senior notes.

     Income Tax Expense.  Income tax expense was $54.7 million in 2006 as compared to $26.8 million in 2005. Our effective tax rate in 2006 and 2005 was approximately 36% and 38%, respectively.

     Loss on Early Extinguishment of Debt.  In April 2006, we used the proceeds from our issuance of $225 million aggregate principal amount of senior notes to pay in full our Term B Loan under or senior credit facility. In connection with the payment on the Term B Loan, we recognized a loss on the early extinguishment of debt and wrote-off unamortized debt issuance costs of approximately $2.7 million compared to an approximately $627,000 loss on the early extinguishment of debt in 2005 for amending and restating our credit facility.

Liquidity and Capital Resources

     Currently, our primary capital resources are net cash flows from our operations, utilization of capital leases as allowed under our 2007 Credit Facility and availability under our 2007 Credit Facility, of which approximately $59.5 million was available at December 31, 2007. As of December 31, 2007, we had cash and cash equivalents of $91.9 million compared to $51.4 million as of December 31, 2006. 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 $198.6 million for the year ended December 31, 2007 as compared to $145.7 million in 2006, and $99.2 million in 2005. The increase in 2007 was due primarily to higher depreciation

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and amortization, deferred income taxes and working capital changes in 2007. The increase in operating cash flows in 2006 compared to 2005 was primarily due to increased operating profits and depreciation and amortization which were offset by increases in working capital, mainly accounts receivable.

  Capital Expenditures

     Capital expenditures are the main component of our investing activities. Cash capital expenditures (including for acquisitions) for 2007 were $298.2 million as compared to $240.1 million in 2006, and $108.5 million in 2005. In 2007 and 2006, the majority of our capital expenditures were for business acquisitions. In 2005, the majority of our capital expenditures were for the expansion of our fleet. We also added assets through our capital lease program of approximately $26.8 million, $26.4 million, and $10.3 million in 2007, 2006 and 2005, respectively.

     For 2008, we currently have planned approximately $115 million in cash capital expenditures and $33 million in new capital leases, none of which is planned for acquisitions. We do not budget acquisitions in the normal course of business, but we believe that we may spend a significant amount for acquisitions in 2008. The $115 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 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 $87.5 million at December 31, 2007, the availability under our credit facility of $59.5 million at December 31, 2007 and a cash balance of $91.9 million at December 31, 2007. In 2007, 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 rig purchase obligations, (6) our asset retirement obligations, and (7) our other long-term liabilities. The following table outlines our contractual obligations as of December 31, 2007 (in thousands):

	Obligations Due in Periods Ended
	December 31,
Contractual Obligations	Total		2008		2009-2010		2011-2012		Thereafter
Long-term debt (excluding capital leases)	$	375,000	$	—	$	150,000	$	—	$	225,000
Interest on long-term debt		177,045		26,953		53,906		32,063		64,123
Capital leases		48,673		17,367		26,234		4,872		200
Operating leases		18,316		3,450		6,203		4,541		4,122
Rig purchase obligations		16,394		16,394		—		—		—
Asset retirement obligations		1,552		—		382		168		1,002
Other long-term liabilities		4,290		3,912		326		52		—
Total	$	641,270	$	68,076	$	237,051	$	41,696	$	294,447

     Our long-term debt, excluding capital leases, consists primarily of term loan and revolver indebtedness outstanding under our senior credit facilities. Interest on senior notes relates to our future contractual interest obligation on our $225 million 7.125% Senior Notes offering in April of 2006 and $150 million outstanding under our 2007 credit facility. Interest on our 2007 credit facility is payable based upon the amount outstanding at December 31, 2007, 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, 2007, we had a maximum potential obligation of $25.6 million related to the contingent earn-out agreements. This amount does not include the balance owed for an acquisition with no maximum earn-out exposure. In this situation, we will pay to the sellers an amount for each of the five consecutive 12 month periods equal to 50% of the amount by which annual EBITDA will be reached. See note 3 of the notes to our historical consolidated financial statements for additional detail.

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     At December 31, 2007, of the $225 million in financial commitments under the revolving line of credit under our senior credit facility, there was only $59.5 million of available capacity due to the outstanding balance of $150 million and the $15.5 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 outstanding balance under the revolving credit facility. Remaining proceeds were used for general corporate purposes, including acquisitions.

     We issued the Senior Notes pursuant to an indenture, dated as of April 12, 2006, by and among us, the guarantor parties thereto and The Bank of New York Trust Company, N.A., as trustee.

     Interest on the Senior Notes will accrue from and including April 12, 2006 at a rate of 7.125% per year. Interest on the Senior Notes is payable in cash semi-annually in arrears on April 15 and October 15 of each year, commencing on October 15, 2006. The Senior Notes 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 secured credit facilities, to the extent of the value of the assets securing such obligations.

     The indenture contains covenants that limit the ability of us and certain of our subsidiaries to:

• incur additional indebtedness;

• pay dividends or repurchase or redeem capital stock;

• make certain investments;

• incur liens;

• enter into certain types of transactions with affiliates;

• limit dividends or other payments by restricted subsidiaries; and

• sell assets or consolidate or merge with or into other companies.

     These limitations are subject to a number of important qualifications and exceptions.

     Upon an Event of Default (as defined in the indenture), the trustee or the holders of at least 25% in aggregate principal amount of the Senior Notes then outstanding may declare all of the amounts outstanding under the Senior Notes to be due and payable immediately.

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     We may, at our option, redeem all or part of the Senior Notes, at any time on or after April 15, 2011 at a redemption price equal to 100% of the principal amount thereof, plus a premium declining ratably to par and accrued and unpaid interest, if any, to the date of redemption.

     At any time or from time to time prior to April 15, 2009, we, at our option, may redeem up to 35% of the outstanding Senior Notes with money that we raise in one or more equity offerings at a redemption price of 107.125% of the principal amount of the Senior Notes redeemed, plus accrued and unpaid interest, as long as:

• at least 65% of the aggregate principal amount of Senior Notes issued under the indenture remains outstanding immediately after giving effect to any such redemption; and

• we redeem the Senior Notes not more than 90 days after the closing date of any such equity offering.

     If we experience certain kinds of changes of control, holders of the Senior Notes will be entitled to require us to purchase all or a portion of the Senior Notes at 101% of their principal amount, plus accrued and unpaid interest.

  Credit Facilities

  2007 Credit Facility

     On February 6, 2007, we amended and restated our existing credit agreement by entering into a Fourth Amended and Restated Credit Agreement with a syndicate of lenders (the “2007 Credit Facility”). At December 31, 2007, we had $150 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 lender’s total revolving commitments from $150 million to $225 million

• increasing the “Incremental Revolving Commitments” under the 2007 Credit Facility from $75.0 million to an aggregate principal amount of $100 million;

• changing the applicable margins for Alternative Base Rate or Eurodollar revolving loans;

• amending our negative covenants relating to our ability to incur indebtedness and liens, to add tests based on a percentage of our consolidated tangible assets in addition to fixed dollar amounts, or to increase applicable dollar limits on baskets or other tests for permitted indebtedness or liens;

• amending our negative covenants relating to our ability to pay dividends, or repurchase or redeem our capital stock, in order to conform more closely with permitted payments under our senior notes; and

• Eliminating certain restrictions on our ability to create or incur certain lease obligations.

     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 at any time. Additionally, the 2007 Credit Facility permits us to make greater expenditures for acquisitions, capital expenditures and capital leases and to incur greater purchase money obligations, acquisition indebtedness and general unsecured indebtedness. The commitment under the Revolver provides for (1) the borrowing of funds, (2) the issuance of up to $30 million of letters of credit and (3) $2.5 million of swing-line loans. All of the outstanding amounts under the Revolver are due and payable on December 15, 2010. The 2007 Credit Facility is secured by substantially all of our tangible and intangible assets. We incurred approximately $0.7 million in debt issuance costs in connection with the 2007 Credit Facility.

     At our option, borrowings under the Revolver bears interest at either (1) the “Alternative Base Rate” (i.e., the higher of the bank’s prime rate or the federal funds rate plus .50% per year) plus a margin ranging from 0.25% to

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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 3.50 to 1.00, reducing to 3.25 to 1.00 on April 1, 2007, and

• a minimum interest coverage ratio of 3.00 to 1.00.

  Other Debt

     We have a variety of other capital leases and notes payable outstanding that is generally customary in our business. None of these debt instruments are material individually or in the aggregate. As of December 31, 2007, we had total capital leases of approximately $48.7 million.

  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.

     In 2005, Basic recognized a loss on the early extinguishment of debt. Basic wrote-off unamortized debt issuance costs of approximately $0.6 million.

  Credit Rating Agencies

     In April 2006, we received credit ratings of Baa3 from Moody’s and B+ from Standard & Poor’s for our 2005 Credit Facility. Also, we received ratings of B1 from Moody’s and B from Standard & Poor’s for our Senior Notes. None of our debt or other instruments is dependent upon our credit ratings. However, the credit ratings may affect our ability to obtain financing in the future. On February 6, 2007, we received credit ratings of Ba1 from Moody’s and BB from Standard & Poor’s for our 2007 Credit Facility.

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  Preferred Stock

     At December 31, 2007 and December 31, 2006, Basic had 5,000,000 shares of $.01 par value preferred stock authorized, of which none was designated.

Other Matters

  Net Operating Losses

     As of December 31, 2007, we had approximately $3.1 million of NOL carryforwards related to the pre-acquisition period of FESCO, which is subject to an annual limitation of approximately $900,000. The carryforwards begin to expire in 2017.

  Recent Accounting Pronouncements

     In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation No. 48 (FIN 48), Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109, Accounting for Income Taxes. The interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken, in a tax return. Our adoption in January 2007 of FIN 48 did not result in any change to retained earnings or any additional unrecognized tax benefit. Interest will be recorded in interest expense and penalties will be recorded in income tax expense. We had no interest or penalties related to an uncertain tax position during 2007. The company files federal income tax returns and state income tax returns in Texas and other state tax jurisdictions. In general, the company’s tax returns for fiscal years after 2002 currently remain subject to examination by appropriate taxing authorities. None of the company’s income tax returns are under examination at this time.

     In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS 157), which will become 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 becomes 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. The company does not anticipate that election, if any, of this fair-value option will have a material effect on its results of operations or consolidated financial position.

19

     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.

  Impact of Inflation on Operations

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

20

EX-99.4

Exhibit 99.4

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Basic Energy Services, Inc.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Management’s Report on Internal Control Over Financial Reporting		1
Reports of Independent Registered Public Accounting Firm		2
Consolidated Balance Sheets as of December 31, 2007 and 2006		4
Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2007, 2006 and 2005		5
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2007, 2006 and 2005		6
Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006 and 2005		7
Notes to Consolidated Financial Statements		8

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, 2007, 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, 2007, 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 JetStar Consolidated Holdings, Inc., Sledge Drilling Holding Corp., and Wildhorse Services, Inc during 2007, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007 any internal control evaluation over financial reporting the associated total assets of approximately $236.1 million and total revenues of approximately $85.8 million included in the consolidated financial statements of Basic Energy Services Inc. and subsidiaries as of and for the year ended December 31, 2007.

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

1

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 (Company) internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). 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, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

     The Company acquired JetStar Consolidated Holdings, Inc., Sledge Drilling Holding Corp., and Wildhorse Services, Inc. (collectively the 2007 Excluded Acquisitions) during 2007, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007, the 2007 Excluded Acquisitions’ internal control over financial reporting associated with total assets of $236.1 million and total revenues of $85.8 million included in the consolidated financial statements of Basic Energy Services, Inc. and subsidiaries as of and for the year ended December 31, 2007. Our audit of internal control over financial reporting of Basic Energy Services, Inc. also excluded an evaluation of the internal control over financial reporting of the 2007 Excluded Acquisitions.

     We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Basic Energy Services, Inc. as of December 31, 2007 and 2006, 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, 2007, and our report dated March 7, 2008 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

Dallas, Texas
March 7, 2008

2

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
Basic Energy Services, Inc.:

We have audited the accompanying consolidated balance sheets of Basic Energy Services, Inc. and subsidiaries as of December 31, 2006 and 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, 2007. 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, 2007 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2007, 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, present fairly, in all material respects, the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, effective January 1, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), Share Based Payment.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Basic Energy Services, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 7, 2008 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

KPMG LLP

Dallas, Texas
March 7, 2008, except for the updated disclosures pertaining
to the resegmenting and the updated subsequent event occurring
in 2008 as described in Notes 1, 2, 4, 15 and 19 as to which
the date is May 7, 2008.

3

Basic Energy Services, Inc.

Consolidated Balance Sheets

	December 31,
	2007		2006
	(In thousands, except
	share data)
ASSETS
Current assets:
Cash and cash equivalents	$	91,941	$	51,365
Trade accounts receivable, net of allowance of $6,090 and $3,963, respectively		138,384		129,381
Accounts receivable — related parties		91		94
Federal income tax receivable		1,130		—
Inventories		11,034		8,409
Prepaid expenses		6,999		8,873
Other current assets		6,353		3,210
Deferred tax assets		10,593		8,432
Total current assets		266,525		209,764
Property and equipment, net		636,924		475,431
Deferred debt costs, net of amortization		6,100		6,536
Goodwill		204,963		101,579
Other intangible assets		26,975		1,550
Other assets		2,122		1,400
	$	1,143,609	$	796,260
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	22,146	$	20,335
Accrued expenses		51,003		43,719
Income taxes payable		—		12,301
Current portion of long-term debt		17,413		12,001
Other current liabilities		1,474		1,430
Total current liabilities		92,036		89,786
Long-term debt		406,306		250,742
Deferred tax liabilities		114,604		73,413
Other long-term liabilities		5,842		3,069
Commitments and contingencies
Stockholders’ equity:
Preferred stock; $.01 par value; 5,000,000 shares authorized; non designated at December 31, 2007 and December 31, 2006, respectively		—		—
Common stock; $.01 par value; 80,000,000 shares authorized; 40,925,530 issued; 40,896,217 shares outstanding at December 31 2007 and 38,297,605 issued; 38,297,605 shares outstanding at December 31, 2006		409		383
Additional paid-in capital		314,705		256,527
Retained earnings		209,707		122,340
Treasury stock, 29,313 shares at December 31, 2007, at cost		—		—
Total stockholders’ equity		524,821		379,250
	$	1,143,609	$	796,260

See accompanying notes to consolidated financial statements.

4

Basic Energy Services, Inc.

Consolidated Statements of Operations and Comprehensive Income

	Years Ended December 31
	2007			2006			2005
	(Dollars in thousands, except per share amounts)
Revenues:
Well servicing	$	342,697		$	323,755		$	221,993
Fluid services		259,324			245,011			177,927
Completion and remedial services		240,692			154,412			59,832
Contract drilling		34,460			6,970			—
Total revenues		877,173			730,148			459,752
Expenses:
Well servicing		205,132			178,028			137,392
Fluid services		165,327			153,445			114,551
Completion and remedial services		125,948			74,981			30,900
Contract drilling		22,510			8,400			—
General and administrative, including stock-based compensation of $3,964, $3,429, and $2,890 in 2007, 2006 and 2005, respectively		99,042			81,318			55,411
Depreciation and amortization		93,048			62,087			37,072
(Gain) loss on disposal of assets		477			277			(222	)
Total expenses		711,484			558,536			375,104
Operating income		165,689			171,612			84,648
Other income (expense):
Interest expense		(27,416	)		(17,466	)		(13,065	)
Interest income		2,280			1,962			405
Loss on early extinguishment of debt		(230	)		(2,705	)		(627	)
Other income (expense)		176			169			220
Income from continuing operations before income taxes		140,499			153,572			71,581
Income tax expense		(52,766	)		(54,742	)		(26,800	)
Net income available to common stockholders		87,733			98,830			44,781
Basic earnings per share of common stock:
Net income available to common stockholders	$	2.19		$	2.87		$	1.57
Diluted earnings per share of common stock:
Net income available to common stockholders	$	2.13		$	2.56		$	1.35
Comprehensive income:
Net income	$	87,733		$	98,830		$	44,781
Unrealized gains on hedging activities		—			51			193
Less: reclassification adjustment for gain included in net income		—			(287	)		—
Comprehensive income:	$	87,733		$	98,594		$	44,974

See accompanying notes to consolidated financial statements.

5

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, 2004		28,931,935		58		142,802			(4,990	)		—			(16,127	)		43			121,786
Stock-based compensation awards		—		—		5,241			(5,241	)		—			—			—			—
Amortization of deferred compensation		—		—		—			2,890			—			—			—			2,890
Unrealized gain on interest rate swap agreement		—		—		—			—			—			—			193			193
Forfeited 11,250 shares at cost of $0		—		—		—			—			—			—			—			—
Effect of stock split		—		231		(231	)		—			—			—			—			—
Proceeds from common stock issuance, net of $2,044 of offering costs		5,000,000		50		91,406			—			—			—			—			91,456
Purchase of 135,326 of treasury stock		—		—		—			—			(2,531	)		—			—			(2,531	)
Net income		—		—		—			—			—			44,781			—			44,781
Balance — December 31, 2005		33,931,935		339		239,218			(7,341	)		(2,531	)		28,654			236			258,575
Adoption of Statement of Financial Accounting Standard No. 123R		—		—		(7,341	)		7,341			—			—			—			—
Amortization of deferred compensation		—		—		3,429			—			—			—			—			3,429
Unrealized gain on interest rate swap agreement		—		—		—			—			—			—			51			51
Settlement of interest rate swap agreement		—		—		—			—			—			—			(287	)		(287	)
Offering costs		—		—		(227	)		—			—			—			—			(227	)
Exercise of stock warrants		4,350,000		44		17,357			—			—			—			—			17,401
Purchase of treasury stock		—		—		—			—			(3,218	)		—			—			(3,218	)
Exercise of stock options		15,670		—		4,091			—			5,749			(5,144	)		—			4,696
Net income		—		—		—			—			—			98,830			—			98,830
Balance — December 31, 2006		38,297,605		383		256,527			—			—			122,340			—			379,250
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

See accompanying notes to consolidated financial statements.

6

Basic Energy Services, Inc.

Consolidated Statements of Cash Flows

	Years Ended December 31,
	2007			2006			2005
	(In thousands)
Cash flows from operating activities:
Net income	$	87,733		$	98,830		$	44,781
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		93,048			62,087			37,072
Accretion on asset retirement obligation		115			78			42
Change in allowance for doubtful accounts		2,127			1,188			(333	)
Amortization of deferred financing costs		962			804			1,062
Non-cash compensation		3,964			3,429			2,890
Loss on early extinguishment of debt		230			2,705			627
(Gain) loss on disposal of assets		477			277			(222	)
Deferred income taxes		15,285			2,611			18,301
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable		4,396			(32,933	)		(27,577	)
Inventories		(328	)		(714	)		(262	)
Prepaid expenses and other current assets		6,325			(6,771	)		304
Other assets		(753	)		(450	)		(49	)
Accounts payable		(1,237	)		5,128			2,174
Excess tax benefits from exercise of employee stock options		(2,169	)		(4,022	)		—
Income tax payable		(11,262	)		6,344			7,013
Other liabilities		(332	)		(171	)		374
Accrued expenses		10			7,258			12,992
Net cash provided by operating activities		198,591			145,678			99,189
Cash flows from investing activities:
Purchase of property and equipment		(98,536	)		(104,574	)		(83,095	)
Proceeds from sale of assets		6,815			5,560			2,436
Payments for other long-term assets		(2,709	)		(6,769	)		(1,642	)
Payments for businesses, net of cash acquired		(199,673	)		(135,568	)		(25,378	)
Net cash used in investing activities		(294,103	)		(241,351	)		(107,679	)
Cash flows from financing activities:
Proceeds from debt		150,000			305,546			16,000
Debt acquired in acquisitions		58,602			—			—
Payments of debt		(15,838	)		(204,793	)		(81,924	)
Debt paid from acquisitions		(58,602	)		—			—
Proceeds from common stock, net of $2,044 of offering costs		—			—			91,456
Purchase of treasury stock		(462	)		(3,218	)		(2,531	)
Offering costs related to initial public offering		—			(227	)		—
Excess tax benefits from exercise of employee stock options		2,169			4,022			—
Tax withholding from exercise of stock options		(1,290	)		(1,310	)		—
Exercise of employee stock options		2,265			1,984			—
Proceeds from exercise stock warrants		—			17,401			—
Deferred loan costs and other financing activities		(756	)		(5,212	)		(1,813	)
Net cash provided by financing activities		136,088			114,193			21,188
Net increase (decrease) in cash and equivalents		40,576			18,520			12,698
Cash and cash equivalents — beginning of year		51,365			32,845			20,147
Cash and cash equivalents — end of year	$	91,941		$	51,365		$	32,845

See accompanying notes to consolidated financial statements.

7

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements
December 31, 2007, 2006, and 2005

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 business segments beginning in the first quarter of 2008. 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 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

8

     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 consists primarily of the sale, transportation, storage and disposal of fluids used in drilling, production and maintenance of oil and natural gas wells. Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Basic prices fluid services by the job, by the hour or by the quantities sold, disposed of or hauled.

     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 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:

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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.

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     Goodwill and intangible assets not subject to amortization are tested annually for impairment, and are tested for impairment more frequently if events and circumstances indicate that the asset might be impaired. An impairment loss is recognized to the extent that the carrying amount exceeds the asset’s fair value.

   Deferred Debt Costs

     Basic capitalizes certain costs in connection with obtaining its borrowings, such as lender’s fees and related attorney’s fees. These costs are being amortized to interest expense using the effective interest method.

     Deferred debt costs of approximately $7.6 million at December 31, 2007 and $7.1 million at December 31, 2006, represent debt issuance costs and are recorded net of accumulated amortization of $1.5 million, and $523,000 at December 31, 2007 and December 31, 2006, respectively. Amortization of deferred debt costs totaled approximately $962,000, $804,000 and $1.1 million for the years ended December 31, 2007, 2006 and 2005, respectively.

     In 2006, Basic recognized a loss on early extinguishment of debt related to deferred debt costs. (See note 5)

   Goodwill and Other Intangible Assets

     Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”) eliminates the amortization of goodwill and other intangible assets with indefinite lives. Intangible assets with lives restricted by contractual, legal, or other means will continue to be amortized over their useful lives. Goodwill and other intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. SFAS No. 142 requires a two-step process for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. If impairment is indicated, then the fair value of the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination. The amount of impairment for goodwill is measured as the excess of its carrying value over its fair value. Basic completed its assessment of goodwill impairment as of the date of adoption and completed a subsequent annual impairment assessment as of December 31 each year thereafter. The assessments did not result in any indications of goodwill impairment.

     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 $23.8 million as of December 31, 2007. The gross carrying amount of non-compete agreements subject to amortization totaled approximately $5.2 million and $2.9 million at December 31, 2007 and 2006, respectively. Accumulated amortization related to these intangible assets totaled approximately $2.1 and $1.3 million at December 31, 2007 and 2006, respectively. Amortization expense for the years ended December 31, 2007, 2006 and 2005 was approximately $773,000, $650,000, and $519,000, respectively. Amortization expense for the next five succeeding years is estimated to be approximately $2.5 million, $2.4 million, $2.3 million, $2.1 million, and $1.8 million in 2008, 2009, 2010, 2011, and 2012 respectively.

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Amortizable Intangible Assets at December 31, 2007 (in thousands):
Customer Relationships	$	23,812
Non-Compete Agreements		5,243
Accumulated Amortization Non-Compete Agreements		(2,080	)
Total Amortizable Intangible Assets	$	26,975

     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, 2007 is $26.8 million, $43.3 million, $111.5 million and $23.4 million, respectively. The change in the carrying amount of goodwill for the year ended December 31, 2007 of $103.4 million relates to goodwill from acquisitions and payments pursuant to contingent earn-out agreements, with approximately $4.7 million, $1.3 million, $74.0 million and $23.4 million of goodwill additions relating to the well servicing, fluid services, completion and remedial and contract drilling units, respectively. Other intangibles net of accumulated amortization allocated to reporting units as of December 31, 2007 is $258,000, $710,000, $19.7 million and $6.3 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 differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in the period that includes the statutory enactment date. A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized.

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   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 2007, 2006, or 2005.

   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.

     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, 2007 and 2006 (in thousands):

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Balance, December 31, 2005	$	569
Additional asset retirement obligations recognized through acquisitions		289
Accretion expense		78
Settlements		(78	)
Increase in asset retirement obligations due to change in estimate		479
Balance, December 31, 2006	$	1,336
Additional asset retirement obligations recognized through acquisitions		101
Accretion expense		115
Settlements		—
Increase in asset retirement obligations due to change in estimate		—
Balance, December 31, 2007	$	1,552

   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 June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation No. 48 (FIN 48), Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109, Accounting for Income Taxes. The interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken, in a tax return. Our adoption in January 2007 of FIN 48 did not result in any change to retained earnings or any additional unrecognized tax benefit. Interest will be recorded in interest expense and penalties will be recorded in income tax expense. We had no interest or penalties related to an uncertain tax position during 2007. The company files federal income tax returns and state income tax returns in Texas and other state tax jurisdictions. In general, the company’s tax returns for fiscal years after 2002 currently remain subject to examination by appropriate taxing authorities. None of the company’s income tax returns are under examination at this time.

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     In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS 157), which will become 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 No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS 159), which becomes 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. The company does not anticipate that the adoption of SFAS 159 will have a material effect on its results of operations or consolidated financial position.

     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.

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3.  Acquisitions

     In 2007, 2006 and 2005, 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)
R & R Hot Oil Service	January 5, 2005	$	1,702
Premier Vacuum Service, Inc.	January 28, 2005		1,009
Spencer’s Coating Specialist	February 9, 2005		619
Mark’s Well Service	February 25, 2005		579
Max-Line, Inc.	April 28, 2005		1,498
MD Well Service, Inc.	May 17, 2005		4,478
179 Disposal, Inc.	August 4, 2005		1,729
Oilwell Fracturing Services, Inc.	October 11, 2005		13,764
Total 2005		$	25,378
LeBus Oil Field Services Co.	January 31, 2006	$	24,618
G&L Tool, Ltd.	February 28, 2006		58,514
Arkla Cementing, Inc.	March 27, 2006		5,012
Globe Well Service, Inc.	May 30, 2006		11,674
Hydro-Static Tubing Testers, Inc.	July 6, 2006		1,143
Hennessey Rental Tools, Inc.	August 1, 2006		8,205
Stimulation Services, LLC	August 1, 2006		4,500
Chaparral Service, Inc.	August 15, 2006		17,605
Reddline Services, LLC	August 24, 2006		1,900
Rebel Testers, Ltd.	September 14, 2006		2,397
Total 2006		$	135,568
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		86,314
Sledge Drilling Holding Corp.	April 2, 2007		50,655
Eagle Frac Tank Rentals, LP	May 30, 2007		3,813
Wildhorse Services, Inc.	June 1, 2007		17,315
Bilco Machine, Inc.	June 21, 2007		600
Steve Carter Inc. and Hughes Services Inc.	September 26, 2007		18,049
Total 2007		$	201,504

     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 and JetStar Consolidated Holdings, Inc. and Sledge Drilling Holding Corp. in 2007 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

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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 purchase price will be adjusted and finalized when the Company completes its analysis of identifiable intangible assets. The following table summarizes the preliminary estimated fair value of the assets acquired and liabilities assumed at the date of acquisition for JetStar (in thousands):

Current Assets	$	13,356
Property and Equipment		60,407
Amortizable Intangible Assets(1)		17,857
Goodwill(2)		58,917
Total Assets Acquired		150,537
Current Liabilities		(3,881	)
Deferred Income Taxes		(18,979	)
Current and Long Term Debt(3)		(37,563	)
Total Liabilities Assumed		(60,423	)
Net Assets Acquired	$	90,114

(1)	Consists of Customer Relationship of $17,543, amortizable over 15 years, and Non-Compete Agreements of $314, amortizable over 5 years.
(2)	Approximately $22,491 is expected to be deductible for tax purposes
(3)	Total balance was paid by Basic on the closing date

   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 purchase price will be adjusted and finalized when Basic receives an appraisal of fair value of property and equipment received and completes its analysis of identifiable intangible assets. The following table summarizes the preliminary estimated fair value of the assets acquired and liabilities assumed at the date of acquisition for Sledge (in thousands):

Current Assets	$	6,029
Property and Equipment		30,638
Intangible Assets(1)		6,365
Goodwill(2)		23,405
Total Assets Acquired		66,437
Current Liabilities		(587	)
Deferred Income Taxes		(3,886	)
Current and Long Term Debt(3)		(19,093	)
Total Liabilities Assumed		(23,566	)
Net Assets Acquired	$	42,871

(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

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     Revisions to the fair values, which may be significant, will be recorded by the Company as further adjustments to the purchase price allocations.

     The following unaudited pro-forma results of operations have been prepared as though the JetStar, Sledge, and G&L acquisitions had been completed on January 1, 2006. 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,
	2007		2006
Revenues	$	899,732	$	831,433
Net income	$	91,640	$	110,124
Earnings per common share — basic	$	2.27	$	3.00
Earnings per common share — diluted	$	2.21	$	2.70

     Basic does not believe the pro-forma effect of the remainder of the acquisitions completed in 2005, 2006 or 2007 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, 2007 (in thousands):

		Maximum
		exposure of
	Termination date of	contingent		Amount paid or
	contingent earn-out	earn-out		accrued through
Acquisition	arrangement	arrangement		December 31, 2007
New Force Energy Services	January 27, 2008	$	2,700	$	2,700
Rolling Plains	April 30, 2009		*		5,377
Premier Vacuum Services, Inc.	February 1, 2010		900		754
Chaparral Services, Inc.	August 31, 2011		1,000		100
G&L Tool, Ltd.	February 28, 2011		21,000		7,817
		$	25,600	$	16,748

* 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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4.  Property and Equipment

     Property and equipment consists of the following (in thousands):

	December 31,		December 31,
	2007		2006
Land	$	3,475	$	2,913
Buildings and improvements		21,655		13,293
Well service units and equipment		328,468		264,034
Fluid services equipment		91,830		87,139
Brine and fresh water stations		8,964		8,710
Frac/test tanks		85,649		49,582
Pressure pumping equipment		132,746		67,540
Construction equipment		28,798		27,342
Contract drilling equipment		59,231		19,050
Disposal facilities		27,790		25,913
Vehicles		36,440		32,215
Rental equipment		33,381		32,548
Aircraft		4,119		4,119
Other		15,858		8,807
		878,404		643,205
Less accumulated depreciation and amortization		241,480		167,774
Property and equipment, net	$	636,924	$	475,431

     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,
	2007		2006
Light vehicles	$	25,768	$	23,843
Well service units and equipment		1,016		808
Fluid services equipment		34,668		26,460
Pressure pumping equipment		4,540		1,820
Construction equipment		4,440		3,559
Software		6,308		—
		76,740		56,490
Less accumulated amortization		22,660		13,785
	$	54,080	$	42,705

     Amortization of assets held under capital leases of approximately $8.9 million, $5.3 million, and $1.3 million for the years ended December 31, 2007, 2006, and 2005, respectively, is included in depreciation and amortization expense in the consolidated statements of operations.

5.  Long-Term Debt

     Long-term debt consists of the following (in thousands):

	December 31,		December 31,
	2007		2006
Credit Facilities:
Revolver	$	150,000	$	—
7.125% Senior Notes		225,000		225,000
Capital leases and other notes		48,719		37,743
		423,719		262,743
Less current portion		17,413		12,001
	$	406,306	$	250,742

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   Senior Notes

     On April 12, 2006, the Company issued $225.0 million of 7.125% Senior Notes due April 2016 in a private placement. Proceeds from the sale of the Senior Notes were used to retire the outstanding balance on the $90.0 million Term B Loan and to pay down approximately $96.0 million under the revolving credit facility, which amounts may be reborrowed to fund future acquisitions or for general corporate purposes. Interest payments on the Senior Notes are due semi-annually, on April 15 and October 15, commencing on October 15, 2006. The Senior Notes are unsecured. Under the terms of the sale of the Senior Notes, the Company was required to take appropriate steps to offer to exchange other Senior Notes with the same terms that have been registered with the Securities and Exchange Commission for the private placement Senior Notes. The Company completed the exchange offer for all of the Senior Notes on October 16, 2006.

     The Senior Notes are redeemable at the option of the Company on or after April 15, 2011 at the specified redemption price as described in the Indenture. Prior to April 15, 2011, the Company may redeem, in whole or in part, at a redemption price equal to 100% of the principal amount of the Senior Notes redeemed plus the Applicable Premium as defined in the Indenture. Prior to April 15, 2009, the Company may redeem up to 35% of the Senior Notes with the proceeds of certain equity offerings at a redemption price equal to 107.125% of the principal amount of the 7.125% Senior Notes, plus accrued and unpaid interest to the date of redemption. This redemption must occur less than 90 days after the date of the closing of any such equity offering.

     Following a change of control, as defined in the Indenture, the Company will be required to make an offer to repurchase all or any portion of the 7.125% Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest to the date of repurchase.

     Pursuant to the Indenture, the Company is subject to covenants that limit the ability of the Company and its restricted subsidiaries to, among other things: incur additional indebtedness, pay dividends or repurchase or redeem capital stock, make certain investments, incur liens, enter into certain types of transactions with affiliates, limit dividends or other payments by restricted subsidiaries, and sell assets or consolidate or merge with or into other companies. These limitations are subject to a number of important qualifications and exceptions set forth in the Indenture. The Company was in compliance with the restrictive covenants at December 31, 2007.

     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.

   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 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 at any time. Additionally, the 2007 Credit Facility permits us to make greater expenditures for acquisitions, capital expenditures and capital leases and to incur greater purchase money obligations, acquisition indebtedness and general unsecured indebtedness. The commitment under the Revolver provides for (1) the borrowing of funds, (2) the issuance of up to $30 million of letters of credit and (3) $2.5 million of swing-line loans. All of the outstanding amounts under the Revolver are due and payable on December 15, 2010. The 2007 Credit Facility is secured by substantially all of our tangible and intangible assets. 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

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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, 2007, Basic, under its Revolver, had outstanding $150 million of borrowings and $15.5 million of letters of credit and no amounts outstanding in swing-line loans. At December 31, 2007, Basic had availability under its Revolver of $59.5 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, 2007, 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.

     As of December 31, 2007 the aggregate maturities of debt, including capital leases, for the next five years and thereafter are as follows (in thousands):

	Debt		Capital Leases
2008	$	—	$	17,413
2009		—		15,115
2010		150,000		11,119
2011		—		4,140
2012		—		732
Thereafter		225,000		200
	$	375,000	$	48,719

Basic’s interest expense consisted of the following (in thousands):

	Years Ended December 31,
	2007		2006		2005
Cash payments for interest	$	25,594	$	12,587	$	11,421
Commitment and other fees paid		249		566		185
Amortization of debt issuance costs		962		805		1,062
Accrued interest		540		3,384		—
Other		71		124		397
	$	27,416	$	17,466	$	13,065

   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

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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.

     In 2005, Basic recognized a loss on the early extinguishment of debt. Basic wrote-off unamortized debt issuance costs of approximately $0.6 million.

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6.  Income Taxes

     Income tax expense consists of the following (in thousands):

	Years Ended December 31,
	2007		2006			2005
Current:
Federal	$	33,157	$	50,499		$	8,048
State		5,160		1,632			451
Total	$	38,317	$	52,131		$	8,499
Deferred:
Federal	$	14,207	$	3,594		$	17,335
State		242		(983	)		966
Total	$	14,449	$	2,611		$	18,301

     Basic paid Federal income taxes of $44.1 million during 2007, $40.2 million during 2006 and $1.3 million during 2005.

     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,
	2007			2006			2005
Statutory federal income tax	$	49,174		$	53,750		$	25,053
Meals and entertainment		532			430			324
State taxes, net of federal benefit		4,062			778			1,415
Changes in estimates and other		(1,002	)		(216	)		8
	$	52,766		$	54,742		$	26,800

     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,
	2007			2006
Deferred tax assets:
Receivables allowance	$	2,314		$	1,461
Inventory		41			—
Asset retirement obligation		283			234
Accrued liabilities		8,044			6,659
Operating loss carryforward		1,100			1,412
Deferred Compensation		2,648			1,790
Total deferred tax assets		14,430			11,556
Deferred tax liabilities:
Property and equipment		(104,476	)		(73,926	)
Goodwill and intangibles		(13,846	)		(2,611	)
Prepaid expenses		(119	)		—
Total deferred tax liabilities		(118,441	)		(76,537	)
Net deferred tax liability		(104,011	)		(64,981	)
Recognized as:
Deferred tax assets — current		10,593			8,432
Deferred tax liabilities — non-current		(114,604	)		(73,413	)
Net deferred tax liability	$	(104,011	)	$	(64,981	)

     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, 2007 or 2006.

     As of December 31, 2007, Basic had approximately $3.1 million of net operating loss carryforwards (“NOL”) for U.S. federal income tax purposes related to the preacquisition period of FESCO, which are subject to an annual limitation of approximately $900,000. The carryforwards begin to expire in 2017.

     See adoption of FIN 48 in note 2.

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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, 2006, the future minimum lease payments under non-cancelable operating leases are as follows (in thousands):

Year Ended December 31,
2008	$	3,450
2009		3,175
2010		3,027
2011		2,656
2012		1,885
Thereafter		4,122

     Rent expense approximated $17.4 million, $13.9 million, and $7.0 million for 2007, 2006 and 2005, respectively.

     Basic leases rights for the use of various brine and fresh water wells and disposal wells ranging in terms from month-to-month up to 99 years. The above table reflects the future minimum lease payments if the lease contains a periodic rental. However, the majority of these leases require payments based on a royalty percentage or a volume usage.

   Employment Agreements

     Under the employment agreement with Mr. Huseman, Chief Executive Officer and president of Basic, effective December 31, 2006 through December 31, 2009, amended January 23, 2007, Mr. Huseman will be entitled to an annual salary of $525,000. 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

24

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 2008. 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 $250,000 and $175,000, respectively. Basic has lower deductibles per occurrence for automobile liability and general liability. Basic maintains accruals in the accompanying consolidated balance sheets related to self-insurance retentions by using third-party data and claims history.

     At December 31, 2007 and December 31, 2006, self-insured risk accruals totaled approximately $15.1 million, net of $0 receivable for medical and dental coverage, and $12.6 million, net of $652,000 receivable for medical and dental coverage, respectively.

8.  Stockholders’ Equity

   Common Stock

     In February 2002, a group of related investors purchased a total of 3,000,000 shares of Basic’s common stock at a purchase price of $4 per share, for a total purchase price of $12 million. As part of the purchase, 600,000 common stock warrants were issued in connection with this transaction, the fair value of which was approximately $1.2 million (calculated using an option valuation model). The warrants 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 $1.2 million, $1.3 million and $1.6 million for the years ended December 31, 2007, 2006 and 2005.

     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.

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     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.

     During the year ended 2007, Basic issued 22,800 shares of common stock from treasury stock for the exercise of stock options. Also, Basic issued 169,875 shares of newly-issued common stock for the exercise of stock options.

   Preferred Stock

     At December 31, 2007 and 2006, Basic had 5,000,000 shares of $.01 par value preferred stock authorized, of which none is designated.

9.  Stockholders’ Agreement

     Basic has a Stockholders’ Agreement, as amended on April 2, 2004 (“Stockholders’ Agreement”), which provides for rights relating to the shares of our stockholders and certain corporate governance matters.

     The Stockholders’ Agreement provides for participation rights of the other stockholders to require affiliates of DLJ Merchant Banking to offer to include a specified percentage of their shares whenever affiliates of DLJ Merchant Banking sell their shares for value, other than a public offering or a sale in which all of the parties to the Stockholders’ Agreement agree to participate. The Stockholders’ Agreement also contains “drag-along” rights. The “drag-along” rights entitle the affiliated of DLJ Merchant Banking to require the other stockholders who are a party to this agreement to sell a portion of their shares of common stock and common stock equivalents in the sale in any proposed to sale of shares of common stock and common stock equivalents representing more than 50% of such equity interest held by the affiliates of DLJ Merchant Banking to a person or persons who are not an affiliate of them.

     The Stockholders’ Agreement currently provides for demand and piggyback registration rights following the completion of our 2005 initial public offering of Basic’s common stock.

10.  Incentive Plan

     In May 2003, Basic’s board of directors and stockholders approved the Basic 2003 Incentive Plan (as amended effective April 22, 2005) (the “Plan”), which provides for granting of incentive awards in the form of stock options, restricted stock, performance awards, bonus shares, phantom shares, cash awards and other stock-based awards to officers, employees, directors and consultants of Basic. The Plan assumed awards of the plans of Basic’s successors that were awarded and remained outstanding prior to adoption of the Plan. The Plan provides for the issuance of 5,000,000 shares. Of these shares, approximately 2.2 million shares are available for grant as of December 31, 2007. 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

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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.

     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 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, 2007, 2006 and 2005, compensation expense related to share-based arrangements was approximately $3.9 million, $3.4 million and $2.9 million , respectively. For compensation expense recognized during the years ended December 31, 2007, 2006 and 2005 Basic recognized a tax benefit of approximately $1.5 million, $1.2 million and $1.1 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			2005
Risk-free interest rate		4.5	%		4.7	%		4.2% - 4.5	%
Expected term		6.65			6.65			6.00 - 10.00
Expected volatility		45.3	%		47.0	%		0.0	%
Expected dividend yield		—			—			—

     Options granted under the Plan expire 10 years from the date they are granted, and generally vest over a three-to-five year service period.

     The following table reflects the summary of stock options outstanding at December 31, 2007 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		2,457,780		$	9.05
Options granted		92,000		$	22.66
Options forfeited		(99,750	)	$	17.13
Options exercised		(192,675	)	$	5.15
Options expired		—		$	—
Outstanding, end of period		2,257,355		$	9.58		6.29	$	29,707
Exercisable, end of period		1,244,522		$	4.85		5.13	$	21,277
Vested or expected to vest, end of period		2,252,755		$	9.55		6.28	$	29,707

     The weighted-average grant date fair value of share options granted during the years ended December 31, 2007, 2006 and 2005 was $11.85, $14.47 and $8.00, respectively. The total intrinsic value of share options exercised during the years ended December 31, 2007, 2006 and 2005 was approximately $3.6 million, $7.1 million and $0, respectively.

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     A summary of the status of the Company’s non-vested share grants at December 31, 2007 and changes during the year ended December 31, 2007 is presented in the following table:

				Weighted Average
	Number of			Grant Date Fair
Nonvested Shares	Shares			Value per Share
Nonvested at beginning of period		361,250		$	6.98
Granted during period		229,100			22.70
Vested during period		(180,625	)		6.98
Forfeited during period		(31,725	)		16.17
Nonvested at end of period		378,000		$	15.74

     As of December 31, 2007, there was $9.4 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 2.43 years. The total fair value of share-based awards vested during the years ended December 31, 2007, 2006 and 2005 was approximately $11.3 million, $12.3 million and $5.3 million, respectively. The actual tax benefit realized for the tax deduction from vested share-based awards was $1.6 million, $2.1 million and $0, respectively for the years ended December 31, 2007, 2006 and 2005.

     Cash received from share option exercises under the incentive plan was approximately $975,000, $674,000 and $0 for the years ended December 31, 2007, 2006 and 2005, respectively. The actual tax benefit realized for the tax deductions from options exercised was $1.4 million, $4.0 million and $0, respectively, for the years ended December 31, 2007, 2006 and 2005.

     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 $91,000 and $94,000 as of December 31, 2007 and December 31, 2006, respectively. During 2006, Basic entered into a lease agreement with Darle Vuelta Cattle Co., LLC, an affiliate of the Chief Executive Officer, for approximately $69,000. The term of the lease is five years and will continue on a year-to-year basis unless terminated by either party.

12.  Profit Sharing Plan

     Basic has a 401(k) profit sharing plan that covers substantially all employees with more than 90 days of service. Employees may contribute up to their base salary not to exceed the annual Federal maximum allowed for such plans. Basic makes a matching contribution proportional to each employee’s contribution. Employee contributions are fully vested at all times. Employer matching contributions vest incrementally, with full vesting occurring after five years of service. Employer contributions to the 401(k) plan approximated $3.0 million, $2.5 million, and $0.5 million in 2007, 2006 and 2005, respectively.

13.  Deferred Compensation Plan

     In April 2005, Basic established a deferred compensation plan for certain employees. Participants may defer up to 50% of their salary and 100% of any cash bonuses. Basic makes matching contributions of 100% of the first 3% of the participants’ deferred pay and 50% of the next 2% of the participants’ deferred pay to a maximum match of $8,800 per year. Employer matching contributions and earnings thereon are subject to a five-year vesting schedule with full vesting occurring after five years of service. Employer contributions to the deferred compensation plan approximated $216,000, $199,000, and $56,000 in 2007, 2006 and 2005, respectively.

14.  Earnings Per Share

     Basic presents earnings per share information in accordance with the provisions of Statement of Financial Accounting Standards No. 128, “Earnings per Share” (“SFAS No. 128”). Under SFAS No. 128, basic earnings per common share are determined by dividing net earnings applicable to common stock by the weighted average

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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,
	2007		2006		2005
Numerator (both basic and diluted):
Net income available to common stockholders	$	87,733	$	98,830	$	44,781
Denominator:
Denominator for basic earnings per share		40,013,054		34,471,771		28,580,911
Stock options		831,026		1,054,040		789,991
Unvested restricted stock		268,324		244,153		638,442
Common stock warrants		—		2,823,029		3,159,035
Denominator for diluted earnings per share		41,112,404		38,592,993		33,168,379
Basic earnings per common share:
Net income available to common stockholders	$	2.19	$	2.87	$	1.57
Diluted earnings per common share:
Net income available to common stockholders	$	2.13	$	2.56	$	1.35

     The number of antidilutive shares at December 31, 2007, 2006 and 2005 was 442,000, 401,000 and 37,500, respectively.

15.  Business Segment Information

     Basic revised its reportable business segments beginning in the first quarter of 2008. 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 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.

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     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, 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
Year ended December 31, 2005
Operating revenues	$	221,993		$	177,927		$	59,832		$	—		$	—	$	459,752
Direct operating costs		(137,392	)		(114,551	)		(30,900	)		—			—		(282,843	)
Segment profits	$	84,601		$	63,376		$	28,932		$	—		$	—	$	176,909
Depreciation and amortization	$	18,671		$	12,223		$	3,644		$	—		$	2,534	$	37,072
Capital expenditures, (excluding acquisitions)	$	42,838		$	28,045		$	8,361		$	—		$	3,851	$	83,095
Identifiable assets	$	169,487		$	129,335		$	45,850		$	—		$	152,621	$	497,293

	Year Ended December 31,
	2007			2006			2005
Segment profits	$	358,256		$	315,294		$	176,909
General and administrative expenses		(99,042	)		(81,318	)		(55,411	)
Depreciation and amortization		(93,048	)		(62,087	)		(37,072	)
Gain (loss) on disposal of assets		(477	)		(277	)		222
Operating income	$	165,689		$	171,612		$	84,648

     The following table reconciles the segment profits reported above to the operating income as reported in the consolidated statements of operations (in thousands):

16.  Accrued Expenses

     The accrued expenses are as follows (in thousands):

	December 31,
	2007		2006
Compensation related	$	16,790	$	14,006
Workers’ compensation self-insured risk reserve		9,326		8,497
Health self-insured risk reserve		6,054		5,289
Accrual for receipts		3,955		3,608
Authority for expenditure accrual		211		1,325
Ad valorem taxes		73		106
Sales tax		1,140		1,886
Insurance obligations		995		489
Purchase order accrual		45		41
Professional fee accrual		424		216
Acquired contingent earnout obligation		1,158		2,189
Retainers		172		181
Fuel accrual		1,692		460
Accrued interest		3,926		3,620
Contingent liability		1,296		—
Franchise Tax Payable		3,704		1,789
Other		42		17
	$	51,003	$	43,719

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17.  Supplemental Schedule of Cash Flow Information

     The following table reflects non-cash financing and investing activity during:

	Year Ended December 31,
	2007		2006		2005
	(In thousands)
Capital leases issued for equipment	$	26,814	$	26,420	$	10,334
Value of shares that may be issued	$	2,194	$	—	$	—
Contingent earnout accrual	$	1,032	$	2,256	$	—
Asset retirement obligation additions	$	101	$	767	$	74
Value of common stock issued in business combinations	$	51,193	$	—	$	—

     Basic paid income taxes of approximately $44.1 million, $43.2 million and $1.3 million during the years ended December 31, 2007, 2006 and 2005, respectively.

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18.  Quarterly Financial Data (Unaudited)

     The following table summarizes results for each of the four quarters in the years ended December 31, 2007 and 2006:

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Year
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 (loss) 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
Year ended December 31, 2006:
Total revenues	$	154,306	$	183,833	$	194,555	$	197,454	$	730,148
Segment profits	$	64,894	$	80,969	$	84,989	$	84,442	$	315,294
Income from continuing operations	$	19,681	$	24,487	$	27,328	$	27,334	$	98,830
Net income available to common stockholders	$	19,681	$	24,487	$	27,328	$	27,334	$	98,830
Basic earnings per share of common stock(a):
Continuing operations	$	0.59	$	0.73	$	0.81	$	0.73	$	2.87
Net income available to common stockholders	$	0.59	$	0.73	$	0.81	$	0.73	$	2.87
Diluted earnings per share of common stock(a):
Continuing operations	$	0.53	$	0.64	$	0.71	$	0.70	$	2.56
Net income available to common stockholders	$	0.53	$	0.64	$	0.71	$	0.70	$	2.56
Weighted average common shares outstanding:
Basic		33,262		33,434		33,537		37,669		34,472
Diluted		36,902		38,526		38,442		39,116		38,593

(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 January 28, 2008, Basic acquired all of the outstanding capital stock of Xterra Fishing and Rental Tools Co. for a total acquisition price of $19.0 million cash, excluding working capital acquired. This acquisition will operate in Basic’s completion and remedial line of business.

     On January 30, 2008, Basic acquired substantially all of the operating assets of Lackey Construction L.L.C. for total consideration of $4.3 million cash. This acquisition will operate in Basic’s well servicing line of business.

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     On April 21, 2008, the Company announced that the Board of Directors had approved a definitive agreement to combine with Grey Wolf, Inc. in a “merger of equals.” The combined company will be named Grey Wolf, Inc., establish incorporation in the state of Delaware and trade on the New York Stock Exchange under the symbol “GW.” Terms of the agreement give shareholders of the Company 0.9195 shares of the new company and $6.70 in cash for every share owned. Shareholders of Grey Wolf will receive 0.25 shares of the new company and $1.82 in cash for each share owned.

     The transaction is expected to close in the third quarter of 2008. Completion of the transaction is subject to shareholder approval of both the Company and Grey Wolf, Inc., receipt of financing proceeds, regulatory approvals and other customary conditions.

     On April 30, 2008, the Company purchased all assets of B&S Disposal, LLC and B&S Equipment, Ltd. for total consideration of approximately $6.7 million, including capital expenditure reimbursement. The new assets will operate in the Company’s Well Servicing and Fluid Services lines of business in the Mid-Continent area.

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