Basic Energy Services (BASWQ) 424B3 Prospectus supplement

Filed pursuant to Rule 424(b)(3)

Registration No. 333-135807

Basic Energy Services, Inc.

Offer to Exchange Up to

$225,000,000 of 7.125% Senior Notes Due 2016

that have been registered under the Securities Act of 1933

for

$225,000,000 of 7.125% Senior Notes Due 2016

that have not been registered under the Securities Act of 1933

THE EXCHANGE OFFER WILL EXPIRE AT 5:00 PM, NEW YORK

CITY TIME, ON OCTOBER 12, 2006, UNLESS WE EXTEND THE DATE

      Terms of the Exchange Offer:

• We are offering to exchange up to $225.0 million aggregate principal amount of registered 7.125% Senior Notes due 2016, which we refer to as the new notes, for any and all of our $225.0 million aggregate principal amount of unregistered 7.125% Senior Notes due 2016, which we refer to as the old notes, that were issued on April 12, 2006.

• We will exchange all outstanding old notes that are validly tendered and not validly withdrawn prior to the expiration of the exchange offer for an equal principal amount of new notes.

• The terms of the new notes are substantially identical to those of the outstanding old notes, except that the transfer restrictions and registration rights relating to the old notes do not apply to the new notes.

• You may withdraw tenders of old notes at any time prior to the expiration of the exchange offer.

• The exchange of new notes for old notes will not be a taxable transaction for U.S. federal income tax purposes.

• We will not receive any cash proceeds from the exchange offer.

• The old notes are, and the new notes will be, guaranteed on a senior unsecured basis by all of our current and certain future domestic restricted subsidiaries, other than certain immaterial subsidiaries.

• There is no established trading market for the new notes or the old notes.

• We do not intend to apply for listing of the new notes on any national securities exchange or for quotation through any quotation system.

      See “Risk Factors” beginning on page 18 for a discussion of certain risks that you should consider prior to tendering your outstanding old notes in the exchange offer.

     Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

      Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the consummation of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any such resale. Please read “Plan of Distribution.”

Prospectus dated September 11, 2006

TABLE OF CONTENTS

	Page
Prospectus Summary		1
Risk Factors		18
Forward-Looking Statements and Industry Data		29
Ratio of Earnings to Fixed Charges		30
Use of Proceeds		30
Capitalization		31
Selected Historical Financial Data		32
Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
Business		60
Management		77
Certain Relationships and Related Party Transactions		89
Principal Stockholders		91
Description of Certain Other Indebtedness		94
The Exchange Offer		96
Description of the New Notes		107
Global Securities; Book-entry System		151
Material United States Federal Income Tax Considerations		154
Plan of Distribution		155
Legal Matters		156
Experts		156
Where You Can Find More Information		156
Index to Consolidated Financial Statements		F-1
Appendix A — Glossary of Terms		A-1

      This prospectus is part of a registration statement we filed with the Securities and Exchange Commission, referred to in this prospectus as the SEC. In making your decision to participate in the exchange offer, you should rely only on the information contained in this prospectus and in the accompanying letter of transmittal. We have not authorized anyone to provide you with any other information. If you received any unauthorized information, you must not rely on it. We are not making an offer to sell these securities in any state or jurisdiction where the offer is not permitted. You should not assume that the information contained in this prospectus, or the documents incorporated by reference into this prospectus, is accurate as of any date other than the date on the front cover of this prospectus or the date of such document incorporated by reference, as the case may be.

     THIS PROSPECTUS INCORPORATES IMPORTANT BUSINESS AND FINANCIAL INFORMATION ABOUT OUR COMPANY THAT HAS NOT BEEN INCLUDED IN OR DELIVERED WITH THIS PROSPECTUS. WE WILL PROVIDE WITHOUT CHARGE TO EACH PERSON TO WHOM THIS PROSPECTUS IS DELIVERED, UPON WRITTEN OR ORAL REQUEST, A COPY OF ANY SUCH INFORMATION. REQUESTS FOR SUCH COPIES SHOULD BE DIRECTED TO: CHIEF FINANCIAL OFFICER, BASIC ENERGY SERVICES, INC., 400 W. ILLINOIS, SUITE 800, MIDLAND, TEXAS 79701; TELEPHONE NUMBER: (432) 620 5500. TO OBTAIN TIMELY DELIVERY, YOU SHOULD REQUEST THE DOCUMENTS AND INFORMATION NO LATER THAN OCTOBER 11, 2006.

      In this prospectus, we use the terms “Basic Energy Services,” “we,” “us” and “our” to refer to Basic Energy Services, Inc. together with its subsidiaries unless the context otherwise requires.

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PROSPECTUS SUMMARY

     This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the risks discussed in the “Risk Factors” section, the historical consolidated financial statements and notes to those financial statements. This summary may not contain all of the information that investors should consider before making a decision to participate in the exchange offer. If you are not familiar with some of the oil and gas industry terms used in this prospectus, please read our Glossary of Terms included as Appendix A to this prospectus.

Our Company

      We provide a wide range of well site services to oil and gas drilling and producing companies, including well servicing, fluid services, drilling and completion services and well site construction services. These services are fundamental to establishing and maintaining the flow of oil and gas throughout the productive life of a well. Our broad range of services enables us to meet multiple needs of our customers at the well site. Our operations are managed regionally and are concentrated in the major United States onshore oil and gas producing regions in Texas, New Mexico, Oklahoma and Louisiana and the Rocky Mountain states. We provide our services to a diverse group of over 1,000 oil and gas companies. We operate the third-largest fleet of well servicing rigs (also commonly referred to as workover rigs) in the United States, representing approximately 13% of the overall available U.S. fleet. Our two larger competitors control approximately 32% and 18%, respectively, as of June 2006, according to the Association of Energy Services Companies and other publicly available data. We have expanded our asset base from $53.0 million of total assets as of December 31, 2000 to $497.0 million of total assets as of December 31, 2005 and increased our revenues from $56.5 million in 2000 to $459.8 million in 2005.

      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 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 increase spending for drilling new wells and well servicing activities related to maintaining or increasing production from existing wells. The utilization rate for our fleet of well servicing rigs increased from approximately 71% in 2003 to 78% in 2004, 87% in 2005, and 90% in the first six months of 2006. Because our services are required to support drilling and workover activities, we are also subject to changes in capital spending by our customers as oil and gas prices increase or decrease.

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

•   Well Servicing. Our well servicing segment (48% of our revenues in 2005 and 46% of our revenues in the first six months of 2006) operates our fleet of over 340 well servicing rigs and related equipment. This business segment encompasses a full range of services performed with a mobile well servicing rig, including the installation and removal of downhole equipment and elimination of obstructions in the well bore to facilitate the flow of oil and gas. These services are performed to establish, maintain and improve production throughout the productive life of an oil and gas well and to plug and abandon a well at the end of its productive life. Our well servicing equipment and capabilities are essential to facilitate most other services performed on a well.

•   Fluid Services. Our fluid services segment (29% of our revenues in 2005 and 27% of our revenues in the first six months quarter of 2006) utilizes our fleet of over 590 fluid services trucks and related assets, including specialized tank trucks, storage tanks, water wells, disposal facilities and related equipment. These assets provide, transport, store and dispose of a variety of fluids. These services are required in most workover, drilling and completion projects and are routinely used in daily producing well operations.

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•   Drilling and Completion Services. Our drilling and completion services segment (13% of our revenues in 2005 and 20% of our revenues in the first six months of 2006) operates our fleet of 74 pressure pumping units, 31 air compressor packages specially configured for underbalanced drilling operations and 10 cased-hole wireline units. These services are designed to initiate or stimulate oil and gas production. The largest portion of this business consists of pressure pumping services focused on cementing, acidizing and fracturing services in niche markets. We also entered the fishing and rental tool business through an acquisition in the first quarter of 2006.

•   Well Site Construction Services. Our well site construction services segment (10% of our revenues in 2005 and 7% of our revenues in the first six months of 2006) utilizes our fleet of over 200 operated power units, which include dozers, trenchers, motor graders, backhoes and other heavy equipment. We utilize these assets primarily to provide services for the construction and maintenance of oil and gas production infrastructure, such as preparing and maintaining access roads and well locations, installation of small diameter gathering lines and pipelines and construction of temporary foundations to support drilling rigs.

      Our industry historically has consisted of a large number of small companies, several regional contractors and a few large national companies. Over the last decade, our industry has consolidated, including the consolidation of the well servicing segment of our industry, from nine large competitors (with 50 or more well servicing rigs) to four. However, the industry still remains fragmented with an estimated 120 companies owning approximately 900 remaining well servicing rigs, or approximately 26% of the industry’s total fleet. We have led recent consolidation of this industry by acquiring regional businesses and assets in 41 separate acquisitions from the beginning of 2001 through June 30, 2006. We plan to continue participating in the consolidation of our industry by selectively acquiring additional businesses and assets that complement and expand our existing service offerings and geographic footprint and offer attractive projected rates of return on capital employed. However, we cannot assure you that we can complete such acquisitions.

General Industry Overview

      Demand for services offered by our industry is a function of our customers’ willingness to make operating and capital expenditures to explore for, develop and produce hydrocarbons in the U.S., which in turn is affected by current and expected levels of oil and gas prices. The following industry statistics illustrate the growing spending dynamic in the U.S. oil and gas sector (including the offshore sector that we do not serve):

• With the rebound in oil and gas prices in early 1999, oil and gas companies have increased their drilling and workover activities. The increased activity resulted in increased exploration and production spending compared to the prior year of 16% and 30% in 2004 and 2005, respectively, and is expected to increase 16% in 2006, according to www.WorldOil.com.

• A survey of 18 U.S. major integrated and 130 independent oil and gas companies by World Oil Magazine projected the U.S. drilling activity in 2006 to be skewed more towards independent players. Specifically, independent oil and gas companies, which represent over 90% of our revenues, are expected to drill 27% more wells in 2006 than in 2005, while the major integrated producers are expected to drill only 16% more wells over the same period. This trend is primarily driven by the increased acquisitions of proved oil and gas properties by independent producers. When these types of properties are acquired, purchasers typically intensify drilling, workover and well maintenance activities to accelerate production from the newly acquired reserves.

      Increased expenditures for exploration and production activities generally involve the deployment of more drilling and well servicing rigs, which often serves as an indicator of demand for our services. Rising oil and gas prices since early 1999 and the corresponding increase in onshore oil exploration

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and production spending have led to expanded drilling and well service activity, as the U.S. land-based drilling rig count increased approximately 36% from year-end 2002 to year-end 2003, 11% from year-end 2003 to year-end 2004, 22% from year-end 2004 to year-end 2005 and 9% during the first six months of 2006, according to Baker Hughes. In addition, the U.S. land-based workover rig count increased approximately 13% from year-end 2002 to year-end 2003, 10% from year-end 2003 to year-end 2004, 17% from year-end 2004 to year-end 2005 and 9% during the first six months of 2006, according to Baker Hughes.

      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.

Competitive Strengths

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

•   Significant Market Position. We maintain a significant market share for our well servicing operations in our core operating areas throughout Texas and a growing market share in the other markets that we serve. Our fleet of over 340 well servicing rigs represents the third-largest fleet in the United States, and our goal is to be one of the top two providers of well site services in each of our core operating areas. Our market position allows us to expand the range of services performed on a well throughout its life, such as completion, maintenance, workover and plugging and abandonment services.

•   Modern and Active Fleet. We operate a modern and active fleet of well servicing rigs. We believe over 95% of the active US well servicing rig fleet was built prior to 1985. Approximately 112, or 32%, of our rigs at June 30, 2006 were either 2000 model year or newer, or have undergone major refurbishments during the last four years. Since October 2004, we have taken delivery of 54 newbuild well servicing rigs through June 30, 2006 as part of a 102-rig newbuild commitment, driven by our desire to maintain one of the most efficient, reliable and safest fleets in the industry. The remainder of these newbuilds is scheduled to be delivered to us prior to the end of December 2007. Approximately 98% of our fleet was active or available for work and the remainder was awaiting refurbishment at June 30, 2006. Since 2003, we have obtained annual independent reviews and evaluations of substantially all of our assets, which confirmed the location and condition of these assets.

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

• Diversified Service Offering for Further Revenue Growth. Our experience, equipment and network of over 90 service locations position us to market our full range of well site services to our existing customers. We believe our range of well site services provides us a competitive advantage over smaller companies that typically offer fewer services. By utilizing a wider range

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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.

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

Our Business Strategy

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

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

• Expand Within Our Regional Markets. We intend to continue strengthening our presence within our existing geographic footprint through internal growth and acquisitions of businesses with strong customer relationships, well-maintained equipment and experienced and skilled personnel. Our larger competitors have not actively pursued acquisitions of small to mid-size regional businesses or assets in recent years due to the small relative scale and financial impact of these potential acquisitions. In contrast, we have successfully pursued these types of acquisitions, which remain attractive to us and make a meaningful impact on our overall operations.

• 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. Our rigs are often the first equipment to arrive at the well site and typically the last to leave, providing us the opportunity to offer our customers other complementary services. We believe the fragmented nature of the well servicing market creates an opportunity to sell more services to our core customers and to expand our total service offering within each of our markets. We have expanded our suite of services available to our customers and increased our opportunities to cross-sell new services to our core well servicing customers through recent acquisitions and internal growth. We expect to continue to develop or selectively acquire capabilities to provide additional services to expand and further strengthen our customer relationships.

• Pursue Growth Through Selective Capital Deployment. We intend to continue growing our business through selective acquisitions, continuing a newbuild program and/or upgrading our existing assets. Our capital investment decisions are determined by an analysis of the projected

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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.

      Our strategies could be affected by any of the risk factors described in “Risk Factors” beginning on page 18.

How You Can Contact Us

      Our principal executive offices are located at 400 W. Illinois, Suite 800, Midland, Texas 79701, and our telephone number is (432) 620-5500.

Recent Developments

      On January 31, 2006, we acquired all of the outstanding capital stock of LeBus Oil Field Service Co. for a total acquisition price of approximately $26 million in cash, subject to adjustment. LeBus, which generated approximately $21 million in revenues in 2005, has 57 fluid services trucks, 225 frac tanks, and six disposal facilities. LeBus provides transportation, storage and disposal of oilfield fluids in the East Texas and North Louisiana regions from its New London and Tenaha, Texas operating locations. This acquisition is indicative of our acquisition strategy to expand within our regional markets.

      On February 28, 2006, we purchased substantially all of the operating assets of G&L Tool, Ltd., an oilfield services fishing and rental tool business headquartered in Abilene, Texas, for total consideration of $58 million in cash. The assets acquired from G&L generated approximately $39 million in revenues during 2005. This acquisition provides us entry into the fishing and rental tool business and allows us to pursue complementary and cross-selling opportunities throughout our West and North Texas locations. This acquisition is indicative of our strategy to develop additional service offerings within the well servicing market.

      In April 2006, we completed a private offering for $225 million aggregate principal amount of 7.125% Senior Notes due April 15, 2006. 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 revolving balance under our 2005 Credit Facility. Remaining proceeds will be used for general corporate purposes, including acquisitions. For a description of our 2005 Credit Facility, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facilities.”

      On July 6, 2006, we acquired substantially all of the operating assets of Hydro-Static Tubing Testers, Inc. for total consideration of $1.2 million in cash. This acquisition will operate in our well servicing segment in the Northern Rocky Mountain region.

      On August 1, 2006, we acquired all of the outstanding capital stock of Hennessey Rental Tools, Inc. for an acquisition price of $8.5 million, subject to adjustments. This acquisition will operate in both our well servicing and drilling and completion segments in the Mid-Continent region.

      On August 1, 2006, we acquired substantially all of the operating assets of Stimulation Services for total consideration of $4.5 million in cash. This acquisition will operate in our drilling and completion segment in the Ark-La-Tex region.

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Corporate Structure

      Below is a chart that illustrates our corporate structure. The issuer and the guarantors of the notes are shaded.

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Ratio of Earnings to Fixed Charges

      The following table sets forth our consolidated ratio of earnings to fixed charges for the periods shown:

	Year Ended December 31,															Six
																Months Ended
	2001			2002			2003			2004			2005			June 30, 2006
Ratio of earnings to fixed charges		4.6	x		—	(1)		2.1	x		3.2	x		6.5	x		9.9x

      The ratio was computed by dividing earnings by fixed charges. For this purpose, “earnings” means the sum of income before income taxes and fixed charges exclusive of capitalized interest, and “fixed charges” means interest expensed and capitalized, amortized premiums, discounts and capitalized expenses relating to indebtedness and an estimate of the portion of annual rental expense on capital leases that represents the interest factor.

(1)  For the year ended December 31, 2002, our ratio of earnings to fixed charges was less thanone-to-one, and our coverage deficiency was $6.4 million.

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The Exchange Offer

      On April 12, 2006, we completed a private offering of the old notes. As part of the private offering, we entered into a registration rights agreement with the initial purchasers of the old notes in which we agreed, among other things, to deliver this prospectus to you and to use our reasonable efforts to consummate the exchange offer within 270 days of the issue date of the old notes. The following is a summary of the exchange offer.

Old Notes	7.125% Senior Notes due April 15, 2016, which were issued on April 12, 2006.
New Notes	7.125% Senior Notes due April 15, 2016. The terms of the new notes are substantially identical to those terms of the outstanding old notes, except that the transfer restrictions and registration rights relating to the old notes do not apply to the new notes.
Exchange Offer	We are offering to exchange up to $225.0 million aggregate principal amount of our new notes that have been registered under the Securities Act for an equal amount of our outstanding old notes that have not been registered under the Securities Act to satisfy our obligations under the registration rights agreement.
	The new notes will evidence the same debt as the old notes and will be issued under and be entitled to the benefits of the same indenture that governs the old notes. Holders of the old notes do not have any appraisal or dissenter rights in connection with the exchange offer. Because the new notes will be registered, the new notes will not be subject to transfer restrictions, and holders of old notes that have tendered and had their old notes accepted in the exchange offer will have no registration rights.
Expiration Date	The exchange offer will expire at 5:00 p.m., New York City time, on October 12, 2006, unless we decide to extend it.
Conditions to the Exchange Offer	The exchange offer is subject to customary conditions, which we may waive. Please read “The Exchange Offer — Conditions to the Exchange Offer” for more information regarding the conditions to the exchange offer.
Procedures for Tendering Old   Notes	Unless you comply with the procedures described under the caption “The Exchange Offer — Procedures for Tendering — Guaranteed Delivery,” you must do one of the following on or prior to the expiration of the exchange offer to participate in the exchange offer:
	•  tender your old notes by sending the certificates for your old notes, in proper form for transfer, a properly completed and duly executed letter of transmittal, with any required signature guarantees, and all other documents required by the letter of transmittal, to The Bank of New York Trust Company, N.A., as registrar and exchange agent, at the address listed under the caption “The Exchange Offer — Exchange Agent”; or

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	•  tender your old notes by using the book-entry transfer procedures described below and transmitting a properly completed and duly executed letter of transmittal, with any required signature guarantees, or an agent’s message instead of the letter of transmittal, to the exchange agent. In order for a book-entry transfer to constitute a valid tender of your old notes in the exchange offer, The Bank of New York Trust Company, N.A., as registrar and exchange agent, must receive a confirmation of book-entry transfer of your old notes into the exchange agent’s account at The Depository Trust Company prior to the expiration of the exchange offer. For more information regarding the use of book-entry transfer procedures, including a description of the required agent’s message, please read the discussion under the caption “The Exchange Offer — Procedures for Tendering — Book-entry Transfer.”
Guaranteed Delivery Procedures	If you are a registered holder of the old notes and wish to tender your old notes in the exchange offer, but
	•  the old notes are not immediately available,
	•  time will not permit your old notes or other required documents to reach the exchange agent before the expiration of the exchange offer, or
	•  the procedure for book-entry transfer cannot be completed prior to the expiration of the exchange offer,
	then you may tender old notes by following the procedures described under the caption “The Exchange Offer — Procedures for Tendering — Guaranteed Delivery.”
Special Procedures for Beneficial   Owners	If you are a beneficial owner whose old notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your old notes in the exchange offer, you should promptly contact the person in whose name the old notes are registered and instruct that person to tender on your behalf.
	If you wish to tender in the exchange offer on your own behalf, prior to completing and executing the letter of transmittal and delivering the certificates for your old notes, you must either make appropriate arrangements to register ownership of the old notes in your name or obtain a properly completed bond power from the person in whose name the old notes are registered.
Withdrawal; Non-Acceptance	You may withdraw any old notes tendered in the exchange offer at any time prior to 5:00 p.m., New York City time, on October 12, 2006. If we decide for any reason not to accept any old notes tendered for exchange, the old notes will be returned to the registered holder at our expense promptly after the expiration or termination of the exchange offer. In the case of old notes tendered by book-entry transfer into the exchange agent’s account at The Depository Trust Company, any withdrawn or unaccepted old notes will be credited to the tendering

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	holder’s account at The Depository Trust Company. For further information regarding the withdrawal of tendered old notes, please read “The Exchange Offer — Withdrawal Rights.”
U.S. Federal Income Tax   Considerations	The exchange of new notes for old notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes. Please read the discussion under the caption “Material United States Federal Income Tax Considerations” for more information regarding the tax consequences to you of the exchange offer.
Use of Proceeds	The issuance of the new notes will not provide us with any new proceeds. We are making this exchange offer solely to satisfy our obligations under the registration rights agreement.
Fees and Expenses	We will pay all of our expenses incident to the exchange offer.
Exchange Agent	We have appointed The Bank of New York Trust Company, N.A. as exchange agent for the exchange offer. For the address, telephone number and fax number of the exchange agent, please read “The Exchange Offer — Exchange Agent.”
Resales of New Notes	Based on interpretations by the staff of the SEC, as set forth in no-action letters issued to third parties that are not related to us, we believe that the new notes you receive in the exchange offer may be offered for resale, resold or otherwise transferred by you without compliance with the registration and prospectus delivery provisions of the Securities Act so long as:
	•  the new notes are being acquired in the ordinary course of business;
	•  you are not participating, do not intend to participate, and have no arrangement or understanding with any person to participate in the distribution of the new notes issued to you in the exchange offer;
	•  you are not our affiliate; and
	•  you are not a broker-dealer tendering old notes acquired directly from us for your account.
	The SEC has not considered this exchange offer in the context of a no-action letter, and we cannot assure you that the SEC would make similar determinations with respect to this exchange offer. If any of these conditions are not satisfied, or if our belief is not accurate, and you transfer any new notes issued to you in the exchange offer without delivering a resale prospectus meeting the requirements of the Securities Act or without an exemption from registration of your new notes from those requirements, you may incur liability under the Securities Act. We will not assume, nor will we indemnify you against, any such liability. Each broker-dealer that receives new notes for its own account in exchange for old notes, where the old notes were acquired by such broker-dealer as a result of market-making or other trading activities, must acknowledge that it will

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	deliver a prospectus in connection with any resale of such new notes. Please read “Plan of Distribution.”
	Please read “The Exchange Offer — Resales of New Notes” for more information regarding resales of the new notes.
Consequences of Not Exchanging   Your Old Notes	If you do not exchange your old notes in this exchange offer, you will no longer be able to require us to register your old notes under the Securities Act, except in the limited circumstances provided under the registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer your old notes unless we have registered the old notes under the Securities Act, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.
	For information regarding the consequences of not tendering your old notes and our obligation to file a registration statement, please read “The Exchange Offer — Consequences of Failure to Exchange Outstanding Securities” and “Description of the New Notes.”

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Description of the New Notes

     The terms of the new notes and those of the outstanding old notes are substantially identical, except that the transfer restrictions and registration rights relating to the old notes do not apply to the new notes. As a result, the new notes will not bear legends restricting their transfer and will not have the benefit of the registration rights and special interest provisions contained in the old notes. The new notes represent the same debt as the old notes for which they are being exchanged. Both the old notes and the new notes are governed by the same indenture.

     The following summary contains basic information about the notes and is not intended to be complete. For a more complete understanding of the notes, please refer to the section in this prospectus entitled “Description of the New Notes.”

Issuer	Basic Energy Services, Inc.
Securities offered	$225,000,000 aggregate principal amount of our 7.125% Senior Notes due 2016.
Interest	The notes will accrue interest from the date of their issuance at the rate of 7.125% per year. Interest on the notes will be payable semi-annually in arrears on each April 15 and October 15, commencing on October 15, 2006. We have agreed to make additional interest payments to holders of the notes under certain circumstances if we do not comply with our obligations under the registration rights agreement.
Maturity date	April 15, 2016.
Guarantees	All of our existing and future restricted subsidiaries will guarantee the notes.
Ranking	The notes and the guarantees will be unsecured and will rank equally with all of our and the guarantors’ existing and future unsecured and unsubordinated obligations. The notes and the guarantees will be 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 notes and the guarantees. The notes and the guarantees will be effectively subordinated to our and the guarantors’ secured obligations, including our senior secured credit facilities (the “2005 Credit Facility”), to the extent of the value of the assets securing such obligations. As of June 30, 2006, we and the guarantors had approximately $254.1 million of total debt, $29.1 million of which was secured, and had availability for up to $140.4 million of additional borrowings under our 2005 Credit Facility and the potential to expand term or revolving borrowings under our 2005 Credit Facility by up to an additional $75 million. As of June 30, 2006, we had no secured indebtedness under our revolving credit facility compared to $96.0 million as of March 31, 2006.
Optional redemption	We may redeem the notes, in whole or in part, 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 to the date of redemption.

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	At any time before April 15, 2009, we may redeem up to 35% of the aggregate principal amount of the notes issued under the indenture with the net cash proceeds of one or more qualified equity offerings at a redemption price equal to 107.125% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest to the date of redemption; provided that:
	•  at least 65% of the aggregate principal amount of the notes issued under the indenture remains outstanding immediately after the occurrence of such redemption; and
	•  such redemption occurs within 90 days of the date of the closing of any such qualified equity offering.
	In addition, at any time before April 15, 2011, we may redeem some or all of the notes at a redemption price equal to 100% of the principal amount of the notes, plus an applicable premium and accrued and unpaid interest to the date of redemption.
Change of control	Upon a change of control, if we do not redeem the notes, each holder of notes will be entitled to require us to purchase all or a portion of its notes at a purchase price equal to 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase. Our ability to purchase the notes upon a change of control will be limited by the terms of our debt agreements, including our senior secured credit facilities. We cannot assure you that we will have the financial resources to purchase the notes in such circumstances.
Certain covenants	The indenture will contain covenants that, among other things, will limit our ability and the ability of 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 our affiliates;
	•  limit dividends or other payments by our restricted subsidiaries to us; and
	•  sell assets or consolidate or merge with or into other companies.
	These and other covenants that will be contained in the indenture are subject to important exceptions and qualifications, which are described under “Description of the New Notes.”

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If the notes receive an Investment Grade Rating (as defined under “Description of the New Notes — Certain Covenants — Covenant Suspension”), then for so long as such rating is maintained, certain of the covenants will cease to apply as described under “Description of the New Notes — Certain Covenants — Covenant Suspension.”

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Summary Historical Financial Information

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

												Six Months
												Ended
			Year Ended December 31,									June 30,
			2003			2004			2005			2005			2006
												(unaudited)
			(dollars in thousands)
Statement of Operations Data:
Revenues:
	Well servicing		$	104,097		$	142,551		$	221,993		$	98,650		$	154,619
	Fluid services			52,810			98,683			132,280			60,839			91,982
	Drilling and completion services			14,808			29,341			59,832			24,276			68,394
	Well site construction services			9,184			40,927			45,647			19,866			23,144
		Total revenues		180,899			311,502			459,752			203,631			338,139
Expenses:
	Well servicing			73,244			98,058			137,392			61,464			87,131
	Fluid services			34,420			65,167			82,551			39,119			55,648
	Drilling and completion services			9,363			17,481			30,900			12,731			33,034
	Well site construction services			6,586			31,454			32,000			14,663			16,463
	General and administrative(1)			22,722			37,186			55,411			26,463			38,149
	Depreciation and amortization			18,213			28,676			37,072			16,818			27,959
	Loss (gain) on disposal of assets			391			2,616			(222	)		(50	)		727
		Total expenses		164,939			280,638			375,104			171,208			259,111
		Operating income		15,960			30,864			84,648			32,423			79,028
Other income (expense):
	Net interest expense			(5,174	)		(9,550	)		(12,660	)		(6,002	)		(6,873	)
	Loss on early extinguishment of debt			(5,197	)		—			(627	)		—			(2,705	)
	Other income (expense)			146			(398	)		220			137			55
	Income from continuing operations before income taxes			5,735			20,916			71,581			26,558			69,505
	Income tax expense			(2,772	)		(7,984	)		(26,800	)		(10,010	)		(25,337	)
	Income from continuing operations			2,963			12,932			44,781			16,548			44,168
	Discontinued operations, net of tax			22			(71	)		—			—			—
	Cumulative effect of accounting change, net of tax			(151	)		—			—			—			—
	Net income			2,834			12,861			44,781			16,548			44,168
	Preferred stock dividend			(1,525	)		—			—			—			—
	Accretion of preferred stock discount			(3,424	)		—			—			—			—
	Net income (loss) available to common stockholders		$	(2,115	)	$	12,861		$	44,781		$	16,548		$	44,168

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											Six Months
											Ended
		Year Ended December 31,									June 30,
		2003			2004			2005			2005			2006
											(unaudited)
		(dollars in thousands)
Statement of Cash Flow Data:
Cash flows from operating activities		$	29,815		$	46,539		$	99,189		$	44,823		$	50,954
Cash flows from investing activities			(84,903	)		(73,587	)		(107,679	)		(45,354	)		(150,471	)
Cash flows from financing activities			79,859			21,498			21,188			(5,550	)		104,212
Capital expenditures:
	Acquisitions, net of cash acquired		61,885			19,284			25,378			9,885			98,988
	Property and equipment		23,501			55,674			83,095			35,488			48,827

	As of December 31,						As of
							June 30,
	2003		2004		2005		2006
							(unaudited)
	(dollars in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	25,697	$	20,147	$	32,845	$	37,540
Property and equipment, net		188,243		233,451		309,075		424,720
Total assets		302,653		367,601		496,957		685,738
Total long-term debt, including current portion		148,509		182,476		126,887		254,062
Total stockholders’ equity		107,295		121,786		258,575		303,939

(1)  Includes approximately $994,000, $1,587,000 and $2,890,000 of non-cash stock-based compensation expense for the years ended December 31, 2003, 2004 and 2005, respectively, and $1,359,000 and $1,633,000 for the six months ended June 30, 2005 and 2006, respectively.

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Operating Data

      The following table sets forth operating data for our well servicing, fluid services, drilling and completion services and well site construction services segments for the periods shown. The data presented below reflects the following:

• we charge our well servicing customers on an hourly basis — rig hours reflect actual billed hours;

• our rig utilization rate is calculated using a55-hour work week per rig;

• our fluid services segment includes an array of services billed on an hourly, daily and per barrel basis; accordingly, we believe revenue per truck is the more meaningful information for this measure; and

• in our drilling and completion services segment, we charge different rates for our pressure pumping trucks based on the type of services performed and varying horsepower requirements, and in our well site construction services segment, we similarly charge different rates for different equipment, in each case making segment profits the most meaningful measure of performance.

										Six Months
	Year Ended December 31,									Ended June 30,
	2003			2004			2005			2005			2006
Well Servicing
Weighted average number of rigs		257			279			305			298			336
Rig hours (000’s)		523.9			618.8			760.7			367.7			430.8
Rig utilization rate		71.4	%		77.8	%		87.1	%		86.3	%		89.7	%
Revenue per rig hour	$	199		$	230		$	292		$	268		$	359
Segment profits per rig hour	$	59		$	72		$	111		$	101		$	157
Segment profits as a percent of revenue		29.6	%		31.2	%		38.1	%		37.7	%		43.6	%
Fluid Services
Weighted average number of fluid service trucks		249			386			455			443			559
Revenue per fluid service truck (000’s)	$	212		$	256		$	291		$	137		$	165
Segment profits per fluid service truck (000’s)	$	74		$	87		$	109		$	49		$	65
Segment profits as a percent of revenue		34.8	%		34.0	%		37.6	%		35.7	%		39.5	%
Drilling and Completion Services
Segment profits as a percent of revenue		36.8	%		40.4	%		48.4	%		47.6	%		51.7	%
Well Site Construction Services
Segment profits as a percent of revenue		28.3	%		23.1	%		29.9	%		26.2	%		28.9	%

      Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Well Servicing,” “— Fluid Services,” “— Drilling and Completion Services” and “— Well Site Construction Services” for an analysis of our well servicing, fluid services, drilling and completion and well site construction services.

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RISK FACTORS

     You should carefully consider the risks described below, as well as the other information included in this prospectus, before making a decision to participate in the exchange offer. If any of these risks were to occur, our business, results of operations or financial condition could be materially and adversely affected. When we use the term “notes” in this prospectus, unless the context requires otherwise, the term includes the old notes and the new notes.

Risks Related to the Exchange Offer and the New Notes

If you do not properly tender your old notes, you will continue to hold unregistered outstanding notes and your ability to transfer outstanding notes will be adversely affected.

      We will only issue new notes in exchange for old notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the old notes and you should carefully follow the instructions on how to tender your old notes. Neither we nor the exchange agent is required to tell you of any defects or irregularities with respect to your tender of old notes. Please read “The Exchange Offer — Procedures for Tendering” and “Description of the New Notes.”

      If you do not exchange your old notes for new notes in the exchange offer, you will continue to be subject to the restrictions on transfer of your old notes described in the legend on the certificates for your old notes. In general, you may only offer or sell the old notes if they are registered under the Securities Act and applicable state securities laws, or offered and sold under an exemption from these requirements. We do not plan to register any sale of the old notes under the Securities Act. For further information regarding the consequences of tendering your old notes in the exchange offer, please read “The Exchange Offer — Consequences of Failure to Exchange Outstanding Securities.”

You may find it difficult to sell your new notes.

      Although the new notes will trade in The PORTAL^sm Market and will be registered under the Securities Act, the new notes will not be listed on any securities exchange. Because there is no public market for the new notes, you may not be able to resell them.

      We cannot assure you that an active market will exist for the new notes or that any trading market that does develop will be liquid. If an active market does not develop or is not maintained, the market price and liquidity of our new notes may be adversely affected. If a market for the new notes develops, they may trade at a discount from their initial offering price. The trading market for the notes may be adversely affected by:

• changes in the overall market for non-investment grade securities;

• changes in our financial performance or prospects;

• the financial performance or prospects for companies in our industry generally;

• the number of holders of the notes;

• the interest of securities dealers in making a market for the notes; and

• prevailing interest rates and general economic conditions.

      Historically, the market for non-investment grade debt has been subject to substantial volatility in prices. The market for the new notes, if any, may be subject to similar volatility. Prospective investors in the new notes should be aware that they may be required to bear the financial risks of such investment for an indefinite period of time.

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Some holders who exchange their old notes may be deemed to be underwriters.

      If you exchange your old notes in the exchange offer for the purpose of participating in a distribution of the new notes, you may be deemed to have received restricted securities and, if so, will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

Risks Related to Our Business

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

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

      Prices for oil and gas historically have been extremely volatile and are expected to continue to be volatile. For example, although oil and natural gas prices have recently hit record prices exceeding $70 per barrel and $14.00 per mcf, respectively, oil and natural gas prices fell below $11 per barrel and $2 per mcf, respectively, in early 1999. The Cushing WTI Spot Oil Price averaged $31.08, $41.51, $56.64 and $66.89 per barrel in 2003, 2004, 2005, and the first six months of 2006, respectively, and the average wellhead price for natural gas, as recorded by the Energy Information Agency, was $4.98, $5.49, $7.51 and $6.84 per mcf for 2003, 2004, 2005, and the first six months of 2006, respectively. Commodity prices have increased significantly in recent years, and these prices may not remain at current levels.

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

      We depend on our customers’ willingness to make operating and capital expenditures to explore, develop and produce oil and gas in the United States. Customers’ expectations for lower market prices for oil and gas may curtail spending thereby reducing demand for our services and equipment.

      Industry conditions are influenced by numerous factors over which we have no control, such as the supply of and demand for oil and gas, domestic and worldwide economic conditions, political instability in oil and gas producing countries and merger and divestiture activity among oil and gas producers. The volatility of the oil and gas industry and the consequent impact on exploration and production activity could adversely impact the level of drilling and workover activity by some of our customers. This reduction may cause a decline in the demand for our services or adversely affect the price of our services. In addition, reduced discovery rates of new oil and gas reserves in our market areas also may have a negative long-term impact on our business, even in an environment of stronger oil and gas prices, to the extent existing production is not replaced and the number of producing wells for us to service declines.

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

      Our business strategy includes growth through the acquisitions of other businesses. We may not be able to continue to identify attractive acquisition opportunities or successfully acquire identified targets. In addition, we may not be successful in integrating our current or future acquisitions into our existing operations, which may result in unforeseen operational difficulties or diminished financial

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performance or require a disproportionate amount of our management’s attention. Even if we are successful in integrating our current or future acquisitions into our existing operations, we may not derive the benefits, such as operational or administrative synergies, that we expected from such acquisitions, which may result in the commitment of our capital resources without the expected returns on such capital. Furthermore, competition for acquisition opportunities may escalate, increasing our cost of making further acquisitions or causing us to refrain from making additional acquisitions. We also must meet certain financial covenants in order to borrow money under our existing credit agreement to fund future acquisitions.

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

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

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

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

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

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We may require additional capital in the future. We cannot assure you that we will be able to generate sufficient cash internally or obtain alternative sources of capital on favorable terms, if at all. If we are unable to fund capital expenditures our business may be adversely affected.

      We anticipate that we will continue to make substantial capital investments to purchase additional equipment to expand our services, refurbish our well servicing rigs and replace existing equipment. For the year ended December 31, 2005, we invested approximately $83.1 million in cash for capital investments, excluding acquisitions. During the first six months of 2006, we made capital expenditures of approximately $48.8 million, and we expect to spend a total of approximately $93 million in cash capital expenditures during fiscal year 2006, excluding acquisitions. Historically, we have financed these investments through internally generated funds, debt and equity offerings, our capital lease program and our secured credit facilities. These significant capital investments require cash that we could otherwise apply to other business needs. However, if we do not incur these expenditures while our competitors make substantial fleet investments, our market share may decline and our business may be adversely affected. In addition, if we are unable to generate sufficient cash internally or obtain alternative sources of capital to fund our proposed capital expenditures, acquisitions, take advantage of business opportunities or respond to competitive pressures, it could materially adversely affect our results of operations, financial condition and growth. If we raise additional funds by issuing equity securities, dilution to existing stockholders may result.

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

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

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

      Our customers consist primarily of major and independent oil and gas companies. During 2005 and the first six months of 2006, our top five customers accounted for 16% and 18%, respectively, of our revenues. The loss of any one of our largest customers or a sustained decrease in demand by any of such customers could result in a substantial loss of revenues and could have a material adverse effect on our results of operations.

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

      We currently purchase our well servicing rigs from a single supplier as part of a 102-rig commitment for rigs to be delivered through the end of December 2007, of which 54 rigs have been delivered as of June 30, 2006. There is also a limited number of suppliers that manufacture this type of equipment. Although pricing is generally fixed for this newbuild contract and program, future price increases could affect our ability to continue to increase the number of newbuild rigs in our fleet at economic levels. In addition, the failure of our current supplier to timely deliver the newbuild rigs could adversely affect our budgeted or projected financial and operational data.

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

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

      Other factors may also inhibit our ability to find enough workers to meet our employment needs. Our services require skilled workers who can perform physically demanding work. As a result of our industry volatility and the demanding nature of the work, workers may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive with ours. We believe that our success is dependent upon our ability to continue to employ and retain skilled technical personnel. Our inability to employ or retain skilled technical personnel generally could have a material adverse effect on our operations.

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

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

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

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

• personal injury or loss of life;

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

• suspension of operations.

      The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our financial condition and results of operations. In addition, claims for loss of oil and gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in us being named as a defendant in lawsuits asserting large claims.

      We maintain insurance coverage that we believe to be customary in the industry against these hazards. However, we do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. We are also self-insured up to retention limits with regard to workers’ compensation and medical and dental coverage of our employees and, with certain exceptions, we generally maintain no physical property damage coverage on our workover rig fleet. We maintain accruals in our consolidated balance sheets related to self-insurance retentions by using third-party data and historical claims history. The occurrence of an event not fully insured against, or the failure of an insurer to meet its insurance obligations, could result in substantial losses. In addition, we

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may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of these risks, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitive. It is likely that, in our insurance renewals, our premiums and deductibles will be higher, and certain insurance coverage either will be unavailable or considerably more expensive than it has been in the recent past. In addition, our insurance is subject to coverage limits and some policies exclude coverage for damages resulting from environmental contamination.

We are subject to federal, state and local regulation regarding issues of health, safety and protection of the environment. Under these regulations, we may become liable for penalties, damages or costs of remediation. Any changes in laws and government regulations could increase our costs of doing business.

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

      Laws protecting the environment generally have become more stringent over time and are expected to continue to do so, which could lead to material increases in costs for future environmental compliance and remediation. The modification or interpretation of existing laws or regulations, or the adoption of new laws or regulations, could curtail exploratory or developmental drilling for oil and gas and could limit well servicing opportunities. Some environmental laws and regulations may impose strict liability, which means that in some situations we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or conduct of, or conditions caused by, prior operators or other third parties.Clean-up costs and other damages arising as a result of environmental laws, and costs associated with changes in environmental laws and regulations could be substantial and could have a material adverse effect on our financial condition. Please read “Business — Environmental Regulation” for more information on the environmental laws and government regulations that are applicable to us.

Our indebtedness could restrict our operations and make us more vulnerable to adverse economic conditions.

      As of June 30, 2006, our total debt was $254.1 million, including $225.0 million of Senior Notes due 2016 and capital lease obligations in the aggregate amount of $29.1 million. Our Senior Notes due 2016 bear interest at 7.125%, payable semi-annually in arrears on April 15 and October 15 of each year, starting October 15, 2006. In addition, as of June 30, 2006, we had $9.6 million of letters of credit outstanding and availability for up to $140.4 million of additional borrowings under our 2005 Credit Facility and the potential to expand term or revolving borrowings under our 2005 Credit Facility by up to an additional $75 million.

      Our current and future indebtedness could have important consequences to you. For example, it could:

• impair our ability to make investments and obtain additional financing for working capital, capital expenditures, acquisitions or other general corporate purposes;

• limit our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make principal and interest payments on our indebtedness;

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• make us more vulnerable to a downturn in our business, our industry or the economy in general as a substantial portion of our operating cash flow will be required to make principal and interest payments on our indebtedness, making it more difficult to react to changes in our business and in industry and market conditions;

• limit our ability to obtain additional financing that may be necessary to operate or expand our business;

• put us at a competitive disadvantage to competitors that have less debt; and

• increase our vulnerability to interest rate increases to the extent that we incur variable rate indebtedness.

      If we are unable to generate sufficient cash flow or are otherwise unable to obtain the funds required to make principal and interest payments on our indebtedness, or if we otherwise fail to comply with the various covenants in our 2005 Credit Facility, the indenture governing our Senior Notes or other instruments governing any future indebtedness, we could be in default under the terms of our 2005 Credit Facility, the indenture governing our Senior Notes or such instruments. In the event of a default, the holders of our indebtedness could elect to declare all the funds borrowed under those instruments to be due and payable together with accrued and unpaid interest, the lenders under our 2005 Credit Facility could elect to terminate their commitments thereunder and we or one or more of our subsidiaries could be forced into bankruptcy or liquidation. Any of the foregoing consequences could restrict our ability to grow our business and cause the value of our common stock to decline.

Our 2005 Credit Facility and the indenture governing our Senior Notes impose restrictions on us that may affect our ability to successfully operate our business.

      Our 2005 Credit Facility and the indenture governing our Senior Notes limit our ability to take various actions, such as:

• limitations on the incurrence of additional indebtedness;

• restrictions on mergers, sales or transfer of assets without the lenders’ consent; and

• limitation on dividends and distributions.

      In addition, our 2005 Credit Facility requires us to maintain certain financial ratios and to satisfy certain financial conditions and covenants, several of which become more restrictive over time and may require us to reduce our debt or take some other action in order to comply with them. The failure to comply with any of these financial conditions, financial ratios or covenants would cause a default under our 2005 Credit Facility. A default, if not waived, could result in acceleration of the outstanding indebtedness under our 2005 Credit Facility, in which case the debt would become immediately due and payable. In addition, a default or acceleration of indebtedness under our 2005 Credit Facility could result in a default or acceleration of our Senior Notes or other indebtedness with cross-default or cross-acceleration provisions. If this occurs, we may not be able to pay our debt or borrow sufficient funds to refinance it. Even if new financing is available, it may not be available on terms that are acceptable to us. These restrictions could also limit our ability to obtain future financings, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We also may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under our 2005 Credit Facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facilities  — 2005 Credit Facility” for a discussion of our 2005 Credit Facility.

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

      Steven A. Webster, the Chairman of our Board of Directors, is the Co-Managing Partner of Avista Capital Holdings, L.P., a private equity firm that makes investments in the energy sector. This relationship may create a conflict of interest because of his responsibilities to Avista and its owners. His duties as a partner in, or director or officer of, Avista or its affiliates may conflict with his duties as a director of our company regarding corporate opportunities and other matters. The resolution of this conflict may not always be in our or our stockholders’ best interest.

Risks Related to our Relationship with DLJ Merchant Banking

Affiliates of DLJ Merchant Banking will have a substantial influence on the outcome of stockholder voting and may exercise this voting power in a manner that may not be in the best interest of our other stockholders.

      As of June 30, 2006, DLJ Merchant Banking Partners III, L.P. and affiliated funds (“DLJ Merchant Banking”), which are managed by affiliates of Credit Suisse, a Swiss Bank, and Credit Suisse Securities (USA) LLC, beneficially owned approximately 47.4% of our outstanding common stock. DLJ Merchant Banking is in a position to have a substantial influence on the outcome of matters requiring a stockholder vote, including the election of directors, adoption of amendments to our certificate of incorporation or bylaws or approval of transactions involving a change of control. The interests of DLJ Merchant Banking may differ from those of our other stockholders, and DLJ Merchant Banking may vote its common stock in a manner that may not be in the best interest of the other stockholders.

Risks Related to the Notes

The notes are unsecured and will be effectively subordinated to our existing and future secured debt and other secured obligations, and the guarantees of the notes will be effectively subordinated to the guarantors’ secured debt and other secured obligations.

      The notes will not be secured by any of our or our subsidiaries’ assets. As a result, the notes and the guarantees will be effectively subordinated to all of our and the guarantors’ secured obligations to the extent of the value of the assets securing such obligations. The notes and the guarantees will be effectively subordinated to all such secured debt to the extent of the value of its collateral. In the event of any distribution or payment of our or any other guarantor’s assets in any foreclosure, dissolution, winding-up, liquidation, reorganization or other bankruptcy proceeding, holders of secured debt will have a prior claim to the assets that constitute their collateral. Holders of the notes will participate ratably with all holders of our and the guarantors’ unsecured senior debt, and potentially with all of their other general creditors, based upon the respective amounts owed to each holder or creditor, in their respective remaining assets. In any of the foregoing events, we cannot assure you that there will be sufficient assets to pay amounts due on the notes. As a result, holders of notes may receive less, ratably, than holders of secured debt. As of June 30, 2006, we and the guarantors had approximately $29.1 million of secured debt under our capital leases, and had availability for up to $140.4 million of additional borrowings under the revolving portion of our 2005 Credit Facility and the potential to expand term or revolving borrowings under our 2005 Credit Facility by up to an additional $75 million. The indenture governing the notes permits us and our subsidiaries to incur secured debt, including pursuant to our credit facility, purchase money instruments and other forms of secured debt.

We will require a significant amount of cash to service our debt. Our ability to generate cash depends on many factors beyond our control.

      Our ability to make payments on and to refinance our debt, including the notes, and to fund planned capital expenditures will depend on our ability to generate cash in the future. This is subject to general economic, financial, competitive, legislative, regulatory and other factors that may be beyond

25

our control. We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our 2005 Credit Facility or otherwise in an amount sufficient to enable us to pay our debt, including the notes, or to fund our other liquidity needs. We may need to refinance all or a portion of our debt, including the notes, on or before maturity. We cannot assure you that we will be able to refinance any of our debt, including our 2005 Credit Facility, lease facilities, or the notes, on commercially reasonable terms or at all.

In addition to our current indebtedness, we may incur substantially more debt, including additional secured debt. This could further exacerbate the risks associated with our substantial debt.

      We and our subsidiaries may be able to incur substantial additional debt in the future, including an increase of $75 million of borrowing capacity under our 2005 Credit Facility. Although the indenture governing the notes will contain restrictions on the incurrence of additional debt, these restrictions are subject to a number of qualifications and exceptions and, under certain circumstances, debt incurred in compliance with these restrictions could be substantial. If new debt is added to our current debt levels, the substantial risks described above would intensify. See “Capitalization,” “Selected Historical Consolidated Financial Data,” “Description of the New Notes” and “Description of Certain Other Indebtedness.”

We are a holding company with no direct operations.

      Basic Energy Services, Inc. is a holding company with no direct operations. Our principal assets are the equity interests and investments we hold in our subsidiaries. As a result, we depend on dividends and other payments from our subsidiaries to generate the funds necessary to meet our financial obligations, including the payment of principal of and interest on our outstanding debt. Our subsidiaries are legally distinct from us and have no obligation to pay amounts due on our debt or to make funds available to us for such payment except as provided in the note guarantees or pursuant to intercompany notes.

Federal and state statutes may allow courts, under specific circumstances, to void the guarantees and require noteholders to return payments received from guarantors.

      Under federal bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee could be deemed a fraudulent transfer if the guarantor received less than a reasonably equivalent value in exchange for giving the guarantee and

• was insolvent on the date that it gave the guarantee or became insolvent as a result of giving the guarantee, or

• was engaged in business or a transaction, or was about to engage in business or a transaction, for which property remaining with the guarantor was an unreasonably small capital, or

• intended to incur, or believed that it would incur, debts that would be beyond the guarantor’s ability to pay as those debts matured.

      A guarantee could also be deemed a fraudulent transfer if it was given with actual intent to hinder, delay or defraud any entity to which the guarantor was or became, on or after the date the guarantee was given, indebted.

      The measures of insolvency for purposes of the foregoing considerations will vary depending upon the law applied in any proceeding with respect to the foregoing. Generally, however, a guarantor would be considered insolvent if:

• the sum of its debts, including contingent liabilities, is greater than all its assets, at a fair valuation, or

26

• the present fair saleable value of its assets is less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature, or

• it could not pay its debts as they become due.

      The indenture will contain a provision intended to limit each subsidiary guarantor’s liability under its guarantee to the maximum amount that it could incur without causing the guarantee to be a fraudulent transfer. This provision may not be effective to protect the subsidiary guarantees from being voided under fraudulent transfer law.

      If a guarantee is deemed to be a fraudulent transfer, it could be voided altogether, or it could be subordinated to all other debts of the guarantor. In such case, any payment by the guarantor pursuant to its guarantee could be required to be returned to the guarantor or to a fund for the benefit of the creditors of the guarantor. If a guarantee is voided or held unenforceable for any other reason, holders of the notes would cease to have a claim against the subsidiary based on the guarantee and would be creditors only of Basic Energy Services, Inc. and any guarantor whose guarantee was not similarly voided or otherwise held unenforceable.

We may not have the ability to raise funds necessary to finance any change of control offer required under the indenture.

      If a change of control (as defined in the indenture) occurs, we will be required to offer to purchase your notes at 101% of their principal amount plus accrued and unpaid interest. If a purchase offer obligation arises under the indenture governing the notes, a change of control could also have occurred under the 2005 Credit Facility, which could result in the acceleration of the indebtedness outstanding thereunder. Any of our future debt agreements may contain similar restrictions and provisions. If a purchase offer were required under the indenture for our debt, we may not have sufficient funds to pay the purchase price of all debt, including your notes, that we are required to purchase or repay.

An active trading market may not develop for the notes.

      The notes are a new issue of securities. There is no active public trading market for the notes. We do not intend to apply for listing of the notes on a security exchange. The initial purchasers of the notes have informed us that they intend to make a market in the notes. However, the initial purchasers may cease their market-making at any time. We have agreed to file a registration statement covering the exchange offer for the notes and the guarantees thereof. Consummation of the exchange offer will require SEC clearance. Even after consummation of the exchange offer, we cannot assure you that an active trading market will develop for the notes or that the exchange notes offered in the exchange offer will trade as one class with the originally issued notes. In addition, the liquidity of the trading market in the notes and the market prices quoted for the notes may be adversely affected by changes in the overall market for high yield securities and by changes in our financial performance or prospects or in the prospects for companies in our industry generally. As a consequence, an active trading market may not develop for your notes, you may not be able to sell your notes, or, even if you can sell your notes, you may not be able to sell them at an acceptable price.

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Certain covenants contained in the indenture will not be applicable during any period in which the notes are rated investment grade by both Moody’s and S&P.

      The indenture will provide that certain covenants will not be applicable during any period in which the notes are rated investment grade by both Moody’s and S&P. The covenants restrict, among other things, our ability to pay dividends, incur debt, sell assets, enter into transactions with affiliates, enter into business combinations and enter into other transactions. There can be no assurance that the notes will ever be rated investment grade, or that if they are rated investment grade, the notes will maintain such rating. However, suspension of these covenants would allow us to engage in certain transactions that would not be permitted while these covenants were in force, and any such actions that we take while these covenants are not in force will effectively be “grandfathered” even if the notes are subsequently downgraded below investment grade. See “Description of the New Notes — Certain Covenants — Covenant Suspension.”

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FORWARD-LOOKING STATEMENTS AND INDUSTRY DATA

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

      The words “believe,” “may,” “estimate,” “continue,” “anticipate,” “intend,” “plan,” “expect” and similar expressions are intended to identify forward-looking statements. All statements other than statements of current or historical fact contained in this prospectus are forward-looking statements.

      Although we believe that the forward-looking statements contained in this prospectus are based upon reasonable assumptions, the forward-looking events and circumstances discussed in this prospectus may not occur and actual results could differ materially from those anticipated or implied in the forward-looking statements.

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

• a decline in or substantial volatility of oil and gas prices, and any related changes in expenditures by our customers;

• the effects of future acquisitions on our business;

• changes in customer requirements in markets or industries we serve;

• competition within our industry;

• general economic and market conditions;

• our access to current or future financing arrangements;

• our ability to replace or add workers at economic rates; and

• environmental and other governmental regulations.

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

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

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RATIO OF EARNINGS TO FIXED CHARGES

      The following table sets forth our consolidated ratio of earnings to fixed charges for the periods shown:

	Year Ended December 31,															Six
																Months Ended
	2001			2002			2003			2004			2005			June 30, 2006
Ratio of earnings to fixed charges		4.6	x		—	(1)		2.1	x		3.2	x		6.5	x		9.9	x

      The ratio was computed by dividing earnings by fixed charges. For this purpose, “earnings” means the sum of income before income taxes and fixed charges exclusive of capitalized interest, and “fixed charges” means interest expensed and capitalized, amortized premiums, discounts and capitalized expenses relating to indebtedness and an estimate of the portion of annual rental expense on capital leases that represents the interest factor.

(1)  For the year ended December 31, 2002, our ratio of earnings to fixed charges was less thanone-to-one, and our coverage deficiency was $6.4 million.

USE OF PROCEEDS

      The exchange offer is intended to satisfy our obligations under the registration rights agreement we entered into in connection with the private offering of the old notes. We will not receive any proceeds from the issuance of the new notes in the exchange offer. In consideration for issuing the new notes as contemplated in this prospectus, we will receive, in exchange, outstanding old notes in like principal amount. We will cancel all old notes surrendered in exchange for new notes in the exchange offer. As a result, the issuance of the new notes will not result in any increase or decrease in our indebtedness.

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CAPITALIZATION

      The following table sets forth our capitalization at June 30, 2006. The information was derived from and is qualified by reference to our financial statements included elsewhere in this prospectus. You should read this information in conjunction with “Selected Historical Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our combined financial statements and the related notes thereto included elsewhere in this prospectus.

				June 30,
				2006
				(in thousands)
Cash and cash equivalents				$	37,540
Total long-term debt, including current portion:
	Notes payable:
		Revolving credit facility			—
		Term B Loan			—
		7.125% Senior Notes			225,000
		Other debt and obligations under capital leases			29,062
			Total		254,062
Stockholders’ equity:
	Common stock, $.01 par value, 80,000,000 shares authorized; 33,931,935 shares issued and 33,815,405 shares outstanding				339
	Additional paid-in capital				236,415
	Deferred compensation				—
	Retained earnings				70,195
	Treasury stock, 116,530 shares at cost				(3,010	)
	Accumulated other comprehensive income				—
		Total stockholders’ equity			303,939
		Total capitalization		$	558,001

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SELECTED HISTORICAL 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 “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements included elsewhere in this prospectus. The amounts for each historical annual period presented below were derived from our audited financial statements.

																			Six Months Ended
				Year Ended December 31,															June 30,
				2001			2002			2003			2004			2005			2005			2006
																			(unaudited)
				(dollars in thousands)
Statement of Operations Data:
Revenues:
	Well servicing			$	62,943		$	73,848		$	104,097		$	142,551		$	221,993		$	98,650		$	154,619
	Fluid services				36,766			34,170			52,810			98,683			132,280			60,839			91,982
	Drilling and completion services				—			733			14,808			29,341			59,832			24,276			68,394
	Well site construction services				—			—			9,184			40,927			45,647			19,866			23,144
		Total revenues			99,709			108,751			180,899			311,502			459,752			203,631			338,139
Expenses:
	Well servicing				40,906			55,643			73,244			98,058			137,392			61,464			87,131
	Fluid services				21,363			22,705			34,420			65,167			82,551			39,119			55,648
	Drilling and completion services				—			512			9,363			17,481			30,900			12,731			33,034
	Well site construction services				—			—			6,586			31,454			32,000			14,663			16,463
	General and administrative(1)				10,813			13,019			22,722			37,186			55,411			26,463			38,149
	Depreciation and amortization				9,599			13,414			18,213			28,676			37,072			16,818			27,959
	Loss (gain) on disposal of assets				(10	)		351			391			2,616			(222	)		(50	)		727
		Total expenses			82,671			105,644			164,939			280,638			375,104			171,208			259,111
			Operating income		17,038			3,107			15,960			30,864			84,648			32,423			79,028
Other income (expense):
Net interest expense					(3,303	)		(4,750	)		(5,174	)		(9,550	)		(12,660	)		(6,002	)		(6,873	)
Gain (loss) on early extinguishment of debt					(1,462	)		—			(5,197	)		—			(627	)		—			(2,705	)
Other income (expense)					16			31			146			(398	)		220			137			55
Income (loss) from continuing operations before income taxes					12,289			(1,612	)		5,735			20,916			71,581			26,558			69,505
Income tax (expense) benefit					(4,688	)		382			(2,772	)		(7,984	)		(26,800	)		(10,010	)		(25,337	)
Income (loss) from continuing operations					7,601			(1,230	)		2,963			12,932			44,781			16,548			44,168
Income (loss) from discontinued operations, net of tax					—			—			22			(71	)		—			—			—
Cumulative effect of accounting change, net of tax					—			—			(151	)		—			—			—			—
Net income (loss)					7,601			(1,230	)		2,834			12,861			44,781			16,548			44,168
Preferred stock dividend					—			(1,075	)		(1,525	)		—			—			—			—
Accretion of preferred stock discount					—			(374	)		(3,424	)		—			—			—			—
Net income (loss) available to common stockholders				$	7,601		$	(2,679	)	$	(2,115	)	$	12,861		$	44,781		$	16,548		$	44,168

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																	Six Months Ended
		Year Ended December 31,															June 30,
		2001			2002			2003			2004			2005			2005			2006
																	(unaudited)
		(dollars in thousands)
Statement of Cash Flow:
Cash flows from operating activities		$	14,060		$	17,012		$	29,815		$	46,539		$	99,189		$	44,823		$	50,954
Cash flows from investing activities			(60,305	)		(45,303	)		(84,903	)		(73,587	)		(107,679	)		(45,354	)		(150,471	)
Cash flows from financing activities			50,770			21,572			79,859			21,498			21,188			(5,550	)		104,212
Capital expenditures:
	Acquisitions, net of cash acquired		44,928			31,075			61,885			19,284			25,378			9,885			98,988
	Property and equipment		15,208			14,674			23,501			55,674			83,095			35,488			48,827

	As of December 31,										As of
											June 30,
	2001		2002		2003		2004		2005		2006
											(unaudited)
	(dollars in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	7,645	$	926	$	25,697	$	20,147	$	32,845	$	37,540
Property and equipment, net		78,602		108,487		188,243		233,451		309,075		424,720
Total assets		126,207		156,502		302,653		367,601		496,957		685,738
Long-term debt, including current portion		45,258		39,706		148,509		182,476		126,887		254,062
Mandatorily redeemable cumulative preferred stock		—		12,093		—		—		—		—
Stockholders’ equity		58,938		72,558		107,295		121,786		258,575		303,939

(1)  Includes approximately $994,000, $1,587,000 and $2,890,000 of non-cash stock compensation expense for the years ended December 31, 2003, 2004 and 2005, respectively, and $1,359,000 and $1,633,000 for the six months ended June 30, 2005 and 2006, respectively.

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MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Overview

      We provide a wide range of well site services to oil and gas drilling and producing companies, including well servicing, fluid services, drilling and completion services and well site construction services. Our results of operations since the beginning of 2002 reflect the impact of our acquisition strategy as a leading consolidator in the domestic land-based well services industry during this period. Our acquisitions have increased our breadth of service offerings at the well site and expanded our market presence. In implementing this strategy, we have purchased businesses and assets in 41 separate acquisitions from January 1, 2001 to June 30, 2006. Our weighted average number of well servicing rigs has increased from 126 in 2001 to 341 in the second quarter of 2006, and our weighted average number of fluid service trucks has increased from 156 to 568 in the same period. In 2003, primarily through acquisitions, we significantly increased our drilling and completion (principally pressure pumping) services and entered the well site construction services segment. These acquisitions make changes in revenues, expenses and income not directly comparable.

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

		Year Ended December 31,												Six Months Ended June 30,
		2003				2004				2005				2005				2006
Revenues:
Well servicing		$	104.1	58	%	$	142.6	46	%	$	222.0	48	%	$	98.6	48	%	$	154.6	46	%
Fluid services			52.8	29	%		98.7	32	%		132.3	29	%		60.8	30	%		92.0	27	%
Drilling and completion services			14.8	8	%		29.3	9	%		59.8	13	%		24.3	12	%		68.4	20	%
Well site construction services			9.2	5	%		40.9	13	%		45.7	10	%		19.9	10	%		23.1	7	%
	Total revenues	$	180.9	100	%	$	311.5	100	%	$	459.8	100	%	$	203.6	100	%	$	338.1	100	%

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

      We derive a majority of our revenues from services supporting production from existing oil and gas operations. Demand for these production related services, including well servicing and fluid services, tends to remain relatively stable 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 our production related services generally increases as our customers increase spending for drilling new wells and well servicing activities related to maintaining or increasing production from existing 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.

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

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

• Fluid Services — revenue per truck and segment profits as a percent of revenues;

• Drilling and Completion Services — segment profits as a percent of revenues; and

• Well Site Construction Services — segment profits as a percent of revenues.

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

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

Recent Strategic Acquisitions and Expansions

      During the period from 2003 through 2005, we grew significantly through acquisitions and capital expenditures. During 2003, this growth was focused more on acquisitions of new lines of related business and of regional platforms for our existing businesses. During 2004 and 2005, we directed our focus for growth more on the integration and expansion of our existing businesses, through capital expenditures and to a lesser extent, acquisitions. During the first six months of 2006, we completed four additional acquisitions, one of which was significant for purposes of Statement of Financial Accounting Standards No. 141 “Business Combinations.”

      We discuss the aggregate purchase prices and related financing issues below in “— Liquidity and Capital Resources” and present the pro forma effects of the acquisition of G&L in note 3 of the unaudited historical financial statements included in this prospectus.

Selected 2003 Acquisitions

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

New Force Energy Services, Inc.

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

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FESCO Holdings, Inc./ First Energy Services Company

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

PWI Inc.

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

Pennant Services Company

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

Selected 2004 Acquisitions

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

Energy Air Drilling

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

AWS Wireline Services

      On November 1, 2004, we completed the acquisition of substantially all of the operating assets of AWS Wireline Services, a cased-hole wireline company based in Albany, Texas. This acquisition of six wireline units was our initial entry into the wireline business. This service is complementary to our

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existing pressure pumping service organization infrastructure in this same market area. This transaction was structured as an asset purchase for a total purchase price of approximately $4.3 million in cash.

Selected 2005 Acquisitions

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

MD Well Service, Inc.

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

Oilwell Fracturing Services, Inc.

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

Selected 2006 Acquisitions

      During the first six months of 2006, we made four acquisitions that complement our existing lines of business and increased our presence in the rental tool business. These included:

LeBus Oil Field Service Co.

      On January 31, 2006, we acquired all of the outstanding capital stock of LeBus Oil Field Service Co. (“LeBus”) for an acquisition price of $26 million, subject to adjustments. The acquisition will operate in our fluid services line of business in the Ark-La-Tex division. The cash used to acquire LeBus was primarily from borrowings under our 2005 Credit Facility.

G&L Tool, Ltd.

      On February 28, 2006, we acquired substantially all of the operating assets of G&L Tool, Ltd. (“G&L”) for total consideration of $58 million cash. This acquisition will operate in our drilling and completion line of business. The purchase agreement also contained an earn-out agreement based on annual EBITDA targets. The cash used to acquire G&L was primarily from borrowings under our 2005 Credit Facility. Certain pro forma effects of this acquisition are set forth in note 3 of the unaudited historical financial statements included in this prospectus.

Segment Overview

Well Servicing

      In 2005, our well servicing segment represented 48% of our revenues and, during the first six months of 2006, 46% 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

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services generate more revenue per hour than maintenance work due to the use of auxiliary equipment, but demand for workover and completion services fluctuates more with the overall activity level in the industry.

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

      The following is an analysis of our well servicing operations for each of the quarters and years in the years ended December 31, 2003, 2004 and 2005 and the quarters ended March 31, 2006 and June 30, 2006 (dollars in thousands):

	Weighted									Segment
	Average				Rig			Revenue		Profits
	Number		Rig		Utilization			per Rig		per Rig		Segment
	of Rigs		Hours		Rate			Hour		Hour		Profits %
2003:
First Quarter		252		128,200		71.2	%	$	188	$	52		27.2	%
Second Quarter		252		131,000		72.7	%	$	195	$	62		31.8	%
Third Quarter		252		133,200		73.9	%	$	200	$	62		30.8	%
Fourth Quarter		270		131,500		68.1	%	$	211	$	59		28.6	%
Full Year		257		523,900		71.4	%	$	199	$	59		29.6	%
2004:
First Quarter		272		145,900		75.0	%	$	218	$	69		31.5	%
Second Quarter		276		154,600		78.4	%	$	222	$	69		31.1	%
Third Quarter		282		162,400		80.5	%	$	234	$	72		30.6	%
Fourth Quarter		284		155,900		76.8	%	$	246	$	78		31.7	%
Full Year		279		618,800		77.8	%	$	230	$	72		31.2	%
2005:
First Quarter		291		175,300		84.3	%	$	255	$	94		37.1	%
Second Quarter		303		192,400		88.8	%	$	280	$	107		38.2	%
Third Quarter		311		198,000		89.0	%	$	299	$	108		36.0	%
Fourth Quarter		316		195,000		86.3	%	$	329	$	134		40.7	%
Full Year		305		760,700		87.1	%	$	292	$	111		38.1	%
2006:
First Quarter		327		209,000		89.4	%	$	352	$	152		43.4	%
Second Quarter		341		221,800		91.0	%	$	366	$	161		43.9	%

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

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

      We have been able to increase our revenue per rig hour from $195 in the second quarter of 2003 to $366 in the second quarter of 2006 mainly as a result of this higher utilization, which has contributed to our improved segment profits.

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Fluid Services

      In 2005, our fluid services segment represented 29% of our revenues and, during the first six months of 2006, 27% of our revenues. Revenues in our fluid services segment are earned from the sale, transportation, storage and disposal of fluids used in the drilling, production and maintenance of oil and gas wells. The fluid services segment has a base level of business consisting of transporting and disposing of salt water produced as a by-product of the production of oil and gas. These services are necessary for our customers and generally have a stable demand but typically produce lower relative segment profits than other parts of our fluid services segment. Fluid services for completion and workover projects typically require fresh or brine water for making drilling mud, circulating fluids or frac fluids used during a job, and all of these fluids require storage tanks and hauling and disposal. Because we can provide a full complement of fluid sales, trucking, storage and disposal required on most drilling and workover projects, the add-on services associated with drilling and workover activity enable us to generate higher segment profits contributions. The higher segment profits are due to the relatively small incremental labor costs associated with providing these services in addition to our base fluid services segment. We typically price fluid services by the job, by the hour or by the quantities sold, disposed of or hauled.

      The following is an analysis of our fluid services operations for each of the quarters and years in the years ended December 31, 2003, 2004 and 2005 and the quarters ended March 31, 2006 and June 30, 2006 (dollars in thousands):

	Weighted
	Average				Segment
	Number of		Revenue per		Profits per
	Fluid Service		Fluid Service		Fluid Service		Segment
	Trucks		Truck		Truck		Profits %
2003:
First Quarter		202	$	51	$	16		32.4	%
Second Quarter		209	$	53	$	18		34.7	%
Third Quarter		223	$	50	$	18		35.3	%
Fourth Quarter		363	$	56	$	21		35.8	%
Full Year		249	$	212	$	74		34.8	%
2004:
First Quarter		371	$	60	$	21		34.5	%
Second Quarter		376	$	61	$	20		33.4	%
Third Quarter		386	$	67	$	23		33.7	%
Fourth Quarter		411	$	68	$	23		34.3	%
Full Year		386	$	256	$	87		34.0	%
2005:
First Quarter		435	$	67	$	24		34.3	%
Second Quarter		447	$	71	$	26		37.0	%
Third Quarter		465	$	74	$	28		38.6	%
Fourth Quarter		472	$	79	$	31		39.8	%
Full Year		455	$	291	$	109		37.6	%
2006:
First Quarter		529	$	82	$	32		39.0	%
Second Quarter		568	$	86	$	34		39.9	%

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

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

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further increase our fluid services truck fleet through internal expansion. We also expanded this segment with the acquisition of LeBus during the first quarter of 2006.

      The majority of the increase in revenue per fluid services truck from $53,000 in the second quarter of 2003 to $86,000 in the second quarter of 2006 is due to the revenues derived from the expansion of our frac tank fleet and disposal facilities as well as increases in prices charged for our services. Our segment profits per fluid services truck have increased because of these factors and increased utilization of our equipment.

Drilling and Completion Services

      In 2005, our drilling and completion services segment represented 13% of our revenues and, during the first six months of 2006, 20% of our revenue. Revenues from our drilling and completion services segment are generally derived from a variety of services designed to stimulate oil and gas production or place cement slurry within the wellbores. Our drilling and completion services segment includes pressure pumping, cased-hole wireline services, underbalanced drilling and fishing and rental tool operations.

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

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

      We entered the fishing and rental tool business through our acquisition of G&L in the first quarter of 2006.

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

      The following is an analysis of our drilling and completion services for each of the quarters and years in the years ended December 31, 2003, 2004 and 2005 and the quarters ended March 31, 2006 and June 30, 2006 (dollars in thousands):

			Segment
	Revenues		Profits %
2003:
First Quarter	$	2,642		45.3	%
Second Quarter	$	3,454		32.7	%
Third Quarter	$	4,183		38.2	%
Fourth Quarter	$	4,529		33.6	%
Full Year	$	14,808		36.8	%

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			Segment
	Revenues		Profits %
2004:
First Quarter	$	4,865		35.5	%
Second Quarter	$	7,251		46.0	%
Third Quarter	$	8,463		41.0	%
Fourth Quarter	$	8,762		38.0	%
Full Year	$	29,341		40.4	%
2005:
First Quarter	$	10,764		45.6	%
Second Quarter	$	13,512		49.1	%
Third Quarter	$	15,883		48.2	%
Fourth Quarter	$	19,673		49.5	%
Full Year	$	59,832		48.4	%
2006:
First Quarter	$	27,455		49.5	%
Second Quarter	$	40,939		53.1	%

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

Well Site Construction Services

      In 2005, our well site construction services segment represented 10% of our revenues and, during the first six months of 2006, 7% of our revenues. Revenues from our well site construction services segment are derived primarily from preparing and maintaining access roads and well locations, installing small diameter gathering lines and pipelines, constructing foundations to support drilling rigs and providing maintenance services for oil and gas facilities. We entered the well site construction services segment during the fourth quarter of 2003 in the Gulf Coast through the acquisition of PWI and in the Rocky Mountain states through our acquisition of FESCO.

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

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      The following is an analysis of our well site construction services for the quarter ended December 31, 2003 (when we first entered this segment), each of the quarters and years in the years ended December 31, 2004 and 2005 and the quarters ended March 31, 2006 and June 30, 2006 (dollars in thousands):

			Segment
	Revenues		Profits %
2003:
Fourth Quarter	$	9,184		28.3	%
2004:
First Quarter	$	8,776		24.6	%
Second Quarter	$	9,869		21.3	%
Third Quarter	$	11,297		24.3	%
Fourth Quarter	$	10,985		22.4	%
Full Year	$	40,927		23.1	%
2005:
First Quarter	$	8,948		20.6	%
Second Quarter	$	10,918		30.8	%
Third Quarter	$	11,367		31.6	%
Fourth Quarter	$	14,414		33.6	%
Full Year	$	45,647		29.9	%
2006:
First Quarter	$	10,265		25.5	%
Second Quarter	$	12,879		31.5	%

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

Operating Cost Overview

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

Critical Accounting Policies and Estimates

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

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Critical Accounting Policies

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

     Property and Equipment. Property and equipment are stated at cost, or at estimated fair value at acquisition date if acquired in a business combination. Expenditures for repairs and maintenance are charged to expense as incurred. We also review the capitalization of refurbishment of workover rigs as described in note 2 of the notes to our audited 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 our24-hour workover rigs and newly manufactured rigs. We have deductibles per occurrence for workers’ compensation and medical and dental coverage of $150,000 and $125,000, respectively. We have lower deductibles per occurrence for automobile liability and general liability. We maintain accruals in our consolidated balance sheets related to self-insurance retentions by using third party data and historical claims history.

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

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

Critical Accounting Estimates

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

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

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

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

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

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

      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

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growth and acquisitions and because we had consistently used our internal valuation methodology for previous stock awards.

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

      As disclosed in note 10 to our audited historical consolidated financial statements for the year ended December 31, 2005, we granted stock options as follows for the year ended December 31, 2005:

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

      The reasons for the differences between the fair value per share at the option grant date and our December 2005 initial public offering price of $20.00 are as follows:

• During the three months ended March 31, 2005, we closed four acquisitions which added two well servicing rigs, 12 fluid hauling trucks/trailers, two salt water disposal wells and other equipment. Industry conditions also improved in the first quarter. As a result of this, our revenues exceeded the first quarter projected revenues by 12%. In addition, we placed an order for six new well servicing rigs which were delivered throughout the remainder of 2005.

• During the three months ended June 30, 2005, we closed two acquisitions which added six well servicing rigs and additional pressure pumping equipment. Demand for our equipment and services continued to strengthen during this quarter. Our well servicing rig revenue per hour increased by 10% from the first quarter of 2005. Based on the market outlook, we placed an order for an additional 24 new well servicing rigs, five of which were put into service later in 2005.

• We increased our projected EBITDA and cash flows for 2005 and 2006 due to the acquisitions and improved operating results.

• Market prices of publicly traded energy service companies have increased significantly from January 1, 2005 due to increases in demand caused by increasing commodity prices.

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

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

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     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 becomes 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.

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

     Revenues. Revenues increased 66% to $338.1 million in the first six months in 2006 from $203.6 million during the same period 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 higher oil and gas prices.

      Well servicing revenues increased 57% to $154.6 million during the first six months in 2006 compared to $98.7 million during the same period in 2005. This increase was due primarily to the internal growth of this segment as well as an increase in our revenue per rig hour of approximately 34%, from $268 per hour to $359 per hour. Our weighted average number of rigs increased to 336 during the first six months in 2006 compared to 298 in the same period in 2005, an increase of approximately 13%. In addition, the utilization rate of our rig fleet increased to 89.7% during the first six months of 2006 compared to 86.3% in the same period in 2005.

      Fluid services revenues increased 51% to $92.0 million during the first six months in 2006 as compared to $60.8 million in the same period in 2005. The increase in revenue was due primarily to our internal growth of this segment. Our weighted average number of fluid service trucks increased to 559 during the first six months in 2006 compared to 443 in the same period in 2005, an increase of approximately 26%. The increase in weighted average number of fluid service trucks is primarily due to internal expansion as well as the trucks added from the LeBus acquisition. During the first six months in 2006, our average revenue per fluid service truck was approximately $165,000 as compared to approximately $137,000 in the same period in 2005. The increase in average revenue per fluid service truck reflects the expansion of our frac tank fleet and saltwater disposal operations, and increases in prices charged for our services.

      Drilling and completion services revenue increased 182% to $68.4 million during the first six months in 2006 as compared to $24.3 million in the same period in 2005. The increase in revenue between these periods was primarily the result of internal expansion, the acquisition of Oilwell Fracturing Services in October 2005, the acquisition of G&L during February 2006 and improved pricing and utilization of our services.

      Well-site construction services revenue increased 17% to $23.1 million during the first six months in 2006 as compared to $19.9 million during the same period in 2005.

     Direct Operating Expenses. Direct operating expenses, which primarily consist of labor, including workers compensation and health insurance, and maintenance and repair costs, increased 50% to $192.3 million during the first six months of 2006 from $128.0 million in the same period in 2005 primarily as a result of additional rigs and trucks, as well as higher utilization of our equipment. Operating expenses decreased to 57% of revenue for the first six months of 2006 from 63% in the same period in 2005, as fixed operating costs such as field supervision, insurance and vehicle

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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 42% to $87.1 million in the first six months of 2006 compared to $61.5 million in the same period in 2005 primarily due to the internal growth of this segment. Segment profits for this segment increased to 43.6% of revenues during the first six months of 2006 compared to 37.7% in the same period in 2005 primarily due to the improved pricing and higher utilization of our equipment.

      Direct operating expenses for the fluid services segment increased 42% to $55.6 million in the first six months of 2006 compared to $39.1 million in the same period in 2005 primarily due to increased activity and expansion of our fluid services fleet. Segment profits for this segment increased to 39.5% of revenues during the first six months of 2006 compared to 35.7% in the same period in 2005 primarily due to the expansion of our frac tank fleet and saltwater disposal operations, and increases in prices charged for our services.

      Direct operating expenses for the drilling and completion services segment increased 159% to $33.0 million during the first six months of 2006 compared to $12.7 million in the same period in 2005 primarily due to the increased activity and expansion of our services and equipment, including the G&L acquisition. Segment profits for this segment increased to 51.7% of revenues during the first six months of 2006 compared to 47.6% in the same period in 2005.

      Direct operating expenses for the well-site construction services segment increased 12% to $16.5 million during the first six months of 2006 compared to $14.7 million in the same period in 2005. Segment profits for this segment increased to 28.9% of revenues during the first six months of 2006 compared to 26.2% in the same period in 2005.

     General and Administrative Expenses. General and administrative expenses increased 44% to $38.1 million during the first six months of 2006 from $26.5 million in the same period in 2005. The increase primarily reflects higher salary and office expenses related to the expansion of our business as well as additional staffing to enhance internal controls as a public company.

     Depreciation and Amortization Expenses. Depreciation and amortization expenses were $28.0 million for the first six months of 2006 and $16.8 million in the same period in 2005, reflecting the increase in the size and investment in our asset base. We invested $99.0 million for acquisitions and an additional $48.8 million for capital expenditures, including capital leases, in the first six months in 2006.

     Interest Expense. Interest expense was $7.8 million during the first six months of 2006 compared to $6.2 million in the same period in 2005.

     Loss on Early Extinguishment of Debt. Loss on early extinguishment of debt was $2.7 million during the six months ended June 30, 2006 compared to $0 in same period in 2005. The loss related to the payment in full of the Term B Loan.

     Income Tax Expense (Benefit). Income tax expense was $25.3 million during the first six months of 2006 compared to $10.0 million in the same period in 2005, reflecting the improvement in our profitability. Our effective tax rate in the first six months of 2006 and 2005 was approximately 36% and 38%.

     Net Income. Our net income increased to $44.2 million during the first six months of 2006 from $16.6 million in the same period in 2005. This improvement was due primarily to the factors described above, including our increased asset base and related revenues, higher utilization rates and increased revenues per rig and fluid service truck, and higher operating margins on our drilling and completion services equipment.

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

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

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

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

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

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

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

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

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

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

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

     General and Administrative Expenses. General and administrative expenses increased by 49% to $55.4 million in 2005 from $37.2 million in 2004 which included $2.9 million and $1.6 million of stock-

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based compensation expense in 2005 and 2004, respectively. The increase primarily reflects higher salary and office expenses related to the expansion of our business.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

     Interest Expense. Interest expense increased 85.6% to $9.7 million in 2004 from $5.2 million in 2003. The increase was due to an increase in long-term debt which was primarily used in connection with our acquisitions, most of which was added in the fourth quarter of 2003, and capital expenditures for property and equipment. In addition, both prime and LIBOR interest rates increased in 2004, and our Term B Loan interest rate is tied directly to these rates. Our 2003 interest expense was favorably impacted by the reduced interest rate we received in our January 2003 refinancing, as well as an additional reduction in interest rates in our October 2003 refinancing. As part of the refinancings in January 2003 and October 2003, we recognized a loss of $5.2 million from the early extinguishment of debt. As part of our 2004 refinancing, we further reduced our base interest rate by 50 basis points. See “— Liquidity and Capital Resources.”

     Income Tax Expense. Income taxes increased to an $8.0 million expense in 2004 from a $2.8 million expense in 2003. The change was due to improved profitability offset in part by a decrease in the effective tax rate in 2004. The effective tax rate in 2004 was approximately 38.2% as compared to 48.3% in 2003. The decrease in the effective tax rate in 2004 was due primarily to an adjustment of

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the federal tax rate from 34% in previous years to 35% in 2003, and the associated effects on our deferred tax liability.

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

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

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

Liquidity and Capital Resources

      Currently, our primary capital resources are net cash flows from our operations, utilization of capital leases as allowed under our 2005 Credit Facility and availability under our 2005 Credit Facility, of which approximately $140.4 million was available at June 30, 2006. As of April 30, 2006, we had paid down all amounts under the revolving portion of our 2005 Credit Facility with the proceeds from our offering of Senior Notes and had availability of $140.4 million and $9.6 million of letters of credit outstanding under this facility. As of June 30, 2006, we had cash and cash equivalents of $37.5 million compared to $14.1 million as of June 30, 2005. We have utilized, and expect to utilize in the future, bank and capital lease financing and sales of equity to obtain capital resources. When appropriate, we will consider public or private debt and equity offerings and non-recourse transactions to meet our liquidity needs.

Net Cash Provided By Operating Activities

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

      Cash flow from operating activities was $51.0 million during the first six months of 2006 as compared to $44.8 million during the same period in 2005. The increase in operating cash flows in the first six months of 2006 over the same period in 2005 was primarily due to expansion of our fleet and improvements in the segment profits and utilization of our equipment.

Capital Expenditures

      Capital expenditures are the main component of our investing activities. Cash capital expenditures (including for acquisitions) for the first six months in 2006 were $147.8 million as compared to

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$45.4 million for the same period in 2005. In the first six months of 2006, the majority of our capital expenditures were for business acquisitions, whereas 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 $12.1 million in the first six months of 2006 compared to $3.6 million in the same period in 2005. Cash capital expenditures (including acquisitions) for 2005 were $108.5 million as compared to $75.0 million in 2004, and $85.4 million in 2003. In 2005 and 2004, the majority of our capital expenditures were for the expansion of our fleet. In 2003 the majority of our capital expenditures were for acquisitions. In 2003, we issued 3,650,000 shares of common stock as part of the FESCO acquisition which added a non-cash cost to acquisitions of $18.8 million and is in addition to the $85.4 million spent in 2003. In 2003, we experienced a significant increase in our acquisition activity as compared to the previous periods which allowed us to expand our services and regions where we operate. We also added assets through our capital lease program of approximately $10.3 million, $10.5 million, and $10.8 million in 2005, 2004 and 2003, respectively.

      For 2006, we currently have planned approximately $93 million in cash capital expenditures, none of which is planned for acquisitions. We do not budget acquisitions in the normal course of business, but we completed four acquisitions for total consideration paid of $99.0 million, net of cash acquired during the first six months of 2006 and expect to make additional acquisitions in 2006. The $93 million of capital expenditures planned for property and equipment is primarily for (1) purchase of additional equipment to expand our services, (2) continued refurbishment of our well servicing rigs and (3) replacement of existing equipment. We have taken delivery of 54 newbuild will servicing rigs since October 2004 as part of a 102-rig newbuild commitment. The remainder of these newbuilds is scheduled to be delivered to us prior to the end of December 2007. As of June 30, 2006, we had three executed letters of intent for acquisitions.

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

Capital Resources and Financing

      Our current primary capital resources are cash flow from our operations, the ability to enter into capital leases of up to an additional $20.9 million at June 30, 2006, the availability under our credit facility of $140.4 million at June 30, 2006 and a cash balance of $37.5 million at June 30, 2006. As of April 30, 2006, we had paid down all amounts under revolving borrowings under our 2005 Credit Facility with the proceeds from our offering of Senior Notes. During the first six months of 2006, we financed activities in excess of cash flow from operations primarily through the use of bank debt and capital leases. In 2005, we financed activities in excess of cash flow from operations primarily through the use of bank debt and capital leases. During 2004 and 2003, we utilized bank debt and the issuance of equity for cash as consideration for acquisitions.

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      We have significant contractual obligations in the future that will require capital resources. Our primary contractual obligations are (1) our long-term debt, (2) our capital leases, (3) our operating leases, (4) our rig purchase obligations, (5) our asset retirement obligations and (6) other long-term liabilities. The following table outlines our contractual obligations as of December 31, 2005 (in thousands):

		Obligations Due in Periods Ended December 31,
Contractual Obligations		Total		2006		2007-2008		2009-2010		Thereafter
Long-term debt (excluding capital leases)		$	106,000	$	1,000	$	2,000	$	18,000	$	85,000
Capital leases			20,887		6,646		11,142		3,099		—
Operating leases			4,199		1,198		1,540		998		463
Rig purchase obligations			45,109		22,629		22,480		—		—
Asset retirement obligations			569		—		—		—		569
Other long-term liabilities			1,497		25		1,235		—		237
	Total	$	178,261	$	31,498	$	38,397	$	22,097	$	86,269

      Our long-term debt, excluding capital leases, consists primarily of Term B Loan indebtedness outstanding under our 2005 Credit Facility. Our capital leases relate primarily to light-duty and heavy-duty vehicles and trailers. Our operating leases relate primarily to real estate. Our rig purchase obligations relate to our commitments to purchase new well servicing rigs. Our other long-term liabilities relate to contractual obligations under an employee deferred compensation plan.

      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 June 30, 2006, we had a maximum potential obligation of $20.5 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 exceeds an annual targeted EBITDA. There is no guarantee or assurance that the targeted EBITDA will be reached. See note 3 of the notes to our audited and unaudited historical consolidated financial statements for additional detail.

      The table above also does not reflect $9.6 million of outstanding standby letters of credit issued under our revolving line of credit. At June 30, 2006, of the $150.0 million in financial commitments under the revolving line of credit under our 2005 Credit Facility, there was $140.4 million of available capacity with no outstanding balance and $9.6 million of outstanding standby letters of credit. In the normal course of business, we have performance obligations which are supported by surety bonds and letters of credit. These obligations primarily cover various reclamation and plugging obligations related to our operations, and collateral for future workers compensation and liability retained losses.

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

Senior Notes

      In April 2006, we completed a private offering for $225,000,000 aggregate principal amount of 7.125% Senior Notes due April 15, 2016. The Senior Notes are jointly and severally guaranteed by each of our subsidiaries. The net proceeds from the offering were used to retire the outstanding Term B Loan balance and to pay down the outstanding balance under the revolving credit facility. Remaining proceeds will be 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.

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      Interest on the Senior Notes will accrue from and including April 12, 2006 at a rate of 7.125% per year. Interest on the Senior Notes is payable in cash semi-annually in arrears on April 15 and October 15 of each year, commencing on October 15, 2006. The Senior Notes will mature on April 15, 2016. The Senior Notes and the guarantees are unsecured and will rank equally with all of our and the guarantors’ existing and future unsecured and unsubordinated obligations. The Senior Notes and the guarantees will rank senior in right of payment to any of our and the guarantors’ existing and future obligations that are, by their terms, expressly subordinated in right of payment to the Senior Notes and the guarantees. The Senior Notes and the guarantees will be effectively subordinated to our and the guarantors’ secured obligations, including our senior secured credit facilities, to the extent of the value of the assets securing such obligations.

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

• incur additional indebtedness;

• pay dividends or repurchase or redeem capital stock;

• make certain investments;

• incur liens;

• enter into certain types of transactions with affiliates;

• limit dividends or other payments by restricted subsidiaries; and

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

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

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

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

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

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

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

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

Credit Facilities

2005 Credit Facility

      Under our Third Amended and Restated Credit Agreement with a syndicate of lenders (the “2005 Credit Facility”), as amended effective March 28, 2006, Basic Energy Services, Inc. is the sole borrower and each of our subsidiaries is a subsidiary guarantor. The 2005 Credit Facility provided for a

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$90 million Term B Loan (“Term B Loan”), which outstanding balance was repaid in April 2006, and provides for a $150 million revolving line of credit (“Revolver”). The 2005 Credit Facility includes provisions allowing us to request an increase in commitments under the Term B Loan or the Revolver of up to $75 million at any time.

      The commitment under the Revolver provides for (1) the borrowing of funds, (2) the issuance of up to $30 million of letters of credit and (3) $2.5 million of swing-line loans. The amounts outstanding under the Term B Loan required quarterly amortization at various amounts during each quarter with all amounts outstanding being due and payable in full on December 15, 2011. All the outstanding amounts under the Revolver are due and payable on December 15, 2010. The 2005 Credit Facility is secured by substantially all of our tangible and intangible assets.

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

      At our option, borrowings under the Revolver bear interest at either (1) the Alternative Base Rate plus a margin ranging from 0.50% to 1.25% or (2) the LIBOR rate plus a margin ranging from 1.50% to 2.25%. The margins vary depending on our leverage ratio. At March 31, 2006, our margin on Alternative Base Rates and LIBOR tranches was 0.75% and 1.75%, respectively. Fees on the letters of credit are due quarterly on the outstanding amount of the letters of credit at a rate ranging from 1.50% to 2.25% for participation fees and 0.125% for fronting fees. A commitment fee is due quarterly on the available borrowings under the Revolver at rates ranging from 0.375% to 0.50%.

      At June 30, 2006, we had no amounts outstanding under the Term B Loan or under the Revolver.

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

• assets sales greater than $2.0 million individually or $7.5 million in the aggregate on an annual basis;

• 50% of the proceeds from any equity offering;

• proceeds of any issuance of debt not permitted by the 2005 Credit Facility;

• proceeds of permitted unsecured indebtedness, such as the Senior Notes, without reducing commitments under the revolver; and

• proceeds in excess of $2.5 million from casualty events.

      Prior to the date on which all Term B Loans were paid in April 2006, the 2005 Credit Facility required us to enter into an interest rate hedge, acceptable to the lenders, until May 28, 2006 on at least $65 million of our then-outstanding indebtedness.

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

• limitations on the incurrence of additional indebtedness;

• restrictions on mergers, sales or transfer of assets without the lenders’ consent;

• limitation on dividends and distributions;

• limitations on capital expenditures; and

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• various financial covenants, including:

• a maximum leverage ratio of 3.50 to 1.00 reducing to 3.25 to 1.00, and

• a minimum interest coverage ratio of 3.00 to 1.00.

      The 2005 Credit Facility contains customary events of default (which are subject to customary grace periods and materiality standards) including, among others: (1) non-payment of any amounts payable under the 2005 Credit Facility when due; (2) any representation or warrant made in connection with the 2005 Credit Facility being incorrect in any material respect when made or deemed made; (3) default in the observance or performance of any covenant, condition or agreement contained in the 2005 Credit Facility or related loan documents and such default continuing unremedied or not being waived for 30 days; (4) failure to make payments on other indebtedness involving in excess of $1.0 million; (5) voluntary or involuntary bankruptcy, insolvency or reorganization of us or any of our subsidiaries; (6) entry of fines or judgments against us for payment of an amount in excess of $2.5 million; (7) an ERISA event which could reasonably be expected to cause a material adverse effect or the imposition of a lien on any of our assets; (8) any security agreement or document under the 2005 Credit Facility ceasing to create a lien on any assets securing the 2005 Credit Facility; (9) any guarantee ceasing to be in full force and effect; (10) any material provision of the 2005 Credit Facility ceasing to be valid and binding or enforceable; (11) a change of control as defined in the 2005 Credit Agreement; or (12) any determination, ruling, decision, decree or order of any governmental authority that prohibits or restrains us and our subsidiaries from conducting business and that could reasonably be expected to cause a material adverse effect. At June 30, 2006, we were in compliance with our covenants under our 2005 Credit Facility.

2004 Credit Facility

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

2003 Credit Facility

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

2003 Refinancing Facility

      In January 2003, we refinanced our then-existing credit facilities by entering into a $62 million credit facility with a capital markets group for a combination of term and revolving loans, and a $22 million revolving line of credit with a bank (collectively, the “2003 Refinancing Facility”). The interest rates on the loans under the 2003 Refinancing Facility were tied to a variable index plus a

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margin. At the date the 2003 Refinancing Facility was terminated and refinanced by the 2003 Credit Facility, the outstanding principal balance was approximately $54 million. We incurred approximately $2.5 million in debt issuance costs in obtaining the 2003 Refinancing Facility.

Other Debt

      We have a variety of other capital leases and notes payable outstanding that are generally customary in our business. None of these debt instruments are material individually or in the aggregate. As of June 30, 2006, we had total capital leases of approximately $29.1 million.

Losses on Extinguishment of Debt

      In April 2006, we recognized a loss on the early extinguishment of debt of $2.7 million representing unamortized deferred debt issuance costs in connection with the retirement of the Term B Loan.

      In 2005 we recognized a loss on the early extinguishment of debt of $627,000 in connection with our 2005 Credit Facility discussed above. In 2003, we recognized a loss on the early extinguishment of debt. We paid termination fees of approximately $1.7 million and wrote off unamortized debt issuance costs of approximately $3.5 million, which resulted in a loss of approximately $5.2 million. The 2003 Refinancing Facility was done (1) to provide for a facility which would better accommodate acquisitions and (2) to realize better interest rate margins and fees. The 2003 Credit Facility was primarily done to enable us to fund the significant acquisitions in the fourth quarter in 2003, which could not be economically negotiated under the 2003 Refinancing Facility.

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

Credit Rating Agencies

      Effective November 22, 2005, we received credit ratings of Ba3 from Moody’s and B+ from Standard & Poor’s for the 2005 Credit Facility. We received initial credit ratings of B1 from Moody’s and B from Standard and Poor’s for the Senior Notes issued in April 2006. None of our debt or other instruments is dependent upon our credit ratings. However, the credit ratings may affect our ability to obtain financing in the future.

Preferred Stock

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

Other Matters

Net Operating Losses

      We used all of our then-available net operating losses for federal income tax purposes when we completed a recapitalization in December 2000, which included a significant amount of debt forgiveness. In 2002, our profitability suffered and, when combined with a significant level of capital expenditures, we ended 2002 with a net operating loss, or NOL, of $30.4 million. In 2003, we returned to profitability, but we again made significant investments in existing equipment, additional equipment

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and acquisitions. Due to these events, we again reported a tax loss in 2003 and ended the year with a $50.7 million NOL, including $7.0 million that was included in the purchase of FESCO. As of December 31, 2005, we had approximately $4.9 million of NOL carryforwards related to the pre-acquisition period of FESCO, which is subject to an annual limitation of approximately $900,000. The carryforwards begin to expire in 2017.

Recent Accounting Pronouncements

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

      Compensation cost for the unvested portion of awards that are outstanding as of January 1, 2006 will be recognized ratably over the remaining vesting period. The compensation cost for the unvested portion of awards will be based on the fair value at date of grant as calculated for our pro forma disclosure under SFAS No. 123. However, we will continue to account for any portion of awards outstanding on January 1, 2006 that were initially measured using the minimum value method under the intrinsic value method in accordance with APB No. 25. We began to recognize compensation expense for awards under our 2003 Incentive Plan on January 1, 2006.

      We estimate that the effect on net income and earnings per share in the periods following adoption of SFAS No. 123R will be consistent with our pro forma disclosure under SFAS No. 123, except that estimated forfeitures will be considered in the calculation of compensation expense under SFAS No. 123R and volatility will be considered in determination of grant date fair value under SFAS 123R. However, the actual effect on net income and earnings per share will vary depending upon the number of options granted in future years compared to prior years and the number of shares exercised under our 2003 Incentive Plan. Further, we will use the Black-Scholes-Merton model to calculate fair value.

      In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation No. 48 (FIN 48),Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109,Accounting for Income Taxes. The interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken, in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties accounting in interim periods, disclosure and transition. The interpretation is effective for fiscal years beginning after December 15, 2006. We have not determined the effects that adoption of FIN 48 will have on our financial position, cash flows and results of operations.

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Impact of Inflation on Operations

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

Quantitative and Qualitative Disclosures about Market Risk

      As of June 30, 2006, we had no outstanding borrowings subject to variable interest rate risk. In April 2006, we completed a private offering for $225,000,000 aggregate principal amount of 7.125% Senior Notes. The net proceeds from the offering were used to retire the outstanding Term B Loan balance and to pay down the outstanding balance under the revolving credit facility. When the Term B Loan was retired, we settled an existing interest rate swap agreement and realized a gain on settlement of $287,000.

      However, we do have available borrowing capacity under the revolving credit facility, and we will be subject to variable interest rate risk in the event we have outstanding borrowings under the revolving credit facility in the future.

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BUSINESS

General

      We provide a wide range of well site services to oil and gas drilling and producing companies, including well servicing, fluid services, drilling and completion services and well site construction services. These services are fundamental to establishing and maintaining the flow of oil and gas throughout the productive life of a well. Our broad range of services enables us to meet multiple needs of our customers at the well site. Our operations are managed regionally and are concentrated in the major United States onshore oil and gas producing regions in Texas, New Mexico, Oklahoma and Louisiana and the Rocky Mountain states. We provide our services to a diverse group of over 1,000 oil and gas companies. We operate the third-largest fleet of well servicing rigs (also commonly referred to as workover rigs) in the United States, representing approximately 13% of the overall available U.S. fleet. Our two larger competitors control approximately 32% and 18%, respectively, as of June 2006, according to the Association of Energy Services Companies and other publicly available data.

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

•   Well Servicing. Our well servicing segment (48% of our revenues in 2005 and 46% of our revenues in the first six months of 2006) operates our fleet of over 340 well servicing rigs and related equipment. This business segment encompasses a full range of services performed with a mobile well servicing rig, including the installation and removal of downhole equipment and elimination of obstructions in the well bore to facilitate the flow of oil and gas. These services are performed to establish, maintain and improve production throughout the productive life of an oil and gas well and to plug and abandon a well at the end of its productive life. Our well servicing equipment and capabilities are essential to facilitate most other services performed on a well.

•   Fluid Services. Our fluid services segment (29% of our revenues in 2005 and 27% of our revenues in the first six months of 2006) utilizes our fleet of over 590 fluid services trucks and related assets, including specialized tank trucks, storage tanks, water wells, disposal facilities and related equipment. These assets provide, transport, store and dispose of a variety of fluids. These services are required in most workover, drilling and completion projects and are routinely used in daily producing well operations.

•   Drilling and Completion Services. Our drilling and completion services segment (13% of our revenues in 2005 and 20% of our revenues in the first six months of 2006) operates our fleet of 74 pressure pumping units, 31 air compressor packages specially configured for underbalanced drilling operations and 10 cased-hole wireline units. These services are designed to initiate or stimulate oil and gas production. The largest portion of this business consists of pressure pumping services focused on cementing, acidizing and fracturing services in niche markets. We also entered the fishing and rental tool business through an acquisition in the first quarter of 2006.

•   Well Site Construction Services. Our well site construction services segment (10% of our revenues in 2005 and 7% of our revenues in the first six months of 2006) utilizes our fleet of over 200 operated power units, which include dozers, trenchers, motor graders, backhoes and other heavy equipment. We utilize these assets primarily to provide services for the construction and maintenance of oil and gas production infrastructure, such as preparing and maintaining access roads and well locations, installation of small diameter gathering lines and pipelines and construction of temporary foundations to support drilling rigs.

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Our Competitive Strengths

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

     Significant Market Position. We maintain a significant market share for our well servicing operations in our core operating areas throughout Texas and a growing market share in the other markets that we serve. Our fleet of over 340 well servicing rigs represents the third-largest fleet in the United States, and our goal is to be one of the top two providers of well site services in each of our core operating areas. Our market position allows us to expand the range of services performed on a well throughout its life, such as completion, maintenance, workover and plugging and abandonment services.

     Modern and Active Fleet. We operate a modern and active fleet of well servicing rigs. We believe over 95% of the active U.S. well servicing rig fleet was built prior to 1985. Approximately 112, or 32%, of our rigs at June 30, 2006 were either 2000 model year or newer, or have undergone major refurbishments during the last four years. Since October 2004, we have taken delivery of 54 newbuild well servicing rigs through June 30, 2006 as part of a 102-rig newbuild commitment, driven by our desire to maintain one of the most efficient, reliable and safest fleets in the industry. The remainder of these newbuilds is scheduled to be delivered to us prior to the end of December 2007. In addition to our regular maintenance program, we have an established program to routinely monitor and evaluate the condition of our fleet. We selectively refurbish rigs and other assets to maintain the quality of our service and to provide a safe work environment for our personnel and have made major refurbishments on 52 of our rigs since the beginning of 2001. Approximately 98% of our fleet was active or available for work and the remainder was awaiting refurbishment at June 30, 2006. We believe only approximately 66% of the well servicing rig fleet of our two major competitors are active and available for work. Since 2003, we have obtained annual independent reviews and evaluations of substantially all of our assets, which confirmed the location and condition of these assets.

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

     Diversified Service Offering for Further Revenue Growth. Our experience, equipment and network of over 90 service locations position us to market our full range of well site services to our existing customers. We believe our range of well site services provides us a competitive advantage over smaller companies that typically offer fewer services. By utilizing a wider range of our services, our customers can use fewer service providers, which enables them to reduce their administrative costs and simplify their logistics. Furthermore, offering a broader range of services allows us to capitalize on our existing customer base and management structure to grow within existing markets, generate more business from existing customers, and increase our operating profits as we spread our overhead costs over a larger revenue base.

     Decentralized Management with Strong Corporate Infrastructure. Our corporate group is responsible for maintaining a unified infrastructure to support our diversified operations through standardized financial and accounting, safety, environmental and maintenance processes and controls. Below our corporate level, we operate a decentralized operational organization in which our seven regional managers are responsible for their regional operations, including asset management, cost control, policy compliance and training and other aspects of quality control. With an average of over

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28 years of industry experience, each regional manager has extensive knowledge of the customer base, job requirements and working conditions in each local market. Below our seven regional or product line managers, our area managers are directly responsible for customer relationships, personnel management, accident prevention and equipment maintenance, the key drivers of our operating profitability. This management structure allows us to monitor operating performance on a daily basis, maintain financial, accounting and asset management controls, integrate acquisitions, prepare timely financial reports and manage contractual risk.

Our Business Strategy

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

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

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

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

     Pursue Growth Through Selective Capital Deployment. We intend to continue growing our business through selective acquisitions, continuing a newbuild program and/or upgrading our existing assets. Our capital investment decisions are determined by an analysis of the projected return on capital employed of each of those alternatives. Acquisitions are evaluated for “fit” with our area and

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regional operations management and are thoroughly reviewed by corporate level financial, equipment, safety and environmental specialists to ensure consideration is given to identified risks. We also evaluate the cost to acquire existing assets from a third party, the capital required to build new equipment and the point in the oil and gas commodity price cycle. Based on these factors, we make capital investment decisions that we believe will support our long-term growth strategy, and these decisions may involve a combination of asset acquisitions and the purchase of new equipment. In 2005, we completed eight separate acquisitions for an aggregate purchase price of $25.4 million net of cash acquired, and took delivery of 31 new well servicing rigs. In the first six months of 2006, we completed four separate acquisitions for an aggregate purchase price of $99.0 million net of cash acquired, and took delivery of 19 new well servicing rigs.

General Industry Overview

      Demand for services offered by our industry is a function of our customers’ willingness to make operating and capital expenditures to explore for, develop and produce hydrocarbons in the U.S., which in turn is affected by current and expected levels of oil and gas prices. The following industry statistics illustrate the growing spending dynamic in the U.S. oil and gas sector (including the offshore sector that we do not serve):

• With the rebound in oil and gas prices in early 1999, oil and gas companies have increased their drilling and workover activities. The increased activity resulted in increased exploration and production spending compared to the prior year of 16% and 30% in 2004 and 2005, respectively, and is expected to increase 16% in 2006, according to www.WorldOil.com.

• A survey of 18 U.S. major integrated and 130 independent oil and gas companies by World Oil Magazine projected the U.S. drilling activity in 2006 to be skewed more towards independent players. Specifically, independent oil and gas companies, which represent over 90% of our revenues, are expected to drill 27% more wells in 2006 than in 2005, while the major integrated producers are expected to drill only 16% more wells over the same period. This trend is primarily driven by the increased acquisitions of proved oil and gas properties by independent producers. When these types of properties are acquired, purchasers typically intensify drilling, workover and well maintenance activities to accelerate production from the newly acquired reserves.

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

	Cushing WTI Spot		Average Wellhead Price
Period	Oil Price ($/bbl)		Natural Gas ($mcf)
1/1/99 — 12/31/99	$	19.34	$	2.19
1/1/00 — 12/31/00		30.38		3.69
1/1/01 — 12/31/01		25.97		4.01
1/1/02 — 12/31/02		26.18		2.95
1/1/03 — 12/31/03		31.08		4.98
1/1/04 — 12/31/04		41.51		5.49
1/1/05 — 12/31/05		56.64		7.51
1/1/06 — 6/30/06		66.89		6.84

Source: U.S. Department of Energy.

      Increased expenditures for exploration and production activities generally involve the deployment of more drilling and well servicing rigs, which often serves as an indicator of demand for our services. Rising oil and gas prices since early 1999 and the corresponding increase in onshore oil exploration

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and production spending have led to expanded drilling and well service activity, as the U.S. land-based drilling rig count increased approximately 36% from year-end 2002 to year-end 2003, 11% from year-end 2003 to year-end 2004, 22% from year-end 2004 to year-end 2005 and 9% during the first six months of 2006, according to Baker Hughes. In addition, the U.S. land-based workover rig count increased approximately 13% from year-end 2002 to year-end 2003, 10% from year-end 2003 to year-end 2004, 17% from year-end 2004 to year-end 2005 and 9% during the first six months of 2006, according to Baker Hughes.

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

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

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

      Our business is influenced substantially by both operating and capital expenditures by oil and gas companies. Because existing oil and gas wells require ongoing spending to maintain production, expenditures by oil and gas companies for the maintenance of existing wells are relatively stable and predictable compared to exploration and drilling expenditures. In contrast, capital expenditures by oil and gas companies for 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 348 well service rigs as of June 30, 2006, including 54 newbuilds since October 2004 and 52 rebuilds since the beginning of 2001. We operate from more than 90 facilities in Texas, Wyoming, Oklahoma, New Mexico, Louisiana, Colorado, Montana, North Dakota, Arkansas and Utah, most of which are used jointly for our business segments. Our rigs are mobile units that generally operate within a radius of approximately 75 to 100 miles from their respective bases. Prior to December 2004, our well servicing segment consisted entirely of land-based equipment. During December 2004, we acquired three inland barges, two of which are equipped with rigs, have been refurbished and were placed into service in the second quarter of 2005. Inland barges are used to service wells in shallow water marine environments, such as coastal marshes and bays.

      The following table sets forth the location, characteristics and number of the well servicing rigs that we operated at June 30, 2006. We categorize our rig fleet by the rated capacity of the mast, which indicates the maximum weight that the rig is capable of lifting. This capability is the limiting factor in our ability to provide services. These figures do not include 48 new well servicing rigs that we have contracted for delivery from July 2006 through December 2007 as part of a 102-rig newbuild commitment:

				Operating Division
				Permian		South		Ark-		Mid-		Northern		Southern
Rig Type		Rated Capacity		Basin		Texas		La-Tex		Continent		Rockies		Rockies		Stacked		Total
Swab			N/A		3		1		8		4		0		0		0		16
Light Duty			<90 tons		14		2		0		24		2		0		2		44
Medium Duty		>90-125 tons			94		35		23		38		18		18		1		227
Heavy Duty			2/3125 tons		28		3		6		5		5		3		2		52
24-Hour			2/3125 tons		1		4		0		0		0		0		0		5
Drilling Rigs			2/3125 tons		0		0		0		0		0		2		0		2
Inland Barge			2/3125 tons		0		0		2		0		0		0		0		2
	Total		128		140		45		39		71		25		23		5		348

      Management estimates that there are approximately 3,500 onshore well servicing rigs currently in the U.S., owned by an estimated 125 contractors, and that the actual number that are actively marketed and operable without major capital expenditures may be as much as 20% lower than this estimate. Based on information from U.S. contractors reporting their utilization to Weatherford-AESC, there were 2,514 well servicing rigs working in June 2006. This figure represents a projected utilization rate of 92% for the available fleet that are operable without major capital expenditures.

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

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      Based on the most recent publicly available information, our two largest competitors own a combined 2,053 rigs of which 1,361 are marketed and 692 are stacked. These two competitors’ total rigs represent approximately 59% of the industry’s total fleet. We have the third-largest fleet with over 340 rigs, or about 10% of the overall U.S. industry’s fleet. Due to the fragmented nature of the market, we believe only one company other than us and our two larger competitors owns more than 50 rigs (with a total of only approximately 135 rigs) and a total of an estimated 120 companies own the approximately 900 estimated remaining well servicing rigs, or approximately 26% of the industry’s total fleet.

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

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

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

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

     New Well Completion. New well completion services involve the preparation of newly drilled wells for production. The completion process may involve selectively perforating the well casing in the productive zones to allow oil or gas to flow into the well bore, stimulating and testing these zones and installing the production string and other downhole equipment. We provide well service rigs to assist in this completion process. Newly drilled wells are frequently completed by well servicing rigs to minimize

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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 lesswell-to-well mobilization of equipment and generally provide higher operating margins than regular maintenance work. The demand for completion services is directly related to drilling activity levels, which are sensitive to expectations relating to and changes in oil and gas prices.

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

Fluid Services Segment

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

• transportation of fluids used in drilling and workover operations and of salt water produced as a by-product of oil and gas production;

• sale and transportation of fresh and brine water used in drilling and workover activities;

• rental of portable frac tanks and test tanks used to store fluids on well sites; and

• operation of company owned fresh water and brine source wells and of non-hazardous wastewater disposal wells.

      This segment utilizes our fleet of fluid services trucks and related assets, including specialized tank trucks, portable storage tanks, water wells, disposal facilities and related equipment. The following table sets forth the type, number and location of the fluid services equipment that we operated at June 30, 2006:

	Operating Division
	Northern		Permian		Ark-		South		Mid-
	Rockies		Basin		La-Tex		Texas		Continent		Stacked		Total
Fluid Services Trucks		83		160		181		124		43		1		592
Salt Water Disposal Wells		—		12		20		8		6		—		46
Fresh/ Brine Water Stations		—		28		—		3		1		—		32
Fluid Storage Tanks		212		293		677		256		65		—		1,503

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

      We provide a full array of fluid sales, transportation, storage and disposal services required on most workover, drilling and completion projects. Our breadth of capabilities in this business segment allows us to serve as a one-stop source for our customers. Many of our smaller competitors in this

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segment can provide some, but not all, of the equipment and services required by customers, requiring them to use several companies to meet their requirements and increasing their administrative burden.

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

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

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

     Fluid Services and Support Trucks. We currently own and operate over 590 fluid service tank trucks equipped with a fluid hauling capacity of up to 150 barrels. Each fluid service truck is equipped to pump fluids from or into wells, pits, tanks and other storage facilities. The majority of our fluid service trucks are also used to transport water to fill frac tanks on well locations, including frac tanks provided by us and others, to transport produced salt water to disposal wells, including injection wells owned and operated by us, and to transport drilling and completion fluids to and from well locations. In conjunction with the rental of our frac tanks, we generally use our fluid service trucks to transport water for use in fracturing operations. Following completion of fracturing operations, our fluid service trucks are used to transport the flowback produced as a result of the fracturing operations from the well site to disposal wells. Fluid services trucks are generally provided to oilfield operators within a50-mile radius of our nearest yard. Our “hot oil” trucks are used to remove paraffin, a by-product of oil production in many fields, from the well bore. If paraffin is left untreated, it can inhibit a well’s production. Our support trucks are used to move our fluid storage tanks and other equipment to and from the job sites of our customers.

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

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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. These locations also allows us to expand our customer base.

     Fluid Storage Tanks. Our fluid storage tanks can store up to 500 barrels of fluid and are used by oilfield operators to store various fluids at the well site, including water, brine, drilling mud and acid for frac jobs, flowback, temporary production and mud storage. We transport the tanks on our trucks to well locations that are usually within a50-mile radius of our nearest yard. Frac tanks are used during all phases of the life of a producing well. We generally rent fluid services tanks at daily rates for a minimum of three days. A typical fracturing operation can be completed within four days using 10 to 40 frac tanks.

Drilling and Completion Services Segment

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

• niche pressure pumping, such as cementing, acidizing, fracturing, coiled tubing and pressure testing;

• cased-hole wireline services;

• underbalanced drilling in low pressure and fluid sensitive reservoirs; and

• oilfield services fishing and rental tool business.

      This segment currently operates 74 pressure pumping units to conduct a variety of services designed to stimulate oil and gas production or to enable cement slurry to be placed in or circulated within a well. As of June 30, 2006, we also operated 31 air compressor packages, including foam circulation units, for underbalanced drilling and 10 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

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cases, sand or another form of proppant is pumped with the fluid as a means of holding open the newly created fractures.

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

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

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

      The following table sets forth the type, number and location of the drilling and completion services equipment that we operated at June 30, 2006:

	Operating Division
	Ark-		Mid-		Northern		Southern
	La-Tex		Continent		Rockies		Rockies		Total
Pressure Pumping Units		12		59		3		—		74
Coiled Tubing Units		—		2		1		—		3
Air/ Foam Packages		—		—		—		31		31
Wireline Units		—		10		—		—		10

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

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

      Cased-hole wireline services typically utilize a single truck equipped with a spool of wireline that is used to lower and raise a variety of specialized tools in and out of a cased wellbore. These tools can be used to measure pressures and temperatures as well as the condition of the casing and the cement that holds the casing in place. Other applications for wireline tools include placing equipment in or retrieving equipment from the wellbore, or perforating the casing and cutting off pipe that is stuck in the well so that the free section can be recovered. Electric wireline contains a conduit that allows signals to

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be transmitted to or from tools located in the well. A simpler form of wireline, slickline, lacks an electrical conduit and is used only to perform mechanical tasks such as setting or retrieving various tools. Wireline trucks are often used in place of a well servicing rig when there is no requirement to remove tubulars from the well in order to make repairs. Wireline trucks, like well servicing rigs, are utilized throughout the life of a well.

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

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

      Our fishing and rental tool business provides a range of specialized services and equipment that are utilized on a non-routine basis for both drilling and well servicing operations. Drilling and well servicing rigs are equipped with a complement of tools to complete routine operations under normal conditions for most projects in the geographic area where they are employed. When problems develop with drilling or servicing operations, or conditions require non-routine equipment, our customers will rely on a provider of fishing and rental tools to augment equipment that is provided with a typical drilling or well servicing rig package.

      The term “fishing” applies to a wide variety of downhole operations designed to correct a problem that has developed when drilling or servicing a well. Most commonly the problem involves equipment that has become lodged in the well and cannot be removed without special equipment. Our customers employ our technicians and our tools that are specifically suited to retrieve the trapped equipment, or “fish,” in order for operations to resume.

Well Site Construction Services Segment

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

• preparation and maintenance of access roads;

• building of drilling locations;

• installation of small gathering lines and pipelines; and

• maintenance of production facilities.

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

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

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

Properties

      Our principal executive offices are currently located at 400 W. Illinois, Suite 800, Midland, Texas 79701. During 2005 we also purchased and are currently renovating a facility in Midland County, Texas to consolidate our corporate office and to expand our refurbishment capacities. We currently conduct our business from 94 area offices, 45 of which we own and 49 of which we lease. Each office typically includes a yard, administrative office and maintenance facility. Of our 94 area offices, 60 are located in Texas, 11 are in Oklahoma, six are in New Mexico, five are in Wyoming, four are in Colorado, two are in Louisiana, two are in Montana, two are in North Dakota, 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 2005 and the first six months of 2006, we provided services to more than 1,000 customers, with our top five customers comprising only 16% and 18% of our revenues, respectively. The majority of our business is with independent oil and gas companies. While we believe we could redeploy equipment in the current market environment if we lost a single material customer, or a few of them, such loss could have an adverse effect on our business until the equipment is redeployed.

Operating Risks and Insurance

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

• personal injury or loss of life;

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

• suspension of operations.

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

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

      Despite our efforts to maintain high safety standards, we from time to time have suffered accidents in the past and anticipate that we could experience accidents in the future. In addition to the property

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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. We believe our two largest competitors, Key Energy Services, Inc. and Nabors Well Services Co., combined own approximately 59% of the well service market share based on total well servicing rig ownership based on publicly available data reported by these competitors. Both of these competitors are public companies or subsidiaries of public companies that operate in most of the large oil and gas producing regions in the U.S. These competitors have centralized management teams that direct their operations and decision making primarily from corporate and regional headquarters. In addition, because of their size, these companies market a large portion of their work to the major oil and gas companies.

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

Safety Program

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

      We believe our approach to safety management is consistent with our decentralized management structure. Company mandated policies and procedures provide the overall framework to ensure our

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operations minimize the hazards inherent in our work and are intended to meet regulatory requirements, while allowing our operations to satisfy customer mandated policies and local needs and practices.

Environmental Regulation

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

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

      The federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, referred to as “RCRA”, generally does not regulate most wastes generated by the exploration and production of oil and natural gas because that act specifically excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and gas from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies as non-hazardous wastes as long as these wastes are not commingled with regulated hazardous wastes. Moreover, in the ordinary course of our operations, industrial wastes such as paint wastes and waste solvents as well as wastes generated in the course of us providing well services may be regulated as hazardous waste under RCRA or hazardous substances under CERCLA.

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

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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 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.

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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 June 30, 2006, we employed approximately 3,900 people, with approximately 85% employed on an hourly basis. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements, and we consider our relations with our employees to be satisfactory.

Litigation

      On September 3, 2004, David Hudson, Jr. et al commenced a civil action against us in the District Court of Panola County, Texas, 123rd Judicial District,David Hudson, Jr. et al v. Basic Energy Services Company,Cause No. 2004-A-137. The complaint alleged that our operation of a saltwater disposal well had contaminated both the groundwater and the soil in the surrounding area. The relief requested in the complaint was monetary damages, injunctive relief, environmental remediation and a court order requiring us to provide drinking water to the community. This matter was settled in April 2006 for an immaterial amount.

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

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

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

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MANAGEMENT

Directors, Executive Officers and Other Key Employees

      Our directors, executive officers and other key employees and their respective ages and positions are as follows:

Name	Age		Position
Steven A. Webster		54	Chairman of the Board
Kenneth V. Huseman		54	President, Chief Executive Officer and Director
Alan Krenek		51	Senior Vice President, Chief Financial Officer, Treasurer and Secretary
Charles W. Swift.		56	Senior Vice President — Rig and Truck Operations
Dub W. Harrison		47	Vice President — Equipment & Safety
Mark D. Rankin		53	Vice President — Risk Management
James E. Tyner		55	Vice President — Human Resources
James S. D’Agostino, Jr.		59	Director
William E. Chiles		57	Director
Robert F. Fulton		54	Director
Sylvester P. Johnson, IV		50	Director
Thomas P. Moore, Jr.		67	Director
H. H. Wommack, III		50	Director

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

     Steven A. Webster (Chairman of the Board)has been the Chairman of our Board of Directors and a director since January 2001. Mr. Webster has served as Co-Managing Partner of Avista Capital Holdings, L.P. (“Avista”), a private equity firm focused on investments in the energy, media and healthcare sectors since July 1, 2005. Prior to his position with Avista, Mr. Webster served as Chairman of Global Energy Partners, a specialty group within Credit Suisse’s asset management business that made investments in energy companies, from 1999 until June 30, 2005. Mr. Webster has continued to serve as a consultant to Credit Suisse’s asset management business through arrangements with an affiliate of Avista, and serves on the boards of, and monitors the operations of, various existing DLJ Merchant Banking portfolio companies, including Basic Energy Services. From 1998 to 1999, Mr. Webster served as Chief Executive Officer and President of R&B Falcon Corporation, and from 1988 to 1998, Mr. Webster served as Chairman and Chief Executive Officer of Falcon Drilling Corporation, both offshore drilling contractors. Mr. Webster serves as a director of Grey Wolf, Inc., SEACOR Holdings Inc., Hercules Offshore, Inc., Brigham Exploration Company, Goodrich Petroleum Corporation, Camden Property Trust, Geokinetics, Inc., and various privately-held companies. In addition, Mr. Webster serves as Chairman of Carrizo Oil & Gas, Inc., Crown Resources Corporation, and Pinnacle Gas Resources, Inc. Mr. Webster was the founder and an original shareholder of Falcon Drilling Company, a predecessor to Transocean, Inc., and was a co-founder and original shareholder of Carrizo Oil & Gas, Inc. Mr. Webster holds a B.S.I.M. from Purdue University and an M.B.A. from Harvard Business School.

     Kenneth V. Huseman (President — Chief Executive Officer and Director)has 26 years of well servicing experience. He has been our President, Chief Executive Officer and Director since 1999. Prior to joining us, he was Chief Operating Officer at Key Energy Services from 1996 to 1999. He was a Divisional Vice President at WellTech, Inc. from 1993 to 1996. He was a Vice President of Operations at Pool Energy Services Co. from 1982 to 1993, where he managed operations throughout the United States, including drilling operations in Alaska. Mr. Huseman graduated with a B.B.A. degree in Accounting from Texas Tech University.

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     Alan Krenek (Senior Vice President, Chief Financial Officer, Treasurer and Secretary)has 18 years of related industry experience. He has been our Vice President, Chief Financial Officer and Treasurer since January 2005. He became Senior Vice President and Secretary in May 2006. From October 2002 to January 2005, he served as Vice President and Controller of Fleetwood Retail Corp., a subsidiary in the manufactured housing division of Fleetwood Enterprises, Inc. From March 2002 to August 2002, he was a consultant involved in management, assessment of operational and financial internal controls, cost recovery and cash flow management. Mr. Krenek pursued personal interests from November 2001 to March 2002. From December 1999 to November 2001, he acted as the Vice President of Finance and later the Chief Financial Officer of Digital Commerce Corporation, abusiness-to-government internet-based marketplace solutions company that filed for Chapter 11 bankruptcy protection in June 2001. From January 1997 to December 1999, Mr. Krenek was the Vice President, Finance of Global TeleSystems, Inc. From September 1995 to December 1996, he served as Corporate Controller of Landmark Graphics Corporation where he was responsible for SEC reporting, general accounting, financial policies and procedures and purchasing functions. He worked in various financial management positions at Pool Energy Services Co. from 1980 to 1993 and at Noble Corporation from 1993 to 1995. Mr. Krenek graduated with a B.B.A. degree in Accounting from Texas A&M University in 1977 and is a certified public accountant.

     Charles W. Swift (Senior Vice President — Rig and Truck Operations)has 33 years of related industry experience including 25 years specifically in the domestic well service business. He was named Senior Vice President — Rig and Truck Operations in July 2006, has served as a Vice President since 1997 and was involved in integrating several acquisitions during our expansion phase in late 1997. He was a co-owner of S&N Well Service from 1986 to 1997 and expanded the business to 17 rigs at the time of sale of the company to us. From 1980 to 1986, he worked at Pool Energy Services Co. where he managed the well service and fluid services businesses. Mr. Swift graduated with a B.B.A. degree in International Trade from Texas Tech University.

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

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

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

     James S. D’Agostino, Jr. (Director)has served as a director since February 2004. Mr. D’Agostino has served as Chairman of the Board, President and Chief Executive Officer of Encore Bank since November 1999, during which time he initiated turnaround efforts and raised over $30 million of new equity to create a unique private banking organization. From 1998 to 1999, Mr. D’Agostino served as Vice Chairman and Group Executive and from 1997 until 1998, he served as

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President, Member of the Office of Chairman and Director of American General Corporation. Mr. D’Agostino graduated with an economics degree from Villanova University and a J.D. from Seton Hall University School of Law.

     William E. Chiles (Director)has served as a director since August 2003. Mr. Chiles has served as the Chief Executive Officer, President and a Director of Bristow Group Inc. (formerly named Offshore Logistics, Inc.), a provider of helicopter transportation services to the worldwide offshore oil and gas industry, since July 2004. Mr. Chiles served as Executive Vice President and Chief Operating Officer of Grey Wolf, Inc. from March 2003 until June 2004. Mr. Chiles served as Vice President of Business Development at ENSCO International Incorporated from August 2002 until March 2003. From August 1997 until its merger into an ENSCO International affiliate in August 2002, Mr. Chiles served as President and Chief Executive Officer of Chiles Offshore, Inc. Mr. Chiles has a B.B.A. in Petroleum Land Management from The University of Texas and an M.B.A. in Finance and Accounting with honors from Southern Methodist University, Dallas.

     Robert F. Fulton (Director)has served as a director since 2001. Mr. Fulton has served as President and Chief Executive Officer of Frontier Drilling ASA since September 2002. From December 2001 to August 2002, Mr. Fulton managed personal investments. He served as Executive Vice President and Chief Financial Officer of Merlin Offshore Holdings, Inc. from August 1999 until November 2001. From 1998 to June 1999, Mr. Fulton served as Executive Vice President of Finance for R&B Falcon Corporation, during which time he closed the merger of Falcon Drilling Company with Reading & Bates Corporation to create R&B Falcon Corporation and then the merger of R&B Falcon Corporation and Cliffs Drilling Company. He graduated with a B.S. degree in Accountancy from the University of Illinois and an M.B.A. in finance from Northwestern University.

     Sylvester P. Johnson, IV (Director)has served as a director since 2001. Mr. Johnson has served as President, Chief Executive Officer and a director of Carrizo Oil & Gas, Inc. since December 1993. Prior to that, he worked for Shell Oil Company for 15 years. His managerial positions included Operations Superintendent, Manager of Planning and Finance and Manager of Development Engineering. Mr. Johnson is a Registered Petroleum Engineer and has a B.S. in Mechanical Engineering from the University of Colorado.

     Thomas P. Moore, Jr. (Director)has served as a director since December 2005. Mr. Moore was a Senior Principal of State Street Global Advisors, the head of Global Fundamental Strategies, and a member of the Senior Management Group from 2001 through July 2005. Mr. Moore retired from this position in July 2005. From 1986 through 2001, he was a Senior Vice President of State Street Research & Management Company and was head of the State Street Research International Equity Team. From 1977 to 1986 he served in positions of increasing responsibility with Petrolane, Inc., including Administrative Vice President (1977-1981), President of Drilling Tools, Inc., an oilfield equipment rental subsidiary (1981-1984), and President of Brinkerhoff-Signal, Inc., an oil well contract drilling subsidiary (1984-1986). Mr. Moore is a Chartered Financial Analyst and currently serves as a director of several privately-held companies. Mr. Moore holds an M.B.A. degree from Harvard Business School.

     H. H. Wommack, III (Director)has served as a director since 1992. Mr. Wommack was our founder and our Chairman of the Board from 1992 until January 2001. Mr. Wommack is currently a principal of and Chief Executive Officer of Saber Resources, LLC, a privately held oil and gas company that he founded in May 2004. Mr. Wommack served as Chairman of the Board, President, Chief Executive Officer and a Director of Southwest Royalties Holdings, Inc. from its formation in July 1997 until April 2005 and of Southwest Royalties, Inc. from its formation in 1983 until its sale in May 2004. Prior to the formation of Southwest Royalties, Mr. Wommack was a self-employed independent oil and gas producer. Mr. Wommack is currently Chairman of the Board of Midland Red Oak Realty, a commercial real estate company involved in investments in the Southwest. Mr. Wommack is also currently the President of Fortress Holdings, LLC and Anchor Resources, LLC. He graduated with a B.A. from the University of North Carolina and a J.D. from the University of Texas School of Law.

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Board of Directors

      Our board of directors currently consists of eight members, including four independent members — Messrs. D’Agostino, Chiles, Moore and Johnson. The listing requirements of the New York Stock Exchange require that our board of directors be composed of a majority of independent directors within one year of the listing of our common stock on the NYSE. Accordingly, we intend to appoint an additional independent director to our board of directors or otherwise satisfy that obligation prior to such time.

      Our board of directors is divided into three classes. The directors serve staggered three-year terms. The current terms of the directors of each class expire at the annual meetings of stockholders to be held in 2007 (Class II), 2008 (Class III) and 2009 (Class I). At each annual meeting of stockholders, one class of directors is elected for a full term of three years to succeed that class of directors whose terms are expiring. The classification of directors are as follows:

• Class II — Messrs. Chiles and Fulton;

• Class III — Messrs. D’Agostino, Moore and Huseman; and

• Class I — Messrs. Johnson, Webster and Wommack.

Committees

      In compliance with the requirements of the Sarbanes Oxley Act of 2002, the NYSE listing standards and SEC rules and regulations, a majority of the directors on our nominating and corporate governance and compensation committees are currently independent and, within one year of listing on the NYSE, these committees will be fully independent and a majority of our board will be independent.

Audit Committee

      Our audit committee is currently comprised of Messrs. D’Agostino, Chiles and Moore, with Mr. Moore currently serving as chairman. Our board has determined that Messrs. D’Agostino, Chiles and Moore are independent directors as defined under and required by the Securities Exchange Act of 1934, or the Exchange Act, and the listing requirements of the New York Stock Exchange, or NYSE. Our board of directors has determined that Messrs. Moore and D’Agostino are “audit committee financial experts.” The responsibilities of the Audit Committee include:

• to appoint, engage and terminate our independent auditors;

• to approve fees paid to our independent auditors for audit and permissible non-audit services in advance;

• to evaluate, at least on an annual basis, the qualifications, independence and performance of our independent auditors;

• to review and discuss with our independent auditors reports provided by the independent auditors to the Audit Committee regarding financial reporting issues;

• to review and discuss with management and our independent auditors our quarterly and annual financial statements prior to our filing of periodic reports;

• to review our procedures for internal auditing and the adequacy of our disclosure controls and procedures and internal control over financial reporting; and

• to evaluate its own performance at least on an annual basis.

      To promote the independence of the audit, the Audit Committee consults separately and jointly with the independent auditors, the internal auditors and management.

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Nominating and Corporate Governance Committee

      Our nominating and corporate governance committee currently consists of Messrs. Johnson, Webster and Moore, with Mr. Johnson currently serving as chairman. Our board has determined that Messrs. Johnson and Moore are independent as required by the listing requirements of the NYSE. The responsibilities of the Nominating and Corporate Governance Committee include:

• to identify, recruit and evaluate candidates for membership on the Board and to develop processes for identifying and evaluating such candidates;

• to annually present to the Board a list of nominees recommended for election to the Board at the annual meeting of stockholders, and to present to the Board, as necessary, nominees to fill any vacancies that may occur on the Board;

• to adopt a policy regarding the consideration of any director candidates recommended by our stockholders and the procedures to be followed by such stockholders in making such recommendations;

• to adopt a process for our stockholders to send communications to the Board;

• to evaluate its own performance at least annually and deliver a report setting forth the results of such evaluation to the Board;

• to oversee our policies and procedures regarding compliance with applicable laws and regulations relating to the honest and ethical conduct of our directors, officers and employees;

• to have the sole responsibility for granting any waivers under our Code of Ethics and Corporate Governance Guidelines; and

• to evaluate annually, based on input from the entire Board, the performance of the CEO and report the results of such evaluation to the Compensation Committee of the Board.

Compensation Committee

      Our compensation committee currently consists of Messrs. Chiles, D’Agostino and Wommack, with Mr. Chiles currently serving as chairman. Our board has determined that Messrs. Chiles and D’Agostino are independent as required by the listing requirements of the NYSE. The responsibilities of the Compensation Committee include:

• to evaluate and develop the compensation policies applicable to our executive officers and make recommendations to the Board with respect to the compensation to be paid to our executive officers;

• to review, approve and evaluate on an annual basis the corporate goals and objectives with respect to compensation for our Chief Executive Officer;

• to determine and approve our Chief Executive Officer’s compensation, including salary, bonus, incentive and equity compensation;

• to review and make recommendations regarding the compensation paid to non-employee directors;

• to review and make recommendations to the Board with respect to our incentive compensation plans and to assist the Board with the administration of such plans; and

• to evaluate its own performance at least annually and deliver a report setting forth the results of such evaluation to the Board.

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Web Access

      We provide access through our website atwww.basicenergyservices.comto current information relating to governance, including a copy of each board committee charter, our Code of Ethics, our corporate governance guidelines and other matters impacting our governance principles. You may also contact our Chief Financial Officer for paper copies of these documents free of charge.

Compensation Committee Interlocks and Insider Participation

      None of our executive officers serve as a member of the board of directors or compensation committee of any entity that has one or more of its executive officers serving as a member of our board of directors or compensation committee.

Compensation of Executive Officers

      The following table summarizes all compensation earned by our Chief Executive Officer and each of our four other most highly compensated executive officers during the years ended December 31, 2003, 2004 and 2005, to whom we refer in this prospectus as our named executive officers.

								Long-Term
								Compensation
		Annual Compensation(1)
								Restricted		Securities
		Fiscal						Stock		Underlying		All Other
Name and Principal Position		Year		Salary		Bonus		Awards(2)		Options		Compensation(3)
				($)		($)		($)		(#)		($)
Kenneth V. Huseman			2005		325,000		275,000		—		100,000		1,600
	President and		2004		327,884		500,000		3,141,000		—		2,308
	Chief Executive Officer		2003		269,231		125,000		—		200,000		16,955
Alan Krenek			2005		170,769		187,500		—		125,000		52,331
	Senior Vice President —		2004		NA		NA		NA		NA		NA
	Finance and Chief Financial Officer(4)		2003		NA		NA		NA		NA		NA
James J. Carter(5)			2005		170,000		60,000		—		30,000		1,288
	Executive Vice President		2004		168,846		200,000		698,000		—		—
	and Secretary		2003		127,692		25,000		—		60,000		—
Charles W. Swift.			2005		150,000		95,068		—		35,000		14,400
	Vice President — Permian		2004		151,924		69,894		349,000		—		9,600
			2003		123,077		24,714		—		50,000		9,600
Dub W. Harrison			2005		140,000		48,000		—		25,000		10,240
	Vice President —		2004		141,539		60,250		349,000		—		9,600
	Equipment & Safety		2003		115,385		14,000		—		50,000		9,600

(1)

Under the terms of their employment agreements, Messrs. Huseman, Krenek, Carter, Swift and Harrison are entitled to the compensation described under “Employment Agreements” below. Perquisites and other personal benefits paid or distributed during fiscal 2003, 2004 and 2005 to the individuals listed in the table above did not exceed, for any individual, the lesser of $50,000 or 10 percent of such individual’s total salary and bonus.

(2)

Shares of restricted stock were granted to the named executive officers during 2004 as follows: Huseman — 450,000 shares; Carter — 100,000 shares; Swift — 50,000 shares; and Harrison — 50,000 shares. The fair market value as of the date of grant of the shares of restricted stock during February 2004, as determined by our board of directors, was $6.98. These shares are subject to vesting in one-fourth increments on each of February 24, 2005, 2006, 2007 and 2008 for each person other than Mr. Carter, whose shares vested one-half on February 24, 2005 and one-half on February 24, 2006. Cash dividends, if any are paid, would be payable on these shares of restricted stock, but we will retain any stock dividends applicable to these shares until the vesting period is

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	satisfied on the shares on which the stock dividend is issued. For information concerning grants of and the aggregate holdings of restricted stock by the named executive officers, see “Employment Agreements” below. For information regarding repurchases of shares of restricted stock by us from the named executive officers and other officers during 2005 and 2006, see “Certain Relationships and Related Party Transactions” below.
(3)	For 2005, includes: for Mr. Huseman, deferred compensation contributions of $1,600; for Mr. Krenek, moving related allowance of $52,331; for Mr. Carter, deferred compensation contributions of $1,288; for Mr. Swift, vehicle allowance of $9,600 and deferred compensation contributions of $4,800; and for Mr. Harrison, vehicle allowance of $9,600 and deferred compensation contributions of $640. For 2004 includes: for Mr. Huseman, vehicle allowance of $2,308; for each of Mr. Swift and Mr. Harrison, vehicle allowance of $9,600. For 2003 includes: for Mr. Huseman, vehicle allowance of $12,000 and life insurance costs of $4,955; for each of Mr. Swift and Mr. Harrison, vehicle allowance of $9,600.
(4)	Mr. Krenek has served as our Chief Financial Officer since January 2005.
(5)	Mr. Carter, our former Executive Vice President and Secretary, retired effective April 30, 2006.

Aggregated Option Exercises in 2005 and Fiscal Year-End Option Values

      The following table sets forth information concerning options exercised during the last fiscal year and held as of December 31, 2005 by each of the named executive officers. None of the named executive officers exercised options during the year ended December 31, 2005. Amounts described in the following table under the heading “Value of UnexercisedIn-the-Money Options at December 31, 2005” are determined by multiplying the number of shares issued or issuable upon the exercise of the option by the difference between the closing price of our common stock at December 31, 2005 and the per share option exercise price.

	Number of Shares
	Underlying Unexercised				Value of Unexercised
	Options at				In-the-Money Options at
	December 31, 2005				December 31, 2005
	Exercisable		Unexercisable		Exercisable		Unexercisable
Kenneth V. Huseman		399,755		166,650	$	6,376,092	$	2,360,068
Alan Krenek		—		125,000		—		1,803,450
James J. Carter		128,720		50,000		2,053,084		708,100
Dub W. Harrison		89,560		41,665		1,428,482		590,057
Charles W. Swift.		89,560		51,665		1,428,482		719,757

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Option Grants in Last Fiscal Year

      The following table sets forth information concerning options granted during the year ended December 31, 2005 to each of the named executive officers.

	Individual Grants
										Potential Realizable
			% of Total							Value at Assumed
	Number of		Options							Annual Rates of Stock
	Securities		Granted to		Exercise					Price Appreciation For
	Underlying		Employees		or Base					Option Term
	Options		in Fiscal		Price		Expiration
Name	Granted(#)(1)		Year(2)		($/Sh)		Date			5%($)		10%($)
Kenneth V. Huseman		100,000		10.2		6.98		3/1/2015		$	1,383,727	$	2,616,803
Alan Krenek(3)		125,000		12.7		5.52		(4	)		1,398,557		2,635,975
James J. Carter		30,000		3.1		6.98		3/1/2015			415,118		785,041
Charles W. Swift		35,000		3.6		6.98		3/1/2015			484,305		915,881
Dub W. Harrison		25,000		2.5		6.98		3/1/2015			345,932		654,201

(1)	Except as provided in note (3) below, all options reflected in the table were earned in fiscal 2005 and granted on March 2, 2005. No stock appreciation rights (“SARs”) were granted in tandem with the options reflected in this table. Except as provided in note (3) below, these options vest in equal one-fourth increments on each of January 1, 2007, 2008, 2009 and 2010.
(2)	Reflects the percentage of total options granted in fiscal 2005.
(3)	Includes options to purchase 100,000 shares of common stock granted to Mr. Krenek on January 26, 2005 in connection with the commencement of his employment with us. These options vest in equal one-third increments on each of January 26, 2006, 2007 and 2008.
(4)	Options to purchase 100,000 shares of common stock expire on January 25, 2015 and options to purchase 25,000 shares of common stock expire on March 1, 2015.

Compensation of Directors

      Directors who are our employees do not receive a retainer or fees for service on the board or any committees. We pay non-employee members of the board for their service as directors. Directors who are not employees receive, effective May 1, 2005, an annual fee of $30,000. In addition, the chairman of each committee receives the following annual fees: audit committee — $10,000; compensation committee — $6,000; and nominating and corporate governance committee — $6,000. Directors who are not employees currently receive a fee of $2,000 for each board meeting attended in person, and a fee of $1,000 for attendance at a board meeting held telephonically. For committee meetings, directors who are not employees currently receive a fee of $3,000 for each committee meeting attended in person, and a fee of $1,500 for attendance at a committee meeting held telephonically. In addition, each non-employee director has received, upon election to the board, a stock option to purchase 37,500 shares of our common stock at the market price on the date of grant that vests ratably over three years. Directors are reimbursed for reasonableout-of-pocket expenses incurred in attending meetings of the board or committees and for other reasonable expenses related to the performance of their duties as directors.

Second Amended and Restated 2003 Incentive Plan

      Our 2003 Incentive Plan, which was adopted by our Board of Directors and has been approved by our stockholders as amended, covers stock awards issued under our original 2003 Incentive Plan and

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predecessor equity plan. This incentive plan permits the granting of any or all of the following types of awards:

• stock options;

• restricted stock;

• performance awards;

• phantom shares;

• other stock-based awards;

• bonus shares; and

• cash awards.

      All non-employee directors and employees of, and any consultants to, us or any of our affiliates are eligible for participation under the incentive plan.

      The number of shares with respect to which awards may be granted under the 2003 Incentive Plan may not exceed 5,000,000 shares, of which awards for 3,680,050 shares have been issued as of June 30, 2006. The incentive plan will be administered by the compensation committee of our board of directors. The compensation committee will select the participants who will receive awards, determine the type and terms of the awards to be granted and interpret and administer the incentive plan. No awards may be granted under the incentive plan after April 12, 2014.

      The options granted pursuant to the 2003 Incentive Plan may be either incentive options qualifying for beneficial tax treatment for the recipient as “incentive stock options” under Section 422 of the Code or non-qualified options. No person may be issued incentive stock options that first become exercisable in any calendar year with respect to shares having an aggregate fair market value, at the date of grant, in excess of $100,000. No incentive stock option may be granted to a person if at the time such option is granted the person owns stock possessing more than 10% of the total combined voting power of all classes of our stock or any of our subsidiaries as defined in Section 424 of the Code, unless at the time incentive stock options are granted the purchase price for the option shares is at least 110% of the fair market value of the option shares on the date of grant and the incentive stock options are not exercisable five years after the date of grant.

      The 2003 Incentive Plan permits the payment of qualified performance-based compensation within the meaning of Section 162(m) of the Code, which generally limits the deduction that we may take for compensation paid in excess of $1,000,000 to certain of our “covered officers” in any one calendar year unless the compensation is “qualified performance-based compensation” within the meaning of Section 162(m) of the Code. The 2003 Incentive Plan was approved by our stockholders prior to our initial public offering of common stock. This prior stockholder approval (assuming no further material modifications of the plan) will satisfy the stockholder approval requirements of Section 162(m) following our initial public offering of common stock for a transition period ending not later than our annual meeting of stockholders in 2009.

Tax Treatment for Our 2003 Incentive Plan

      The following is a brief summary of certain of the United States federal income tax consequences relating to our 2003 Incentive Plan based on federal income tax laws currently in effect. This summary applies to the plan as normally operated and is not intended to provide or supplement tax advice. Individual circumstances may vary these results, and we recommend that each participant consult his or her own tax counsel for advice regarding tax treatment under the plan. The summary contains general statements based on current United States federal income tax statutes, regulations and currently available interpretations thereof. This summary is not intended to be exhaustive and does not

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describe state, local or foreign tax consequences or the effect, if any, of gift, estate and inheritance taxes.

     Non-qualified Stock Options. An optionee will not recognize any taxable income upon the grant of a non-qualified stock option. We will not be entitled to a federal income tax deduction with respect to the grant of a non-qualified stock option. Upon exercise of a non-qualified stock option, the excess of the fair market value of the common stock transferred to the optionee over the option exercise price will be taxable as compensation income to the optionee and will be subject to applicable withholding taxes. Such fair market value generally will be determined on the date the shares of common stock are transferred pursuant to the exercise. We generally will be entitled to a federal income tax deduction at such time in the amount of such compensation income. The optionee’s federal income tax basis for the common stock received pursuant to the exercise of a non-qualified stock option will equal the sum of the compensation income recognized and the exercise price. In the event of a sale of common stock received upon the exercise of a non-qualified stock option, any appreciation or depreciation after the exercise date generally will be taxed as capital gain or loss.

     Incentive Stock Options. An optionee will not recognize any taxable income at the time of grant or timely exercise of an incentive stock option (but in some circumstances may be subject to an alternative minimum tax as a result of exercise), and we will not be entitled to a federal income tax deduction with respect to such grant or exercise. A sale or exchange by an optionee of shares acquired upon the exercise of an incentive stock option more than one year after the transfer of the shares to such optionee and more than two years after the date of grant of the incentive stock option will result in the difference between the amount realized and the exercise price, if any, being treated as long-term capital gain (or loss) to the optionee. If such sale or exchange takes place within two years after the date of grant of the incentive stock option or within one year from the date of transfer of the shares to the optionee, such sale or exchange generally will constitute a “disqualifying disposition” of such shares that will have the following result: any excess of (a) the lesser of (1) the fair market value of the shares at the time of exercise of the incentive stock option and (2) the amount realized on such disqualifying disposition of the shares over (b) the option exercise price of such shares, will be ordinary income to the optionee, and we generally will be entitled to a federal income tax deduction in the amount of such income. The balance, if any, of the optionee’s gain upon a disqualifying disposition will qualify as capital gain and will not result in any deduction by us.

     Restricted Stock. A grantee generally will not recognize taxable income upon the grant of restricted stock, and the recognition of any income will be postponed until such shares are no longer subject to restrictions on transfer or the risk of forfeiture. When either the transfer restrictions or the risk of forfeiture lapses, the grantee will recognize ordinary income equal to the fair market value of the restricted stock at the time of such lapse and, subject to satisfying applicable income reporting requirements and any deduction limitation under Section 162(m) of the Code, we will be entitled to a federal income tax deduction in the same amount and at the same time as the grantee recognized ordinary income. A grantee may elect to be taxed at the time of the grant of restricted stock and, if this election is made, the grantee will recognize ordinary income equal to the excess of the fair market value of the restricted stock at the time of grant (determined without regard to any of the restrictions thereon) over the amount paid, if any, by the grantee for such shares. We generally will be entitled to a federal income tax deduction in the same amount and at the same time as the grantee recognizes ordinary income.

     Performance Awards, Phantom Shares and Other Stock-Based Awards. Generally, a grantee will not recognize any taxable income and we will not be entitled to a deduction upon the award of performance awards, phantom shares and other stock-based awards. Upon vesting, the participant would include in ordinary income the value of any shares received and an amount equal to any cash received. Subject to satisfying applicable income reporting requirements and any deduction limitation under Section 162(m) of the Code, we will be entitled to a federal income tax deduction equal to the amount of ordinary income recognized by the grantee.

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     Bonus Shares and Cash Awards. Upon the receipt of bonus shares and cash awards, the grantee would include in ordinary income the value of any shares received and an amount equal to any cash received. Subject to satisfying applicable income reporting requirements and any deduction limitation under Section 162(m) of the Code, we will be entitled to a federal income tax deduction equal to the amount of ordinary income recognized by the grantee.

     Deferred Compensation and Parachute Taxes. Section 409A of the Code provides for an additional 20% tax, among other things, on awards that, if subject to Section 409A, do not comply with the requirements of this section. We intend for awards to comply with Section 409A. In addition, if, upon a change of control of us, the vesting or payment of awards to certain “disqualified individuals” exceeds certain amounts, that individual will be subject to a 20% excise tax on such payments and those amounts will not be deductible by us.

Employment Agreements

      Under the current employment agreement with Mr. Huseman effective March 1, 2004 through February 2007, Mr. Huseman is entitled to an annual salary of $325,000 and an annual bonus ranging from $50,000 to $325,000 based on Mr. Huseman’s performance. Under this employment agreement, Mr. Huseman is eligible from time to time to receive grants of stock options and other long-term equity incentive compensation under our Amended and Restated 2003 Incentive Plan. In addition, upon a qualified termination of employment Mr. Huseman would be entitled to three times his base salary plus his current annual incentive target bonus for the full year in which the termination of employment occurred. Similarly, following a change of control of our company, Mr. Huseman would be entitled to a lump sum payment of two times his base salary plus his current annual incentive target bonus for the full year in which the change of control occurred.

      Mr. Huseman’s bonus in 2005 was unanimously approved by our Board of Directors, including the independent directors. In 2005 the Board of Directors approved the payment of a $275,000 bonus to Mr. Huseman, and the Board has approved a salary for Mr. Huseman effective in March 2006 of $400,000.

      We have also entered into employment agreements with Dub W. Harrison and Charles W. Swift through June 2009 and with Mr. Tyner through January 2007. Mr. Harrison is entitled to an annual salary of $150,000, Mr. Swift is entitled to an annual salary of $200,000 and Mr. Tyner is entitled to an annual salary of $110,000. 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 six months’ salary, or 18 months’ salary (12 months salary is the case of Mr. Tyner) if termination is on or following a change of control of our company. The Board has approved a 2006 salary for Mr. Tyner of $140,000 effective March 2006.

      Under an employment agreement with Alan Krenek effective January 26, 2005 through January 2008, Mr. Krenek is entitled to an annual salary of $185,000 and an annual bonus, based on Mr. Krenek’s performance, ranging from $25,000 to $138,750. Mr. Krenek is also eligible to participate in our 2003 Incentive Plan. Under this employment agreement, Mr. Krenek received a one-time cash bonus of $37,500 and an initial grant of options to purchase 100,000 shares of stock. Under this agreement, if Mr. Krenek’s employment is terminated for certain reasons, he would be entitled to a lump sum severance payment equal to 12 months’ salary plus his current annual incentive target bonus for the full year in which the termination of employment occurred, such lump sum to be increased by 50% if termination is on or following a change of control of our company. The Board has approved a 2006 salary for Mr. Krenek of $240,000 effective in March 2006.

      James J. Carter, our former Executive Vice President and Secretary, retired effective April 30, 2006. Mr. Carter’s employment agreement entitled him to an annual salary of $130,000, and the Board approved a 2006 annual salary of $170,000 for Mr. Carter that was effective prior to his retirement.

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Indemnification Agreements

      We have also entered into indemnification agreements with all of our directors and some of our executive officers. These indemnification agreements are intended to permit indemnification to the fullest extent now or hereafter permitted by the General Corporation Law of the State of Delaware. It is possible that the applicable law could change the degree to which indemnification is expressly permitted.

      The indemnification agreements cover expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement incurred as a result of the fact that such person, in his or her capacity as a director or officer, is made or threatened to be made a party to any suit or proceeding. The indemnification agreements generally cover claims relating to the fact that the indemnified party is or was an officer, director, employee or agent of us or any of our affiliates, or is or was serving at our request in such a position for another entity. The indemnification agreements also obligate us to promptly advance all reasonable expenses incurred in connection with any claim. The indemnitee is, in turn, obligated to reimburse us for all amounts so advanced if it is later determined that the indemnitee is not entitled to indemnification. The indemnification provided under the indemnification agreements is not exclusive of any other indemnity rights; however, double payment to the indemnitee is prohibited.

      We are not obligated to indemnify the indemnitee with respect to claims brought by the indemnitee against:

• us, except for:

• claims regarding the indemnitee’s rights under the indemnification agreement;

• claims to enforce a right to indemnification under any statute or law; and

• counter-claims against us in a proceeding brought by us against the indemnitee; or

• any other person, except for claims approved by our board of directors.

      We have also agreed to obtain and maintain director and officer liability insurance for the benefit of each of the above indemnitees. These policies will include coverage for losses for wrongful acts and omissions and to ensure our performance under the indemnification agreements. Each of the indemnitees will be named as an insured under such policies and provided with the same rights and benefits as are accorded to the most favorably insured of our directors and officers.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Transactions with Officers and Directors

      We performed well servicing and fluid services for Southwest Royalties, Inc. in exchange for $1.3 million, $140,000 and $0 for the years ended 2003, 2004 and 2005, respectively. We believe prices charged to Southwest Royalties to be comparable to prices charged in the region. Mr. Wommack, one of our directors, served as President and Chairman of the Board of Southwest Royalties from 1983 until May 2004. Southwest Royalties Holdings, Inc., a former stockholder of Southwest Royalties, owned shares of our common stock, and transferred those shares to Fortress Holdings, LLC in April 2005. Mr. Wommack is the President and a board member of Fortress Holdings. Fortress Holdings also owns an equity interest in Anchor Resources, LLC, which is the general partner of two of our stockholders, Southwest Partners II, L.P. and Southwest Partners III, L.P. Mr. Wommack serves as President and is a board member of Anchor Resources.

      We performed well servicing and fluid services for Saber Resources, LLC in exchange for approximately $67,000 during the year ended December 31, 2005. We believe prices charged to Saber Resources to be comparable to prices charged in the region. Mr. Wommack, one of our directors, is the President and Chairman of the Board of Saber Resources.

      Prior to our initial public offering, we entered into Share Tender and Repurchase Agreements with ten of our officers. Pursuant to these agreements, we repurchased, and nine of the officers sold, an aggregate of 135,326 shares of our common stock at $18.70 per share, the initial public offering price, less underwriting discounts and commissions, on the closing date of our initial public offering. These shares were repurchased to provide such officers the cash amounts necessary to pay certain tax liabilities associated with the vesting of restricted shares owned by them. The shares repurchased represented up to 39.2% of the vested shares of each officer issued as compensation. We withheld minimum tax liability requirements from these proceeds and paid the remainder of the proceeds to the officers for their use in paying estimated tax liabilities. The four executive officers and number of shares that we repurchased from them upon the closing of our initial public offering were as follows: Kenneth V. Huseman — 101,975 shares; James J. Carter — 10,005 shares; Dub W. Harrison — 11,184 shares; and Charles W. Swift — 4,161 shares. The remaining five officers who sold shares were not executive officers.

      In addition to the repurchase of shares on the closing date of our initial public offering, under the Share Tender and Repurchase Agreements, we repurchased, and nine of the officers sold, an aggregate of 78,656 shares of our common stock on February 24, 2006 at $25.00 per share, the closing price per share of common stock on that date. These shares were repurchased to provide such officers the cash amounts necessary to pay certain tax liabilities associated with the vesting of restricted shares owned by them and represented up to 36.45% of the restricted shares owned by each officer that vest on that date. We withheld minimum tax liability requirements from these proceeds and paid the remainder of the proceeds to the officers for their use in paying estimated tax liabilities. The four executive officers and number of shares that we repurchased from them on February 24, 2006 were as follows: Kenneth V. Huseman — 41,000 shares; James J. Carter — 18,225 shares; Dub W. Harrison — 4,557 shares; and Charles W. Swift — 4,557 shares.

      In 2006, we entered into a lease agreement with Darle Vuelta Cattle Co., LLC, an affiliate of our Chief Executive Officer, Kenneth V. Huseman, for approximately $69,000. The term of the lease is five years and will continue on ayear-to-year basis unless terminated by either party.

Summary of Certain Equity Issuances

      During the past three years, we have completed the following issuances of equity, including to affiliates, outside the issuance of awards pursuant to our 2003 Incentive Plan and the exchange of shares in our holding company reorganization on January 24, 2003. We believe these transactions

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were on terms at least as favorable as we could have obtained from unaffiliated third parties as a result of arm’s-length negotiations.

      In February 2002, our predecessor issued 3,000,000 shares of our common stock, together with warrants exercisable for an aggregate of 600,000 shares of our common stock, to DLJ Merchant Banking and its affiliated funds for aggregate cash consideration of $12 million.

      On June 25, 2002, our predecessor issued 150,000 shares of Series A 10% Cumulative Preferred Stock, together with warrants exercisable for an aggregate of 3,750,000 shares of our common stock, to DLJ Merchant Banking and its affiliated funds for aggregate cash consideration of $15 million. Offering expenses related to this transaction totaled $58,000.

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

      On October 3, 2003, in connection with the refinancing of certain indebtedness and request of our lenders, we exchanged an aggregate of 3,304,085 shares of our common stock for outstanding shares of our Series A 10% Cumulative Preferred Stock at an exchange rate of one share of our common stock for each $5.1584 of outstanding liquidation value ($100.00 per share) of our Series A 10% Cumulative Preferred Stock and accrued but unpaid interest thereon, as of the date of exchange. The holders of these shares at the time of exchange were DLJ Merchant Banking and its affiliated funds.

      On October 3, 2003, we issued an aggregate of 3,650,000 shares of common stock, including 730,000 shares of common stock issued into escrow, to the former stockholders of FESCO Holdings, Inc. as consideration for all of the outstanding shares of FESCO Holdings, Inc. The implied value per share in connection with the share exchange was $5.16 per share. Former stockholders of FESCO Holdings, Inc. include First Reserve Fund VIII, L.P.

Relationships with Certain Directors

      Steven A. Webster, the Chairman of our Board of Directors, is the Co-Managing Partner of Avista Capital Holdings, L.P. (“Avista”), a private equity firm that makes investments in the energy sector. This relationship may create a conflict of interest because of his responsibilities to Avista and its owners. His duties as a partner in or director or officer of Avista or its affiliates may conflict with his duties as a director of our company regarding corporate opportunities and other matters. The resolution of this conflict of interest may not always be in our stockholders’ best interest. We expect to address transactions involving potential conflicts of interest by having such transactions approved by the disinterested members of our Board of Directors.

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PRINCIPAL STOCKHOLDERS

      The following table sets forth information with respect to the beneficial ownership of our common stock as of July 13, 2006 by:

• each person who is known by us to own beneficially 5% or more of our outstanding common stock;

• each of our named executive officers;

• each of our directors; and

• all of our executive officers and directors as a group (15 persons).

      Except as otherwise indicated, the person or entities listed below have sole voting and investment power with respect to all shares of our common stock beneficially owned by them, except to the extent this power may be shared with a spouse. Unless otherwise indicated, the address of each stockholder listed below is 400 W. Illinois, Suite 800, Midland, TX 79701. The following information was obtained by us in reliance upon information set forth in statements filed by the principal stockholders on Schedules 13D and 13G, on Forms 3 or 4 pursuant to Section 16 of the Securities and Exchange Act of 1934, questionnaires or other information provided by such stockholders.

	Shares Beneficially
	Owned
Name of Beneficial Owner	Number		Percent
DLJ Merchant Banking Partners III, L.P. and affiliated funds(1)		18,059,424		47.4	%
RS Investment Management Co. LLC(2)		1,754,400		5.2	%
Fortress Holdings, LLC(3)(4)		667,205		2.0	%
Anchor Resources, LLC(3)(4)		1,434,436		4.2	%
Kenneth V. Huseman(5)		1,022,725		3.0	%
Alan Krenek(6)		33,535		*
James J. Carter(7)		157,082		*
Dub W. Harrison(8)		146,514		*
Charles W. Swift(9)		158,378		*
Steven A. Webster(10)		62,500		*
James S. D’Agostino, Jr.(11)		35,870		*
William E. Chiles(12)		35,000		*
Robert F. Fulton(10)		62,500		*
Sylvester P. Johnson, IV(10)		62,500		*
Thomas P. Moore, Jr.(13)		10,000
H.H. Wommack, III(3)(4)(14)		2,164,141		6.4	%
Directors and Executive Officers as a Group (15 persons)(15)		3,985,835		11.5	%

 *   Less than one percent.

(1)  Includes 13,709,424 shares of common stock and 4,350,000 shares of common stock issuable upon exercise of warrants owned by DLJ Merchant Banking Partners III, L.P. and affiliated funds as follows: DLJ Merchant Banking Partners III, L.P. (9,556,892 shares and warrants exercisable for 3,093,225 shares); DLJ ESC II, L.P. (1,493,185 shares); DLJ Offshore Partners III, C.V. (416,670 shares and warrants exercisable for 29,195 shares); DLJ Offshore Partners III-1, C.V. (24,488 shares and warrants exercisable for 7,530 shares); DLJ Offshore Partners III-2, C.V. (17,441 shares and warrants exercisable for 5,365 shares); DLJ Merchant Banking III, Inc., as Advisory General Partner on behalf of DLJ Offshore Partners III, C.V. (251,846 shares and warrants exercisable for 186,820 shares); DLJ Merchant Banking III, Inc., as Advisory General Partner on behalf of DLJ Offshore Partners III-1, C.V. and asattorney-in-fact for DLJ Merchant Banking III, L.P., as Associate General Partner of DLJ Offshore PartnersIII-1, C.V.

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(147,981 shares and warrants exercisable for 48,285 shares); DLJ Merchant Banking III, Inc., as Advisory General Partner on behalf of DLJ Offshore Partners III-2, C.V. and asattorney-in-fact for DLJ Merchant Banking III, L.P., as Associate General Partner of DLJ Offshore PartnersIII-2, C.V. (105,421 shares and warrants exercisable for 34,395 shares); DLJMB Partners III GmbH & Co. KG (81,518 shares and warrants exercisable for 26,380 shares); DLJMB Funding III, Inc. (132,220 shares); Millennium Partners II, L.P. (16,211 shares and warrants exercisable for 5,305 shares); MBP III Plan Investors, L.P. (1,465,551 shares and warrants exercisable for 913,500 shares).

Credit Suisse, a Swiss bank, owns the majority of the voting stock of Credit Suisse Holdings (USA), Inc., a Delaware corporation which in turn owns all of the voting stock of Credit Suisse (USA) Inc., a Delaware corporation(“CS-USA”). The entities discussed in the above paragraph are merchant banking funds managed by indirect subsidiaries ofCS-USA and form part of Credit Suisse’s asset management business. The ultimate parent company of Credit Suisse is Credit Suisse Group (“CSG”). CSG disclaims beneficial ownership of the reported common stock that is beneficially owned by its direct and indirect subsidiaries. Steven A. Webster served as the Chairman of Global Energy Partners, a specialty group within Credit Suisse’s asset management business, from 1999 until June 30, 2005 and remains a consultant to Credit Suisse’s asset management business.

All of the DLJ Merchant Banking entities can be contacted at Eleven Madison Avenue, New York, New York10010-3629 except for the three “Offshore Partners” entities, which can be contacted at John B. Gosiraweg, 14, Willemstad, Curacao, Netherlands Antilles.

(2)  RS Investment Management Co. LLC is the parent company of registered investment advisers whose clients have the right to receive or the power to direct the receipt of dividends from, or the proceeds from the sale of, the shares. No individual client’s holdings of the shares, except for RS Global Natural Resources Fund, are more than five percent of our outstanding common stock.

RS Investment Management, L.P. is a registered adviser, managing member of registered investment advisers, and the investment adviser to RS Global Natural Resources Fund, a registered investment company. RS Investment Management Co. LLC is the General Partner of RS Investment Management, L.P. George R. Hecht is a control person of RS Investment Management Co. LLC and RS Investment Management, L.P. RS Investment Management Co. LLC can be contacted at 388 Market Street, Suite 1700, San Francisco, CA 94111.

(3)

Fortress Holdings, LLC, successor in interest to Southwest Royalties Holdings, Inc., directly owns 667,205 shares, or 2.0% of total shares outstanding. Mr. Wommack, our director, is also a director and President of Fortress Holdings, LLC. The members of Fortress Holdings, LLC who beneficially own 5% or more of the outstanding units of Fortress Holdings, LLC are H. H. Wommack, III, Galloway Bend, Ltd., Sagebrush Oil Company and H. Allen Corey, who own approximately 33%, 32%, 5% and 5% of its outstanding units, respectively. Does not include shares in which Fortress Holdings, LLC has an indirect interest as a member of Anchor Resources, LLC as described in footnote 4 below.

(4)

Includes 477,366 shares owned directly by Southwest Partners II, L.P. and 957,070 shares owned directly by Southwest Partners III, L.P. Anchor Resources, LLC, controls the vote of all shares owned by Southwest Partners II, L.P. and Southwest Partners III, L.P. as managing general partner of each of the two partnerships. The number of beneficially owned shares and percentage of class listed above reflect this control. Anchor Resources, LLC owns a 15% managing general partner interest and a 1.7% limited partner interest in Southwest Partners II. No other person owns 5% or more of the partnership interests in Southwest Partners II. Anchor Resources, LLC owns a 15% managing general partner interest and a 0.2% limited partner interest in Southwest Partners III. No other person owns 5% or more of the partnership interests in Southwest Partners III. Mr. Wommack, our director, is also a director and President of Anchor Resources, LLC. The members of Anchor Resources, LLC who beneficially own 5% or more of the units of

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	Anchor Resources, LLC are Bosworth & Co., Fortress Holdings, LLC, Harvard & Co., Bear Stearns Securities Corp., and Cudd & Co., who own approximately 25%, 23%, 13%, 11% and 10% of its units, respectively.
(5)	Includes 307,025 shares of restricted stock, of which 225,000 remain subject to vesting in one-half increments on February 24, 2007 and 2008, and 466,405 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 160,000 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan. Also includes an aggregate of 91,060 shares owned directly by the Kenneth V. Huseman Grantor Retained Annuity Trust and the Jaye M. Huseman Grantor Retained Annuity Trust.
(6)	Includes 33,335 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 116,665 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.
(7)	Includes 56,770 shares of restricted stock, which are fully vested. Mr. Carter resigned effective April 30, 2006.
(8)	Includes 34,259 shares of restricted stock, of which 25,000 remain subject to vesting in one-half increments on February 24, 2007 and 2008, and 91,225 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 40,000 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.
(9)	Includes 41,282 shares of restricted stock, of which 25,000 remain subject to vesting in one-half increments on February 24, 2007 and 2008, and 102,225 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 50,000 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.

(10)	Includes 62,500 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 35,000 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.
(11)	Includes 31,670 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 45,830 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.
(12)	Includes 35,000 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 47,500 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.
(13)	Does not include 42,500 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.
(14)	Includes 62,500 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 35,000 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan. Also reflects the beneficial ownership of an aggregate of 2,101,641 shares beneficially owned by Fortress Holdings, LLC and Anchor Resources, LLC. H. H. Wommack, III is a significant unitholder of Fortress Holdings, LLC and a director, manager and the President of each of Fortress Holdings, LLC and Anchor Resources, LLC with the intercompany relationships discussed in footnotes 3 and 4 above. Mr. Wommack disclaims beneficial ownership of the shares beneficially owned directly by Fortress Holdings, LLC and indirectly by Anchor Resources, LLC other than to the extent of his pecuniary interest in such shares.
(15)	Includes an aggregate of 454,336 restricted shares, of which 275,000 remain subject to vesting, and an aggregate of 1,062,200 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 754,155 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.

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DESCRIPTION OF CERTAIN OTHER INDEBTEDNESS

2005 Credit Facility

      Under our Third Amended and Restated Credit Agreement with a syndicate of lenders, as amended effective March 28, 2006, which we refer to as amended as the 2005 Credit Facility, Basic Energy Services, Inc. is the sole borrower and each of our subsidiaries is a subsidiary guarantor. The 2005 Credit Facility provided for a $90 million Term B Loan, which outstanding balance was repaid in April 2006, and provides for a $150 million revolving line of credit, or Revolver. The 2005 Credit Facility includes provisions allowing us to request an increase in commitments under the Term B Loan or the Revolver of up to $75 million at any time.

      The commitment under the Revolver provides for (1) the borrowing of funds, (2) the issuance of up to $30 million of letters of credit and (3) $2.5 million of swing-line loans. The amounts outstanding under the Term B Loan required quarterly amortization at various amounts during each quarter with all amounts outstanding being due and payable in full on December 15, 2011. All the outstanding amounts under the Revolver are due and payable on December 15, 2010. The 2005 Credit Facility is secured by substantially all of our tangible and intangible assets.

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

      At our option, borrowings under the Revolver bear interest at either (1) the Alternative Base Rate plus a margin ranging from 0.50% to 1.25% or (2) the LIBOR rate plus a margin ranging from 1.50% to 2.25%. The margins vary depending on our leverage ratio. At March 31, 2006, our margin on Alternative Base Rates and LIBOR tranches was 0.75% and 1.75%, respectively. Fees on the letters of credit are due quarterly on the outstanding amount of the letters of credit at a rate ranging from 1.50% to 2.25% for participation fees and 0.125% for fronting fees. A commitment fee is due quarterly on the available borrowings under the Revolver at rates ranging from 0.375% to 0.50%.

      At June 30, 2006, we had no amounts outstanding under the Term B Loan or under the Revolver.

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

• assets sales greater than $2.0 million individually or $7.5 million in the aggregate on an annual basis;

• 50% of the proceeds from any equity offering;

• proceeds of any issuance of debt not permitted by the 2005 Credit Facility;

• proceeds of permitted unsecured indebtedness, such as the Senior Notes, without reducing commitments under the revolver; and

• proceeds in excess of $2.5 million from casualty events.

      Prior to the date on which all Term B Loans were paid in April 2006, the 2005 Credit Facility required us to enter into an interest rate hedge, acceptable to the lenders, until May 28, 2006 on at least $65 million of our then-outstanding indebtedness.

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

• limitations on the incurrence of additional indebtedness;

• restrictions on mergers, sales or transfer of assets without the lenders’ consent;

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• limitation on dividends and distributions;

• limitations on capital expenditures; and

• various financial covenants, including:

• a maximum leverage ratio of 3.50 to 1.00 reducing to 3.25 to 1.00, and

• a minimum interest coverage ratio of 3.00 to 1.00.

      The 2005 Credit Facility contains customary events of default (which are subject to customary grace periods and materiality standards) including, among others: (1) non-payment of any amounts payable under the 2005 Credit Facility when due; (2) any representation or warrant made in connection with the 2005 Credit Facility being incorrect in any material respect when made or deemed made; (3) default in the observance or performance of any covenant, condition or agreement contained in the 2005 Credit Facility or related loan documents and such default continuing unremedied or not being waived for 30 days; (4) failure to make payments on other indebtedness involving in excess of $1.0 million; (5) voluntary or involuntary bankruptcy, insolvency or reorganization of us or any of our subsidiaries; (6) entry of fines or judgments against us for payment of an amount in excess of $2.5 million; (7) an ERISA event which could reasonably be expected to cause a material adverse effect or the imposition of a lien on any of our assets; (8) any security agreement or document under the 2005 Credit Facility ceasing to create a lien on any assets securing the 2005 Credit Facility; (9) any guarantee ceasing to be in full force and effect; (10) any material provision of the 2005 Credit Facility ceasing to be valid and binding or enforceable; (11) a change of control as defined in the 2005 Credit Agreement; or (12) any determination, ruling, decision, decree or order of any governmental authority that prohibits or restrains us and our subsidiaries from conducting business and that could reasonably be expected to cause a material adverse effect. At June 30, 2006, we were in compliance with our covenants under our 2005 Credit Facility.

Other Debt

          Capital Leases

      We have a variety of other capital leases and notes payable outstanding that are generally customary in our business. None of these debt instruments are material individually or in the aggregate. As of June 30, 2006, we had total capital leases of approximately $29.1 million.

          Contingent Earn-out Arrangements

      We have contingent earn-out arrangements in connection with seven of our acquisitions, including most recently G&L Tool. Contingent earn-out arrangements are generally arrangements entered into to encourage the owner or manager of the acquired business to continue operating and building the business after the purchase transaction. The contingent earn-out arrangements are generally linked to certain financial measures and performance of the acquired assets. As of December 31, 2005, we had maximum exposure under our contingent earn-out arrangements of approximately $1.2 million. The amount paid or accrued through December 31, 2005 was approximately $2.9 million.

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THE EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

      On April 12, 2006, we sold $225.0 million in aggregate principal amount at maturity of the old notes in a private placement. The old notes were sold to the initial purchasers who in turn resold the notes to a limited number of qualified institutional buyers pursuant to Rule 144A of the Securities Act.

      In connection with the sale of the old notes, we entered into a registration rights agreement with the initial purchasers of the old notes, pursuant to which we agreed to file and to use our reasonable efforts to cause to be declared effective by the SEC a registration statement with respect to the exchange of the old notes for the new notes. We are making the exchange offer to fulfill our contractual obligations under that agreement. A copy of the registration rights agreement has been filed as an exhibit to the registration statement of which this prospectus is a part.

      Pursuant to the exchange offer, we will issue the new notes in exchange for old notes. The terms of the new notes are identical in all material respects to those of the old notes, except that the new notes (1) have been registered under the Securities Act and therefore will not be subject to certain restrictions on transfer applicable to the old notes and (2) will not have registration rights or provide for any liquidated damages related to the obligation to register. Please read “Description of the New Notes” for more information on the terms of the respective notes and the differences between them.

      We are not making the exchange offer to, and will not accept tenders for exchange from, holders of old notes in any jurisdiction in which an exchange offer or the acceptance thereof would not be in compliance with the securities or blue sky laws of such jurisdiction. Unless the context requires otherwise, the term “holder” with respect to the exchange offer means any person in whose name the old notes are registered on our books or any other person who has obtained a properly completed bond power from the registered holder, or any person whose old notes are held of record by The Depository Trust Company, referred to as DTC, who desires to deliver such old notes by book-entry transfer at DTC.

      We make no recommendation to the holders of old notes as to whether to tender or refrain from tendering all or any portion of their old notes pursuant to the exchange offer. In addition, no one has been authorized to make any such recommendation. Holders of old notes must make their own decision whether to tender pursuant to the exchange offer and, if so, the aggregate amount of old notes to tender after reading this prospectus and the letter of transmittal and consulting with the advisers, if any, based on their own financial position and requirements.

      In order to participate in the exchange offer, you must represent to us, among other things, that:

• you are acquiring the new notes in the exchange offer in the ordinary course of your business;

• you are not engaged in, and do not intend to engage in, a distribution of the new notes;

• you do not have and to your knowledge, no one receiving new notes from you has, any arrangement or understanding with any person to participate in the distribution of the new notes;

• you are not a broker-dealer tendering old notes acquired directly from us for your own account or if you are a broker-dealer, you will comply with the prospectus delivery requirements of the Securities Act in connection with any resale of the new notes; and

• you are not one of our “affiliates,” as defined in Rule 405 of the Securities Act.

      Each broker-dealer that receives new notes for its own account in exchange for old notes, where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. Please read “Plan of Distribution.”

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Terms of Exchange

      Upon the terms and conditions described in this prospectus and in the accompanying letter of transmittal, which together constitute the exchange offer, we will accept for exchange old notes that are properly tendered at or before the expiration time and not withdrawn as permitted below. As of the date of this prospectus, $225.0 million aggregate principal amount of 7.125% Senior Notes due 2016 are outstanding. This prospectus, together with the letter of transmittal, is first being sent on or about the date on the cover page of the prospectus to all holders of old notes known to us. Old notes tendered in the exchange offer must be in denominations of principal amount of $1,000 and any integral multiple of $1,000.

      Our acceptance of the tender of old notes by a tendering holder will form a binding agreement between the tendering holder and us upon the terms and subject to the conditions provided in this prospectus and in the accompanying letter of transmittal.

      The form and terms of the new notes being issued in the exchange offer are the same as the form and terms of the old notes except that:

• the new notes being issued in the exchange offer will have been registered under the Securities Act;

• the new notes being issued in the exchange offer will not bear the restrictive legends restricting their transfer under the Securities Act; and

• the new notes being issued in the exchange offer will not contain the registration rights contained in the old notes.

Expiration, Extension and Amendment

      The expiration time of the exchange offer is 5:00 P.M., New York City time, on October 12, 2006. However, we may, in our sole discretion, extend the period of time for which the exchange offer is open and set a later expiration date for the offer. The term “expiration time” as used herein means the latest time and date to which we extend the exchange offer. If we decide to extend the exchange offer period, we will then delay acceptance of any old notes by giving oral or written notice of an extension to the holders of old notes as described below. During any extension period, all old notes previously tendered will remain subject to the exchange offer and may be accepted for exchange by us. Any old notes not accepted for exchange will be returned to the tendering holder after the expiration or termination of the exchange offer.

      Our obligation to accept old notes for exchange in the exchange offer is subject to the conditions described below under “— Conditions to the Exchange Offer.” We may decide to waive any of the conditions in our discretion. Furthermore, we reserve the right to amend or terminate the exchange offer, and not to accept for exchange any old notes not previously accepted for exchange, upon the occurrence of any of the conditions of the exchange offer specified below under the same heading. We will give oral or written notice of any extension, amendment, non — acceptance or termination to the holders of the old notes as promptly as practicable. If we materially change the terms of the exchange offer, we will resolicit tenders of the old notes, file a post — effective amendment to the prospectus and provide notice to you. If the change is made less than five business days before the expiration of the exchange offer, we will extend the offer so that the holders have at least five business days to tender or withdraw. We will notify you of any extension by means of a press release or other public announcement no later than 9:00 A.M., New York City time, on the first business day after the previously scheduled expiration time.

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Procedures for Tendering

          Valid Tender

      Except as described below, a tendering holder must, prior to the expiration time, transmit to The Bank of New York Trust Company, N.A., the exchange agent, at the address listed below under the caption “— Exchange Agent”:

• a properly completed and duly executed letter of transmittal, including all other documents required by the letter of transmittal; or

• if old notes are tendered in accordance with the book-entry procedures listed below, an agent’s message transmitted through DTC’s Automated Tender Offer Program, referred to as ATOP.

      In addition, you must:

• deliver certificates, if any, for the old notes to the exchange agent at or before the expiration time; or

• deliver a timely confirmation of the book-entry transfer of the old notes into the exchange agent’s account at DTC, the book-entry transfer facility, along with the letter of transmittal or an agent’s message; or

• comply with the guaranteed delivery procedures described below.

      The term “agent’s message” means a message, transmitted by DTC to, and received by, the exchange agent and forming a part of a book-entry confirmation, that states that DTC has received an express acknowledgment that the tendering holder agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against such holder.

      If the letter of transmittal is signed by a person other than the registered holder of old notes, the letter of transmittal must be accompanied by a written instrument of transfer or exchange in satisfactory form duly executed by the registered holder with the signature guaranteed by an eligible institution. The old notes must be endorsed or accompanied by appropriate powers of attorney. In either case, the old notes must be signed exactly as the name of any registered holder appears on the old notes.

      If the letter of transmittal or any old notes or powers of attorney are signed by trustees, executors, administrators, guardians,attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, these persons should so indicate when signing. Unless waived by us, proper evidence satisfactory to us of their authority to so act must be submitted.

      By tendering, each holder will represent to us that, among other things, the person is not our affiliate, the new notes are being acquired in the ordinary course of business of the person receiving the new notes, whether or not that person is the holder, and neither the holder nor the other person has any arrangement or understanding with any person to participate in the distribution of the new notes. Each broker-dealer that receives new notes for its own account in exchange for old notes, where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. Please read “Plan of Distribution.”

      The method of delivery of old notes, letters of transmittal and all other required documents is at your election and risk, and the delivery will be deemed made only upon actual receipt or confirmation by the exchange agent. If the delivery is by mail, we recommend that you use registered mail, properly insured, with return receipt requested. In all cases, you should allow sufficient time to assure timely delivery. Holders tendering through DTC’s ATOP system should allow sufficient time for completion of the ATOP procedures during the normal business hours of DTC on such dates.

      No old notes, agent’s messages, letters of transmittal or other required documents should be sent to us. Delivery of all old notes, agent’s messages, letters of transmittal and other documents must be

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made to the exchange agent. Holders may also request their respective brokers, dealers, commercial banks, trust companies or nominees to effect such tender for such holders.

      If you are a beneficial owner whose old notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee, and wish to tender, you should promptly instruct the registered holder to tender on your behalf. Any registered holder that is a participant in DTC’s ATOP system may make book-entry delivery of the old notes by causing DTC to transfer the old notes into the exchange agent’s account. The tender by a holder of old notes, including pursuant to the delivery of an agent’s message through DTC’s ATOP system, will constitute an agreement between such holder and us in accordance with the terms and subject to the conditions set forth herein and in the letter of transmittal.

      All questions as to the validity, form, eligibility, time of receipt and withdrawal of the tendered old notes will be determined by us in our sole discretion, which determination will be final and binding. We reserve the absolute right to reject any and all old notes not validly tendered or any old notes which, if accepted, would, in the opinion of our counsel, be unlawful. We also reserve the absolute right to waive any irregularities or conditions of tender as to particular old notes. Our interpretation of the terms and conditions of this exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of old notes must be cured within such time as we shall determine. Although we intend to notify you of defects or irregularities with respect to tenders of old notes, none of us, the exchange agent, or any other person shall be under any duty to give notification of defects or irregularities with respect to tenders of old notes, nor shall any of them incur any liability for failure to give such notification. Tenders of old notes will not be deemed to have been made until such irregularities have been cured or waived. Any old notes received by the exchange agent that are not validly tendered and as to which the defects or irregularities have not been cured or waived will be returned without cost to such holder by the exchange agent, unless otherwise provided in the letter of transmittal, as soon as practicable following the expiration date of the exchange offer.

      Although we have no present plan to acquire any old notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any old notes that are not tendered in the exchange offer, we reserve the right, in our sole discretion, to purchase or make offers for any old notes after the expiration date of the exchange offer, from time to time, through open market or privately negotiated transactions, one or more additional exchange or tender offers, or otherwise, as permitted by law, the indenture and our other debt agreements. Following consummation of this exchange offer, the terms of any such purchases or offers could differ materially from the terms of this exchange offer.

          Signature Guarantees

      Signatures on a letter of transmittal or a notice of withdrawal must be guaranteed, unless the old notes surrendered for exchange are tendered:

• by a registered holder of the old notes who has not completed the box entitled “Special Issuance Instructions” or “Special Delivery Instructions” on the letter of transmittal, or

• for the account of an “eligible institution.”

      If signatures on a letter of transmittal or a notice of withdrawal are required to be guaranteed, the guarantees must be by an “eligible institution.” An “eligible institution” is an “eligible guarantor institution” meeting the requirements of the registrar for the notes within the meaning of Rule 17Ad-15 under the Exchange Act.

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          Book-entry Transfer

      The exchange agent will make a request to establish an account for the old notes at DTC for purposes of the exchange offer. Any financial institution that is a participant in DTC’s system may make book-entry delivery of old notes by causing DTC to transfer those old notes into the exchange agent’s account at DTC in accordance with DTC’s procedure for transfer. The participant should transmit its acceptance to DTC at or prior to the expiration time or comply with the guaranteed delivery procedures described below. DTC will verify this acceptance, execute a book-entry transfer of the tendered old notes into the exchange agent’s account at DTC and then send to the exchange agent confirmation of this book-entry transfer. The confirmation of this book-entry transfer will include an agent’s message confirming that DTC has received an express acknowledgment from this participant that this participant has received and agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against this participant.

      Delivery of new notes issued in the exchange offer may be effected through book-entry transfer at DTC. However, the letter of transmittal or facsimile of it or an agent’s message, with any required signature guarantees and any other required documents, must:

• be transmitted to and received by the exchange agent at the address listed under “— Exchange Agent” at or prior to the expiration time; or

• comply with the guaranteed delivery procedures described below.

      Delivery of documents to DTC in accordance with DTC’s procedures does not constitute delivery to the exchange agent.

          Guaranteed Delivery

      If a registered holder of old notes desires to tender the old notes, and the old notes are not immediately available, or time will not permit the holder’s old notes or other required documents to reach the exchange agent before the expiration time, or the procedures for book-entry transfer described above cannot be completed on a timely basis, a tender may nonetheless be made if:

• the tender is made through an eligible institution;

• prior to the expiration time, the exchange agent receives by facsimile transmission, mail or hand delivery from such eligible institution a properly and validly completed and duly executed notice of guaranteed delivery, substantially in the form provided by us:

1.	stating the name and address of the holder of old notes and the amount of old notes tendered,
2.	stating that the tender is being made, and
3.	guaranteeing that within three New York Stock Exchange trading days after the expiration time, the certificates for all physically tendered old notes, in proper form for transfer, or a book-entry confirmation, as the case may be, and a properly completed and duly executed letter of transmittal, or an agent’s message, and any other documents required by the letter of transmittal will be deposited by the eligible institution with the exchange agent; and

• the certificates for all physically tendered old notes, in proper form for transfer, or a book-entry confirmation, as the case may be, and a properly completed and duly executed letter of transmittal, or an agent’s message, and all other documents required by the letter of transmittal, are received by the exchange agent within three New York Stock Exchange trading days after the date of execution of the notice of guaranteed delivery.

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          Determination of Validity

      We will determine in our sole discretion all questions as to the validity, form and eligibility of old notes tendered for exchange. This discretion extends to the determination of all questions concerning the timing of receipts and acceptance of tenders. These determinations will be final and binding. We reserve the right to reject any particular old note not properly tendered or of which our acceptance might, in our judgment or our counsel’s judgment, be unlawful. We also reserve the right to waive any defects or irregularities or conditions of the exchange offer as to any particular old note either before or after the expiration time, including the right to waive the ineligibility of any tendering holder. Our interpretation of the terms and conditions of the exchange offer as to any particular old note either before or after the applicable expiration time, including the letter of transmittal and the instructions to the letter of transmittal, shall be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of old notes must be cured within a reasonable period of time.

      Neither we, the exchange agent nor any other person will be under any duty to give notification of any defect or irregularity in any tender of old notes. Moreover, neither we, the exchange agent nor any other person will incur any liability for failing to give notifications of any defect or irregularity.

Acceptance of Old Notes for Exchange; Issuance of New Notes

      Upon the terms and subject to the conditions of the exchange offer, we will accept, promptly after the expiration time, all old notes properly tendered. We will issue the new notes promptly after acceptance of the old notes. For purposes of an exchange offer, we will be deemed to have accepted properly tendered old notes for exchange when, as and if we have given oral or written notice to the exchange agent, with prompt written confirmation of any oral notice.

      For each old note accepted for exchange, the holder will receive a new note registered under the Securities Act having a principal amount equal to that of the surrendered old note. As a result, registered holders of old notes issued in the exchange offer on the relevant record date for the first interest payment date following the completion of the exchange offer will receive interest accruing from the most recent date to which interest has been paid on the old notes or, if no interest has been paid on the old notes, from April 12, 2006. Old notes that we accept for exchange will cease to accrue interest from and after the date of completion of the exchange offer. Under the registration rights agreement, we may be required to make additional payments in the form of liquidated damages to the holders of the old notes under circumstances relating to the timing of the exchange offer.

      In all cases, issuance of new notes for old notes will be made only after timely receipt by the exchange agent of:

• certificate for the old notes, or a timely book-entry confirmation of the old notes, into the exchange agent’s account at the book-entry transfer facility;

• a properly completed and duly executed letter of transmittal or an agent’s message; and

• all other required documents.

      Unaccepted or non-exchanged old notes will be returned without expense to the tendering holder of the old notes. In the case of old notes tendered by book-entry transfer in accordance with the book-entry procedures described above, the non-exchanged old notes will be credited to an account maintained with DTC as promptly as practicable after the expiration or termination of the exchange offer. For each old note accepted for exchange, the holder of the old note will receive a new note having a principal amount equal to that of the surrendered old note.

Interest Payments on the New Notes

      The new notes will bear interest from the most recent date to which interest has been paid on the old notes for which they were exchanged. Accordingly, registered holders of new notes on the relevant

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record date for the first interest payment date following the completion of the exchange offer will receive interest accruing from the most recent date to which interest has been paid. Old notes accepted for exchange will cease to accrue interest from and after the date of completion of the exchange offer and will be deemed to have waived their rights to receive the accrued interest on the old notes.

Withdrawal Rights

      Tender of old notes may be properly withdrawn at any time before 5:00 p.m., New York City time, on the expiration date of the exchange offer.

      For a withdrawal to be effective with respect to old notes, the exchange agent must receive a written notice of withdrawal before the expiration time delivered by hand, overnight by courier or by mail, at the address indicated under “— Exchange Agent” or, in the case of eligible institutions, at the facsimile number, or a properly transmitted “Request Message” through DTC’s ATOP system. Any notice of withdrawal must:

• specify the name of the person, referred to as the depositor, having tendered the old notes to be withdrawn;

• identify the old notes to be withdrawn, including certificate numbers and principal amount of the old notes;

• contain a statement that the holder is withdrawing its election to have the old notes exchanged;

• other than a notice transmitted through DTC’s ATOP system, be signed by the holder in the same manner as the original signature on the letter of transmittal by which the old notes were tendered, including any required signature guarantees, or be accompanied by documents of transfer to have the trustee with respect to the old notes register the transfer of the old notes in the name of the person withdrawing the tender; and

• specify the name in which the old notes are registered, if different from that of the depositor.

      If certificates for old notes have been delivered or otherwise identified to the exchange agent, then, prior to the release of these certificates the withdrawing holder must also submit the serial numbers of the particular certificates to be withdrawn and signed notice of withdrawal with signatures guaranteed by an eligible institution, unless this holder is an eligible institution. If old notes have been tendered in accordance with the procedure for book-entry transfer described below, any notice of withdrawal must specify the name and number of the account at the book-entry transfer facility to be credited with the withdrawn old notes.

      Any old notes properly withdrawn will be deemed not to have been validly tendered for exchange. New notes will not be issued in exchange unless the old notes so withdrawn are validly re-tendered.

      Properly withdrawn old notes may be re-tendered by following the procedures described under “— Procedures for Tendering” above at any time at or before the expiration time.

      We will determine all questions as to the validity, form and eligibility, including time of receipt, of notices of withdrawal.

Conditions to the Exchange Offer

      Notwithstanding any other provisions of the exchange offer, or any extension of the exchange offer, we will not be required to accept for exchange, or to exchange, any old notes for any new notes, and, as described below, may terminate an exchange offer, whether or not any old notes have been

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accepted for exchange, or may waive any conditions to or amend the exchange offer, if any of the following conditions has occurred or exists:

• there shall occur a change in the current interpretation by the staff of the SEC which permits the new notes issued pursuant to such exchange offer in exchange for old notes to be offered for resale, resold and otherwise transferred by the holders (other than broker-dealers and any holder which is an affiliate) without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that such new notes are acquired in the ordinary course of such holders’ business and such holders have no arrangement or understanding with any person to participate in the distribution of the new notes;

• any action or proceeding shall have been instituted or threatened in any court or by or before any governmental agency or body seeking to enjoin, make illegal or delay completion of the exchange offer or otherwise relating to the exchange offer;

• any law, statute, rule or regulation shall have been adopted or enacted which, in our judgment, would reasonably be expected to impair our ability to proceed with such exchange offer;

• a banking moratorium shall have been declared by United States federal or New York State authorities;

• trading on the New York Stock Exchange or generally in the United Statesover-the-counter market shall have been suspended, or a limitation on prices for securities imposed, by order of the SEC or any other governmental authority;

• an attack on the United States, an outbreak or escalation of hostilities or acts of terrorism involving the United States, or any declaration by the United States of a national emergency or war shall have occurred;

• a stop order shall have been issued by the SEC or any state securities authority suspending the effectiveness of the registration statement of which this prospectus is a part or proceedings shall have been initiated or, to our knowledge, threatened for that purpose or any governmental approval has not been obtained, which approval we shall, in our sole discretion, deem necessary for the consummation of such exchange offer; or

• any change, or any development involving a prospective change, in our business or financial affairs or any of our subsidiaries has occurred which is or may be adverse to us or we shall have become aware of facts that have or may have an adverse impact on the value of the old notes or the new notes, which in our sole judgment in any case makes it inadvisable to proceed with such exchange offer and/or with such acceptance for exchange or with such exchange.

      If we determine in our sole discretion that any of the foregoing events or conditions has occurred or exists, we may, subject to applicable law, terminate the exchange offer, whether or not any old notes have been accepted for exchange, or may waive any such condition or otherwise amend the terms of such exchange offer in any respect. Please read “— Expiration, Extension and Amendment” above.

      If any of the above events occur, we may:

• terminate the exchange offer and promptly return all tendered old notes to tendering holders;

• complete and/or extend the exchange offer and, subject to your withdrawal rights, retain all tendered old notes until the extended exchange offer expires;

• amend the terms of the exchange offer; or

• waive any unsatisfied condition and, subject to any requirement to extend the period of time during which the exchange offer is open, complete the exchange offer.

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      We may assert these conditions with respect to the exchange offer regardless of the circumstances giving rise to them. All conditions to the exchange offer, other than those dependent upon receipt of necessary government approvals, must be satisfied or waived by us before the expiration of the exchange offer. We may waive any condition in whole or in part at any time in our reasonable discretion. Our failure to exercise our rights under any of the above circumstances does not represent a waiver of these rights. Each right is an ongoing right that may be asserted at any time. Any determination by us concerning the conditions described above will be final and binding upon all parties.

      If a waiver constitutes a material change to the exchange offer, we will promptly disclose the waiver by means of a prospectus supplement that we will distribute to the registered holders of the old notes, and we will extend the exchange offer for a period of five to ten business days, as required by applicable law, depending upon the significance of the waiver and the manner of disclosure to the registered holders, if the exchange offer would otherwise expire during the five to ten business day period.

Resales of New Notes

      Based on interpretations by the staff of the SEC, as described inno-action letters issued to third parties that are not related to us, we believe that new notes issued in the exchange offer in exchange for old notes may be offered for resale, resold or otherwise transferred by holders of the new notes without compliance with the registration and prospectus delivery provisions of the Securities Act, if:

• the new notes are acquired in the ordinary course of the holder’s business;

• the holders have no arrangement or understanding with any person to participate in the distribution of the new notes;

• the holders are not “affiliates” of ours within the meaning of Rule 405 under the Securities Act; and

• the holders are not a broker-dealer who purchased old notes directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act.

      However, the SEC has not considered the exchange offer described in this prospectus in the context of ano-action letter. The staff of the SEC may not make a similar determination with respect to the exchange offer as in the other circumstances. Each holder who wishes to exchange old notes for new notes will be required to represent that it meets the requirements above.

      Any holder who is an affiliate of ours or who intends to participate in the exchange offer for the purpose of distributing new notes or any broker-dealer who purchased old notes directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act:

• cannot rely on the applicable interpretations of the staff of the SEC mentioned above;

• will not be permitted or entitled to tender the old notes in the exchange offer; and

• must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

      Each broker-dealer that receives new notes for its own account in exchange for old notes must acknowledge that the old notes were acquired by it as a result of market-making activities or other trading activities and agree that it will deliver a prospectus that meets the requirements of the Securities Act in connection with any resale of the new notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. Please read “Plan of Distribution.” A broker-dealer may use this prospectus, as it may be amended or supplemented from time to time, in connection with the resales of new notes received in exchange for old notes that the broker-dealer

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acquired as a result of market-making or other trading activities. Any holder that is a broker-dealer participating in the exchange offer must notify the exchange agent at the telephone number set forth in the enclosed letter of transmittal and must comply with the procedures for broker-dealers participating in the exchange offer. We have not entered into any arrangement or understanding with any person to distribute the new notes to be received in the exchange offer.

      In addition, to comply with state securities laws, the new notes may not be offered or sold in any state unless they have been registered or qualified for sale in such state or an exemption from registration or qualification, with which there has been compliance, is available. The offer and sale of the new notes to “qualified institutional buyers,” as defined under Rule 144A of the Securities Act, is generally exempt from registration or qualification under the state securities laws. We currently do not intend to register or qualify the sale of new notes in any state where an exemption from registration or qualification is required and not available.

Exchange Agent

      The Bank of New York Trust Company, N.A. has been appointed as the exchange agent for the exchange offer. All executed letters of transmittal and any other required documents should be directed to the exchange agent at the address or facsimile number set forth below. Questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for notices of guaranteed delivery should be directed to the exchange agent addressed as follows:

THE BANK OF NEW YORK TRUST COMPANY, N.A.

By Facsimile for Eligible Institutions:
(212) 298-1915
Attention: Mr. Randolph Holder By Mail/Overnight Delivery/Hand:
The Bank of New York Trust Company, N.A.
Corporate Trust Operations
Reorganization Unit
101 Barclay Street — 7 East
New York, New York 10286 Attention: Mr. Randolph Holder Confirm By
Telephone:
(212) 815-5098

      DELIVERY OF THE LETTER OF TRANSMITTAL TO AN ADDRESS OTHER THAN AS SET FORTH ABOVE OR TRANSMISSION OF SUCH LETTER OF TRANSMITTAL VIA FACSIMILE OTHER THAN AS SET FORTH ABOVE DOES NOT CONSTITUTE A VALID DELIVERY OF THE LETTER OF TRANSMITTAL.

Fees and Expenses

      The expenses of soliciting tenders pursuant to this exchange offer will be paid by us. We have agreed to pay the exchange agent reasonable and customary fees for its services and will reimburse it for its reasonableout-of-pocket expenses in connection with the exchange offer. We will also pay brokerage houses and other custodians, nominees and fiduciaries the reasonableout-of-pocket expenses incurred by them in forwarding copies of this prospectus and related documents to the beneficial owners of old notes, and in handling or tendering for their customers. We will not make any payment to brokers, dealers or others soliciting acceptances of the exchange offer.

      Holders who tender their old notes for exchange will not be obligated to pay any transfer taxes on the exchange. If, however, new notes are to be delivered to, or are to be issued in the name of, any person other than the registered holder of the old notes tendered, or if a transfer tax is imposed for any reason other than the exchange of old notes in connection with the exchange offer, then the amount of any such transfer taxes (whether imposed on the registered holder or any other persons) will be payable by the tendering holder. If satisfactory evidence of payment of such taxes or exemption therefrom is not submitted with the letter of transmittal, the amount of such transfer taxes will be billed directly to such tendering holder.

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Transfer Taxes

      We will pay all transfer taxes, if any, applicable to the exchange of old notes under the exchange offer. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if a transfer tax is imposed for any reason other than the exchange of old notes under the exchange offer.

Consequences of Failure to Exchange Outstanding Securities

      Holders who desire to tender their old notes in exchange for new notes registered under the Securities Act should allow sufficient time to ensure timely delivery. Neither the exchange agent nor us is under any duty to give notification of defects or irregularities with respect to the tenders of old notes for exchange.

      Old notes that are not tendered or are tendered but not accepted will, following the completion of the exchange offer, continue to be subject to the provisions in the indenture regarding the transfer and exchange of the old notes and the existing restrictions on transfer set forth in the legend on the old notes set forth in the indenture for the notes. Except in limited circumstances with respect to specific types of holders of old notes, we will have no further obligation to provide for the registration under the Securities Act of such old notes. In general, old notes, unless registered under the Securities Act, may not be offered or sold except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws.

      We do not currently anticipate that we will take any action to register the old notes under the Securities Act or under any state securities laws. Upon completion of the exchange offer, holders of the old notes will not be entitled to any further registration rights under the registration rights agreement, except under limited circumstances.

      Holders of the new notes issued in the exchange offer, any old notes which remain outstanding after completion of the exchange offer and the previously issued notes will vote together as a single class for purposes of determining whether holders of the requisite percentage of the class have taken certain actions or exercised certain rights under the indenture.

Accounting Treatment

      We will record the new notes at the same carrying value as the old notes, as reflected in our accounting records on the date of the exchange. Accordingly, we will not recognize any gain or loss for accounting purposes. The expenses of the exchange offer will be amortized over the term of the new notes.

Other

      Participation in the exchange offer is voluntary, and you should consider carefully whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

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DESCRIPTION OF THE NEW NOTES

      We issued the old notes under an Indenture (the “Indenture”) among us, the Subsidiary Guarantors and The Bank of New York Trust Company, N.A., as trustee (the “Trustee”). We will issue the new notes under the same Indenture under which we issued the old notes, and the new notes will represent the same debt as the old notes for which they are exchanged.

      The Indenture is governed by the Trust Indenture Act of 1939 (the “Trust Indenture Act”). The terms of the notes include those stated in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act.

      Under the Indenture, we may issue an unlimited principal amount of additional notes having identical terms and conditions as the Notes (the “Additional Notes”). We will only be permitted to issue such Additional Notes in compliance with the covenant described under the subheading “— Certain Covenants — Limitations on Additional Indebtedness.” Any Additional Notes will be part of the same issue as the Notes and will vote on all matters with the holders of the Notes.

      Old notes that remain outstanding after the completion of the exchange offer, together with the new notes, will be treated as a single class of securities under the Indenture. Unless the context otherwise requires, for all purposes of the Indenture and this “Description of the New Notes,” references to the Notes include the old notes, the new notes and any Additional Notes actually issued, and all references to specified percentages in aggregate principal amount of the notes shall be deemed to mean, at any time after the exchange offer is completed, such percentage in aggregate principal amount of the old notes and the new notes then outstanding.

      The terms of the new notes will be substantially identical to the terms of the old notes, except that the new notes:

• will have been registered under the Securities Act;

• will not be subject to transfer restrictions applicable to the old notes; and

• will not have the benefit of the registration rights agreement applicable to the old notes.

      The following description is intended to be a useful overview of the material provisions of the Notes and the Indenture. Since this description of notes is only a summary, you should refer to the Indenture for a complete description of the obligations of the Company and your rights.

      You will find the definitions of capitalized terms used in this description of notes under the heading “Certain Definitions.” For purposes of this description, references to “the Company,” “we,” “our” and “us” refer only to Basic Energy Services, Inc. and not to any of its subsidiaries.

Principal, Maturity and Interest

      The Notes will mature on April 15, 2016. The Notes will bear interest at the rate shown on the cover page of this prospectus, payable in cash semi-annually in arrears on April 15 and October 15 of each year, commencing on October 15, 2006, to Holders of record at the close of business on April 1 or October 1, as the case may be, immediately preceding the related interest payment date. Interest on the Notes will accrue from and including the most recent date to which interest has been paid or, if no interest has been paid, from and including the date of issuance. Interest on the Notes will be computed on the basis of a360-day year of twelve30-day months.

      If an interest payment date falls on a day that is not a Business Day, the interest payment to be made on such interest payment date will be made on the next succeeding Business Day with the same force and effect as if made on such interest payment date, and no additional interest will accrue solely as a result of such delayed payment. Interest on overdue principal and interest and Liquidated Damages, if any, will accrue at the applicable interest rate on the Notes.

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      We also will pay Liquidated Damages to Holders of the Notes if we fail to complete this exchange offer within 270 days after the issue date of the old notes or if certain other conditions contained in the Registration Rights Agreement are not satisfied. Any Liquidated Damages due will be paid on the same dates as interest on the Notes. All references in the Indenture, in any context, to any interest or other amount payable on or with respect to the Notes shall be deemed to include any Liquidated Damages pursuant to the Registration Rights Agreement.

      The Notes will be issued in registered form, without coupons, and in denominations of $1,000 and integral multiples of $1,000.

Methods of Receiving Payments on the Notes

      If a Holder has given wire transfer instructions to the Issuer at least ten Business Days prior to the applicable payment date, the Issuer will make all payments on such Holder’s Notes by wire transfer of immediately available funds to the account specified in those instructions. Otherwise, payments on the Notes will be made at the office or agency of the paying agent (the“Paying Agent”) and registrar (the“Registrar”) for the Notes within the City and State of New York unless the Issuer elects to make interest payments by check mailed to the Holders at their addresses set forth in the register of Holders.

Ranking

      The Notes will be general unsecured obligations of the Issuer. The Notes will rank senior in right of payment to all future obligations of the Issuer that are, by their terms, expressly subordinated in right of payment to the Notes andpari passuin right of payment with all existing and future unsecured obligations of the Issuer that are not so subordinated. Each Note Guarantee (as defined below) will be a general unsecured obligation of the Guarantor thereof and will rank senior in right of payment to all future obligations of such Guarantor that are, by their terms, expressly subordinated in right of payment to such Note Guarantee andpari passuin right of payment with all existing and future unsecured obligations of such Guarantor that are not so subordinated.

      The Notes and each Note Guarantee will be effectively subordinated to secured Indebtedness of the Issuer and the applicable Guarantor to the extent of the value of the assets securing such Indebtedness. The Credit Agreement is and is expected to continue to be secured by substantially all of the assets of the Issuer and its Subsidiaries.

      The Notes will also be effectively subordinated to all existing and future obligations, including Indebtedness, of any Subsidiaries of the Issuer that do not guarantee the Notes, including any Unrestricted Subsidiaries. Claims of creditors of these Subsidiaries, including trade creditors, will generally have priority as to the assets of these Subsidiaries over the claims of the Issuer and the holders of the Issuer’s Indebtedness, including the Notes.

      As of June 30, 2006, the Issuer had $29.1 million aggregate principal amount of outstanding secured Indebtedness and $140.4 million of undrawn borrowings available under the Credit Agreement. Although the Indenture contains limitations on the amount of additional secured Indebtedness that the Issuer and the Restricted Subsidiaries may incur, under certain circumstances, the amount of this Indebtedness could be substantial. See “— Certain Covenants — Limitations on Additional Indebtedness” and “— Limitations on Liens.”

Note Guarantees

      The Issuer’s obligations under the Notes and the Indenture will be jointly and severally guaranteed (the“Note Guarantees”) by each Domestic Restricted Subsidiary that guarantees any Indebtedness under any Credit Facility and each other Domestic Restricted Subsidiary that the Issuer shall otherwise cause to become a Guarantor pursuant to the terms of the Indenture.

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      As of the date of the Indenture, all of our current Subsidiaries were “Domestic Restricted Subsidiaries,” and all of them guaranteed the Notes. However, under the circumstances described below under the subheading “— Certain Covenants — Limitation on Designation of Unrestricted Subsidiaries,” the Issuer will be permitted to designate any of its Subsidiaries as “Unrestricted Subsidiaries.” The effect of designating a Subsidiary as an “Unrestricted Subsidiary” will be that:

• an Unrestricted Subsidiary will not be subject to many of the restrictive covenants in the Indenture;

• an Unrestricted Subsidiary will not guarantee the Notes;

• a Subsidiary that has previously been a Guarantor and that is designated an Unrestricted Subsidiary will be released from its Note Guarantee and its obligations under the Indenture and the Registration Rights Agreement; and

• the assets, income, cash flow and other financial results of an Unrestricted Subsidiary will not be consolidated with those of the Issuer for purposes of calculating compliance with the restrictive covenants contained in the Indenture.

      The obligations of each Guarantor under its Note Guarantee will be limited to the maximum amount as will, after giving effect to all other contingent and fixed liabilities of such Guarantor (including, without limitation, any guarantees under the Credit Agreement) and after giving effect to any collections from or payments made by or on behalf of any other Guarantor in respect of the obligations of such other Guarantor under its Note Guarantee or pursuant to its contribution obligations under the Indenture, result in the obligations of such Guarantor under its Note Guarantee not constituting a fraudulent conveyance or fraudulent transfer under federal or state law. Nonetheless, in the event of the bankruptcy or financial difficulty of a Guarantor, such Guarantor’s obligations under its Note Guarantee may be subject to review and avoidance under state and federal fraudulent transfer laws. Among other things, such obligations may be avoided if a court concludes that such obligations were incurred for less than a reasonably equivalent value or fair consideration at a time when the Guarantor was insolvent, was rendered insolvent, or was left with inadequate capital to conduct its business. A court would likely conclude that a Guarantor did not receive reasonably equivalent value or fair consideration to the extent that the aggregate amount of its liability on its Note Guarantee exceeds the economic benefits it receives from the issuance of the Note Guarantee. See “Risk Factors — Risks Relating to the Notes — Federal and state statutes may allow courts, under specific circumstances, to void the guarantees and require noteholders to return payments received from guarantors.”

      Each Guarantor that makes a payment for distribution under its Note Guarantee is entitled to a contribution from each other Guarantor in apro rata amount based on adjusted net assets of each Guarantor.

      A Subsidiary Guarantor shall be released from its obligations under its Note Guarantee and its obligations under the Indenture and the Registration Rights Agreement:

(1) in the event of a sale or other disposition of all or substantially all of the assets of such Subsidiary Guarantor, by way of merger, consolidation or otherwise, or a sale or other disposition of all of the Equity Interests of such Subsidiary Guarantor then held by the Issuer and the Restricted Subsidiaries; or

(2) if such Subsidiary Guarantor is designated as an Unrestricted Subsidiary or otherwise ceases to be a Restricted Subsidiary, in each case in accordance with the provisions of the Indenture, upon effectiveness of such designation or when it first ceases to be a Restricted Subsidiary, respectively.

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Optional Redemption

          General

      At any time or from time to time on or after April 15, 2011, the Issuer, at its option, may redeem the Notes, in whole or in part, at the redemption prices (expressed as percentages of principal amount) set forth below, together with accrued and unpaid interest and Liquidated Damages thereon, if any, to the redemption date, if redeemed during the12-month period beginning April 15 of the years indicated:

	Optional
	Redemption
Year	Price
2011		103.563%
2012		102.375%
2013		101.188%
2014 and thereafter		100.000%

          Redemption with Proceeds from Equity Offerings

      At any time or from time to time prior to April 15, 2009, the Issuer, at its option, may on any one or more occasions redeem Notes issued under the Indenture with the net cash proceeds of one or more Qualified Equity Offerings at a redemption price equal to 107.125% of the principal amount of the Notes to be redeemed, plus accrued and unpaid interest and Liquidated Damages thereon, if any, to the date of redemption;providedthat:

(1) at least 65% of the aggregate principal amount of Notes issued under the Indenture remains outstanding immediately after giving effect to any such redemption; and

(2) the redemption occurs not more than 90 days after the date of the closing of any such Qualified Equity Offering.

          Redemption at Applicable Premium

      The Notes may also be redeemed, in whole or in part, at any time prior to April 15, 2011 at the option of the Issuer upon not less than 30 nor more than 60 days’ prior notice mailed by first-class mail to each holder of Notes at its registered address, at a redemption price equal to 100% of the principal amount of the Notes redeemed plus the Applicable Premium as of, and accrued and unpaid interest and Liquidated Damages, if any, to, the applicable redemption date (subject to the right of Holders of record on the relevant record date to receive interest due on the relevant interest payment date).“Applicable Premium”means, with respect to any Note on any applicable redemption date, the greater of:

(1) 1.0% of the principal amount of such Note; and

(2) the excess, if any, of:

(a) the present value at such redemption date of (i) the redemption price of such Note at April 15, 2011 (such redemption price being set forth in the table appearing above under the caption “— Optional Redemption — General”) plus (ii) all required interest payments (excluding accrued and unpaid interest to such redemption date) due on such Note through April 15, 2011, computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over

(b) the principal amount of such Note.

     “Treasury Rate”means, as of any redemption date, the yield to maturity at the time of computation of United States Treasury securities with a constant maturity (as compiled and published

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in the most recent Federal Reserve Statistical Release H.15 (519) which has become publicly available at least two Business Days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source or similar market data)) most nearly equal to the period from the redemption date to April 15, 2011;provided, however, that if the period from the redemption date to April 15, 2011 is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Treasury Rate shall be obtained by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given, except that if the period from the redemption date to April 15, 2011 is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year shall be used.

      The Issuer may acquire Notes by means other than a redemption, whether pursuant to an issuer tender offer, open market purchase or otherwise, so long as the acquisition does not otherwise violate the terms of the Indenture.

Selection and Notice of Redemption

      In the event that less than all of the Notes are to be redeemed at any time pursuant to an optional redemption, the Trustee will select the Notes for redemption in compliance with the requirements of the principal national securities exchange, if any, on which the Notes are listed or, if the Notes are not then listed on a national security exchange, on apro ratabasis, by lot or by such method as the Trustee shall deem fair and appropriate;provided, however, that no Notes of a principal amount of $1,000 or less shall be redeemed in part. In addition, if a partial redemption is made pursuant to the provisions described under “— Optional Redemption — Redemption with Proceeds from Equity Offerings,” selection of the Notes or portions thereof for redemption shall be made by the Trustee only on apro ratabasis or on as nearly apro ratabasis as is practicable (subject to the procedures of The Depository Trust Company(“DTC”)), unless that method is otherwise prohibited.

      Notice of redemption will be mailed by first-class mail at least 30, but not more than 60, days before the date of redemption to each Holder of Notes to be redeemed at its registered address, except that redemption notices may be mailed more than 60 days prior to a redemption date if the notice is issued in connection with a satisfaction and discharge of the Indenture. If any Note is to be redeemed in part only, the notice of redemption that relates to that Note will state the portion of the principal amount of the Note to be redeemed. A new Note in a principal amount equal to the unredeemed portion of the Note will be issued in the name of the Holder of the Note upon cancellation of the original Note. On and after the applicable date of redemption, interest will cease to accrue on Notes or portions thereof called for redemption so long as the Issuer has deposited with the paying agent for the Notes funds in satisfaction of the applicable redemption price (including accrued and unpaid interest on the Notes to be redeemed) pursuant to the Indenture.

Change of Control

      Upon the occurrence of any Change of Control, unless the Issuer has previously or concurrently exercised its right to redeem all of the Notes as described under “— Optional Redemption,” each Holder will have the right to require that the Issuer purchase all or any portion (equal to $1,000 or an integral multiple thereof) of that Holder’s Notes for a cash price (the“Change of Control Purchase Price”) equal to 101% of the principal amount of the Notes to be purchased, plus accrued and unpaid interest and Liquidated Damages, if any, thereon to the date of purchase.

      Within 30 days following any Change of Control, the Issuer will mail, or caused to be mailed, to the Holders, with a copy to the Trustee, a notice:

(1) describing the transaction or transactions that constitute the Change of Control;

(2) offering to purchase, pursuant to the procedures required by the Indenture and described in the notice (a“Change of Control Offer”), on a date specified in the notice (which shall be a

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Business Day not earlier than 30 days, nor later than 60 days, from the date the notice is mailed) and for the Change of Control Purchase Price, all Notes properly tendered by such Holder pursuant to such Change of Control Offer; and

(3) describing the procedures, as determined by the Issuer, that Holders must follow to accept the Change of Control Offer.

      A Change of Control Offer will be required to remain open for at least 20 Business Days or for such longer period as is required by law. The Issuer will publicly announce the results of the Change of Control Offer on or as soon as practicable after the date of purchase.

      If a Change of Control Offer is made, there can be no assurance that the Issuer will have available funds sufficient to pay for all or any of the Notes that might be delivered by Holders seeking to accept the Change of Control Offer. In addition, we cannot assure you that in the event of a Change of Control the Issuer will be able to obtain the consents necessary to consummate a Change of Control Offer from the lenders under agreements governing outstanding Indebtedness which may prohibit the offer.

      The provisions described above that require us to make a Change of Control Offer following a Change of Control will be applicable regardless of whether any other provisions of the Indenture are applicable to the transaction giving rise to the Change of Control. Except as described above with respect to a Change of Control, the Indenture does not contain provisions that permit the Holders of the Notes to require that the Issuer purchase or redeem the Notes in the event of a takeover, recapitalization or similar transaction.

      The Issuer’s obligation to make a Change of Control Offer will be satisfied if a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the Indenture applicable to a Change of Control Offer made by the Issuer and purchases all Notes properly tendered and not withdrawn under such Change of Control Offer.

      With respect to any disposition of assets, the phrase “all or substantially all” as used in the Indenture (including as set forth under the definition of “Change of Control” and “— Certain Covenants — Limitations on Mergers, Consolidations, Etc.” below) varies according to the facts and circumstances of the subject transaction, has no clearly established meaning under New York law (which governs the Indenture) and is subject to judicial interpretation. Accordingly, in certain circumstances there may be a degree of uncertainty in ascertaining whether a particular transaction would involve a disposition of “all or substantially all” of the assets of the Issuer, and therefore it may be unclear as to whether a Change of Control has occurred and whether the Holders have the right to require the Issuer to purchase Notes.

      The Issuer will comply with applicable tender offer rules, including the requirements of Rule 14e-l under the Exchange Act and any other applicable laws and regulations in connection with the purchase of Notes pursuant to a Change of Control Offer. To the extent that the provisions of any securities laws or regulations conflict with the “Change of Control” provisions of the Indenture, the Issuer shall comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the “Change of Control” provisions of the Indenture by virtue of this compliance.

      The provisions under the Indenture relating to the Issuer’s obligation to make a Change of Control Offer may be waived, modified or terminated prior to the occurrence of the triggering Change of Control with the written consent of the Holders of a majority in principal amount of the Notes then outstanding.

      Notwithstanding anything to the contrary herein, a Change of Control Offer may be made in advance of a Change of Control, conditional upon such Change of Control, if a definitive agreement is in place for the Change of Control at the time of making of the Change of Control Offer.

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Certain Covenants

          Covenant Suspension

      During any period of time that the Notes have a Moody’s rating of Baa3 or higher or an S&P rating of BBB- or higher (each, an“Investment Grade Rating”) and no Default has occurred and is then continuing, the Issuer and the Restricted Subsidiaries will not be subject to the following covenants:

• “Change of Control;”

• “— Certain Covenants — Limitations on Additional Indebtedness;”

• “— Certain Covenants — Limitations on Layering Indebtedness;”

• “— Certain Covenants — Limitations on Restricted Payments;”

• “— Certain Covenants — Limitations on Dividend and Other Restrictions Affecting Restricted Subsidiaries;”

• “— Certain Covenants — Limitations on Transactions with Affiliates;”

• “— Certain Covenants — Limitations on Asset Sales;”

• clause (3) of the covenant described under “— Certain Covenants — Limitations on Mergers, Consolidations, Etc.;”

• “— Certain Covenants — Additional Note Guarantees;” and

• “— Certain Covenants — Conduct of Business”

(collectively, the“Suspended Covenants”). In the event that the Issuer and the Restricted Subsidiaries are not subject to the Suspended Covenants for any period of time as a result of the preceding sentence and, subsequently, one or both of the Rating Agencies, as applicable, withdraws its ratings or downgrades the ratings assigned to the Notes such that the Notes do not have an Investment Grade Rating, then the Issuer and the Restricted Subsidiaries will thereafter again be subject to the Suspended Covenants, it being understood that no actions taken by (or omissions of) the Issuer or any of its Restricted Subsidiaries during the suspension period shall constitute a Default or an Event of Default under the Suspended Covenants. Furthermore, after the time of reinstatement of the Suspended Covenants upon such withdrawal or downgrade, calculations with respect to Restricted Payments will be made in accordance with the terms of the covenant described below under “— Certain Covenants — Limitations on Restricted Payments” as though such covenant had been in effect during the entire period of time from the Issue Date.

          Limitations on Additional Indebtedness

      The Issuer will not, and will not permit any Restricted Subsidiary to, directly or indirectly, incur any Indebtedness;providedthat the Issuer or any Guarantor may incur additional Indebtedness and any Restricted Subsidiary may incur Acquired Indebtedness, in each case, if, after giving effect thereto, the Consolidated Interest Coverage Ratio would be at least 2.00 to 1.00 (the“Coverage Ratio Exception”);provided, however, that Acquired Indebtedness shall not exceed an aggregate principal amount of $20.0 million at any time outstanding.

      Notwithstanding the above, each of the following shall be permitted (the“Permitted Indebtedness”):

(1) Indebtedness of the Issuer and any Guarantor under the Credit Facilities in an aggregate amount at any time outstanding not to exceed (a) the greater of (i) $225.0 million and (ii) 20.0% of the Issuer’s Consolidated Tangible Assets,minus(b) to the extent a permanent repayment and/or commitment reduction is required thereunder as a result of such application, the aggregate amount

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of Net Available Proceeds applied to repayments under the Credit Facilities in accordance with the covenant described under “— Limitations on Asset Sales”;

(2) Indebtedness under (a) the Notes and the Note Guarantees issued on the Issue Date and (b) the Exchange Notes and the Note Guarantees in respect thereof to be issued pursuant to the Registration Rights Agreement;

(3) Indebtedness of the Issuer and the Restricted Subsidiaries to the extent outstanding on the Issue Date after giving effect to the intended use of proceeds of the Notes (other than Indebtedness referred to in clause (1), (2) or (5));

(4) Indebtedness under Hedging Obligations entered into forbona fidehedging purposes of the Issuer or any Restricted Subsidiary not for the purpose of speculation;providedthat in the case of Hedging Obligations relating to interest rates, (a) such Hedging Obligations relate to payment obligations on Indebtedness otherwise permitted to be incurred by this covenant, and (b) the notional principal amount of such Hedging Obligations at the time incurred does not exceed the principal amount of the Indebtedness to which such Hedging Obligations relate;

(5) Indebtedness of the Issuer owed to a Restricted Subsidiary and Indebtedness of any Restricted Subsidiary owed to the Issuer or any other Restricted Subsidiary;provided, however, that upon any such Restricted Subsidiary ceasing to be a Restricted Subsidiary or such Indebtedness being owed to any Person other than the Issuer or a Restricted Subsidiary, the Issuer or such Restricted Subsidiary, as applicable, shall be deemed to have incurred Indebtedness not permitted by this clause (5);

(6) Indebtedness in respect of (a) self-insurance obligations or completion, bid, performance, appeal or surety bonds issued for the account of the Issuer or any Restricted Subsidiary in the ordinary course of business, including guarantees or obligations of the Issuer or any Restricted Subsidiary with respect to letters of credit supporting such self-insurance, completion, bid, performance, appeal or surety obligations (in each case other than for an obligation for money borrowed) or (b) obligations represented by letters of credit for the account of the Issuer or any Restricted Subsidiary, as the case may be, in order to provide security for workers’ compensation claims;

(7) Purchase Money Indebtedness incurred by the Issuer or any Restricted Subsidiary after the Issue Date, and Refinancing Indebtedness thereof, in an aggregate principal amount not to exceed at any time outstanding the greater of (a) $50.0 million or (b) 15.0% of the Issuer’s Consolidated Tangible Assets;

(8) Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument inadvertently (except in the case of daylight overdrafts) drawn against insufficient funds in the ordinary course of business;provided, however, that such Indebtedness is extinguished within five Business Days of incurrence;

(9) Indebtedness arising in connection with endorsement of instruments for deposit in the ordinary course of business;

(10) Refinancing Indebtedness with respect to Indebtedness incurred pursuant to the Coverage Ratio Exception or clause (2) or (3) above or this clause (10);

(11) indemnification, adjustment of purchase price, earn-out or similar obligations (including without limitation any Earn Out Obligations), in each case, incurred or assumed in connection with the acquisition or disposition of any business or assets of the Issuer or any Restricted Subsidiary or Equity Interests of a Restricted Subsidiary, other than guarantees of Indebtedness incurred by any Person acquiring all or any portion of such business, assets or Equity Interests for the purpose of financing or in contemplation of any such acquisition;providedthat (a) any amount of such obligations included on the face of the balance sheet of the Issuer or any Restricted Subsidiary

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shall not be permitted under this clause (11) and (b) in the case of a disposition, the maximum aggregate liability in respect of all such obligations outstanding under this clause (11) shall at no time exceed the gross proceeds actually received by the Issuer and the Restricted Subsidiaries in connection with such disposition;

(12) Contingent Obligations of the Issuer and the Guarantors in respect of Indebtedness otherwise permitted under this covenant;

(13) Indebtedness of Foreign Restricted Subsidiaries in an aggregate amount outstanding at any one time not to exceed 10% of such Foreign Restricted Subsidiaries’ Consolidated Tangible Assets; and

(14) additional Indebtedness of the Issuer or any Restricted Subsidiary in an aggregate principal amount not to exceed $40.0 million at any time outstanding.

      For purposes of determining compliance with this covenant, in the event that an item of Indebtedness meets the criteria of more than one of the categories of Permitted Indebtedness described in clauses (1) through (14) above or is entitled to be incurred pursuant to the Coverage Ratio Exception, the Issuer shall, in its sole discretion, classify such item of Indebtedness and may divide and classify such Indebtedness in more than one of the types of Indebtedness described, except that Indebtedness incurred under the Credit Facilities on the Issue Date shall be deemed to have been incurred under clause (1) above, and may later reclassify any item of Indebtedness described in clauses (1) through (14) above (providedthat at the time of reclassification it meets the criteria in such category or categories). In addition, for purposes of determining any particular amount of Indebtedness under this covenant, guarantees, Liens or letter of credit obligations supporting Indebtedness otherwise included in the determination of such particular amount shall not be included so long as incurred by a Person that could have incurred such Indebtedness.

Limitations on Layering Indebtedness

      The Issuer will not, and will not permit any Restricted Subsidiary to, directly or indirectly, incur any Indebtedness that is or purports to be by its terms (or by the terms of any agreement governing such Indebtedness) subordinated to any other Indebtedness of the Issuer or of such Restricted Subsidiary, as the case may be, unless such Indebtedness is also by its terms (or by the terms of any agreement governing such Indebtedness) made expressly subordinate to the Notes or the Note Guarantee of such Restricted Subsidiary, to the same extent and in the same manner as such Indebtedness is subordinated to such other Indebtedness of the Issuer or such Restricted Subsidiary, as the case may be.

      For purposes of the foregoing, no Indebtedness will be deemed to be subordinated in right of payment to any other Indebtedness of the Issuer or any Restricted Subsidiary solely by virtue of being unsecured or secured by a Permitted Lien or by virtue of the fact that the holders of such Indebtedness have entered into intercreditor agreements or other arrangements giving one or more of such holders priority over the other holders in the collateral held by them.

Limitations on Restricted Payments

      The Issuer will not, and will not permit any Restricted Subsidiary to, directly or indirectly, make any Restricted Payment if at the time of such Restricted Payment:

(1) a Default shall have occurred and be continuing or shall occur as a consequence thereof;

(2) the Issuer is not able to incur at least $1.00 of additional Indebtedness (other than Permitted Indebtedness) pursuant to the Coverage Ratio Exception; or

(3) the amount of such Restricted Payment, when added to the aggregate amount of all other Restricted Payments made after the Issue Date (other than Restricted Payments made pursuant to

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clauses (2), (3), (4) or (5) of the next paragraph), exceeds the sum (the“Restricted Payments Basket”) of (without duplication):

(a) 50% of Consolidated Net Income for the period (taken as one accounting period) commencing on the first day of the fiscal quarter in which the Issue Date occurs to and including the last day of the fiscal quarter ended immediately prior to the date of such calculation for which consolidated financial statements are available (or, if such Consolidated Net Income shall be a deficit, minus 100% of such deficit),plus

(b) 100% of (A) (i) the aggregate net cash proceeds and (ii) the Fair Market Value of (x) marketable securities (other than marketable securities of the Issuer), (y) Equity Interests of a Person (other than the Issuer or an Affiliate of the Issuer) engaged in a Permitted Business and (z) other assets used in any Permitted Business, in the case of clauses (i) and (ii), received by the Issuer since the Issue Date as a contribution to its common equity capital or from the issue or sale of Qualified Equity Interests of the Issuer or from the issue or sale of convertible or exchangeable Disqualified Equity Interests or convertible or exchangeable debt securities of the Issuer that have been converted into or exchanged for such Qualified Equity Interests (other than Equity Interests or debt securities sold to a Subsidiary of the Issuer), and (B) the aggregate net cash proceeds, if any, received by the Issuer or any of its Restricted Subsidiaries upon any conversion or exchange described in clause (A) above,plus

(c) 100% of (A) the aggregate amount by which Indebtedness (other than any Subordinated Indebtedness) of the Issuer or any Restricted Subsidiary is reduced on the Issuer’s consolidated balance sheet upon the conversion or exchange after the Issue Date of any such Indebtedness into or for Qualified Equity Interests of the Issuer and (B) the aggregate net cash proceeds, if any, received by the Issuer or any of its Restricted Subsidiaries upon any conversion or exchange described in clause (A) above,plus

(d) in the case of the disposition or repayment of or return on any Investment that was treated as a Restricted Payment made after the Issue Date, an amount (to the extent not included in the computation of Consolidated Net Income) equal to the lesser of (i) 100% of the aggregate amount received by the Issuer or any Restricted Subsidiary in cash or other property (valued at the Fair Market Value thereof) as the return of capital with respect to such Investment and (ii) the amount of such Investment that was treated as a Restricted Payment, in either case, less the cost of the disposition of such Investment and net of taxes,plus

(e) upon a Redesignation of an Unrestricted Subsidiary as a Restricted Subsidiary, the lesser of (i) the Fair Market Value of the Issuer’s proportionate interest in such Subsidiary immediately following such Redesignation, and (ii) the aggregate amount of the Issuer’s Investments in such Subsidiary to the extent such Investments reduced the Restricted Payments Basket and were not previously repaid or otherwise reduced.

      Notwithstanding the foregoing, the provisions set forth in the immediately preceding paragraph will not prohibit:

(1) the payment of (a) any dividend or redemption payment or the making of any distribution within 60 days after the date of declaration thereof if, on the date of declaration, the dividend, redemption or distribution payment, as the case may be, would have complied with the provisions of the Indenture or (b) any dividend or similar distribution by a Restricted Subsidiary of the Issuer to the holders of its Equity Interests on a pro rata basis;

(2) the redemption or acquisition of any Equity Interests of the Issuer or any Restricted Subsidiary in exchange for, or out of the proceeds of the substantially concurrent issuance and sale of, Qualified Equity Interests;

(3) the purchase, repurchase, redemption, defeasance or other acquisition or retirement for value of Subordinated Indebtedness of the Issuer or any Restricted Subsidiary (a) in exchange for, or out

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of the proceeds of the substantially concurrent issuance and sale of, Qualified Equity Interests, (b) in exchange for, or out of the proceeds of the substantially concurrent incurrence of, Refinancing Indebtedness permitted to be incurred under the “Limitations on Additional Indebtedness” covenant and the other terms of the Indenture or (c) upon a Change of Control or in connection with an Asset Sale to the extent required by the agreement governing such Subordinated Indebtedness but only if the Issuer shall have complied with the covenants described under “— Change of Control” and “— Limitations on Asset Sales” and purchased all Notes validly tendered pursuant to the relevant offer prior to redeeming such Subordinated Indebtedness;

(4) the redemption, repurchase or other acquisition or retirement for value of Equity Interests of the Issuer held by officers, directors or employees or former officers, directors or employees (or their transferees, estates or beneficiaries under their estates), either (x) upon any such individual’s death, disability, retirement, severance or termination of employment or service or (y) pursuant to any equity subscription agreement, stock option agreement, stockholders’ agreement or similar agreement;provided,in any case, that the aggregate cash consideration paid for all such redemptions, repurchases or other acquisitions or retirements shall not exceed (A) $5.0 million during any calendar year (with unused amounts in any calendar year being carried forward to the next succeeding calendar year)plus(B) the amount of any net cash proceeds received by or contributed to the Issuer from the issuance and sale after the Issue Date of Qualified Equity Interests of the Issuer to its officers, directors or employees that have not been applied to the payment of Restricted Payments pursuant to this clause (4),plus(C) the net cash proceeds of any “key-man” life insurance policies that have not been applied to the payment of Restricted Payments pursuant to this clause (4);

(5) (a) repurchases, redemptions or other acquisitions or retirements for value of Equity Interests deemed to occur upon the exercise of stock options, warrants, rights to acquire Equity Interests or other convertible securities to the extent such Equity Interests represent a portion of the exercise or exchange price thereof and (b) any repurchases, redemptions or other acquisitions or retirements for value of Equity Interests made in lieu of withholding taxes in connection with any exercise or exchange of stock options, warrants or other similar rights;

(6) dividends on Preferred Stock or Disqualified Equity Interests issued in compliance with the covenant “— Limitations on Additional Indebtedness” to the extent such dividends are included in the definition of Consolidated Interest Expense;

(7) the payment of cash in lieu of fractional Equity Interests;

(8) payments or distributions to dissenting stockholders pursuant to applicable law in connection with a merger, consolidation or transfer of assets that complies with the provisions described under the caption “— Covenants — Limitations on Mergers, Consolidations, Etc.;” or

(9) payment of other Restricted Payments from time to time in an aggregate amount not to exceed $15.0 million in any fiscal year;

providedthat (a) in the case of any Restricted Payment pursuant to clauses (3), (4) or (9) above, no Default shall have occurred and be continuing or occur as a consequence thereof and (b) no issuance and sale of Qualified Equity Interests used to make a payment pursuant to clauses (2), (3) or (4)(B) above shall increase the Restricted Payments Basket.

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Limitations on Dividend and Other Restrictions Affecting Restricted Subsidiaries

      The Issuer will not, and will not permit any Restricted Subsidiary to create or otherwise cause or permit to exist or become effective any consensual encumbrance or consensual restriction on the ability of any Restricted Subsidiary to:

(a) pay dividends or make any other distributions on or in respect of its Equity Interests;

(b) make loans or advances, or pay any Indebtedness or other obligation owed, to the Issuer or any other Restricted Subsidiary; or

(c) transfer any of its assets to the Issuer or any other Restricted Subsidiary;

      except for:

(1) encumbrances or restrictions existing under or by reason of applicable law, regulation or order;

(2) encumbrances or restrictions existing under the Indenture, the Notes and the Note Guarantees;

(3) non-assignment provisions of any contract or any lease entered into in the ordinary course of business;

(4) encumbrances or restrictions existing under agreements existing on the date of the Indenture (including, without limitation, the Credit Facilities) as in effect on that date;

(5) restrictions relating to any Lien permitted under the Indenture imposed by the holder of such Lien;

(6) restrictions imposed under any agreement to sell Equity Interests or assets, as permitted under the Indenture, to any Person pending the closing of such sale;

(7) any instrument governing Acquired Indebtedness or Equity Interests of a Person acquired by the Issuer or any of its Restricted Subsidiaries, which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person or the properties or assets of the Person so acquired;

(8) any other agreement governing Indebtedness entered into after the Issue Date that contains encumbrances and restrictions that are not materially more restrictive with respect to any Restricted Subsidiary than those in effect on the Issue Date with respect to that Restricted Subsidiary pursuant to agreements in effect on the Issue Date;

(9) customary provisions in partnership agreements, limited liability company organizational governance documents, joint venture agreements and other similar agreements entered into in the ordinary course of business that restrict the transfer of ownership interests in such partnership, limited liability company, joint venture or similar Person;

(10) Purchase Money Indebtedness incurred in compliance with the covenant described under “— Limitations on Additional Indebtedness” that imposes restrictions of the nature described in clause (c) above on the assets acquired;

(11) restrictions on cash or other deposits or net worth imposed by customers, suppliers or landlords under contracts entered into in the ordinary course of business;

(12) Indebtedness incurred or Equity Interests issued by any Restricted Subsidiary, provided that the restrictions contained in the agreements or instruments governing such Indebtedness or Equity Interests (a) either (i) apply only in the event of a payment default or a default with respect to a financial covenant in such agreement or instrument or (ii) will not materially affect the Issuer’s ability to pay all principal, interest and premium and Liquidated Damages, if any, on the Notes, as determined in good faith by the Chief Executive Officer and the Chief Financial Officer of the Issuer, whose determination shall be conclusive; and (b) are not materially more disadvantageous

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to the Holders of the Notes than is customary in comparable financings (as determined by the Chief Financial Officer of the Issuer, whose determination shall be conclusive); and

(13) any encumbrances or restrictions imposed by any amendments or refinancings of the contracts, instruments or obligations referred to in clauses (1) through (12) above;providedthat such amendments or refinancings are, in the good faith judgment of the Issuer’s Board of Directors, no more materially restrictive with respect to such encumbrances and restrictions than those prior to such amendment or refinancing.

Limitations on Transactions with Affiliates

      The Issuer will not, and will not permit any Restricted Subsidiary to, directly or indirectly, in one transaction or a series of related transactions, sell, lease, transfer or otherwise dispose of any of its assets to, or purchase any assets from, or enter into any contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate (an“Affiliate Transaction”), unless:

(1) such Affiliate Transaction is on terms that are no less favorable to the Issuer or the relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction at such time on an arm’s-length basis by the Issuer or that Restricted Subsidiary from a Person that is not an Affiliate of the Issuer or that Restricted Subsidiary; and

(2) the Issuer delivers to the Trustee:

(a) with respect to any Affiliate Transaction involving aggregate value in excess of $5.0 million, an Officers’ Certificate certifying that such Affiliate Transaction complies with clause (1) above and a Secretary’s Certificate which sets forth and authenticates a resolution that has been adopted by the Independent Directors approving such Affiliate Transaction; and

(b) with respect to any Affiliate Transaction involving aggregate value of $25.0 million or more, the certificates described in the preceding clause (a) and a written opinion as to the fairness of such Affiliate Transaction to the Issuer or such Restricted Subsidiary from a financial point of view issued by an Independent Financial Advisor to the Board of Directors of the Issuer.

      The foregoing restrictions shall not apply to:

(1) transactions exclusively between or among (a) the Issuer and one or more Restricted Subsidiaries or (b) Restricted Subsidiaries;

(2) reasonable director, officer and employee compensation (including bonuses) and other benefits (including pursuant to any employment agreement or any retirement, health, stock option or other benefit plan) and indemnification arrangements, in each case, as determined in good faith by the Issuer’s Board of Directors or senior management;

(3) the entering into of a tax sharing agreement, or payments pursuant thereto, between the Issuer and/or one or more Subsidiaries, on the one hand, and any other Person with which the Issuer or such Subsidiaries are required or permitted to file a consolidated tax return or with which the Issuer or such Subsidiaries are part of a consolidated group for tax purposes to be used by such Person to pay taxes, and which payments by the Issuer and the Restricted Subsidiaries are not in excess of the tax liabilities that would have been payable by them on a stand-alone basis;

(4) scheduled payments of Earn Out Obligations of $5.0 million in any fiscal year of the Issuer;

(5) any Permitted Investments;

(6) any Restricted Payments which are made in accordance with the covenant described under “— Limitations on Restricted Payments;”

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(7) (x) any agreement in effect on the Issue Date, as in effect on the Issue Date or as thereafter amended or replaced in any manner that, taken as a whole, is not more disadvantageous to the Holders or the Issuer in any material respect than such agreement as it was in effect on the Issue Date or (y) any transaction pursuant to any agreement referred to in the immediately preceding clause (x);

(8) any transaction with a Person (other than an Unrestricted Subsidiary of the Issuer) which would constitute an Affiliate of the Issuer solely because the Issuer or a Restricted Subsidiary owns an equity interest in or otherwise controls such Person; and

(9) (a) any transaction with an Affiliate where the only consideration paid by the Issuer or any Restricted Subsidiary is Qualified Equity Interests or (b) the issuance or sale of any Qualified Equity Interests.

Limitations on Liens

      The Issuer shall not, and shall not permit any Restricted Subsidiary to, directly or indirectly, create, incur, assume or permit or suffer to exist any Lien (other than Permitted Liens) of any nature whatsoever against any assets of the Issuer or any Restricted Subsidiary (including Equity Interests of a Restricted Subsidiary), whether owned at the Issue Date or thereafter acquired, which Lien secures Indebtedness or trade payables, unless contemporaneously therewith:

(1) in the case of any Lien securing an obligation that rankspari passuwith the Notes or a Note Guarantee, effective provision is made to secure the Notes or such Note Guarantee, as the case may be, at least equally and ratably with or prior to such obligation with a Lien on the same collateral; and

(2) in the case of any Lien securing an obligation that is subordinated in right of payment to the Notes or a Note Guarantee, effective provision is made to secure the Notes or such Note Guarantee, as the case may be, with a Lien on the same collateral that is prior to the Lien securing such subordinated obligation,

in each case, for so long as such obligation is secured by such Lien.

Limitations on Asset Sales

      The Issuer will not, and will not permit any Restricted Subsidiary to, directly or indirectly, consummate any Asset Sale unless:

(1) the Issuer or such Restricted Subsidiary receives consideration at the time of such Asset Sale at least equal to the Fair Market Value of the assets included in such Asset Sale; and

(2) at least 75% of the total consideration in such Asset Sale consists of cash or Cash Equivalents.

      For purposes of clause (2), the following shall be deemed to be cash:

(a) the amount (without duplication) of any Indebtedness (other than Subordinated Indebtedness) of the Issuer or such Restricted Subsidiary that is expressly assumed by the transferee of any such assets pursuant to (i) a written novation agreement that releases the Issuer or such Restricted Subsidiary from further liability therefor or (ii) an assignment agreement that includes, in lieu of such a release, the agreement of the transferee or its parent company to indemnify and hold harmless the Issuer or such Restricted Subsidiary from and against any loss, liability or cost in respect of such assumed liability,

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(b) the amount of any obligations received from such transferee that are within 30 days after such Asset Sale converted by the Issuer or such Restricted Subsidiary into cash (to the extent of the cash actually so received), and

(c) the Fair Market Value of (i) any assets (other than securities) received by the Issuer or any Restricted Subsidiary to be used by it in a Permitted Business, (ii) Equity Interests in a Person that is a Restricted Subsidiary or in a Person engaged in a Permitted Business that shall become a Restricted Subsidiary immediately upon the acquisition of such Person by the Issuer or (iii) a combination of (i) and (ii).

      If at any time any non-cash consideration received by the Issuer or any Restricted Subsidiary, as the case may be, in connection with any Asset Sale is repaid or converted into or sold or otherwise disposed of for cash (other than interest received with respect to any such non-cash consideration), then the date of such repayment, conversion or disposition shall be deemed to constitute the date of an Asset Sale hereunder and the Net Available Proceeds thereof shall be applied in accordance with this covenant.

      Any Asset Sale pursuant to a condemnation, appropriation or other similar taking, including by deed in lieu of condemnation, or pursuant to the foreclosure or other enforcement of a Permitted Lien or exercise by the related lienholder of rights with respect thereto, including by deed or assignment in lieu of foreclosure shall not be required to satisfy the conditions set forth in clauses (1) and (2) of the first paragraph of this covenant.

      Notwithstanding the foregoing, the 75% limitation referred to above shall be deemed satisfied with respect to any Asset Sale in which the cash or Cash Equivalents portion of the consideration received therefrom, determined in accordance with the foregoing provision on an after-tax basis, is equal to or greater than what the after-tax proceeds would have been had such Asset Sale complied with the aforementioned 75% limitation.

      If the Issuer or any Restricted Subsidiary engages in an Asset Sale, the Issuer or such Restricted Subsidiary shall, no later than 365 days following the consummation thereof, apply all or any of the Net Available Proceeds therefrom to:

(1) satisfy all mandatory repayment obligations under the Credit Agreement arising by reason of such Asset Sale, and in the case of any such repayment under any revolving credit facility, effect a permanent reduction in the availability under such revolving credit facility;

(2) repay any Indebtedness which was secured by the assets sold in such Asset Sale;

(3) (A) make any capital expenditure or otherwise invest all or any part of the Net Available Proceeds thereof in the purchase of assets (other than securities) to be used by the Issuer or any Restricted Subsidiary in the Permitted Business, (B) acquire Qualified Equity Interests in a Person that is a Restricted Subsidiary or in a Person engaged in a Permitted Business that shall become a Restricted Subsidiary immediately upon the consummation of such acquisition or (C) a combination of (A) and (B); and/or

(4) make a Net Proceeds Offer (and purchase or redeem Pari Passu Indebtedness) in accordance with the procedures described below and in the Indenture.

      The amount of Net Available Proceeds not applied or invested as provided in the preceding paragraph will constitute“Excess Proceeds.”

      When the aggregate amount of Excess Proceeds equals or exceeds $15.0 million, the Issuer will be required to make an offer to purchase from all Holders and, if applicable, purchase or redeem (or make an offer to do so) any Pari Passu Indebtedness of the Issuer the provisions of which require the Issuer to purchase or redeem such Indebtedness with the proceeds from any Asset Sales (or offer to

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do so), in an aggregate principal amount of Notes and such Pari Passu Indebtedness equal to the amount of such Excess Proceeds as follows:

(1) the Issuer will (a) make an offer to purchase (a“Net Proceeds Offer”) to all Holders in accordance with the procedures set forth in the Indenture, and (b) purchase or redeem (or make an offer to do so) any such other Pari Passu Indebtedness, pro rata in proportion to the respective principal amounts of the Notes and such other Indebtedness required to be purchased or redeemed, the maximum principal amount of Notes and Pari Passu Indebtedness that may be purchased or redeemed out of the amount (the“Payment Amount”) of such Excess Proceeds;

(2) the offer price for the Notes will be payable in cash in an amount equal to 100% of the principal amount of the Notes tendered pursuant to a Net Proceeds Offer, plus accrued and unpaid interest and Liquidated Damages thereon, if any, to the date such Net Proceeds Offer is consummated (the“Offered Price”), in accordance with the procedures set forth in the Indenture, and the purchase or redemption price for such Pari Passu Indebtedness (the“Pari Passu Indebtedness Price”) shall be as set forth in the related documentation governing such Indebtedness;

(3) if the aggregate Offered Price of Notes validly tendered and not withdrawn by Holders thereof exceeds thepro rataportion of the Payment Amount allocable to the Notes, Notes to be purchased will be selected on apro ratabasis; and

(4) upon completion of such Net Proceeds Offer in accordance with the foregoing provisions, the amount of Excess Proceeds with respect to which such Net Proceeds Offer was made shall be deemed to be zero.

      To the extent that the sum of the aggregate Offered Price of Notes tendered pursuant to a Net Proceeds Offer and the aggregate Pari Passu Indebtedness Price paid to the holders of such Pari Passu Indebtedness is less than the Payment Amount relating thereto (such shortfall constituting a“Net Proceeds Deficiency”), the Issuer may use the Net Proceeds Deficiency, or a portion thereof, for any purposes not otherwise prohibited by the provisions of the Indenture.

      Notwithstanding the foregoing, the sale, conveyance or other disposition of all or substantially all of the assets of the Issuer and its Restricted Subsidiaries, taken as a whole, will be governed by the provisions of the Indenture described under the caption “— Change of Control” and/or the provisions described under the caption “— Certain Covenants — Limitations on Mergers, Consolidations, Etc.” and not by the provisions of the Asset Sale covenant.

      The Issuer will comply with applicable tender offer rules, including the requirements of Rule 14e-1 under the Exchange Act and any other applicable laws and regulations in connection with the purchase of Notes pursuant to a Net Proceeds Offer. To the extent that the provisions of any securities laws or regulations conflict with the “Limitations on Asset Sales” provisions of the Indenture, the Issuer shall comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the “Limitations on Asset Sales” provisions of the Indenture by virtue of this compliance.

Limitations on Designation of Unrestricted Subsidiaries

      The Issuer may designate any Subsidiary (including any newly formed or newly acquired Subsidiary) of the Issuer as an “Unrestricted Subsidiary” under the Indenture (a“Designation”) only if:

(1) no Default shall have occurred and be continuing at the time of or after giving effect to such Designation; and

(2) the Issuer would be permitted to make, at the time of such Designation, (a) a Permitted Investment or (b) an Investment pursuant to the first paragraph of “— Limitations on Restricted

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Payments” above, in either case, in an amount (the“Designation Amount”) equal to the Fair Market Value of the Issuer’s proportionate interest in such Subsidiary on such date.

No Subsidiary shall be Designated as an “Unrestricted Subsidiary” unless such Subsidiary:

(1) has no Indebtedness other than Non-Recourse Debt;

(2) is not party to any agreement, contract, arrangement or understanding with the Issuer or any Restricted Subsidiary unless the terms of the agreement, contract, arrangement or understanding are no less favorable to the Issuer or the Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates;

(3) is a Person with respect to which neither the Issuer nor any Restricted Subsidiary has any direct or indirect obligation (a) to subscribe for additional Equity Interests or (b) to maintain or preserve the Person’s financial condition or to cause the Person to achieve any specified levels of operating results; and

(4) has not guaranteed or otherwise directly or indirectly provided credit support for any Indebtedness of the Issuer or any Restricted Subsidiary, except for any guarantee given solely to support the pledge by the Issuer or any Restricted Subsidiary of the Equity Interests of such Unrestricted Subsidiary, which guarantee is not recourse to the Issuer or any Restricted Subsidiary.

      If, at any time, any Unrestricted Subsidiary fails to meet the preceding requirements as an Unrestricted Subsidiary, it shall thereafter cease to be an Unrestricted Subsidiary for purposes of the Indenture and any Indebtedness of the Subsidiary and any Liens on assets of such Subsidiary shall be deemed to be incurred by a Restricted Subsidiary at such time and, if the Indebtedness is not permitted to be incurred under the covenant described under “— Limitations on Additional Indebtedness” or the Lien is not permitted under the covenant described under “— Limitations on Liens,” the Issuer shall be in default of the applicable covenant.

      The Issuer may redesignate an Unrestricted Subsidiary as a Restricted Subsidiary (a“Redesignation”) only if:

(1) no Default shall have occurred and be continuing at the time of and after giving effect to such Redesignation; and

(2) all Liens, Indebtedness and Investments of such Unrestricted Subsidiary outstanding immediately following such Redesignation would, if incurred or made at such time, have been permitted to be incurred or made for all purposes of the Indenture.

      All Designations and Redesignations must be evidenced by resolutions of the Board of Directors of the Issuer, delivered to the Trustee certifying compliance with the foregoing provisions.

Limitations on Mergers, Consolidations, Etc.

      The Issuer will not, directly or indirectly, in a single transaction or a series of related transactions, consolidate or merge with or into another Person, or sell, lease, transfer, convey or otherwise dispose of or assign all or substantially all of the assets of the Issuer or the Issuer and the Restricted Subsidiaries (taken as a whole) unless:

(1) either:

(a) the Issuer will be the surviving or continuing Person; or

(b) the Person (if other than the Issuer) formed by or surviving such consolidation or merger or to which such sale, lease, transfer, conveyance or other disposition or assignment shall be made (collectively, the“Successor”) is a corporation, limited liability company or limited

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partnership organized and existing under the laws of any State of the United States of America or the District of Columbia, and the Successor expressly assumes, by agreements in form and substance reasonably satisfactory to the Trustee, all of the obligations of the Issuer under the Notes, the Indenture and the Registration Rights Agreement;

(2) immediately after giving effect to such transaction and the assumption of the obligations as set forth in clause (1)(b) above and the incurrence of any Indebtedness to be incurred in connection therewith, and the use of any net proceeds therefrom on a pro forma basis, no Default shall have occurred and be continuing; and

(3) immediately after giving effect to such transaction and the assumption of the obligations as set forth in clause (1)(b) above and the incurrence of any Indebtedness to be incurred in connection therewith, and the use of any net proceeds therefrom on a pro forma basis, the Issuer or the Successor, as the case may be, could incur $1.00 of additional Indebtedness (other than Permitted Indebtedness) pursuant to the Coverage Ratio Exception.

      For purposes of this covenant, any Indebtedness of the Successor which was not Indebtedness of the Issuer immediately prior to the transaction shall be deemed to have been incurred in connection with such transaction.

      Except as provided in the fifth paragraph under the caption “— Note Guarantees,” no Guarantor may consolidate with or merge with or into (whether or not such Guarantor is the surviving Person) another Person, unless:

(1) either:

(a) such Guarantor will be the surviving or continuing Person; or

(b) the Person (if other than such Guarantor) formed by or surviving any such consolidation or merger is another Guarantor or assumes, by agreements in form and substance reasonably satisfactory to the Trustee, all of the obligations of such Guarantor under the Note Guarantee of such Guarantor, the Indenture and the Registration Rights Agreement; and

(2) immediately after giving effect to such transaction, no Default shall have occurred and be continuing.

      For purposes of the foregoing, the transfer (by lease, assignment, sale or otherwise, in a single transaction or series of transactions) of all or substantially all of the properties or assets of one or more Restricted Subsidiaries, the Equity Interests of which constitute all or substantially all of the properties and assets of the Issuer, will be deemed to be the transfer of all or substantially all of the properties and assets of the Issuer.

      Upon any consolidation, combination or merger of the Issuer or a Guarantor, or any transfer of all or substantially all of the assets of the Issuer in accordance with the foregoing, in which the Issuer or such Guarantor is not the continuing obligor under the Notes or its Note Guarantee, the surviving entity formed by such consolidation or into which the Issuer or such Guarantor is merged or the Person to which the sale, conveyance, lease, transfer, disposition or assignment is made will succeed to, and be substituted for, and may exercise every right and power of, the Issuer or such Guarantor under the Indenture, the Notes and the Note Guarantees with the same effect as if such surviving entity had been named therein as the Issuer or such Guarantor and, except in the case of a lease, the Issuer or such Guarantor, as the case may be, will be released from the obligation to pay the principal of and interest on the Notes or in respect of its Note Guarantee, as the case may be, and all of the Issuer’s or such Guarantor’s other obligations and covenants under the Notes, the Indenture and its Note Guarantee, if applicable.

      Notwithstanding the foregoing, (i) any Restricted Subsidiary may consolidate with, merge with or into or convey, transfer or lease, in one transaction or a series of transactions, all or substantially all of its assets to the Issuer or another Restricted Subsidiary and (ii) this covenant will not apply to a merger

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of the Issuer with an Affiliate of the Issuer solely for the purpose of reorganizing the Issuer in another jurisdiction.

Additional Note Guarantees

      If, after the Issue Date, (a) the Issuer or any Restricted Subsidiary shall acquire or create another Domestic Restricted Subsidiary, or (b) any Unrestricted Subsidiary is Redesignated a Domestic Restricted Subsidiary, and (in each such case) such Domestic Restricted Subsidiary guarantees any Indebtedness under any Credit Facility, then the Issuer shall cause such Domestic Restricted Subsidiary to:

(1) execute and deliver to the Trustee (a) a supplemental indenture in form and substance satisfactory to the Trustee pursuant to which such Domestic Restricted Subsidiary shall unconditionally guarantee all of the Issuer’s obligations under the Notes and the Indenture and (b) a notation of guarantee in respect of its Note Guarantee; and

(2) deliver to the Trustee one or more opinions of counsel that such supplemental indenture (a) has been duly authorized, executed and delivered by such Domestic Restricted Subsidiary and (b) constitutes a valid and legally binding obligation of such Domestic Restricted Subsidiary in accordance with its terms;

provided, however,that a Domestic Restricted Subsidiary that owns net assets that have an aggregate fair market value (as determined in good faith by the Board of Directors of the Issuer) of less than 5% of the Consolidated Tangible Assets of the Issuer as of the end of the previous fiscal quarter, need not become a Guarantor.

      Notwithstanding the foregoing, if, as of the end of any fiscal quarter, the Domestic Restricted Subsidiaries that are not required to be Guarantors pursuant to the preceding paragraph collectively own net assets that have an aggregate fair market value (as determined in good faith by the Board of Directors of the Issuer) equal to or greater than 5% of the Issuer’s Consolidated Tangible Assets, then the Issuer will cause one or more of such non-Guarantor Domestic Restricted Subsidiaries promptly to become a Guarantor or Guarantors such that after giving effect thereto, the total net assets owned by all such remaining non-Guarantor Domestic Restricted Subsidiaries will have an aggregate fair market value (as determined in good faith by the Board of Directors of the Issuer) of less than 5% of the Consolidated Tangible Assets of the Issuer. Any such Domestic Restricted Subsidiary so designated must become a Guarantor and execute a supplemental indenture and deliver an opinion of counsel to the Trustee within 15 Business Days of the date on which it was designated.

Conduct of Business

      The Issuer will engage, and will cause its Restricted Subsidiaries to engage, only in businesses that, when considered together as a single enterprise, are primarily the Permitted Business.

Reports

      Whether or not required by the SEC, so long as any Notes are outstanding, the Issuer will furnish to the Holders of Notes, or file electronically with the SEC through the SEC’s Electronic Data Gathering, Analysis and Retrieval System (or any successor system), within the time periods applicable to the Issuer under Section 13(a) or 15(d) of the Exchange Act:

(1) all quarterly and annual financial information that would be required to be contained in a filing with the SEC on Forms 10-Q and 10-K if the Issuer were required to file these Forms, including a “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and, with respect to the annual information only, a report on the annual financial statements by the Issuer’s certified independent accountants; and

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(2) all current reports that would be required to be filed with the SEC on Form 8-K if the Issuer were required to file these reports.

      In addition, whether or not required by the SEC, the Issuer will file a copy of all of the information and reports referred to in clauses (1) and (2) above with the SEC for public availability within the time periods specified in the SEC’s rules and regulations (unless the SEC will not accept the filing) and make the information available to securities analysts and prospective investors upon request. The Issuer and the Guarantors have agreed that, for so long as any Notes remain outstanding, the Issuer will furnish to the Holders and to securities analysts and prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

      Notwithstanding anything to the contrary, the Issuer will be deemed to have complied with its obligations in the preceding two paragraphs following the filing of the Exchange Offer Registration Statement and prior to the effectiveness thereof if the Exchange Offer Registration Statement includes the information specified in clause (1) above at the times it would otherwise be required to file such Forms.

Events of Default

      Each of the following is an“Event of Default”:

(1) failure to pay interest on, or Liquidated Damages with respect to, any of the Notes when the same becomes due and payable and the continuance of any such failure for 30 days;

(2) failure to pay the principal on any of the Notes when it becomes due and payable, whether at stated maturity, upon redemption, upon purchase, upon acceleration or otherwise;

(3) failure by the Issuer to comply with any of its agreements or covenants described above under “— Certain Covenants — Limitations on Mergers, Consolidations, Etc.,” or in respect of its obligations to make a Change of Control Offer as described under “— Change of Control”;

(4) failure by the Issuer to comply with any other agreement or covenant in the Indenture and continuance of this failure for 60 days after notice of the failure has been given to the Issuer by the Trustee or by the Holders of at least 25% of the aggregate principal amount of the Notes then outstanding;

(5) default under any mortgage, indenture or other instrument or agreement under which there may be issued or by which there may be secured or evidenced Indebtedness for borrowed money by the Issuer or any Restricted Subsidiary, whether such Indebtedness now exists or is incurred after the Issue Date, which default:

(a) is caused by a failure to pay at final maturity principal on such Indebtedness within the applicable express grace period and any extensions thereof, or

(b) results in the acceleration of such Indebtedness prior to its express final maturity (which acceleration is not rescinded, annulled or otherwise cured within 30 days of receipt by the Issuer or such Restricted Subsidiary of notice of any such acceleration),

and, in each case, the principal amount of such Indebtedness, together with the principal amount of any other Indebtedness with respect to which an event described in clause (a) or (b) has occurred and is continuing, aggregates $20.0 million or more;

(6) one or more judgments (to the extent not covered by insurance) for the payment of money in an aggregate amount in excess of $20.0 million shall be rendered against the Issuer, any of its Restricted Subsidiaries or any combination thereof and the same shall remain undischarged for a period of 60 consecutive days during which execution shall not be effectively stayed;

(7) certain events of bankruptcy affecting the Issuer or any of its Significant Subsidiaries; or

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(8) any Note Guarantee of any Significant Subsidiary ceases to be in full force and effect (other than in accordance with the terms of such Note Guarantee and the Indenture) or is declared null and void and unenforceable or found to be invalid or any Guarantor denies its liability under its Note Guarantee (other than by reason of release of a Guarantor from its Note Guarantee in accordance with the terms of the Indenture and the Note Guarantee).

      If an Event of Default (other than an Event of Default specified in clause (7) above with respect to the Issuer), shall have occurred and be continuing under the Indenture, the Trustee, by written notice to the Issuer, or the Holders of at least 25% in aggregate principal amount of the Notes then outstanding by written notice to the Issuer and the Trustee, may declare (an“acceleration declaration”) all amounts owing under the Notes to be due and payable. Upon such declaration of acceleration, the aggregate principal of and accrued and unpaid interest on the outstanding Notes shall become due and payable (a) if there is no Indebtedness outstanding under any Credit Facility at such time, immediately and (b) if otherwise, upon the earlier of (x) the final maturity (after giving effect to any applicable grace period or extensions thereof) or an acceleration of any Indebtedness under any Credit Facility prior to the express final stated maturity thereof and (y) five Business Days after the Representative under each Credit Facility receives the acceleration declaration, but, in the case of this clause (b) only, if such Event of Default is then continuing;provided, however, that after such acceleration, but before a judgment or decree based on acceleration, the Holders of a majority in aggregate principal amount of such outstanding Notes may, under certain circumstances, rescind and annul such acceleration if all Events of Default, other than the nonpayment of accelerated principal and interest, have been cured or waived as provided in the Indenture. If an Event of Default specified in clause (7) with respect to the Issuer occurs, all outstanding Notes shall become due and payable without any further action or notice to the extent permitted by applicable law.

      Holders of the Notes may not enforce the Indenture or the Notes except as provided in the Indenture. Subject to certain limitations, Holders of a majority in principal amount of the then outstanding Notes may direct the Trustee in its exercise of any trust or power. The Trustee may withhold from Holders of the Notes notice of any Default or Event of Default (except an Event of Default relating to the payment of principal or interest or Liquidated Damages) if it determines that withholding notice is in their interest.

      The Holders of a majority in aggregate principal amount of the Notes then outstanding by notice to the Trustee may on behalf of the Holders of all of the Notes waive any existing Default or Event of Default and its consequences under the Indenture except a continuing Default or Event of Default in the payment of interest or Liquidated Damages on, or the principal of, the Notes. The Holders of a majority in principal amount of the then outstanding Notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the Trustee. However, the Trustee may refuse to follow any direction that conflicts with law or the Indenture, that may involve the Trustee in personal liability, or that the Trustee determines in good faith may be unduly prejudicial to the rights of Holders of Notes not joining in the giving of such direction and may take any other action it deems proper that is not inconsistent with any such direction received from Holders of Notes. A Holder may not pursue any remedy with respect to the Indenture or the Notes unless:

(1) the Holder gives the Trustee written notice of a continuing Event of Default;

(2) the Holder or Holders of at least 25% in aggregate principal amount of outstanding Notes make a written request to the Trustee to pursue the remedy;

(3) such Holder or Holders offer the Trustee indemnity satisfactory to the Trustee against any costs, liability or expense;

(4) the Trustee does not comply with the request within 60 days after receipt of the request and the offer of indemnity; and

(5) during such60-day period, the Holders of a majority in aggregate principal amount of the outstanding Notes do not give the Trustee a direction that is inconsistent with the request.

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      However, such limitations do not apply to the right of any Holder of a Note to receive payment of the principal of, premium or Liquidated Damages, if any, or interest on, such Note or to bring suit for the enforcement of any such payment, on or after the due date expressed in the Notes, which right will not be impaired or affected without the consent of the Holder.

      The Holders of a majority in aggregate principal amount of the Notes then outstanding by written notice to the Trustee may, on behalf of the Holders of all of the Notes, rescind an acceleration or waive any existing Default or Event of Default and its consequences under the Indenture except a continuing Default or Event of Default in the payment of interest or premium or Liquidated Damages on, or the principal of, the Notes.

      The Issuer is required to deliver to the Trustee annually a statement regarding compliance with the Indenture and, upon any Officer of the Issuer becoming aware of any Default, a statement specifying such Default and what action the Issuer is taking or proposes to take with respect thereto.

Legal Defeasance and Covenant Defeasance

      The Issuer may, at its option and at any time, elect to have its obligations discharged with respect to the outstanding Notes and all obligations of any Guarantors discharged with respect to their Note Guarantees(“Legal Defeasance”). Legal Defeasance means that the Issuer and the Guarantors shall be deemed to have paid and discharged the entire obligations represented by the Notes and the Note Guarantees, and the Indenture shall cease to be of further effect as to all outstanding Notes and Note Guarantees, except as to:

(1) rights of Holders of outstanding Notes to receive payments in respect of the principal of and interest and Liquidated Damages, if any, on such Notes when such payments are due from the trust funds referred to below,

(2) the Issuer’s obligations with respect to the Notes concerning issuing temporary Notes, registration of Notes, mutilated, destroyed, lost or stolen Notes, and the maintenance of an office or agency for payment and money for security payments held in trust,

(3) the rights, powers, trust, duties, and immunities of the Trustee, and the Issuer’s obligation in connection therewith, and

(4) the Legal Defeasance provisions of the Indenture.

      In addition, the Issuer may, at its option and at any time, elect to have its obligations and the obligations of the Guarantors released with respect to the provisions of the Indenture described above under “— Change of Control” and under “— Covenants” (other than the covenant described under “— Covenants — Limitations on Mergers, Consolidations, Etc.,” except to the extent described below) and the limitation imposed by clause (3) under “— Covenants — Limitations on Mergers, Consolidations, Etc.” (such release and termination being referred to as“Covenant Defeasance”), and thereafter any omission to comply with such obligations or provisions will not constitute a Default or Event of Default. Covenant Defeasance will not be effective until such time as bankruptcy, receivership, rehabilitation and insolvency events no longer apply. In the event Covenant Defeasance occurs in accordance with the Indenture, the Events of Default described under clauses (3) through (6) under the caption “— Events of Default” and the Event of Default described under clause (7) under the caption “— Events of Default” (but only with respect to Significant Subsidiaries of the Issuer), in each case, will no longer constitute an Event of Default. The Issuer may exercise its Legal Defeasance option regardless of whether it previously exercised Covenant Defeasance.

      In order to exercise either Legal Defeasance or Covenant Defeasance:

(1) the Issuer must irrevocably deposit with the Trustee, as trust funds, in trust solely for the benefit of the Holders, U.S. legal tender, U.S. Government Obligations or a combination thereof, in such amounts as will be sufficient (without consideration of any reinvestment of interest) in the

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opinion of a nationally recognized investment bank, appraisal firm or firm of independent public accountants selected by the Issuer, to pay the principal of and interest and Liquidated Damages, if any, on the outstanding Notes on the stated date for payment thereof or on the applicable redemption date, as the case may be,

(2) in the case of Legal Defeasance, the Issuer shall have delivered to the Trustee an opinion of counsel in the United States confirming that:

(a) the Issuer has received from, or there has been published by the Internal Revenue Service, a ruling, or

(b) since the date of the Indenture, there has been a change in the applicable U.S. federal income tax law,

in either case to the effect that, and based thereon this opinion of counsel shall confirm that, the Holders of the outstanding Notes will not recognize income, gain or loss for U.S. federal income tax purposes as a result of the Legal Defeasance and will be subject to U.S. federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred,

(3) in the case of Covenant Defeasance, the Issuer shall have delivered to the Trustee an opinion of counsel in the United States reasonably acceptable to the Trustee confirming that the Holders will not recognize income, gain or loss for U.S. federal income tax purposes as a result of such Covenant Defeasance and will be subject to U.S. federal income tax on the same amounts, in the same manner and at the same times as would have been the case if the Covenant Defeasance had not occurred,

(4) no Default shall have occurred and be continuing on the date of such deposit (other than a Default resulting from the borrowing of funds to be applied to such deposit and the grant of any Lien securing such borrowings),

(5) the Legal Defeasance or Covenant Defeasance shall not result in a breach or violation of, or constitute a Default under the Indenture or a default under any other material agreement or instrument to which the Issuer or any of its Subsidiaries is a party or by which the Issuer or any of its Subsidiaries is bound (other than any such Default or default resulting solely from the borrowing of funds to be applied to such deposit and the grant of any Lien securing such borrowings),

(6) the Issuer shall have delivered to the Trustee an Officers’ Certificate stating that the deposit was not made by it with the intent of preferring the Holders over any other of its creditors or with the intent of defeating, hindering, delaying or defrauding any other of its creditors or others, and

(7) the Issuer shall have delivered to the Trustee an Officers’ Certificate and an opinion of counsel, each stating that the conditions precedent provided for in, in the case of the Officers’ Certificate, clauses (1) through (6) and, in the case of the opinion of counsel, clauses (2) and/or (3) and (5) of this paragraph have been complied with.

      If the funds deposited with the Trustee to effect Covenant Defeasance are insufficient to pay the principal of and interest on the Notes when due, then our obligations and the obligations of Guarantors under the Indenture will be revived and no such defeasance will be deemed to have occurred.

Satisfaction and Discharge

      The Indenture will be discharged and will cease to be of further effect (except as to rights of registration of transfer or exchange of Notes which shall survive until all Notes have been canceled) as to all outstanding Notes when either:

(1) all the Notes that have been authenticated and delivered (except lost, stolen or destroyed Notes which have been replaced or paid and Notes for whose payment money has been deposited

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in trust or segregated and held in trust by the Issuer and thereafter repaid to the Issuer or discharged from this trust) have been delivered to the Trustee for cancellation, or

(2) (a) all Notes not delivered to the Trustee for cancellation otherwise (i) have become due and payable, (ii) will become due and payable, or may be called for redemption, within one year or (iii) have been called for redemption pursuant to the provisions described under “— Optional Redemption,” and, in any case, the Issuer has irrevocably deposited or caused to be deposited with the Trustee as trust funds, in trust solely for the benefit of the Holders, U.S. legal tender, U.S. Government Obligations or a combination thereof, in such amounts as will be sufficient (without consideration of any reinvestment of interest) to pay and discharge the entire Indebtedness (including all principal and accrued interest and Liquidated Damages, if any) on the Notes not theretofore delivered to the Trustee for cancellation,

(b) the Issuer has paid all other sums payable by it under the Indenture, and

(c) the Issuer has delivered irrevocable instructions to the Trustee to apply the deposited money toward the payment of the Notes at maturity or on the date of redemption, as the case may be.

      In addition, the Issuer must deliver an Officers’ Certificate and an opinion of counsel stating that all conditions precedent to satisfaction and discharge have been complied with.

Transfer and Exchange

      A Holder will be able to register the transfer of or exchange Notes only in accordance with the provisions of the Indenture. The Registrar may require a Holder, among other things, to furnish appropriate endorsements and transfer documents and to pay any taxes and fees required by law or permitted by the Indenture. Without the prior consent of the Issuer, the Registrar is not required (1) to register the transfer of or exchange any Note selected for redemption, (2) to register the transfer of or exchange any Note for a period of 15 days before a selection of Notes to be redeemed or (3) to register the transfer or exchange of a Note between a record date and the next succeeding interest payment date.

      The Notes will be issued in registered form and the registered Holder will be treated as the owner of such Note for all purposes.

Amendment, Supplement and Waiver

      Except as otherwise provided in the next three succeeding paragraphs, the Indenture or the Notes may be amended with the consent (which may include consents obtained in connection with a tender offer or exchange offer for Notes) of the Holders of at least a majority in principal amount of the Notes then outstanding, and any existing Default under, or compliance with any provision of, the Indenture may be waived (other than any continuing Default in the payment of the principal or interest on the Notes) with the consent (which may include consents obtained in connection with a tender offer or exchange offer for Notes) of the Holders of a majority in principal amount of the Notes then outstanding.

      Without the consent of each Holder affected, an amendment or waiver may not (with respect to any Notes held by a non-consenting Holder):

(1) reduce, or change the maturity of, the principal of any Note;

(2) reduce the rate of or extend the time for payment of interest on any Note;

(3) reduce any premium payable upon redemption of the Notes or change the date on which any Notes are subject to redemption or waive any payment with respect to the redemption of the Notes; provided, however, that solely for the avoidance of doubt, and without any other implication,

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any purchase or repurchase of Notes (including pursuant to the covenants described above under the captions “— Change of Control” and “— Certain Covenants — Limitations on Asset Sales”) shall not be deemed a redemption of the Notes;

(4) make any Note payable in money or currency other than that stated in the Notes;

(5) modify or change any provision of the Indenture or the related definitions to affect the ranking of the Notes or any Note Guarantee in a manner that adversely affects the Holders;

(6) reduce the percentage of Holders necessary to consent to an amendment or waiver to the Indenture or the Notes;

(7) waive a default in the payment of principal of or premium or interest or Liquidated Damages, if any, on any Notes (except a rescission of acceleration of the Notes by the Holders thereof as provided in the Indenture and a waiver of the payment default that resulted from such acceleration);

(8) impair the rights of Holders to receive payments of principal of or interest or Liquidated Damages, if any, on the Notes on or after the due date therefor or to institute suit for the enforcement of any payment on the Notes;

(9) release any Guarantor that is a Significant Subsidiary from any of its obligations under its Note Guarantee or the Indenture, except as permitted by the Indenture; or

(10) make any change in these amendment and waiver provisions.

      Notwithstanding the foregoing, the Issuer and the Trustee may amend the Indenture, the Note Guarantees or the Notes without the consent of any Holder:

(1) to cure any ambiguity, defect or inconsistency;

(2) to provide for uncertificated Notes in addition to or in place of certificated Notes;

(3) to provide for the assumption of the Issuer’s or a Guarantor’s obligations to the Holders in the case of a merger, consolidation or sale of all or substantially all of the Issuer’s or such Guarantor’s assets in accordance with “— Certain Covenants — Limitations on Mergers, Consolidations, Etc.;”

(4) to add any Note Guarantee or to effect the release of any Guarantor from any of its obligations under its Note Guarantee or the Indenture (to the extent permitted by the Indenture);

(5) to make any change that would provide any additional rights or benefits to the Holders or does not materially adversely affect the rights of any Holder;

(6) to effect or maintain the qualification of the Indenture under the Trust Indenture Act;

(7) to secure the Notes or any Note Guarantees or any other obligation under the Indenture;

(8) to evidence and provide for the acceptance of appointment by a successor trustee;

(9) to conform the text of the Indenture or the Notes to any provision of this Description of the New Notes to the extent that such provision in this Description of the New Notes was intended to be a verbatim recitation of a provision of the Indenture, the Note Guarantees or the Notes; or

(10) to provide for the issuance of Additional Notes in accordance with the Indenture.

      The consent of the Holders of the Notes is not necessary under the Indenture to approve the particular form of any proposed amendment or waiver. It is sufficient if such consent approves the substance of the proposed amendment or waiver.

      After an amendment under the Indenture becomes effective, the Issuer is required to mail to Holders of the Notes a notice briefly describing such amendment. However, the failure to give such

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notice to all Holders of the Notes, or any defect therein, will not impair or affect the validity of the amendment.

No Personal Liability of Directors, Officers, Employees and Stockholders

      No director, officer, employee, incorporator or stockholder of the Issuer or any Guarantor will have any liability for any obligations of the Issuer under the Notes or the Indenture or of any Guarantor under its Note Guarantee or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes and the Note Guarantees. The waiver may not be effective to waive liabilities under the federal securities laws. It is the view of the SEC that this type of waiver is against public policy.

Concerning the Trustee

      The Bank of New York Trust Company, N.A. is the Trustee under the Indenture and has been appointed by the Issuer as Registrar and Paying Agent with regard to the Notes. The Indenture contains certain limitations on the rights of the Trustee, should it become a creditor of the Issuer, to obtain payment of claims in certain cases, or to realize on certain assets received in respect of any such claim as security or otherwise. The Trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest (as defined in the Indenture), it must eliminate such conflict within 90 days, apply to the SEC for permission to continue (if the Indenture has been qualified under the Trust Indenture Act) or resign.

      The Holders of a majority in principal amount of the then outstanding Notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the Trustee, subject to certain exceptions. The Indenture provides that, in case an Event of Default occurs and is not cured, the Trustee will be required, in the exercise of its power, to use the degree of care of a prudent person in similar circumstances in the conduct of his own affairs. Subject to such provisions, the Trustee will be under no obligation to exercise any of its rights or powers under the Indenture at the request of any Holder, unless such Holder shall have offered to the Trustee security and indemnity satisfactory to the Trustee.

Governing Law

      The Indenture, the Notes and the Note Guarantees will be governed by, and construed in accordance with, the laws of the State of New York.

Certain Definitions

      Set forth below is a summary of certain of the defined terms used in the Indenture. Reference is made to the Indenture for the full definition of all such terms.

     “Acquired Indebtedness”means (1) with respect to any Person that becomes a Restricted Subsidiary after the Issue Date, Indebtedness of such Person and its Subsidiaries (including, for the avoidance of doubt, Indebtedness incurred in the ordinary course of such Person’s business to acquire assets used or useful in its business) existing at the time such Person becomes a Restricted Subsidiary that was not incurred in connection with, or in contemplation of, such Person becoming a Restricted Subsidiary and (2) with respect to the Issuer or any Restricted Subsidiary, any Indebtedness of a Person (including, for the avoidance of doubt, Indebtedness incurred in the ordinary course of such Person’s business to acquire assets used or useful in its business), other than the Issuer or a Restricted Subsidiary, existing at the time such Person is merged with or into the Issuer or a Restricted Subsidiary, or Indebtedness expressly assumed by the Issuer or any Restricted Subsidiary in connection with the acquisition of an asset or assets from another Person, which Indebtedness was

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not, in any case, incurred by such other Person in connection with, or in contemplation of, such merger or acquisition.

     “Affiliate”of any Person means any other Person which directly or indirectly controls or is controlled by, or is under direct or indirect common control with, the referent Person. For purposes of the covenant described under “— Certain Covenants — Limitations on Transactions with Affiliates,” Affiliates shall be deemed to include, with respect to any Person, any other Person (1) which beneficially owns or holds, directly or indirectly, 10% or more of any class of the Voting Stock of the referent Person, (2) of which 10% or more of the Voting Stock is beneficially owned or held, directly or indirectly, by the referenced Person or (3) with respect to an individual, any immediate family member of such Person. For purposes of this definition,“control”of a Person shall mean the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise.

     “amend”means to amend, supplement, restate, amend and restate or otherwise modify, including successively, and“amendment”shall have a correlative meaning.

     “asset”means any asset or property.

     “Asset Acquisition”means

(1) an Investment by the Issuer or any Restricted Subsidiary of the Issuer in any other Person if, as a result of such Investment, such Person shall become a Restricted Subsidiary of the Issuer, or shall be merged with or into the Issuer or any Restricted Subsidiary of the Issuer, or

(2) the acquisition by the Issuer or any Restricted Subsidiary of the Issuer of all or substantially all of the assets of any other Person (other than a Restricted Subsidiary of the Issuer) or any division or line of business of any such other Person (other than in the ordinary course of business).

     “Asset Sale”means any sale, issuance, conveyance, transfer, lease, assignment or other disposition by the Issuer or any Restricted Subsidiary to any Person other than the Issuer or any Restricted Subsidiary (including by means of a sale and leaseback transaction or a merger or consolidation) (collectively, for purposes of this definition, a“transfer”), in one transaction or a series of related transactions, of any assets of the Issuer or any of its Restricted Subsidiaries other than in the ordinary course of business. For purposes of this definition, the term “Asset Sale” shall not include:

(1) transfers of cash or Cash Equivalents;

(2) transfers of assets (including Equity Interests) that are governed by, and made in accordance with, the covenants described under “— Change of Control” or “— Certain Covenants — Limitations on Mergers, Consolidations, Etc.;”

(3) Permitted Investments and Restricted Payments permitted under the covenant described under “— Certain Covenants — Limitations on Restricted Payments;”

(4) the creation of or realization on any Lien permitted under the Indenture and any disposition of assets resulting from the enforcement or foreclosure of any such Lien;

(5) transfers of damaged, worn-out or obsolete equipment or assets that, in the Issuer’s reasonable judgment, are no longer used or useful in the business of the Issuer or its Restricted Subsidiaries;

(6) sales or grants of licenses or sublicenses to use the patents, trade secrets, know-how and other intellectual property, and licenses, leases or subleases of other assets, of the Issuer or any Restricted Subsidiary to the extent not materially interfering with the business of Issuer and the Restricted Subsidiaries;

(7) any sale, lease, conveyance or other disposition of any assets or any sale or issuance of Equity Interests in each case, made pursuant to a Permitted Joint Venture Investment;

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(8) the trade or exchange by the Issuer or any Restricted Subsidiary of any asset for any other asset or assets;provided, that the Fair Market Value of the asset or assets received by the Issuer or any Restricted Subsidiary in such trade or exchange (including any such cash or Cash Equivalents) is at least equal to the Fair Market Value (as determined in good faith by the Board of Directors or an executive officer of the Issuer or of such Restricted Subsidiary with responsibility for such transaction, which determination shall be conclusive evidence of compliance with this provision) of the asset or assets disposed of by the Issuer or any Restricted Subsidiary pursuant to such trade or exchange; and,provided, further, that if any cash or Cash Equivalents are used in such trade or exchange to achieve an exchange of equivalent value, that the amount of such cash and/or Cash Equivalents shall be deemed proceeds of an “Asset Sale,” subject to the following clause (9); and

(9) any transfer or series of related transfers that, but for this clause, would be Asset Sales, if after giving effect to such transfers, the aggregate Fair Market Value of the assets transferred in such transaction or any such series of related transactions does not exceed $3.0 million per occurrence or $10.0 million in any fiscal year.

     “Board of Directors”means, with respect to any Person, (i) in the case of any corporation, the board of directors of such Person, (ii) in the case of any partnership, the Board of Directors of the general partner of such Person and (iii) in any other case, the functional equivalent of the foregoing or, in each case, other than for purposes of the definition of “Change of Control,” any duly authorized committee of such body.

     “Business Day”means a day other than a Saturday, Sunday or other day on which banking institutions in New York are authorized or required by law to close.

     “Capitalized Lease”means a lease required to be capitalized for financial reporting purposes in accordance with GAAP.

     “Capitalized Lease Obligations”of any Person means the obligations of such Person to pay rent or other amounts under a Capitalized Lease, and the amount of such obligation shall be the capitalized amount thereof determined in accordance with GAAP.

     “Cash Equivalents”means:

(1) marketable obligations issued or directly and fully guaranteed or insured by the United States of America or any agency or instrumentality thereof (providedthat the full faith and credit of the United States of America is pledged in support thereof), maturing within 360 days of the date of acquisition thereof;

(2) demand and time deposits and certificates of deposit of any Lender or any commercial bank having, or which is the principal banking subsidiary of a bank holding company organized under the laws of the United States, any state thereof or the District of Columbia having, capital and surplus aggregating in excess of $300.0 million and a rating of “A” (or such other similar equivalent rating) or higher by at least one nationally recognized statistical rating organization (as defined in Rule 436 under the Securities Act) maturing within 360 days of the date of acquisition by such person;

(3) commercial paper issued by any person incorporated in the United States rated at leastA-1 or the equivalent thereof by S&P or at leastP-1 or the equivalent thereof by Moody’s or an equivalent rating by a nationally recognized rating agency if both S&P and Moody’s cease publishing ratings of commercial paper issuers generally, and in each case maturing not more than one year after the date of acquisition by such person;

(4) repurchase obligations with a term of not more than 30 days for underlying securities of the types described in clause (1) above entered into with any bank meeting the qualifications specified in clause (2) above;

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(5) securities issued and fully guaranteed by any state, commonwealth or territory of the United States of America, or by any political subdivision or taxing authority thereof, rated at least “A” by Moody’s Investors Service, Inc. or Standard & Poor’s Rating Services and having maturities of not more than one year from the date of acquisition;

(6) investments in money market or other mutual funds substantially all of whose assets comprise securities of the types described in clauses (1) through (5) above; and

(7) demand deposit accounts maintained in the ordinary course of business.

     “Change of Control”means the occurrence of any of the following events:

(1) the direct or indirect sale, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets of the Issuer and its Restricted Subsidiaries, taken as a whole, to any “person” (as that term is used in Section 13(d)(3) of the Exchange Act) other than a Permitted Holder;

(2) any “person” or “group” (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act), other than one or more Permitted Holders, is or becomes the beneficial owner (as defined in Rules 13d-3 and13d-5 under the Exchange Act, except that for purposes of this clause that person or group shall be deemed to have “beneficial ownership” of all securities that any such person or group has the right to acquire, whether such right is exercisable immediately or only after the passage of time), directly or indirectly, of Voting Stock representing 50% or more of the voting power of the total outstanding Voting Stock of the Issuer;provided, however, that such event shall not be deemed to be a Change of Control so long as the Permitted Holders own Voting Stock representing in the aggregate a greater percentage of the total voting power of the Voting Stock of the Issuer than such other person or group;

(3) during any period of two consecutive years, individuals who at the beginning of such period constituted the Board of Directors (together with any new directors whose election to such Board of Directors or whose nomination for election by the stockholders of the Issuer was approved by a vote of 66²/3% of the directors of the Issuer then still in office who were either directors at the beginning of such period or whose election or nomination for election was previously so approved) cease for any reason to constitute a majority of the Board of Directors of the Issuer; and

(4) the adoption by the stockholders of the Issuer of a Plan of Liquidation.

      For purposes of this definition, a Person shall not be deemed to have beneficial ownership of securities subject to a stock purchase agreement, merger agreement or similar agreement until the consummation of the transactions contemplated by such agreement.

     “Consolidated Amortization Expense”for any period means the amortization expense of the Issuer and the Restricted Subsidiaries for such period, determined on a consolidated basis in accordance with GAAP.

     “Consolidated Cash Flow”for any period means, without duplication, the sum of the amounts for such period of

(1) Consolidated Net Income,plus

(2) in each case only to the extent (and in the same proportion) deducted in determining Consolidated Net Income and with respect to the portion of Consolidated Net Income attributable to any Restricted Subsidiary only if a corresponding amount would be permitted at the date of determination to be distributed to the Issuer by such Restricted Subsidiary without prior approval (that has not been obtained), pursuant to the terms of its charter and all agreements, instruments,

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judgments, decrees, orders, statutes, rules and governmental regulations applicable to such Restricted Subsidiary or its stockholders,

(a) Consolidated Income Tax Expense,

(b) Consolidated Amortization Expense (but only to the extent not included in Consolidated Interest Expense),

(c) Consolidated Depreciation Expense,

(d) Consolidated Interest Expense, and

(e) all other non-cash items reducing the Consolidated Net Income (excluding any non-cash charge that results in an accrual of a reserve for cash charges in any future period) for such period, in each case determined on a consolidated basis in accordance with GAAP,minus

(3) the aggregate amount of all non-cash items, determined on a consolidated basis, to the extent such items increased Consolidated Net Income for such period.

     “Consolidated Depreciation Expense”for any period means the depreciation expense of the Issuer and the Restricted Subsidiaries for such period, determined on a consolidated basis in accordance with GAAP.

     “Consolidated Income Tax Expense”for any period means the provision for taxes of the Issuer and the Restricted Subsidiaries, determined on a consolidated basis in accordance with GAAP.

     “Consolidated Interest Coverage Ratio”means the ratio of Consolidated Cash Flow during the most recent four consecutive full fiscal quarters for which financial statements are available (the“Four-Quarter Period”) ending on or prior to the date of the transaction giving rise to the need to calculate the Consolidated Interest Coverage Ratio (the“Transaction Date”) to Consolidated Interest Expense for the Four-Quarter Period. For purposes of this definition, Consolidated Cash Flow and Consolidated Interest Expense shall be calculated after giving effect on a pro forma basis for the period of such calculation to:

(1) the incurrence of any Indebtedness or the issuance of any Preferred Stock of the Issuer or any Restricted Subsidiary (and the application of the proceeds thereof) and any repayment, repurchase or redemption of other Indebtedness or other Preferred Stock (and the application of the proceeds therefrom) (other than the incurrence or repayment of Indebtedness in the ordinary course of business for working capital purposes pursuant to any revolving credit arrangement) occurring during the Four-Quarter Period or at any time subsequent to the last day of the Four-Quarter Period and on or prior to the Transaction Date, as if such incurrence, repayment, repurchase, issuance or redemption, as the case may be (and the application of the proceeds thereof), occurred on the first day of the Four-Quarter Period; and

(2) any Asset Sale or Asset Acquisition (including, without limitation, any Asset Acquisition giving rise to the need to make such calculation as a result of the Issuer or any Restricted Subsidiary (including any Person who becomes a Restricted Subsidiary as a result of such Asset Acquisition) incurring Acquired Indebtedness and also including any Consolidated Cash Flow (including any pro forma expense and cost reductions calculated in good faith on a reasonable basis by a responsible financial or accounting Officer of the Issuer) occurring during the Four-Quarter Period or at any time subsequent to the last day of the Four-Quarter Period and on or prior to the Transaction Date), as if such Asset Sale or Asset Acquisition (including the incurrence of, or assumption or liability for, any such Indebtedness or Acquired Indebtedness) occurred on the first day of the Four-Quarter Period;provided, that the Officer making the pro forma calculation described above may in his discretion include any pro forma changes to Consolidated Cash Flow, including any pro forma reductions of expenses and costs, that have occurred or are reasonably expected by such Officer to occur within one year of closing of such Asset Sale or Asset Acquisition (regardless of whether such expense or cost savings or any other operating improvements could then be reflected

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properly in pro forma financial statements prepared in accordance with Regulation S-X under the Securities Act or any other regulation or policy of the SEC).

      In calculating Consolidated Interest Expense for purposes of determining the denominator (but not the numerator) of this Consolidated Interest Coverage Ratio:

(1) interest on outstanding Indebtedness determined on a fluctuating basis as of the Transaction Date and which will continue to be so determined thereafter shall be deemed to have accrued at a fixed rate per annum equal to the rate of interest on such Indebtedness in effect on the Transaction Date;

(2) if interest on any Indebtedness actually incurred on the Transaction Date may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a eurocurrency interbank offered rate, or other rates, then the interest rate in effect on the Transaction Date will be deemed to have been in effect during the Four-Quarter Period; and

(3) notwithstanding clause (1) or (2) above, interest on Indebtedness determined on a fluctuating basis, to the extent such interest is covered by agreements relating to Hedging Obligations, shall be deemed to accrue at the rate per annum resulting after giving effect to the operation of these agreements.

     “Consolidated Interest Expense”for any period means the sum, without duplication, of the total interest expense of the Issuer and the Restricted Subsidiaries for such period, determined on a consolidated basis in accordance with GAAP and including, without duplication,

(1) imputed interest on Capitalized Lease Obligations,

(2) commissions, discounts and other fees and charges owed with respect to letters of credit securing financial obligations, bankers’ acceptance financing and receivables financings,

(3) the net costs associated with Hedging Obligations related to interest rates,

(4) amortization of debt issuance costs, debt discount or premium and other financing fees and expenses,

(5) the interest portion of any deferred payment obligations,

(6) all other non-cash interest expense,

(7) capitalized interest,

(8) all dividend payments on any series of Disqualified Equity Interests of the Issuer or any of its Restricted Subsidiaries or any Preferred Stock of any Restricted Subsidiary (other than dividends on Equity Interests payable solely in Qualified Equity Interests of the Issuer or to the Issuer or a Restricted Subsidiary of the Issuer),

(9) all interest payable with respect to discontinued operations, and

(10) all interest on any Indebtedness described in clause (7) or (8) of the definition of Indebtedness.

     “Consolidated Net Income”for any period means the net income (or loss) of the Issuer and the Restricted Subsidiaries for such period determined on a consolidated basis in accordance with GAAP;providedthat there shall be excluded from such net income (to the extent otherwise included therein), without duplication:

(1) the net income (or loss) of any Person (other than a Restricted Subsidiary) in which any Person other than the Issuer and the Restricted Subsidiaries has an ownership interest, except to the extent that cash in an amount equal to any such income has actually been received by the Issuer or any of its Restricted Subsidiaries during such period;

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(2) except to the extent includible in the consolidated net income of the Issuer pursuant to the foregoing clause (1), the net income (or loss) of any Person that accrued prior to the date that (a) such Person becomes a Restricted Subsidiary or is merged into or consolidated with the Issuer or any Restricted Subsidiary or (b) the assets of such Person are acquired by the Issuer or any Restricted Subsidiary;

(3) the net income of any Restricted Subsidiary during such period to the extent that the declaration or payment of dividends or similar distributions by such Restricted Subsidiary of that income is not permitted by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Subsidiary during such period, except that the Issuer’s equity in a net loss of any such Restricted Subsidiary for such period shall be included in determining Consolidated Net Income;

(4) for the purposes of calculating the Restricted Payments Basket only, in the case of a successor to the Issuer by consolidation, merger or transfer of its assets, any income (or loss) of the successor prior to such merger, consolidation or transfer of assets;

(5) other than for purposes of calculating the Restricted Payments Basket, any gain (or loss), together with any related provisions for taxes on any such gain (or the tax effect of any such loss), realized during such period by the Issuer or any Restricted Subsidiary upon (a) the acquisition of any securities, or the extinguishment of any Indebtedness, of the Issuer or any Restricted Subsidiary or (b) any Asset Sale by the Issuer or any Restricted Subsidiary;

(6) gains and losses due solely to fluctuations in currency values and the related tax effects according to GAAP;

(7) unrealized gains and losses with respect to Hedging Obligations;

(8) the cumulative effect of any change in accounting principles; and

(9) other than for purposes of calculating the Restricted Payments Basket, any extraordinary or nonrecurring gain (or extraordinary or nonrecurring loss), together with any related provision for taxes on any such extraordinary or nonrecurring gain (or the tax effect of any such extraordinary or nonrecurring loss), realized by the Issuer or any Restricted Subsidiary during such period.

      In addition, any return of capital with respect to an Investment that increased the Restricted Payments Basket pursuant to clause (3)(d) of the first paragraph under “— Certain Covenants — Limitations on Restricted Payments” or decreased the amount of Investments outstanding pursuant to clause (16) of the definition of “Permitted Investments” shall be excluded from Consolidated Net Income for purposes of calculating the Restricted Payments Basket.

      For purposes of this definition of “Consolidated Net Income,”“nonrecurring”means any gain or loss as of any date that is not reasonably likely to recur within the two years following such date;providedthat if there was a gain or loss similar to such gain or loss within the two years preceding such date, such gain or loss shall not be deemed nonrecurring.

     “Consolidated Tangible Assets”means, with respect to any Person as of any date, the amount which, in accordance with GAAP, would be set forth under the caption “Total Assets” (or any like caption) on a consolidated balance sheet of such Person and its Restricted Subsidiaries, less all goodwill, patents, tradenames, trademarks, copyrights, franchises, experimental expenses, organization expenses and any other amounts classified as intangible assets in accordance with GAAP.

     “Contingent Obligation”shall mean, as to any person, any obligation, agreement, understanding or arrangement of such person guaranteeing or intended to guarantee any Indebtedness, leases, dividends or other obligations(“primary obligations”) of any other person (the“primary obligor”) in any manner, whether directly or indirectly, including, without limitation, any obligation of such person, whether or not contingent, (a) to purchase any such primary obligation or any property constituting direct or indirect security therefor; (b) to advance or supply funds (i) for the purchase or payment of any

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such primary obligation or (ii) to maintain working capital or equity capital of the primary obligor or otherwise to maintain the net worth or solvency of the primary obligor; (c) to purchase property, securities or services primarily for the purpose of assuring the owner of any such primary obligation of the ability of the primary obligor to make payment of such primary obligation; (d) with respect to bankers’ acceptances and letters of credit, until a reimbursement obligation arises (which obligation shall constitute Indebtedness); or (e) otherwise to assure or hold harmless the holder of such primary obligation against loss in respect thereof;provided, however, that the term “Contingent Obligation” shall not include endorsements of instruments for deposit or collection in the ordinary course of business or any product warranties for deposit or collection in the ordinary course of business. The amount of any Contingent Obligation shall be deemed to be an amount equal to the stated or determinable amount of the primary obligation in respect of which such Contingent Obligation is made (or, if less, the maximum amount of such primary obligation for which such person may be liable, whether severally or jointly, pursuant to the terms of the instrument evidencing such Contingent Obligation) or, if not stated or determinable, the maximum reasonably anticipated liability in respect thereof (assuming such person is required to perform thereunder) as determined by such person in good faith.

     “Coverage Ratio Exception”has the meaning set forth in the proviso in the first paragraph of the covenant described under “— Certain Covenants — Limitations on Additional Indebtedness.”

     “Credit Agreement”means the Third Amended and Restated Credit Agreement dated as of October 3, 2003, as amended and restated through and including December 15, 2005 by and among the Issuer, as Borrower, the subsidiary guarantors party thereto, UBS Loan Finance LLC as swingline lender, Bank of America, N.A. as syndication agent, Hibernia National Bank and BNP Paribas as co-documentation agents, UBS AG, Stamford Branch, as issuing bank, administrative agent and collateral agent and the other lenders named therein, including any notes, guarantees, collateral and security documents, instruments and agreements executed in connection therewith (including Hedging Obligations related to the Indebtedness incurred thereunder), and in each case as further amended or refinanced from time to time.

     “Credit Facilities”means one or more debt facilities (which may be outstanding at the same time and including, without limitation, the Credit Agreement) providing for revolving credit loans, term loans or letters of credit and, in each case, as such agreements may be amended, refinanced or otherwise restructured, in whole or in part from time to time (including increasing the amount of available borrowings thereunder or adding Subsidiaries of the Issuer as additional borrowers or guarantors thereunder) with respect to all or any portion of the Indebtedness under such agreement or agreements or any successor or replacement agreement or agreements and whether by the same or any other agent, lender or group of lenders.

     “Default”means (1) any Event of Default or (2) any event, act or condition that, after notice or the passage of time or both, would be an Event of Default.

     “Designation”has the meaning given to this term in the covenant described under “— Certain Covenants — Limitations on Designation of Unrestricted Subsidiaries.”

     “Designation Amount”has the meaning given to this term in the covenant described under “— Certain Covenants — Limitations on Designation of Unrestricted Subsidiaries.”

     “Disqualified Equity Interests”of any Person means any class of Equity Interests of such Person that, by its terms, or by the terms of any related agreement or of any security into which it is convertible, puttable or exchangeable (in each case, at the option of the holder thereof), is, or upon the happening of any event or the passage of time would be, required to be redeemed by such Person, at the option of the holder thereof, or matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, in whole or in part, on or prior to the date which is 91 days after the final maturity date of the Notes;provided, however, that any class of Equity Interests of such Person that, by its terms, authorizes such Person to satisfy in full its obligations with respect to the payment of dividends or upon maturity, redemption (pursuant to a sinking fund or otherwise) or repurchase thereof

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or otherwise by the delivery of Equity Interests that are not Disqualified Equity Interests, and that is not convertible, puttable or exchangeable for Disqualified Equity Interests or Indebtedness, will not be deemed to be Disqualified Equity Interests so long as such Person satisfies its obligations with respect thereto solely by the delivery of Equity Interests that are not Disqualified Equity Interests;provided, further, however, that any Equity Interests that would not constitute Disqualified Equity Interests but for provisions thereof giving holders thereof (or the holders of any security into or for which such Equity Interests are convertible, exchangeable or exercisable) the right to require the Issuer to repurchase or redeem such Equity Interests upon the occurrence of a change in control or an asset sale occurring prior to the 91st day after the final maturity date of the Notes shall not constitute Disqualified Equity Interests if the change of control or asset sale provisions applicable to such Equity Interests are no more favorable to such holders than the provisions described under “— Change of Control” and “— Certain Covenants — Limitations on Asset Sales,” respectively, and such Equity Interests specifically provide that the Issuer will not repurchase or redeem any such Equity Interests pursuant to such provisions prior to the Issuer’s purchase of the Notes as required pursuant to the provisions described under “— Change of Control” and “— Certain Covenants — Limitations on Asset Sales,” respectively.

     “Domestic Restricted Subsidiary”means (i) each Restricted Subsidiary of the Issuer organized or existing under the laws of the United States, any state thereof or the District of Columbia and (ii) any other Restricted Subsidiary that guarantees any Indebtedness under any Credit Facility.

     “Earn Out Obligation”means those contingent obligations of the Issuer incurred in favor of a seller (or other third party entitled thereto) under or with respect to any Permitted Acquisition (as such term is defined in the Credit Agreement as of the Issue Date).

     “Equity Interests”of any Person means (1) any and all shares or other equity interests (including common stock, preferred stock, limited liability company interests and partnership interests) in such Person and (2) all rights to purchase, warrants or options (whether or not currently exercisable), participations or other equivalents of or interests in (however designated) such shares or other interests in such Person, but excluding from all of the foregoing any debt securities convertible into Equity Interests, regardless of whether such debt securities include any right of participation with Equity Interests.

     “Exchange Act”means the U.S. Securities Exchange Act of 1934, as amended.

     “Fair Market Value”means, with respect to any asset, the price (after taking into account any liabilities relating to such assets) that would be negotiated in an arm’s-length transaction for cash between a willing seller and a willing and able buyer, neither of which is under any compulsion to complete the transaction, as such price is determined in good faith by the Board of Directors of the Issuer or a duly authorized committee thereof, as evidenced by a resolution of such Board of Directors or committee.

     “Foreign Restricted Subsidiary”means any Restricted Subsidiary of the Issuer other than a Domestic Restricted Subsidiary.

     “GAAP”means generally accepted accounting principles set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as may be approved by a significant segment of the accounting profession of the United States, as in effect from time to time.

     “guarantee”means a direct or indirect guarantee by any Person of any Indebtedness of any other Person and includes any obligation, direct or indirect, contingent or otherwise, of such Person (1) to purchase or pay (or advance or supply funds for the purchase or payment of) Indebtedness of such other Person (whether arising by virtue of partnership arrangements, or by agreements to keep-well, to purchase assets, goods, securities or services (unless such purchase arrangements are on arm’s-length terms and are entered into in the ordinary course of business), to take-or-pay, or to maintain

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financial statement conditions or otherwise); or (2) entered into for purposes of assuring in any other manner the obligee of such Indebtedness of the payment thereof or to protect such obligee against loss in respect thereof (in whole or in part);“guarantee,”when used as a verb, and“guaranteed”have correlative meanings.

     “Guarantors”means each Domestic Restricted Subsidiary of the Issuer on the Issue Date, and each other Person that is required to, or at the election of the Issuer does, become a Guarantor by the terms of the Indenture after the Issue Date, in each case, until such Person is released from its Note Guarantee in accordance with the terms of the Indenture.

     “Hedging Obligations”of any Person means the obligations of such Person under swap, cap, collar, forward purchase or similar agreements or arrangements dealing with interest rates, currency exchange rates or commodity prices, either generally or under specific contingencies.

     “Holder”means any registered holder, from time to time, of the Notes.

     “incur”means, with respect to any Indebtedness or Obligation, incur, create, issue, assume, guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to such Indebtedness or Obligation;providedthat (1) the Indebtedness of a Person existing at the time such Person became a Restricted Subsidiary of the Issuer shall be deemed to have been incurred by such Restricted Subsidiary at the time it becomes a Restricted Subsidiary of the Issuer and (2) neither the accrual of interest nor the accretion of original issue discount or the accretion or accumulation of dividends on any Equity Interests shall be deemed to be an incurrence of Indebtedness.

     “Indebtedness”of any Person at any date means, without duplication:

(1) all liabilities, contingent or otherwise, of such Person for borrowed money (whether or not the recourse of the lender is to the whole of the assets of such Person or only to a portion thereof);

(2) all obligations of such Person evidenced by bonds, debentures, notes or other similar instruments;

(3) all reimbursement obligations of such Person in respect of letters of credit, letters of guaranty, bankers’ acceptances and similar credit transactions;

(4) all obligations of such Person to pay the deferred and unpaid purchase price of property or services, except trade payables and accrued expenses incurred by such Person in the ordinary course of business in connection with obtaining goods, materials or services;

(5) the maximum fixed redemption or repurchase price of all Disqualified Equity Interests of such Person;

(6) all Capitalized Lease Obligations of such Person;

(7) all Indebtedness of others secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person;

      (8) all Indebtedness of others guaranteed by such Person to the extent of such guarantee;providedthat Indebtedness of the Issuer or its Subsidiaries that is guaranteed by the Issuer or the Issuer’s Subsidiaries shall only be counted once in the calculation of the amount of Indebtedness of the Issuer and its Subsidiaries on a consolidated basis;

(9) to the extent not otherwise included in this definition, Hedging Obligations of such Person;

(10) all obligations of such Person under conditional sale or other title retention agreements relating to assets purchased by such Person; and

(11) all Contingent Obligations (other than Earn Out Obligations) of such person in respect of Indebtedness or obligations of others of the kinds referred to in clauses (1) through (10) above.

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      The amount of any Indebtedness which is incurred at a discount to the principal amount at maturity thereof as of any date shall be deemed to have been incurred at the accreted value thereof as of such date. The amount of Indebtedness of any Person at any date shall be the outstanding balance at such date of all unconditional obligations as described above, the maximum liability of such Person for any such contingent obligations at such date and, in the case of clause (7), the lesser of (a) the Fair Market Value of any asset subject to a Lien securing the Indebtedness of others on the date that the Lien attaches and (b) the amount of the Indebtedness secured. For purposes of clause (5), the “maximum fixed redemption or repurchase price” of any Disqualified Equity Interests that do not have a fixed redemption or repurchase price shall be calculated in accordance with the terms of such Disqualified Equity Interests as if such Disqualified Equity Interests were redeemed or repurchased on any date on which an amount of Indebtedness outstanding shall be required to be determined pursuant to the Indenture.

     “Independent Director”means a director of the Issuer who

(1) is independent with respect to the transaction at issue;

(2) does not have any material financial interest in the Issuer or any of its Affiliates (other than as a result of holding securities of the Issuer); and

(3) has not and whose Affiliates or affiliated firm has not, at any time during the twelve months prior to the taking of any action hereunder, directly or indirectly, received, or entered into any understanding or agreement to receive, any compensation, payment or other benefit, of any type or form, from the Issuer or any of its Affiliates, other than customary directors’ fees for serving on the Board of Directors of the Issuer or any Affiliate and reimbursement ofout-of-pocket expenses for attendance at the Issuer’s or Affiliate’s board and board committee meetings.

     “Independent Financial Advisor”means an accounting, appraisal or investment banking firm of nationally recognized standing that is, in the reasonable judgment of the Issuer’s Board of Directors, qualified to perform the task for which it has been engaged and disinterested and independent with respect to the Issuer and its Affiliates.

     “Intellectual Property”means all patents, patent applications, trademarks, trade names, service marks, copyrights, technology, trade secrets, proprietary information, domain names, know how and processes necessary for the conduct of the Issuer’s or any Restricted Subsidiary’s business as currently conducted.

     “Investments”of any Person means:

(1) all direct or indirect investments by such Person in any other Person in the form of loans, advances or capital contributions or other credit extensions constituting Indebtedness of such other Person, and any guarantee of Indebtedness of any other Person;

(2) all purchases (or other acquisitions for consideration) by such Person of Indebtedness, Equity Interests or other securities of any other Person (other than any such purchase that constitutes a Restricted Payment of the type described in clause (2) of the definition thereof);

(3) all other items that would be classified as investments on a balance sheet of such Person prepared in accordance with GAAP (including, if required by GAAP, purchases of assets outside the ordinary course of business); and

(4) the Designation of any Subsidiary as an Unrestricted Subsidiary.

      Except as otherwise expressly specified in this definition, the amount of any Investment (other than an Investment made in cash) shall be the Fair Market Value thereof on the date such Investment is made. The amount of Investment pursuant to clause (4) shall be the Designation Amount determined in accordance with the covenant described under “— Certain Covenants — Limitations on Designation of Unrestricted Subsidiaries.” If the Issuer or any Restricted Subsidiary sells or otherwise disposes of any

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Equity Interests of any Restricted Subsidiary, or any Restricted Subsidiary issues any Equity Interests, in either case, such that, after giving effect to any such sale or disposition, such Person is no longer a Subsidiary, the Issuer shall be deemed to have made an Investment on the date of any such sale or other disposition equal to the Fair Market Value of the Equity Interests of and all other Investments in such Restricted Subsidiary retained. Notwithstanding the foregoing, purchases or redemptions of Equity Interests of the Issuer shall be deemed not to be Investments.

     “Issue Date”means the date on which the Notes are originally issued.

     “Lien”means, with respect to any asset, any mortgage, deed of trust, lien (statutory or other), pledge, lease, easement, restriction, covenant, charge, security interest or other encumbrance of any kind or nature in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement.

     “Liquidated Damages”has the meaning set forth in the Registration Rights Agreement.

     “Moody’s”means Moody’s Investors Service, Inc., and its successors.

     “Net Available Proceeds”means, with respect to any Asset Sale, the proceeds thereof in the form of cash or Cash Equivalents received by the Issuer or any of its Restricted Subsidiaries from such Asset Sale, net of

(1) brokerage commissions and other fees and expenses (including fees, discounts and expenses of legal counsel, accountants and investment banks, consultants and placement agents) of such Asset Sale;

(2) provisions for taxes payable as a result of such Asset Sale (after taking into account any available tax credits or deductions and any tax sharing arrangements);

(3) amounts required to be paid to any Person (other than the Issuer or any Restricted Subsidiary and other than under a Credit Facility) owning a beneficial interest in the assets subject to the Asset Sale or having a Lien thereon;

(4) payments of unassumed liabilities (not constituting Indebtedness) relating to the assets sold at the time of, or within 30 days after the date of, such Asset Sale; and

(5) appropriate amounts to be provided by the Issuer or any Restricted Subsidiary, as the case may be, as a reserve required in accordance with GAAP against any adjustment in the sale price of such asset or assets or liabilities associated with such Asset Sale and retained by the Issuer or any Restricted Subsidiary, as the case may be, after such Asset Sale, including pensions and other postemployment benefit liabilities, liabilities related to environmental matters and liabilities under any indemnification obligations associated with such Asset Sale, all as reflected in an Officers’ Certificate delivered to the Trustee;provided, however, that any amounts remaining after adjustments, revaluations or liquidations of such reserves shall constitute Net Available Proceeds.

     “Non-Recourse Debt”means Indebtedness of an Unrestricted Subsidiary:

(1) as to which neither the Issuer nor any Restricted Subsidiary (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness), (b) is directly or indirectly liable as a guarantor or otherwise, or (c) constitutes the lender; and

(2) no default with respect to which (including any rights that the holders thereof may have to take enforcement action against an Unrestricted Subsidiary) would permit upon notice, lapse of time or both any holder of any other Indebtedness (other than the Credit Agreement or Notes) of the Issuer or any Restricted Subsidiary to declare a default on the other Indebtedness or cause the payment thereof to be accelerated or payable prior to its stated maturity.

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     “Obligation”means any principal, interest, penalties, fees, indemnification, reimbursements, costs, expenses, damages and other liabilities payable under the documentation governing any Indebtedness.

     “Officer”means any of the following of the Issuer: the Chairman of the Board of Directors, the Chief Executive Officer, the Chief Financial Officer, the President, any Vice President, the Treasurer or the Secretary.

     “Officers’ Certificate”means a certificate signed by two Officers.

     “Pari Passu Indebtedness”means any Indebtedness of the Issuer or any Guarantor that rankspari passuin right of payment with the Notes or the Note Guarantees, as applicable.

     “Permitted Business”means the businesses engaged in by the Issuer and its Subsidiaries on the Issue Date as described in this prospectus and businesses that are reasonably related thereto or reasonable extensions thereof.

     “Permitted Holder”means Credit Suisse, a Swiss Bank, Credit Suisse Group, First Reserve Corporation, RS Investment Management Co. LLC and their respective Affiliates.

     “Permitted Investment”means:

(1) (i) Investments by the Issuer or any Subsidiary Guarantor in (a) any Subsidiary Guarantor or (b) any Person that will become immediately after such Investment a Subsidiary Guarantor or that will merge or consolidate into the Issuer or any Subsidiary Guarantor and (ii) Investments by any Restricted Subsidiary that is not a Subsidiary Guarantor in any other Restricted Subsidiary;

(2) Investments in the Issuer by any Restricted Subsidiary;

(3) loans and advances to directors, employees and officers of the Issuer and the Restricted Subsidiaries (i) in the ordinary course of business (including payroll, travel and entertainment related advances) (other than any loans or advances to any director or executive officer (or equivalent thereof) that would be in violation of Section 402 of the Sarbanes Oxley Act) and (ii) to purchase Equity Interests of the Issuer not in excess of $2.5 million at any one time outstanding;

(4) Hedging Obligations entered into forbona fidehedging purposes of the Issuer or any Restricted Subsidiary not for the purpose of speculation;

(5) Investments in cash and Cash Equivalents;

(6) receivables owing to the Issuer or any Restricted Subsidiary if created or acquired in the ordinary course of business and payable or dischargeable in accordance with customary trade terms;provided, however, that such trade terms may include such concessionary trade terms as the Issuer or any such Restricted Subsidiary deems reasonable under the circumstances;

(7) Investments in securities of trade creditors or customers received pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of such trade creditors or customers;

(8) Investments made by the Issuer or any Restricted Subsidiary as a result of consideration received in connection with an Asset Sale made in compliance with the covenant described under “— Certain Covenants — Limitations on Asset Sales”;

(9) lease, utility and other similar deposits in the ordinary course of business;

(10) Investments made by the Issuer or a Restricted Subsidiary for consideration consisting only of Qualified Equity Interests of the Issuer or any of its Subsidiaries;

(11) stock, obligations or securities received in settlement of debts created in the ordinary course of business and owing to the Issuer or any Restricted Subsidiary or in satisfaction of judgments;

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(12) Permitted Joint Venture Investments made by the Issuer or any of its Restricted Subsidiaries, in an aggregate amount (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (12), that does not exceed $20.0 million;

(13) Investments existing on the Issue Date;

(14) repurchases of, or other Investments in, the Notes;

(15) advances, deposits and prepayments for purchases of any assets, including any Equity Interests; and

(16) other Investments in any Person having an aggregate Fair Market Value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (16) since the Issue Date, not to exceed the greater of (a) $25.0 million or (b) 5.0% of the Issuer’s Consolidated Tangible Assets.

      In determining whether any Investment is a Permitted Investment, the Issuer may allocate or reallocate all or any portion of an Investment among the clauses of this definition and any of the provisions of the covenant described under the caption “— Covenants — Limitations on Restricted Payments.”

     “Permitted Joint Venture Investment”means, with respect to an Investment by any specified Person, an Investment by such specified Person in any other Person engaged in a Permitted Business (a) over which the specified Person is responsible (either directly or through a services agreement) forday-to-day operations or otherwise has operational and managerial control of such other Person, or veto power over significant management decisions affecting such other Person and (b) of which at least 30% of the outstanding Equity Interests of such other Person is at the time owned directly or indirectly by the specified Person.

     “Permitted Liens”means the following types of Liens:

(1) inchoate Liens for taxes, assessments or governmental charges or levies which (a) are not yet due and payable or delinquent or (b) are being contested in good faith by appropriate proceedings and as to which the Issuer or the Restricted Subsidiaries shall have set aside on its books such reserves as may be required pursuant to GAAP;

(2) Liens in respect of property of the Issuer or any Restricted Subsidiary imposed by law, which were not incurred or created to secure Indebtedness for borrowed money, such as carriers’, warehousemen’s, materialmen’s, landlords’, workmen’s, suppliers’, repairmen’s and mechanics’ Liens and other similar Liens arising in the ordinary course of business, and which do not in the aggregate materially detract from the value of the property of the Issuer or its Restricted Subsidiaries, taken as a whole, and do not materially impair the use thereof in the operation of the business of the Issuer and its Restricted Subsidiaries, taken as a whole;

(3) Liens (i) imposed by law or deposits made in connection therewith in the ordinary course of business in connection with workers’ compensation, unemployment insurance and other types of social security, (ii) incurred in the ordinary course of business to secure the performance of tenders, statutory obligations (other than excise taxes), surety, stay, customs and appeal bonds, statutory bonds, bids, leases, government contracts, trade contracts, performance and return of money bonds and other similar obligations (exclusive of obligations for the payment of borrowed money) or (iii) arising by virtue of deposits made in the ordinary course of business to secure liability for premiums to insurance carriers;

(4) Liens upon specific items of inventory or other goods and proceeds of any Person securing such Person’s obligations in respect of bankers’ acceptances issued or created for the account of such Person to facilitate the purchase, shipment or storage of such inventory or other goods;

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(5) Liens arising out of judgments or awards not resulting in a Default or an Event of Default;

(6) easements, rights of way, restrictions (including zoning restrictions), covenants, encroachments, protrusions and other similar charges or encumbrances, and minor title deficiencies on or with respect to any Real Property, in each case whether now or hereafter in existence, not (i) securing Indebtedness, (ii) individually or in the aggregate materially impairing the value or marketability of such Real Property and (iii) individually or in the aggregate materially interfering with the conduct of the business of the Issuer and its Restricted Subsidiaries at such Real Property;

(7) Liens securing reimbursement obligations with respect to commercial letters of credit which encumber documents and other assets relating to such letters of credit and products and proceeds thereof;

(8) Liens encumbering deposits made to secure obligations arising from statutory, regulatory, contractual or warranty requirements of the Issuer or any Restricted Subsidiary, including rights of offset and setoff;

(9) bankers’ Liens, rights of setoff and other similar Liens existing solely with respect to cash and Cash Equivalents on deposit in one or more of accounts maintained by the Issuer or any Restricted Subsidiary, in each case granted in the ordinary course of business in favor of the bank or banks with which such accounts are maintained, securing amounts owing to such bank with respect to cash management and operating account arrangements, including those involving pooled accounts and netting arrangements;

(10) Leases with respect to the assets or properties of the Issuer and any Restricted Subsidiary, in each case entered into in the ordinary course of the Issuer’s or such Restricted Subsidiary’s business so long as such Leases do not, individually or in the aggregate, (i) interfere in any material respect with the ordinary conduct of the business of the Issuer or any Restricted Subsidiary or (ii) materially impair the use (for its intended purposes) or the value of the property subject thereto;

(11) the filing of financing statements solely as a precautionary measure in connection with operating leases or consignment of goods;

(12) Liens securing all of the Notes and Liens securing any Note Guarantee;

(13) Liens securing Hedging Obligations entered into forbona fidehedging purposes of the Issuer or any Restricted Subsidiary not for the purpose of speculation;

(14) Liens existing on the Issue Date securing Indebtedness outstanding on the Issue Date;providedthat (i) the aggregate principal amount of the Indebtedness, if any, secured by such Liens does not increase; and (ii) such Liens do not encumber any property other than the property subject thereto on the Issue Date;

(15) Liens in favor of the Issuer or a Guarantor;

(16) Liens securing Indebtedness under the Credit Facilities incurred and then outstanding pursuant to clause (1) of the second paragraph of “— Limitations on Additional Indebtedness”;

(17) Liens arising pursuant to Purchase Money Indebtedness incurred pursuant to clause (7) of the second paragraph of “— Limitations on Additional Indebtedness”;providedthat (i) the Indebtedness secured by any such Lien (including refinancings thereof) does not exceed 100% of the cost of the property being acquired or leased at the time of the incurrence of such Indebtedness and (ii) any such Liens attach only to the property being financed pursuant to such Purchase Money Indebtedness and do not encumber any other property of the Issuer or any Restricted Subsidiary.

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(18) Liens securing Acquired Indebtedness permitted to be incurred under the Indenture;providedthat the Liens do not extend to assets not subject to such Lien at the time of acquisition (other than improvements thereon) and are no more favorable to the lienholders than those securing such Acquired Indebtedness prior to the incurrence of such Acquired Indebtedness by the Issuer or a Restricted Subsidiary;

(19) Liens on property of a person existing at the time such person is acquired or merged with or into or consolidated with the Issuer or any Restricted Subsidiary (and not created in anticipation or contemplation thereof);providedthat such Liens do not extend to property not subject to such Liens at the time of acquisition (other than improvements thereon) and are no more favorable to the lienholders than the existing Lien;

(20) Liens to secure Refinancing Indebtedness of Indebtedness secured by Liens referred to in the foregoing clauses (12), (14), (16), (17), (18) and (19);providedthat in the case of Liens securing Refinancing Indebtedness of Indebtedness secured by Liens referred to in the foregoing clauses (14), (17), (18) and (19), such Liens do not extend to any additional assets (other than improvements thereon and replacements thereof);

(21) licenses of Intellectual Property granted by the Issuer or any Restricted Subsidiary in the ordinary course of business and not interfering in any material respect with the ordinary conduct of the business of the Issuer or such Restricted Subsidiary;

(22) Liens arising out of conditional sale, title retention, consignment or similar arrangements for the sale of goods entered into by Issuer or any Restricted Subsidiary in the ordinary course of business in accordance with the past practices of the Issuer or such Restricted Subsidiary;

(23) Liens on assets of any Foreign Restricted Subsidiary to secure Indebtedness of such Foreign Restricted Subsidiary which Indebtedness is permitted by the Indenture;

(24) Liens of franchisors arising in the ordinary course of business not securing Indebtedness;

(25) Liens in favor of the Trustee as provided for in the Indenture on money or property held or collected by the Trustee in its capacity as Trustee; and

(26) other Liens with respect to obligations that do not in the aggregate exceed the greater of (a) $15.0 million or (b) 3.0% of the Issuer’s Consolidated Tangible Assets at any time outstanding;

     “Person”means any individual, corporation, partnership, limited liability company, joint venture, incorporated or unincorporated association, joint-stock company, trust, unincorporated organization or government or other agency or political subdivision thereof or other entity of any kind.

     “Plan of Liquidation”with respect to any Person, means a plan that provides for, contemplates or the effectuation of which is preceded or accompanied by (whether or not substantially contemporaneously, in phases or otherwise): (1) the sale, lease, conveyance or other disposition of all or substantially all of the assets of such Person otherwise than as an entirety or substantially as an entirety; and (2) the distribution of all or substantially all of the proceeds of such sale, lease, conveyance or other disposition of all or substantially all of the remaining assets of such Person to holders of Equity Interests of such Person.

     “Preferred Stock”means, with respect to any Person, any and all preferred or preference stock or other equity interests (however designated) of such Person whether now outstanding or issued after the Issue Date.

     “principal”means, with respect to the Notes, the principal of, and premium, if any, on the Notes.

     “Purchase Money Indebtedness”means Indebtedness, including Capitalized Lease Obligations, of the Issuer or any Restricted Subsidiary incurred for the purpose of financing all or any part of the purchase price of property, plant or equipment used in the business of the Issuer or any Restricted

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Subsidiary or the cost of installation, construction or improvement thereof;provided, however, that (except in the case of Capitalized Lease Obligations) (1) the amount of such Indebtedness shall not exceed such purchase price or cost and (2) such Indebtedness shall be incurred within 90 days after such acquisition of such asset by the Issuer or such Restricted Subsidiary or such installation, construction or improvement.

     “Qualified Equity Interests”of any Person means Equity Interests of such Person other than Disqualified Equity Interests;providedthat such Equity Interests shall not be deemed Qualified Equity Interests to the extent sold or owed to a Subsidiary of such Person or financed, directly or indirectly, using funds (1) borrowed from such Person or any Subsidiary of such Person until and to the extent such borrowing is repaid or (2) contributed, extended, guaranteed or advanced by such Person or any Subsidiary of such Person (including, without limitation, in respect of any employee stock ownership or benefit plan). Unless otherwise specified, Qualified Equity Interests refer to Qualified Equity Interests of the Issuer.

     “Qualified Equity Offering”means the issuance and sale of Qualified Equity Interests of the Issuer to Persons other than (x) any Permitted Holder or (y) any other Person who is, prior to such issuance and sale, an Affiliate of the Issuer;provided, however, that cash proceeds therefrom equal to not less than the redemption price of the Notes to be redeemed are received by the Issuer as a capital contribution immediately prior to such redemption.

     “Rating Agencies”means Moody’s and S&P.

     “Real Property”means, collectively, all right, title and interest (including any leasehold estate) in and to any and all parcels of or interests in real property owned, leased or operated by any person, whether by lease, license or other means, together with, in each case, all easements, hereditaments and appurtenances relating thereto, all improvements and appurtenant fixtures and equipment, all general intangibles and contract rights and other property and rights incidental to the ownership, lease or operation thereof.

     “Redesignation”has the meaning given to such term in the covenant described under “— Certain Covenants — Limitations on Designation of Unrestricted Subsidiaries.”

     “refinance”means to refinance, repay, prepay, replace, renew or refund.

     “Refinancing Indebtedness”means Indebtedness of the Issuer or a Restricted Subsidiary incurred in exchange for, or the proceeds of which are used to redeem, refinance, replace, defease, discharge, refund or otherwise retire for value, in whole or in part, any Indebtedness of the Issuer or any Restricted Subsidiary (the“Refinanced Indebtedness”);providedthat:

(1) the principal amount (and accreted value, in the case of Indebtedness issued at a discount) of the Refinancing Indebtedness does not exceed the principal amount (and accreted value, as the case may be) of the Refinanced Indebtedness plus the amount of accrued and unpaid interest on the Refinanced Indebtedness, any reasonable premium paid to the holders of the Refinanced Indebtedness and reasonable expenses incurred in connection with the incurrence of the Refinancing Indebtedness;

(2) the obligor of Refinancing Indebtedness does not include any Person (other than the Issuer or any Guarantor) that is not an obligor of the Refinanced Indebtedness;

(3) if the Refinanced Indebtedness was subordinated in right of payment to the Notes or the Note Guarantees, as the case may be, then such Refinancing Indebtedness, by its terms, is subordinate in right of payment to the Notes or the Note Guarantees, as the case may be, at least to the same extent as the Refinanced Indebtedness;

(4) the Refinancing Indebtedness has a final stated maturity either (a) no earlier than the Refinanced Indebtedness being repaid or amended or (b) after the maturity date of the Notes;

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(5) the portion, if any, of the Refinancing Indebtedness that is scheduled to mature on or prior to the maturity date of the Notes has a Weighted Average Life to Maturity at the time such Refinancing Indebtedness is incurred that is equal to or greater than the Weighted Average Life to Maturity of the portion of the Refinanced Indebtedness being repaid that is scheduled to mature on or prior to the maturity date of the Notes; and

(6) the proceeds of the Refinancing Indebtedness shall be used substantially concurrently with the incurrence thereof to redeem, refinance, replace, defease, discharge, refund or otherwise retire for value the Refinanced Indebtedness, unless the Refinanced Indebtedness is not then due and is not redeemable or prepayable at the option of the obligor thereof or is redeemable or prepayable only with notice, in which case such proceeds shall be held in a segregated account of the obligor of the Refinanced Indebtedness until the Refinanced Indebtedness becomes due or redeemable or prepayable or such notice period lapses and then shall be used to refinance the Refinanced Indebtedness;providedthat in any event the Refinanced Indebtedness shall be redeemed, refinanced, replaced, defeased, discharged, refunded or otherwise retired for value within one year of the incurrence of the Refinancing Indebtedness.

     “Registration Rights Agreement”means (i) the Registration Rights Agreement dated as of the Issue Date among the Issuer, the Guarantors and the initial purchasers of the Notes issued on the Issue Date and (ii) any other registration rights agreement entered into in connection with an issuance of Additional Notes in a private offering after the Issue Date.

     “Restricted Payment”means any of the following:

(1) the declaration or payment of any dividend or any other distribution on Equity Interests of the Issuer or any Restricted Subsidiary or any payment made to the direct or indirect holders (in their capacities as such) of Equity Interests of the Issuer or any Restricted Subsidiary, including, without limitation, any payment in connection with any merger or consolidation involving the Issuer but excluding (a) dividends or distributions payable solely in Qualified Equity Interests or through accretion or accumulation of such dividends on such Equity Interests and (b) in the case of Restricted Subsidiaries, dividends or distributions payable to the Issuer or to a Restricted Subsidiary andpro ratadividends or distributions payable to minority stockholders of any Restricted Subsidiary;

(2) the purchase, redemption, defeasance or other acquisition or retirement for value of any Equity Interests of the Issuer or any Restricted Subsidiary (including, without limitation, any payment in connection with any merger or consolidation involving the Issuer) but excluding any such Equity Interests held by the Issuer or any Restricted Subsidiary;

(3) any Investment other than a Permitted Investment; or

(4) any principal payment on, purchase, redemption, defeasance, prepayment, decrease or other acquisition or retirement for value prior to any scheduled maturity or prior to any scheduled repayment of principal or sinking fund payment, as the case may be, in respect of Subordinated Indebtedness (other than any Subordinated Indebtedness owed to and held by the Issuer or any Restricted Subsidiary).

     “Restricted Payments Basket”has the meaning given to such term in the first paragraph of the covenant described under “— Certain Covenants — Limitations on Restricted Payments.”

     “Restricted Subsidiary”means any Subsidiary of the Issuer other than an Unrestricted Subsidiary.

     “S&P”means Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc., and its successors.

     “SEC”means the U.S. Securities and Exchange Commission.

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     “Secretary’s Certificate”means a certificate signed by the Secretary of the Issuer.

     “Securities Act”means the U.S. Securities Act of 1933, as amended.

     “Significant Subsidiary”means (1) any Restricted Subsidiary that would be a “significant subsidiary” as defined in Regulation S-X promulgated pursuant to the Securities Act as such Regulation is in effect on the Issue Date and (2) any Restricted Subsidiary that, when aggregated with all other Restricted Subsidiaries that are not otherwise Significant Subsidiaries and as to which any event described in clause (7) under “— Events of Default” has occurred and is continuing, or which are being released from their Guarantees (in the case of clause (9) of the provisions described under “— Amendment, Supplement and Waiver”), would constitute a Significant Subsidiary under clause (1) of this definition.

     “Subordinated Indebtedness”means Indebtedness of the Issuer or any Restricted Subsidiary that is expressly subordinated in right of payment to the Notes or the Note Guarantees, respectively.

     “Subsidiary”means, with respect to any Person:

(1) any corporation, limited liability company, association or other business entity of which more than 50% of the total voting power of the Equity Interests entitled (without regard to the occurrence of any contingency) to vote in the election of the Board of Directors thereof is at the time owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of such Person (or a combination thereof); and

(2) any partnership (a) the sole general partner or the managing general partner of which is such Person or a Subsidiary of such Person or (b) the only general partners of which are such Person or of one or more Subsidiaries of such Person (or any combination thereof).

      Unless otherwise specified, “Subsidiary” refers to a Subsidiary of the Issuer.

     “Subsidiary Guarantor”means any Guarantor that is a Subsidiary.

     “Trust Indenture Act”means the Trust Indenture Act of 1939, as amended.

     “Unrestricted Subsidiary”means (1) any Subsidiary that at the time of determination shall be designated an Unrestricted Subsidiary by the Board of Directors of the Issuer in accordance with the covenant described under “— Certain Covenants — Limitations on Designation of Unrestricted Subsidiaries” and (2) any Subsidiary of an Unrestricted Subsidiary.

     “U.S. Government Obligations”means direct non-callable obligations of, or guaranteed by, the United States of America for the payment of which guarantee or obligations the full faith and credit of the United States is pledged.

     “Voting Stock”with respect to any Person, means securities of any class of Equity Interests of such Person entitling the holders thereof (whether at all times or only so long as no senior class of stock or other relevant equity interest has voting power by reason of any contingency) to vote in the election of members of the Board of Directors of such Person.

     “Weighted Average Life to Maturity”when applied to any Indebtedness at any date, means the number of years obtained by dividing (1) the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payment of principal, including payment at final maturity, in respect thereof by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment by (2) the then outstanding principal amount of such Indebtedness.

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GLOBAL SECURITIES; BOOK-ENTRY SYSTEM

The Global Securities

      The notes will initially be represented by one or more permanent global notes in definitive, fully registered book-entry form (the “global securities”) which will be registered in the name of Cede & Co., as nominee of DTC, or such other name as may be requested by an authorized representative of DTC. The global notes will be deposited with the Trustee as custodian for DTC and may not be transferred except as a whole by DTC to a nominee of DTC or by a nominee of DTC to DTC or another nominee of DTC or by DTC or any nominee to a successor of DTC or a nominee of such successor.

      We expect that pursuant to procedures established by DTC (a) upon deposit of the global securities, DTC or its custodian will credit on its internal system portions of the global securities which will contain the corresponding respective amount of the global securities to the respective accounts of persons who have accounts with such depositary and (b) ownership of the notes will be shown on, and the transfer of ownership thereof will be affected only through, records maintained by DTC or its nominee (with respect to interests of participants (as defined below)) and the records of participants (with respect to interests of persons other than participants). Such accounts initially will be designated by or on behalf of the initial purchasers and ownership of beneficial interests in the global securities will be limited to persons who have accounts with DTC (the “participants”) or persons who hold interests through participants. Noteholders may hold their interests in a global security directly through DTC if they are participants in such system, or indirectly through organizations which are participants in such system.

      So long as DTC or its nominee is the registered owner or holder of any of the notes, DTC or such nominee will be considered the sole owner or holder of such notes represented by such global securities for all purposes under the indenture and under the notes represented thereby. No beneficial owner of an interest in the global securities will be able to transfer such interest except in accordance with the applicable procedures of DTC.

Certain Book-Entry Procedures for the Global Securities

      The operations and procedures of DTC is solely within the control of DTC and are subject to change by them from time to time. Investors are urged to contact the DTC or its participants directly to discuss these matters.

      DTC has advised us that it is:

• a limited purpose trust company organized under the laws of the State of New York;

• a “banking organization” within the meaning of the New York Banking Law;

• a member of the Federal Reserve System;

• a “clearing corporation” within the meaning of the New York Uniform Commercial Code, as amended; and

• a “clearing agency” registered pursuant to Section 17A of the Securities Exchange Act of 1934.

      DTC was created to hold securities for its participants (collectively, the “participants”) and to facilitate the clearance and settlement of securities transactions, such as transfers and pledges, between participants through electronic book-entry changes to the accounts of its participants, thereby eliminating the need for physical transfer and delivery of certificates. DTC’s participants include securities brokers and dealers (including the initial purchasers), banks and trust companies, clearing corporations and certain other organizations. DTC is a wholly owned subsidiary of The Depository Trust & Clearing Corporation, which is owned by a number of direct participants of DTC and by the New York Stock Exchange, Inc., the American Stock Exchange, LLC and the National Association of

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Securities Dealers, Inc. Indirect access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies (collectively, the “indirect participants”) that clear through or maintain a custodial relationship with a participant, either directly or indirectly. Investors who are not participants may beneficially own securities held by or on behalf of DTC only through participants or indirect participants. The rules applicable to DTC and its participants are on file with the SEC.

      The laws of some jurisdictions may require that some purchasers of securities take physical delivery of those securities in definitive form. Accordingly, the ability to transfer beneficial interests in notes represented by a global security to those persons may be limited. In addition, because DTC can act only on behalf of its participants, who in turn act on behalf of persons who hold interests through participants, the ability of a person holding a beneficial interest in a global security to pledge or transfer that interest to persons or entities that do not participate in DTC’s system, or to otherwise take actions in respect of that interest, may be affected by the lack of a physical security in respect of that interest.

      So long as DTC or its nominee is the registered owner of a global security, DTC or that nominee, as the case may be, will be considered the sole legal owner or holder of the notes represented by that global security for all purposes of the notes and the indenture. Except as provided below, owners of beneficial interests in a global security will not be entitled to have the notes represented by that global security registered in their names, will not receive or be entitled to receive physical delivery of certificated securities, and will not be considered the owners or holders of the notes represented by that beneficial interest under the indenture for any purpose, including with respect to the giving of any direction, instruction or approval to the Trustee. To facilitate subsequent transfers, all global securities that are deposited with, or on behalf of, DTC will be registered in the name of DTC’s nominee, Cede & Co. The deposit of global securities with, or on behalf of, DTC and their registration in the name of Cede & Co. effect no change in beneficial ownership. We understand that DTC has no knowledge of the actual beneficial owners of the securities. Accordingly, each holder owning a beneficial interest in a global security must rely on the procedures of DTC and, if that holder is not a participant or an indirect participant, on the procedures of the participant through which that holder owns its interest, to exercise any rights of a holder of notes under the indenture or that global security. We understand that under existing industry practice, in the event that we request any action of holders of notes, or a holder that is an owner of a beneficial interest in a global security desires to take any action that DTC, as the holder of that global security, is entitled to take, DTC would authorize the participants to take that action and the participants would authorize holders owning through those participants to take that action or would otherwise act upon the instruction of those holders.

      Conveyance of notices and other communications by DTC to its direct participants, by its direct participants to indirect participants and by its direct and indirect participants to beneficial owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time.

      Neither DTC nor Cede & Co. will consent or vote with respect to the global securities unless authorized by a direct participant under DTC’s procedures. Under its usual procedures, DTC will mail an omnibus proxy to us as soon as possible after the applicable record date. The omnibus proxy assigns Cede & Co.’s consenting or voting rights to those direct participants of DTC to whose accounts the securities are credited on the applicable record date, which are identified in a listing attached to the omnibus proxy.

      Neither we nor the Trustee will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial interests in the global securities by DTC, or for maintaining, supervising or reviewing any records of DTC relating to those beneficial interests.

      Payments with respect to the principal of and premium, if any, liquidated damages, if any, and interest on a global security will be payable by the Trustee to or at the direction of DTC or its nominee in its capacity as the registered holder of the global security under the Indenture. Under the terms of the Indenture, we and the Trustee may treat the persons in whose names the notes, including the global securities, are registered as the owners thereof for the purpose of receiving payment thereon

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and for any and all other purposes whatsoever. Accordingly, neither we nor the Trustee has or will have any responsibility or liability for the payment of those amounts to owners of beneficial interests in a global security. It is our understanding that DTC’s practice is to credit the direct participants’ accounts upon DTC’s receipt of funds and corresponding detail information from us or the Paying Agent on the applicable payment date in accordance with their respective holdings shown on DTC’s records. Payments by the participants and the indirect participants to the owners of beneficial interests in a global security will be governed by standing instructions and customary industry practice and will be the responsibility of the participants and indirect participants and not of DTC, us or the Trustee, subject to statutory or regulatory requirements in effect at the time.

      Transfers between participants in DTC will be effected in accordance with DTC’s procedures, and, except for trades involving only the Euroclear System as operated by Euroclear Bank S.A./ N.V., or Euroclear, or Clearstream Banking, S.A. of Luxembourg, or Clearstream Luxembourg, such transfers will be settled in same-day funds. Transfers between participants in Euroclear or Clearstream Luxembourg will be effected in the ordinary way in accordance with their respective rules and operating procedures.

      Cross-market transfers between the participants in DTC, on the one hand, and Euroclear or Clearstream Luxembourg participants, on the other hand, will be effected through DTC in accordance with DTC’s rules on behalf of Euroclear or Clearstream Luxembourg, as the case may be, by its respective depositary; however, those cross-market transactions will require delivery of instructions to Euroclear or Clearstream Luxembourg, as the case may be, by the counterparty in that system in accordance with the rules and procedures and within the established deadlines (Brussels time) of that system. Euroclear or Clearstream Luxembourg, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant global securities in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream Luxembourg participants may not deliver instructions directly to the depositaries for Euroclear or Clearstream Luxembourg.

      Because of time zone differences, the securities account of a Euroclear or Clearstream Luxembourg participant purchasing an interest in a global security from a participant in DTC will be credited, and any such crediting will be reported to the relevant Euroclear or Clearstream Luxembourg participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream Luxembourg) immediately following the settlement date of DTC. Cash received in Euroclear or Clearstream Luxembourg as a result of sales of interests in a global security by or through a Euroclear or Clearstream Luxembourg participant to a participant in DTC will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream Luxembourg cash account only as of the business day for Euroclear or Clearstream Luxembourg following DTC’s settlement date.

      Although DTC has agreed to the foregoing procedures to facilitate transfers of interests in the global securities among participants in DTC, it is under no obligation to perform or to continue to perform those procedures, and those procedures may be discontinued at any time. Neither we nor the Trustee will have any responsibility for the performance by DTC or its participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

Certificated Notes

      Notes in physical, certificated form will be issued and delivered to each person that DTC identifies as a beneficial owner of the related notes only if:

• DTC notifies us at any time that it is unwilling or unable to continue as depositary for the global notes and a successor depositary is not appointed within 90 days;

153

• DTC ceases to be registered as a clearing agency under the Exchange Act and a successor depositary is not appointed within 90 days;

• we, at our option, notify the Trustee that we elect to cause the issuance of certificated notes; or

• certain other events provided in the indenture should occur.

      We have provided the foregoing information with respect to DTC to the financial community for information purposes only. Although we obtained the information in this section and elsewhere in this prospectus concerning DTC and its book-entry system from sources that we believe are reliable, we take no responsibility for the accuracy of such information.

MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

      In the opinion of Andrews Kurth LLP, our legal counsel, the following are the material U.S. federal income tax considerations relevant to the exchange of new notes for old notes pursuant to the exchange offer. The discussion does not purport to be a complete analysis of all potential tax effects and is based upon the Internal Revenue Code of 1986, as amended, Treasury Regulations, Internal Revenue Service rulings and pronouncements and judicial decisions now in effect, all of which may be subject to change at any time by legislative, judicial or administrative action. These changes may be applied retroactively in a manner that could adversely affect a holder of new notes. The description does not consider the effect of any applicable foreign, state, local or other tax laws or estate or gift tax considerations.

      The exchange of new notes for old notes pursuant to the exchange offer will not be a taxable exchange for U.S. federal income tax purposes. A holder will not recognize any taxable gain or loss as a result of the exchange and will have the same tax basis and holding period in the new notes as the holder had in the old notes immediately before the exchange.

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PLAN OF DISTRIBUTION

      Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for 180 days after the consummation of the exchange offer, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until October 21, 2006, all dealers effecting transactions in the new notes may be required to deliver a prospectus.

      We will not receive any proceeds from any sale of new notes by broker-dealers. New notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in theover-the-counter market, in negotiated transactions, through the writing of options on the new notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such new notes. Any broker-dealer that resells new notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such new notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on any such resale of new notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The enclosed letter of transmittal states that, by acknowledging that it will deliver and be delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

      For a period of 180 days after the consummation of the exchange offer, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offer (including the expenses of one counsel for the holders of the notes) other than commissions or concessions of any brokers or dealers and will indemnify the holders of the old notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

      Following completion of the exchange offer, we may, in our sole discretion, commence one or more additional exchange offers to holders of old notes who did not exchange their old notes for new notes in the exchange offer on terms which may differ from those contained in this prospectus and the enclosed letter of transmittal. This prospectus, as it may be amended or supplemented from time to time, may be used by us in connection with any additional exchange offers. These additional exchange offers may take place from time to time until all outstanding old notes have been exchanged for new notes, subject to the terms and conditions in the prospectus and letter of transmittal distributed by us in connection with these additional exchange offers.

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LEGAL MATTERS

      The validity of the new notes and certain other matters will be passed upon for us by Andrews Kurth LLP, Houston, Texas.

EXPERTS

      The consolidated financial statements of Basic Energy Services, Inc. and subsidiaries as of December 31, 2004 and 2005, and for each of the years in the three-year period ended December 31, 2005, have been included in this prospectus and in the registration statement in reliance upon the report of KPMG LLP, an independent registered public accounting firm, appearing elsewhere in this prospectus, and upon the authority of said firm as experts in accounting and auditing. The audit report covering the December 31, 2005 consolidated financial statements refers to a change in the method of accounting for asset retirement obligations as of January 1, 2003.

WHERE YOU CAN FIND MORE INFORMATION

      We have filed with the SEC a registration statement on Form S-4, including exhibits and schedules, under the Securities Act with respect to the offer to exchange our senior notes. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the exchange offer, you may desire to review the full registration statement, including its exhibits. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington D.C. 20549. Copies of this material can also be obtained upon written request from the Public Reference Section of the SEC at prescribed rates, or accessed at the SEC’s website on the Internet athttp://www.sec.gov. Please call the SEC at1-800-SEC-0330 for further information on its public reference room. In addition, our future public filings can also be inspected and copied at the offices of the New York Stock Exchange, Inc., 20 Broad Street, New York, New York 10005.

      You should rely only on the information contained in this prospectus. We have not authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus only. Our business, financial condition, results of operations and prospects may have changed since that date.

      We file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. Our website on the Internet is located athttp://www.basicenergyservices.com, and we make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus. You may also request a copy of these filings at no cost, by writing or telephoning us at the following address: Basic Energy Services, Inc., Attention: Chief Financial Officer, 400 W. Illinois, Suite 800, Midland, Texas 79701, (432) 620-5500.

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

		Page
Audited Consolidated Financial Statements
	Report of Independent Registered Public Accounting Firm		F1-1
	Consolidated Balance Sheets as of December 31, 2005 and 2004		F1-2
	Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2005, 2004 and 2003		F1-3
	Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2005, 2004 and 2003		F1-4
	Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003		F1-5
	Notes to Consolidated Financial Statements		F1-6
	Financial Statement Schedule II — Valuation and Qualifying Accounts		F1-35
Unaudited Consolidated Financial Statements
	Consolidated Balance Sheet as of June 30, 2006		F2-1
	Consolidated Statements of Operations and Comprehensive Income for the six months ended June 30, 2006 and 2005		F2-2
	Consolidated Statements of Stockholders’ Equity for the six months ended June 30, 2006		F2-3
	Consolidated Statements of Cash Flows for the six months ended June 30, 2006 and 2005		F2-4
	Notes to Consolidated Financial Statements		F2-5

F-1

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, 2005 and 2004, 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, 2005. 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 schedules 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, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

      As discussed in Note 2 of the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations”.

KPMG LLP

Dallas, Texas

March 20, 2006

F1-1

Basic Energy Services, Inc.

Consolidated Balance Sheets

			December 31,
			2005			2004
			(in thousands,
			except share data)
ASSETS
Current assets:
	Cash and cash equivalents		$	32,845		$	20,147
	Trade accounts receivable, net of allowance of $2,775 and $3,108, respectively			86,932			56,651
	Accounts receivable — related parties			65			103
	Inventories			1,648			1,176
	Prepaid expenses			3,112			1,798
	Other current assets			2,060			2,454
	Deferred tax assets			6,020			4,899
		Total current assets		132,682			87,228
	Property and equipment, net			309,075			233,451
	Deferred debt costs, net of amortization			4,833			4,709
	Goodwill			48,227			39,853
	Other assets			2,140			2,360
			$	496,957		$	367,601
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable		$	13,759		$	11,388
	Accrued expenses			33,548			20,486
	Income taxes payable			7,210			—
	Current portion of long-term debt			7,646			11,561
	Other current liabilities			1,124			545
		Total current liabilities		63,287			43,980
Long-term debt				119,241			170,915
Deferred income				17			44
Deferred tax liabilities				53,770			30,247
Other long-term liabilities				2,067			629
Commitments and contingencies
Stockholders’ equity:
	Common stock; $.01 par value; 80,000,000 shares authorized; 33,931,935 shares issued, 33,785,359 shares outstanding at December 31, 2005 and 28,931,935 shares issued and outstanding at December 31, 2004, respectively			339			58
Additional paid-in capital				239,218			142,802
Deferred compensation				(7,341	)		(4,990	)
Retained earnings (deficit)				28,654			(16,127	)
Treasury stock, 146,576 shares at December 31, 2005, at cost				(2,531	)		—
Accumulated other comprehensive income				236			43
	Total stockholders’ equity			258,575			121,786
			$	496,957		$	367,601

See accompanying notes to consolidated financial statements.

F1-2

Basic Energy Services, Inc.

Consolidated Statements of Operations and Comprehensive Income

				Years Ended December 31
				2005			2004			2003
				(dollars in thousands, except per
				share amounts)
Revenues:
	Well servicing			$	221,993		$	142,551		$	104,097
	Fluid services				132,280			98,683			52,810
	Drilling and completion services				59,832			29,341			14,808
	Well site construction services				45,647			40,927			9,184
		Total revenues			459,752			311,502			180,899
Expenses:
	Well servicing				137,392			98,058			73,244
	Fluid services				82,551			65,167			34,420
	Drilling and completion services				30,900			17,481			9,363
	Well site construction services				32,000			31,454			6,586
	General and administrative, including stock-based compensation of $2,890, $1,587, and $994 in 2005, 2004 and 2003, respectively				55,411			37,186			22,722
	Depreciation and amortization				37,072			28,676			18,213
	(Gain) loss on disposal of assets				(222	)		2,616			391
		Total expenses			375,104			280,638			164,939
			Operating income		84,648			30,864			15,960
Other income (expense):
	Interest expense				(13,065	)		(9,714	)		(5,234	)
	Interest income				405			164			60
	Loss on early extinguishment of debt				(627	)		—			(5,197	)
	Other income (expense)				220			(398	)		146
Income from continuing operations before income taxes					71,581			20,916			5,735
Income tax expense					(26,800	)		(7,984	)		(2,772	)
Income from continuing operations					44,781			12,932			2,963
Discontinued operations, net of tax					—			(71	)		22
Cumulative effect of accounting change, net of tax					—			—			(151	)
Net income					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				$	44,781		$	12,861		$	(2,115	)
Basic earnings per share of common stock:
	Continuing operations			$	1.57		$	0.46		$	(0.09	)
	Discontinued operations				—			—			—
	Net income (loss) available to common stockholders			$	1.57		$	0.46		$	(0.09	)
Diluted earnings per share of common stock:
	Continuing operations			$	1.35		$	0.42		$	(0.09	)
	Discontinued operations				—			—			—
	Net income (loss) available to common stockholders			$	1.35		$	0.42		$	(0.09	)
Comprehensive Income:
Net income				$	44,781		$	12,861		$	2,834
Unrealized gains on hedging activities					193			43			—
Comprehensive Income:				$	44,974		$	12,904		$	2,834

See accompanying notes to consolidated financial statements.

F1-3

Basic Energy Services, Inc.

Consolidated Statements of Stockholders’ Equity

																	Accumulated
	Common Stock				Additional									Retained			Other		Total
					Paid-in			Deferred			Treasury			Earnings			Comprehensive		Stockholders’
	Shares		Amount		Capital			Compensation			Stock			(Deficit)			Income		Equity
	(in thousands, except share data)
Balance — December 31, 2002		20,368,610	$	41	$	97,294		$	—		$	—		$	(24,777	)	$	—	$	72,558
Exercise of EBITDA contingent warrants		771,740		2		—			—			—			—			—		2
EBITDA contingent warrants		—		—		3,571			—			—			(2,660	)		—		911
FESCO Holdings, Inc. acquisition		3,650,000		7		18,820			—			—			—			—		18,827
Stock-based compensation awards		—		—		380			(380	)		—			—			—		—
Amortization of deferred compensation		—		—		—			83			—			—			—		83
Preferred stock conversion to common stock		3,304,085		6		16,459			—			—			564			—		17,029
Accretion of preferred stock discount		—		—		—			—			—			(3,424	)		—		(3,424	)
Preferred stock dividends		—		—		—			—			—			(1,525	)		—		(1,525	)
Net income		—		—		—			—			—			2,834			—		2,834
Balance — December 31, 2003		28,094,435		56		136,524			(297	)		—			(28,988	)		—		107,295
Issuance of restricted stock and stock options		837,500		2		6,278			(6,280	)		—			—			—		—
Amortization of deferred compensation		—		—		—			1,587			—			—			—		1,587
Unrealized gain on interest rate swap agreement		—		—		—			—			—			—			43		43
Net income		—		—		—			—			—			12,861			—		12,861
Balance — December 31, 2004		28,931,935		58		142,802			(4,990	)		—			(16,127	)		43		121,786
Stock-based compensation awards		—		���		5,241			(5,241	)		—			—			—		—
Amortization of deferred compensation		—		—		—			2,890			—			—			—		2,890
Unrealized gain on interest rate swap agreement		—		—		—			—			—			—			193		193
Forfeited 11,250 shares at cost of $0		—		—		—			—			—			—			—		—
Effect of stock split		—		231		(231	)		—			—			—			—		—
Proceeds from common stock issuance, net of $2,044 of offering costs		5,000,000		50		91,406			—			—			—			—		91,456
Purchase of 135,326 of treasury stock		—		—		—			—			(2,531	)		—			—		(2,531	)
Net income		—		—		—			—			—			44,781			—		44,781
Balance — December 31, 2005		33,931,935	$	339	$	239,218		$	(7,341	)	$	(2,531	)	$	28,654		$	236	$	258,575

See accompanying notes to consolidated financial statements.

F1-4

Basic Energy Services, Inc.

Consolidated Statements of Cash Flows

					Years Ended December 31,
					2005			2004			2003
					(in thousands)
Cash flows from operating activities:
	Net income				$	44,781		$	12,861		$	2,834
		Adjustments to reconcile net income to net cash provided by operating activities:
			Depreciation and amortization			37,072			28,676			18,213
			Accretion on asset retirement obligation			42			33			28
			Change in allowance for doubtful accounts			(333	)		1,150			1,279
			Non-cash interest expense			1,062			970			694
			Non-cash compensation			2,890			1,587			994
			Loss on early extinguishment of debt			627			—			3,588
			(Gain) loss on disposal of assets			(222	)		2,616			391
			Deferred income taxes			18,301			7,984			2,840
			Other non-cash items			—			—			(11	)
			Non-cash effect of discontinued operations			—			—			13
			Cumulative effect of accounting change			—			—			151
	Changes in operating assets and liabilities, net of acquisitions:
			Accounts receivable			(27,577	)		(13,841	)		(12,120	)
			Inventories			(262	)		394			125
			Prepaid expenses and other current assets			304			446			(1,243	)
			Other assets			(49	)		(569	)		1,261
			Accounts payable			2,174			3,416			2,863
			Income tax payable			7,013			—			—
			Deferred income and other liabilities			374			127			(11	)
			Accrued expenses			12,992			689			7,926
				Net cash provided by operating activities		99,189			46,539			29,815
	Cash flows from investing activities:
			Purchase of property and equipment			(83,095	)		(55,674	)		(23,501	)
			Proceeds from sale of assets			2,436			2,484			660
			Payments for other long-term assets			(1,642	)		(1,113	)		(177	)
			Payments for businesses, net of cash acquired			(25,378	)		(19,284	)		(61,885	)
				Net cash used in investing activities		(107,679	)		(73,587	)		(84,903	)
	Cash flows from financing activities:
			Proceeds from debt			16,000			43,500			203,012
			Payments of debt			(81,924	)		(21,236	)		(115,603	)
			Proceeds from common stock, net of $2,044 of offering costs			91,456			—			—
			Purchase of treasury stock			(2,531	)		—			—
			Collections of notes receivable			—			—			9
			Proceeds from exercise of EBITDA contingent warrants			—			—			2
			Deferred loan costs and other financing activities			(1,813	)		(766	)		(7,561	)
				Net cash provided by financing activities		21,188			21,498			79,859
				Net increase (decrease) in cash and equivalents		12,698			(5,550	)		24,771
	Cash and cash equivalents — beginning of year					20,147			25,697			926
	Cash and cash equivalents — end of year				$	32,845		$	20,147		$	25,697

See accompanying notes to consolidated financial statements.

F1-5

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements

December 31, 2005, 2004, and 2003

1.     Nature of Operations and Basis of Presentation

          Organization and Restructuring

      Basic Energy Services, Inc. (predecessor entity), a Delaware corporation (“Historical Basic”) commenced operations in 1992. Effective January 24, 2003, Historical Basic changed its corporate structure to a holding company format. The purpose of this corporate restructuring was to provide greater operational, administrative and financial flexibility to Historical Basic, as well as improved economics. In connection with this restructuring, Historical Basic merged with a newly formed subsidiary of BES Holding Co. (“New Basic”), a Delaware corporation incorporated on January 7, 2003 as a wholly-owned subsidiary of New Basic. The merger was structured as a tax-free reorganization to Historical Basic stockholders. As a result of the merger, each share of outstanding common stock of Historical Basic was exchanged for one share of common stock of New Basic, and each share of outstanding Series A 10% Cumulative Preferred Stock of Historical Basic was exchanged for one share of Series A 10% Cumulative Preferred Stock of New Basic, and with respect to any accrued and unpaid dividends, shares of additional preferred stock with a liquidation preference equal to such accrued and unpaid dividends. Historical Basic survived the merger and was subsequently converted to a Delaware limited partnership now known as Basic Energy Services, L.P., which is currently an indirect wholly-owned subsidiary of New Basic. On April 2, 2004, BES Holding Co. changed its name to Basic Energy Services, Inc. Historical Basic prior to January 24, 2003 and New Basic thereafter are referred to in these Notes to Consolidated Financial Statements as “Basic.”

          Basis of Presentation

      The historical consolidated financial statements presented herein of Basic prior to its formation are the historical results of Historical Basic since the ownership of Basic and Historical Basic at the merger date were identical. The financial results of New Basic and Historical Basic are combined to present the consolidated financial statements of Basic.

          Nature of Operations

      Basic provides a range of well site services to oil and gas drilling and producing companies, including well servicing, fluid services, drilling and completion services and well site construction services. These services are primarily provided by Basic’s fleet of equipment. Basic’s operations are concentrated in the major United States onshore oil and gas producing regions in Texas, New Mexico, Oklahoma and Louisiana, and the Rocky Mountain states.

2.     Summary of Significant Accounting Policies

          Principles of Consolidation

      The accompanying consolidated financial statements include the accounts of Basic and its wholly-owned subsidiaries. Basic has no interest in any other organization, entity, partnership, or contract that could require any evaluation under FASB Interpretation No. 46R or Accounting Research Bulletin No. 51. All inter-company 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

F1-6

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

and assumptions that affect the reported amount of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Areas where critical accounting estimates are made by management include:

• Depreciation and amortization of property and equipment and intangible assets

• Impairment of property and equipment and goodwill

• Allowance for doubtful accounts

• Litigation and self-insured risk reserves

• Fair value of assets acquired and liabilities assumed

• Stock-based compensation

• Income taxes

• Asset retirement obligation

          Revenue Recognition

     Well Servicing — Well servicing consists primarily of maintenance services, workover services, completion services and plugging and abandonment services. Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Basic prices well servicing by the hour of service performed.

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

     Drilling and Completion Services — Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Basic prices drilling and completion services by the hour, day, or project depending on the type of service performed. When Basic provides multiple services to a customer, revenue is allocated to the services performed based on the fair values of the services.

     Well Site Construction Services — Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Basic prices well site construction services by the hour, day, or project depending on the type of service performed.

          Cash and Cash Equivalents

      Basic considers all highly liquid instruments purchased with a maturity of three months or less to be cash equivalents. Basic maintains its excess cash in various financial institutions, where deposits may exceed federally insured amounts at times.

F1-7

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

          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

      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 thefirst-in, first-out (“FIFO”) method.

          Property and Equipment

      Property and equipment are stated at cost, or at estimated fair value at acquisition date if acquired in a business combination. Expenditures for repairs and maintenance are charged to expense as incurred and additions and improvements that significantly extend the lives of the assets are capitalized. Upon sale or other retirement of depreciable property, the cost and accumulated depreciation and amortization are removed from the related accounts and any gain or loss is reflected in operations. All property and equipment are depreciated or amortized (to the extent of estimated salvage values) on the straight-line method and the estimated useful lives of the assets are as follows:

Building and improvements	20-30 years
Well servicing rigs and equipment	3-15 years
Fluid service equipment	5-10 years
Brine/fresh water stations	15 years
Frac/test tanks	10 years
Pressure pumping equipment	5-10 years
Construction equipment	3-10 years
Disposal facilities	10-15 years
Vehicles	3-7 years
Rental equipment	3-15 years
Software and computers	3 years
Aircraft	20 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

F1-8

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

which the carrying amount of such assets exceeds the fair value of the assets. Assets to be disposed of would be separately presented in the consolidated balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated. The assets and liabilities, if material, of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the consolidated balance sheet.

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

      Basic had no impairment expense in 2005, 2004 or 2003.

          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 straight line method which approximates the effective interest method over the terms of the related debt.

      Deferred debt costs of approximately $7.0 million at December 31, 2005 and $5.8 million at December 31, 2004, respectively, represent debt issuance costs and are recorded net of accumulated amortization of $2.2 million, and $1.1 million at December 31, 2005 and December 31, 2004, respectively. Amortization of deferred debt costs totaled approximately $1,062,000, $907,000 and $694,000 for the years ended December 31, 2005, 2004 and 2003, respectively.

      In 2005, Basic recognized a loss on early extinguishment of debt related to deferred debt costs. (See note 5)

          Goodwill

      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 non-compete agreements. Amortization expense for the non-compete agreements is calculated using the straight-line method over the period of the agreement, ranging from three to five years. The weighted average amortization period for non-compete agreements acquired during 2005 and 2004 is 60 months.

      The gross carrying amount of non-compete agreements subject to amortization totaled approximately $2.7 million and $3.7 million at December 31, 2005 and 2004, respectively. Accumulated amortization related to these intangible assets totaled approximately $1.6 and $2.4 million at

F1-9

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

December 31, 2005 and 2004, respectively. Amortization expense for the years ended December 31, 2005, 2004 and 2003 was approximately $519,000, $457,000, and $364,000, respectively. Amortization expense for the next five succeeding years is estimated to be approximately $461,000, $325,000, $223,000, $122,000, and $22,000 in 2006, 2007, 2008, 2009, and 2010 respectively.

      Basic has identified its reporting units to be well servicing, fluid services, drilling and completion services and well site construction services. The goodwill allocated to such reporting units as of December 31, 2005 is $9.9 million, $20.6 million, $14.0 million and $3.7 million, respectively. The change in the carrying amount of goodwill for the year ended December 31, 2005 of $8.4 million relates to goodwill from acquisitions and payments pursuant to contingent earn-out agreements, with approximately $1.1 million, $2.2 million and $5.1 million of goodwill additions relating to the well servicing, fluid services and drilling and completion units, respectively.

          Stock-Based Compensation

      Basic accounts for stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25,“Accounting for Stock Issued to Employees”(“APB No. 25”). Accordingly, Basic has adopted the disclosure provisions of Statement of Financial Accounting Standards No. 123,“Accounting for Stock-Based Compensation”(“SFAS No. 123”).

      Statement of Financial Accounting Standards No. 123,“Accounting for Stock-Based Compensation”(“SFAS No. 123”) sets forth alternative accounting and disclosure requirements for stock-based compensation arrangements. Companies may continue to follow the provisions of APB No. 25 to measure and recognize employee stock-based compensation; however, SFAS No. 123 requires disclosure of pro forma net income and earnings per share that would have been reported under the fair value based recognition provisions of SFAS No. 123. The following table illustrates the effect on net income if Basic had applied the fair value recognition provisions of SFAS No. 123 to stock-based employee compensation.

		Years Ended December 31,
		2005			2004			2003
Net income (loss) available to common stockholders — as reported		$	44,781		$	12,861		$	(2,115	)
Add: Stock-based employee compensation expense included in statement of operations, net of tax			1,806			986			523
Deduct: Stock-based employee compensation expense determined under fair-value based method for all awards, net of tax			(2,231	)		(1,283	)		(779	)
Net income available to common stockholders — pro forma basis		$	44,356		$	12,564		$	(2,371	)
Basic earnings per share of common stock:
	As reported	$	1.57		$	0.46		$	(0.09	)
	Pro forma	$	1.55		$	0.45		$	(0.11	)
Diluted earnings per share of common stock:
	As reported	$	1.35		$	0.42		$	(0.09	)
	Pro forma	$	1.34		$	0.41		$	(0.11	)

F1-10

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

      Under SFAS No. 123, the fair value of each stock option grant is estimated on the date of grant using the Black-Scholes-Merton option pricing model with the following weighted average assumptions used for grants during the years ended December 31, 2005, 2004, and 2003:

	2005			2004			2003
Risk-free interest rate		4.5	%		4.4	%		2.9	%
Expected life		9.9			10.0			10.0
Expected volatility		0.5	%		0.0	%		0.0	%
Expected dividend yield		—			—			—

          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.

          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 2005, 2004, or 2003.

          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.

F1-11

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

      Basic had no derivative contacts in 2003. 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 are initially recorded in other comprehensive income, then recognized in income in the same period(s) in which the hedged transaction affects income. Ineffective portions of a cash flow hedging derivative’s change in fair value are recognized currently in earnings. Basic had no ineffectiveness related to its cash flow hedge in 2005 or 2004.

          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 on 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. On January 1, 2003, Basic recorded additional costs, net of accumulated depreciation of approximately $102,000, an asset retirement obligation of approximately $340,000, and an after-tax charge of approximately $151,000 for the cumulative effect on prior year’s depreciation of the additional costs and the accretion expense on the liability related to the expected abandonment costs.

      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, 2005 and 2004 (in thousands):

Balance, December 31, 2003	$	415
Additional asset retirement obligations recognized through acquisitions		36
Accretion expense		33
Settlements		(11	)
Balance, December 31, 2004	$	473
Additional asset retirement obligations recognized through acquisitions		74
Accretion expense		42
Settlements		(20	)
Balance, December 31, 2005	$	569

The pro forma net income (loss) and related per share amounts assuming SFAS no. 143 had been applied in 2003 are as follows (in thousands, except per share data):

		2003
Pro forma net income (loss) available to common shareholders(a)		$	(1,964	)
Pro forma earnings per share of common stock Basic
	Basic	$	(0.09	)
	Diluted	$	(0.09	)

(a) The net income available to common stockholders in 2003 has been adjusted to remove the $151,000 cumulative effect of accounting change attributable to SFAS No. 143.

F1-12

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

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

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

F1-13

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

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

3.     Acquisitions

      In 2005, 2004 and 2003, 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)
New Force Energy Services		January 27, 2003	$	7,665
S & S Bulk Cement		April 17, 2003		195
Briscoe Oil Tools		June 13, 2003		260
FESCO Holdings, Inc.(a)		October 3, 2003		19,093
PWI, Inc.		October 3, 2003		25,104
Pennant Service Company		October 3, 2003		7,387
Graham Acidizing		December 1, 2003		2,181
Total 2003			$	61,885
Action Trucking — Curtis Smith, Inc.		April 27, 2004	$	821
Rolling Plains		May 30, 2004		3,022
Perry’s Pump Service		May 30, 2004		1,379
Lone Tree Construction		June 23, 2004		211
Hayes Services		July 1, 2004		1,595
Western Oil Well		July 30, 2004		854
Summit Energy		August 19, 2004		647
Energy Air Drilling		August 30, 2004		6,500
AWS Wireline		November 1, 2004		4,255
Total 2004			$	19,284
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

(a) This acquisition was funded through the issuance of Basic’s common stock. The total cash paid represents the retirement of debt at closing and transaction costs incurred net of the cash acquired.

F1-14

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

      The operations of each of the acquisitions listed above are included in Basic’s statement of operations as of each respective closing date. The acquisitions of New Force Energy Services (“New Force”), FESCO Holding, Inc. (“FESCO”) and PWI, Inc. and certain other affiliated entities (“PWI”) in 2003 are deemed significant and discussed below in further detail.

          New Force Energy Services

      On January 27, 2003, Basic acquired substantially all of the assets of New Force for $7.7 million plus a $2.7 million contingent earn-out payment. The contingent earn-out payment will be paid upon the New Force assets meeting certain financial objectives in the future. The preliminary cash cost of the New Force acquisition was $7.7 million (including other direct acquisition costs) which was allocated $6.3 million to property and equipment, $1.3 million to goodwill, $105,000 to inventory and $10,000 to non-compete agreements.

          FESCO Holdings, Inc.

      On October 3, 2003, Basic acquired all the capital stock of FESCO. As consideration for the acquisition of FESCO, Basic issued 3,650,000 shares of its common stock, based on an estimated fair value of the stock of $5.16 per share (a total fair value of approximately $18.8 million), and paid approximately $19.1 million in net cash at the closing, representing the retirement of debt of FESCO at closing and the payment of transaction costs incurred, net of the cash held by FESCO. In addition to assuming the working capital of FESCO, Basic incurred other direct acquisition costs and assumed certain other liabilities of FESCO, resulting in Basic recording an aggregate purchase price of approximately $37.9 million. The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):

Current assets, excluding cash		$	12,855
Property and equipment			32,344
Other assets			38
	Total assets acquired		45,237
Current liabilities			5,592
Deferred tax liability			1,725
	Total liabilities assumed		7,317
Net assets acquired		$	37,920

          PWI, Inc.

      On October 3, 2003, Basic acquired substantially all the assets of PWI for $25.1 million plus a $2.5 million contingent earn-out payment. The contingent earn-out agreement was terminated by the parties entering into an agreement to pay $75,000 per year for four years beginning in October 2005. The cash cost of the PWI acquisition was $25.1 million (including other direct acquisition costs) which was allocated $16.4 million to property and equipment, $8.6 million to goodwill, $250,000 to non-compete agreements and $200,000 to liabilities assumed.

          Contingent Earn-out Arrangements and Final Purchase Price Allocations

      Contingent earn-out arrangements are generally arrangements entered in certain acquisitions to encourage the owner/manager to continue operating and building the business after the purchase transaction. The contingent earn-out arrangements of the related acquisitions are generally linked to certain financial measures and performance of the assets acquired in the various acquisitions. All

F1-15

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

amounts paid or reasonably accrued for related to the contingent earn-out payments are reflected as increases to the goodwill associated with the acquisition.

      The following presents a summary of acquisitions that have a contingent earn-out arrangement in effect as of December 31, 2005 (in thousands):

	Termination		Maximum
	Date of		Exposure of
	Contingent		Contingent		Amount Paid or
	Earn-out		Earn-out		Accrued Through
Acquisition	Arrangement		Arrangement		December 31, 2005
Advantage Services, Inc.		October 9, 2005	$	250	$	219
New Force Energy Services		January 27, 2008		2,700		1,639
S&S Bulk Cement		April 20, 2008		115		115
Briscoe Oil Tools		June 12, 2008		125		82
Rolling Plains		April 30, 2009		*		588
Premier Vacuum Services, Inc.		February 1, 2010		900		226
			$	4,090	$	2,869

*  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

      The following unaudited pro forma results of operations have been prepared as though the New Force, FESCO and PWI acquisitions had been completed on January 1, 2003. Pro forma amounts are based on the final purchase price allocations of the significant acquisitions and are not necessarily indicative of the results that may be reported in the future (in thousands, except per share data).

	Year Ended
	December 31, 2003
	(unaudited)
Revenues	$	228,059
Income (loss) from continuing operations less preferred stock dividends and accretion	$	(1,182	)
Earnings per common share — basic	$	(0.05	)
Earnings per common share — diluted	$	(0.05	)

      Basic does not believe the pro-forma effect of the remainder of the acquisitions completed in 2003, 2004, or 2005 is material, either individually or when aggregated, to the reported results of operations.

F1-16

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

4.     Property and Equipment

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

	December 31,		December 31,
	2005		2004
Land	$	1,902	$	1,573
Buildings and improvements		8,634		6,615
Well service units and equipment		199,070		138,957
Fluid services equipment		59,104		53,111
Brine and fresh water stations		7,746		7,722
Frac/test tanks		31,475		19,707
Pressure pumping equipment		31,101		14,971
Construction equipment		24,224		21,964
Disposal facilities		16,828		14,079
Vehicles		23,329		18,881
Rental equipment		6,519		4,885
Aircraft		3,236		3,335
Other		8,602		7,780
		421,770		313,580
Less accumulated depreciation and amortization		112,695		80,129
Property and equipment, net	$	309,075	$	233,451

      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,
	2005		2004
Light vehicles	$	17,912	$	12,993
Fluid services equipment		14,011		10,558
Construction equipment		1,300		840
		33,223		24,391
Less accumulated amortization		8,474		7,201
	$	24,749	$	17,190

      Amortization of assets held under capital leases of approximately $1.8 million, $1.8 million, and $2.5 million for the years ended December 31, 2005, 2004, and 2003, respectively, is included in depreciation and amortization expense in the consolidated statements of operations.

F1-17

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

5.     Long-Term Debt

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

		December 31,		December 31,
		2005		2004
Credit Facilities:
	Term B Loan	$	90,000	$	166,500
	Revolver		16,000		—
Capital leases and other notes			20,887		15,976
			126,887		182,476
Less current portion			7,646		11,561
		$	119,241	$	170,915

          2005 Credit Facility

      On December 15, 2005, Basic entered into a $240 million Third Amended and Restated Credit Agreement with a syndicate of lenders (“2005 Credit Facility”) which refinanced all of its then existing credit facilities. The 2005 Credit Facility provides for a $90 million Term B Loan (“2005 Term B Loan”) and a $150 million revolving line of credit (“Revolver”). The commitment under the Revolver allows for (a) the borrowing of funds (b) issuance of up to $20 million of letters of credit and (c) $2.5 million of swing-line loans (next day borrowing). The amounts outstanding under the 2005 Term B Loan require quarterly amortization at various amounts during each quarter with all amounts outstanding on December 15, 2011 being due and payable in full. All the outstanding amounts under the Revolver are due and payable on December 15, 2010. The 2005 Credit Facility is secured by substantially all of Basic’s tangible and intangible assets. Basic incurred approximately $1.8 million in debt issuance costs in obtaining the 2005 Credit Facility.

      At Basic’s option, borrowings under the 2005 Term B Loan bear interest at either the (a) “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus .5% per annum) plus 1% or (b) the LIBOR rate plus 2.0%. At December 31, 2005, Basic’s weighted average interest rate on its Term B Loan was 6.4%.

      At Basic’s option, borrowings under the 2005 Revolver bear interest at either the (a) “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus .5% per annum) plus a margin ranging from .50% to 1.25% or (b) the LIBOR rate plus a margin ranging from 1.5% to 2.25%. The margins vary depending on Basic’s leverage ratio. At December 31, 2005, Basic’s margin on Alternative Base Rates and LIBOR tranches was .75% and 1.75%, respectively. Fees on the letters of credit are due quarterly on the outstanding amount of the letters of credit at a rate ranging from 1.5% to 2.25% for participation fees and .125% for fronting fees. A commitment fee is due quarterly on the available borrowings under the Revolver at rates ranging from .375% to .5%.

      At December 31, 2005 Basic, under its Revolver, had outstanding $16 million of borrowings and $9.6 million of letters of credit and no amounts outstanding in swing-line loans. At December 31, 2005 Basic had availability under its Revolver of $124.4 million.

      Pursuant to the 2005 Credit Facility, Basic must apply proceeds to reduce principal outstanding under the 2005 Term B Revolver from (a) individual assets sales greater than $2 million or $7.5 million in the aggregate on an annual basis, and (b) 50% of the proceeds from any equity offering. The 2005 Credit Facility required Basic to enter into an interest rate hedge, acceptable to the lenders, through

F1-18

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

May 28, 2006 on at least $65 million of Basic’s then outstanding indebtedness. Paydowns on the 2005 Term B Loan may not be reborrowed.

      The 2005 Credit Facility contains various restrictive covenants and compliance requirements, which include (a) limiting of the incurrence of additional indebtedness, (b) restrictions on mergers, sales or transfers of assets without the lenders’ consent, (c) limitation on dividends and distributions and (d) various financial covenants, including (1) a maximum leverage ratio of 3.5 to 1.0 reducing over time to 3.25 to 1.0, (2) a minimum interest coverage ratio of 3.0 to 1.0 and (e) limitations on capital expenditures in any period of four consecutive quarters in excess of 20% of Consolidated Net Worth unless certain criteria are met. At December 31, 2005 and December 31, 2004, Basic was in compliance with its covenants.

          2004 Credit Facility

      On December 21, 2004, Basic entered into a $220 million Second Amended and Restated Credit Agreement with a syndicate of lenders (“2004 Credit Facility”) which refinanced all of its then existing credit facilities. The 2004 Credit Facility provided for a $170 million Term B Loan (“2004 Term B Loan”) and a $50 million revolving line of credit (“2004 Revolver”). The commitment under the 2004 Revolver allowed for (a) the borrowing of funds (b) issuance of up to $20 million of letters of credit and (c) $2.5 million of swing-line loans (next day borrowing). The amounts outstanding under the 2004 Term B Loan required quarterly amortization at various amounts during each quarter with all amounts outstanding on October 3, 2009 being due and payable in full. All the outstanding amounts under the 2004 Revolver were due and payable on October 3, 2008. The 2004 Credit Facility was secured by substantially all of Basic’s tangible and intangible assets. Basic incurred approximately $766,000 in debt issuance costs in obtaining the 2004 Credit Facility.

      At Basic’s option, borrowings under the 2004 Term B Loan bore interest at either (a) the “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus .5% per annum) plus 2% or (b) LIBOR plus 3%. At December 31, 2004, Basic’s weighted average interest rate on its 2004 Term B Loan was 5.5%.

      At Basic’s option, borrowings under the 2004 Revolver bore interest at either the (a) the “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus .5% per annum) plus a margin ranging from 1.5% to 2.0% or (b) the LIBOR rate plus a margin ranging from 2.5% to 3.0%. The margins varied depending on Basic’s leverage ratio. At December 31, 2004, Basic’s margin on Alternative Base Rates and LIBOR tranches was 2.0% and 3.0%, respectively. Fees on the letters of credit were due quarterly on the outstanding amount of the letters of credit at a rate ranging from 2.5% to 3.0% for participation fees and .125% for fronting fees. A commitment fee was due quarterly on the available borrowings under the 2004 Revolver at rates ranging from .375% to .5%.

      At December 31, 2004, Basic, under its 2004 Revolver, had outstanding $8.3 million of letters of credit and no amounts outstanding in swing-line loans. At December 31, 2004, Basic had availability under its 2004 Revolver of $41.7 million.

          2003 Credit Facility

      On October 3, 2003, Basic entered into a $170 million credit facility with a syndicate of lenders (“2003 Credit Facility”) which refinanced all of its then existing credit facilities. The 2003 Credit Facility provided for a $140 million Term B Loan (“2003 Term B Loan”) and a $30 million revolving line of credit (“2003 Revolver”). The commitment under the 2003 Revolver allowed for (a) the borrowing of funds (b) issuance of up to $10 million of letters of credits and (c) $2.5 million of swing-line loans (next day borrowing). The amounts outstanding under the 2003 Term B Loan required quarterly amortization at

F1-19

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

various amounts during each quarter with all amounts outstanding on October 3, 2009 being due and payable in full. All the outstanding amounts under the 2003 Revolver were due and payable on October 3, 2008. The 2003 Credit Facility was secured by substantially all of Basic’s tangible and intangible assets. Basic incurred approximately $5.1 million in debt issuance costs in obtaining the 2003 Credit Facility.

      At Basic’s option, borrowings under the 2003 Term B Loan bore interest at either (a) the “Alternative Base Rate” (i.e. the higher of the bank’s prime rate of the federal funds rate plus .5% per annum) plus 2.5% or (b) the LIBOR rate plus 3.5%. At December 31, 2003, Basic’s weighted average interest rate on its 2003 Term B Loan was 4.67%.

      At Basic’s option, borrowings under the 2003 Revolver bore interest at either the (a) the “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus .5% per annum) plus a margin ranging from 1.5% to 2.0% or (b) the Libor rate plus a margin ranging from 2.5% to 3.0%. The margins varied depending on Basic’s leverage ration. At December 31, 2003, Basic’s margin on Alternative Base Rates and LIBOR tranches was 2.0% and 3.0%, respectively. Fees on the letters of credit were due quarterly on the outstanding amount of the letters of credit at a rate ranging from 2.5% to 3.0% for participations fees and .125% for fronting fees. A commitment fee was due quarterly on the available borrowings under the 2003 Revolver at rates ranging from .5% to .375%.

      At December 31, 2003, Basic, under its 2003 Revolver, had $5.3 million of outstanding letters of credit and no amounts outstanding in swing-line loans. At December 31, 2003, Basic had availability under its 2003 Revolver of $24.7 million.

          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, 2005, the aggregate maturities of debt, including capital leases, for the next five years and thereafter are as follows (in thousands):

	Debt		Capital Leases
2006	$	1,000	$	6,646
2007		1,000		6,024
2008		1,000		5,118
2009		1,000		2,713
2010		17,000		386
Thereafter		85,000		—
	$	106,000	$	20,887

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

	Year Ended December 31,
	2005		2004		2003
Cash payments for interest	$	11,421	$	8,159	$	3,934
Commitment and other fees paid		185		25		109
Amortization of debt issuance costs		1,062		970		694
Other		397		560		497
	$	13,065	$	9,714	$	5,234

F1-20

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

          Losses on Extinguishment of Debt

      In 2005, Basic recognized a loss on the early extinguishment of debt. Basic wrote-off unamortized debt issuance costs of approximately $627,000.

      In 2003, Basic recognized a loss on the early extinguishment of debt. Basic paid termination fees of approximately $1.7 million and wrote-off unamortized debt issuance costs of approximately $3.5 million which resulted in a loss of approximately $5.2 million.

      In 2003, Basic adopted Statement of Financial Accounting Standards No. 145 “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections” (“SFAS No. 145”). The provisions of SFAS No. 145, which are currently applicable to Basic, rescind Statement No. 4, which required all gains and losses from extinguishment of debt to be aggregated and classified as an extraordinary item, and instead require that such gains and losses be reported as ordinary income or loss. Basic now records gains and losses from the extinguishment of debt as ordinary income or loss.

6.     Income Taxes

      Income tax provision (benefit) was allocated as follows (in thousands):

	Years Ended December 31,
	2005		2004			2003
Income from continuing operations	$	26,800	$	7,984		$	2,772
Discontinued operations		—		(38	)		13
Cumulative effect of accounting change		—		—			(88	)
	$	26,800	$	7,946		$	2,697

      Income tax expense (benefit) attributable to income (loss) from continuing operations consists of the following (in thousands):

	Years Ended December 31,
	2005		2004		2003
Current	$	8,499	$	—	$	(68	)
Deferred		18,301		7,984		2,840
	$	26,800	$	7,984	$	2,772

      Basic paid federal income taxes of $1,325,000 during 2005. No federal income taxes were paid or received in 2004. In 2003 Basic received an income tax refund, net, of approximately $1.5 million.

F1-21

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

      Reconciliation between the amount determined by applying the federal statutory rate of 35% to the income (loss) from continuing operations with the provision (benefit) for income taxes is as follows (in thousands):

	Years Ended December 31,
	2005		2004			2003
Statutory federal income tax	$	25,053	$	7,321		$	2,007
Meals and entertainment		324		265			166
State taxes, net of federal benefit		1,415		421			138
Change in tax rates		—		—			542
Changes in estimates and other		8		(23	)		(81	)
	$	26,800	$	7,984		$	2,772

      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,
			2005			2004
Current deferred taxes:
	Receivables allowance		$	1,025		$	1,148
	Interest rate derivative			(186	)		—
	EBITDA contingent warrants			—			337
	Accrued liabilities			5,181			3,414
		Net current deferred tax asset	$	6,020		$	4,899
Noncurrent deferred taxes:
	Operating loss and tax credit carryforwards		$	1,856		$	20,782
	Property and equipment			(55,768	)		(51,194	)
	Goodwill and intangibles			(1,208	)		(602	)
	Deferred Compensation			1,140			617
	Asset retirement obligation			210			175
	Other			—			(25	)
		Net noncurrent deferred tax liability	$	(53,770	)	$	(30,247	)

      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, 2005 or 2004.

      As of December 31, 2005, Basic had approximately $4.9 million of net operating loss carryforwards (“NOL”) for U.S. federal income tax purposes related to the preacquisition period of FESCO, which are subject to an annual limitation of approximately $900,000. The carryforwards begin to expire in 2017.

7.     Commitments and Contingencies

          Environmental

      Basic is subject to various federal, state and local environmental laws and regulations that establish standards and requirements for protection of the environment. Basic cannot predict the future impact of such standards and requirements which are subject to change and can have retroactive effectiveness. Basic continues to monitor the status of these laws and regulations. Management

F1-22

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

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.

      On September 3, 2004, a group of plaintiffs commenced a civil action against Basic in the District Court of Panola County, Texas, 123rd Judicial District. The complaint alleges that Basic’s operation of a saltwater disposal well has contaminated both the groundwater and the soil in the surrounding area. The relief requested in the complaint is monetary damages, injunctive relief, environmental remediation and a court order requiring Basic to provide drinking water to the community. In response to the complaint, Basic has retained counsel and filed a general denial. Basic is in the beginning stages of discovery and settlement negotiations are underway. Should negotiations fail, Basic intends to defend itself vigorously in this action.

      On October 18, 2005, a group of plaintiffs commenced a civil action against Basic in the 123rd Judicial District Court of Panola County, Texas. The factual basis for this complaint and relief claims that Basic’s operation of a saltwater disposal well has contaminated both the groundwater and the soil in the surrounding area. In addition, this complaint alleges a wrongful death and personal injuries to unspecified persons. In response to this complaint, Basic has retained counsel and intends to defend itself vigorously in this action.

      On July 25, 2005, a jury returned a verdict in favor of a salt water disposal operator who had filed suit against Basic. The jury awarded the plaintiff $1.2 million in damages. Basic’s insurance company denied coverage of liability. Basic believes that it has reached a settlement of this matter in connection with a mediation in March 2006 for $1.0 million. As of December 31, 2005, Basic accrued a $1.0 million loss for this contingency.

          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.

F1-23

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

      As of December 31, 2005, the future minimum lease payments under non-cancelable operating leases are as follows (in thousands):

Year Ended December 31,
2006	$	1,198
2007		816
2008		724
2009		570
2010		428
Thereafter		463

      Rent expense approximated $7.0 million, $5.6 million, and $3.0 million for 2005, 2004, and 2003, respectively.

      Basic leases rights for the use of various brine and fresh water wells and disposal wells ranging in terms frommonth-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 March 1, 2004 through February 2007, Mr. Huseman will be entitled to an annual salary of $325,000 and an annual bonus ranging from $50,000 to $325,000 based on the level of performance objectives achieved by Basic. Under this employment agreement, Mr. Huseman is eligible from time to time to receive grants of stock options and other long-term equity incentive compensation under our Amended and Restated 2003 Incentive Plan. In addition, upon a qualified termination of employment, Mr. Huseman would be entitled to three times his base salary plus his current annual incentive target bonus for the full year in which the termination of employment occurred. Similarly, following a change of control of Basic, Mr. Huseman would be entitled to a lump sum payment of two times his base salary plus his current annual incentive target bonus for the full year in which the change of control occurred.

      Basic has entered into employment agreements with various other executive officers of Basic that range in term up through 2007. Under these agreements, if the officer’s employment is terminated for certain reasons, he would be entitled to a lump sum severance payment equal to six months annual salary, or 12 to 36 months’ annual salary if termination is on or following a change of control of Basic.

          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 its24-hour workover rigs and newly manufactured rigs. Basic has deductibles per occurrence for workers’ compensation and medical and dental coverage of $150,000 and $125,000, 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 historical claims history.

      At December 31, 2005 and December 31, 2004, self-insured risk accruals, net of related recoveries/receivables totaled approximately $9.5 million and $6.6 million, respectively.

F1-24

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

8. Mandatorily Redeemable Preferred Stock and Stockholders’ Equity

          Common Stock

      In February 2002, a group of related investors purchased a total of 3,000,000 shares of Basic’s common stock at a purchase price of $4 per share, for a total purchase price of $12 million. As part of the purchase, 600,000 common stock warrants were issued in connection with this transaction, the fair value of which was approximately $1.2 million (calculated using an option valuation model). The warrants allow the holder to purchase 600,000 shares of Basic’s common stock at $4 per share. The warrants are exercisable in whole or in part after June 30, 2002 and prior to February 13, 2007.

      In May 2003, the holders of the exercisable EBITDA Contingent Warrants purchased 771,740 shares of Basic’s common stock as a price of $.01 per share. See note 11. In October, 2003 Basic issued 3,650,000 shares of its common stock to acquire all the capital sock of FESCO. See note 3.

      In February 2004, Basic granted certain officers and directors 837,500 restricted shares of common stock. The shares vest 25% per year for four years from the award date and are subject to other vesting and forfeiture provisions. The estimated fair value of the restricted shares was $5.8 million at the date of the grant and was recorded as deferred compensation, a component of stockholders’ equity. This amount is being charged to expense over the respective vesting period and totaled approximately $1.6 million and $1.3 million for the years ended December 31, 2005 and 2004, respectively.

      On August 3, 2005, the board of directors of Basic approved a resolution to effect a5-for-1 stock split of the Company’s common stock in the form of a stock dividend resulting in 28,931,935 shares of common stock outstanding, and to amend the Company’s certificate of incorporation to increase the authorized common stock to 80,000,000 shares. The earnings per share information and all common stock information have been retroactively restated for all periods presented to reflect this stock split. On September 22, 2005 the pricing committee set the record date and distribution date for the stock dividend, and the stock dividend was paid on September 26, 2005 to holders of record on September 23, 2005. The Company retained the current par value of $.01 per share for all common shares.

      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.

          Preferred Stock

      In June 2002, Basic issued 150,000 shares of mandatorily redeemable Series A 10% Cumulative Preferred Stock (“Series A Preferred Stock”) to a group of investors for $15 million or $100 per share. After deducting fees, this resulted in net proceeds to Basic totaling approximately $14.9 million.

      Dividends on each share of Series A Preferred Stock accrued on a daily basis at the rate of 10% per annum of the sum of the Liquidation Value ($100) thereof plus all accrued and unpaid dividends thereon from and including the date of issuance of such share. All dividends which had accrued on the Series A Preferred Stock were payable on March 31, June 30, September 30 and December 31 of each year, beginning September 30, 2002. all dividends which had accrued on Series A shares outstanding remained as accumulated dividends until paid to the holders thereof.

      Basic could redeem all or any portion of the Series A Preferred Stock by paying a price per share equal to the Liquidation Value ($100) plus all accrued and unpaid dividends plus a premium equal to

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BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

1% of the sum of the Liquidation Value plus all accrued and unpaid dividends on or prior to March 31, 2008. Basic was required to redeem all Series A Preferred Stock on March 31, 2008 (including accrued and unpaid dividends).

      The difference between the $15 million face value of the Series A Preferred Stock and ultimate redemption value of approximately $26,975,000 (assuming Basic paid no dividends in cash prior to redemption) was being accreted to the face value of the Series A Preferred Stock from the date of issuance to the mandatory redemption date of March 31, 2008 utilizing the effective interest method.

      In connection with the Series A Preferred Stock financing transaction, 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 to the holders of Series A Preferred Stock, the relative fair value of which (the initial fair value was approximately $5.9 million, calculated using an option valuation model, and the relative fair value was approximately $4.4 million) was recorded as a discount on the Series A Preferred and included in additional pain-in capital. The Series A Preferred Stock discount, consisting of the warrant fair value of $4.3 million and $58,000 of offering expenses, was being accreted to the Series A Preferred Stock face value from the date of issuance to the mandatory redemption date of March 31, 2008 utilizing the effective interest method.

      In January 2003, Basic issued an additional 9,020 shares of Series A Preferred Stock in lieu of cash of approximately $902,000 for accrued dividends on the Series A Preferred Stock.

      On October 3, 2003, all the Series A Preferred Stock, plus accrued dividends, was converted into 3,304,085 shares of Basic’s common stock, at which time the estimated fair value of Basic’s common stock was $5.16 per share, pursuant to a share exchange agreement dated September 22, 2003. This conversion did not include the 3,750,000 common stock warrants which remain outstanding at December 31, 2005. The excess of the consideration received by the preferred shareholders over the book value of the preferred stock at the conversion date has been treated as a reduction in net income available to common stockholders.

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 imposes transfer restrictions on the stockholders prior to December 21, 2007 (or earlier upon either (i) DLJ Merchant Banking and its affiliates ceasing to own at least 25% of its percentage based on their initial equity positions, or (ii) the end of a contractuallock-up period imposed by underwriters after in initial public offering). During this period, stockholders are generally prohibited from transferring shares to persons other than permitted assignees. 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.

F1-26

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

      The Stockholders’ Agreement also provided for demand registration rights after an initial public offering, and piggyback registration rights both in and after an 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 (the “Plan”) (as amended effective April 22, 2005) which provides for granting of incentive awards in the form of stock options, restricted stock, performance awards, bonus shares, phantom shares, cash awards and other stock-based awards to officers, employees, directors and consultants of Basic. The Plan assumed awards of the plans of Basic’s successors that were awarded and remained outstanding prior to adoption of the Plan. The Plan provides for the issuance of 5,000,000 shares. The Plan is administered by the Plan committee, and in the absence of a Plan committee, by the Board of Directors, which determines the awards, and the associated terms of the awards and interprets its provisions and adopts policies for implementing the Plan. The number of shares authorized under the Plan and the number of shares subject to an award under the Plan will be adjusted for stock splits, stock dividends, recapitalizations, mergers and other changes affecting the capital stock of Basic.

      On January 26, 2005, March 2, 2005, May 16, 2005, and on December 16, 2005 the board of directors granted various employees options to purchase 100,000, 865,000, 5,000 and 37,500 shares, respectively, of common stock of Basic at exercise prices of $5.16, $6.98, $6.98, and $21.01 per share, respectively. Of the 1,007,500 options granted in 2005, 970,000 options vest over a five-year period and expire 10 years from the date they are granted. The remaining 37,500 options vest over a three-year period and expire 10 years from the date they are granted. In connection with the stock option grants, Basic recorded deferred compensation of approximately $5.2 million which is being amortized over the related vesting period.

      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 the stock options outstanding for the years ended December 31, 2005, 2004, and 2003 and the changes during the years then ended:

			2005					2004					2003
						Weighted					Weighted					Weighted
			Number of			Average		Number of			Average		Number of			Average
			Options			Price		Options			Price		Options			Price
Non-statutory stock options:
	Outstanding, beginning of year			1,463,300		$	4.17		1,290,800		$	4.03		700,800		$	4.00
		Options granted		1,007,500		$	7.32		197,500		$	5.16		642,500		$	4.06
		Options forfeited		(25,000	)	$	6.98		(25,000	)	$	5.16		(52,500	)	$	4.00
		Options exercised		—		$	—		—		$	—		—		$	—
	Outstanding, end of year			2,445,800		$	5.44		1,463,300		$	4.17		1,290,800		$	4.03
	Exercisable, end of year			1,126,665					872,440					421,675
Weighted average fair value of options granted during the year			$	8.00				$	3.14				$	1.61

F1-27

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

      The following table summarizes information about Basic’s stock options outstanding and options exercisable at December 31, 2005:

	Options Outstanding						Options Exercisable
	Number of						Number of
Range of	Options		Weighted Average		Weighted		Options		Weighted
Exercise	Outstanding at		Remaining		Average		Outstanding at		Average
Prices	December 31, 2005		Contractual Life		Exercise Price		December 31, 2005		Exercise Price
$  4.00		1,253,300		6.43 years	$	4.00		1,074,166	$	4.00
$  5.16		310,000		8.48 years	$	5.16		52,499	$	5.16
$  6.98		845,000		9.17 years	$	6.98		—	$	—
$ 21.01		37,500		9.96 years	$	21.01		—	$	—
		2,445,800						1,126,665

11.     EBITDA Contingent Warrants

      On December 21, 2000, Basic issued EBITDA Contingent Warrants to purchase up to an aggregate of (a) 1,149,705 shares, at $.01 per share, of its common stock as a dividend to stockholders of record on December 18, 2000 and (b) 287,425 shares, at $0.01 per share, as part of an authorized issuance to certain members of management of Basic. The determination of the ultimate number of EBITDA Contingent Warrants that may be exercised was dependent of Basic achieving certain levels of financial performance in 2001 and 2002. The warrants became exercisable no later than March 31, 2003 based on the actual financial performance for 2001 and 2002 and expired on May 1, 2003.

      On August 23, 2001, Basic issued additional EBITDA Contingent Warrants to purchase up to an aggregate of 106,310 shares, at $0.01 per share, of Basic’s common stock as part of an authorized issuance to certain members of its management. The determination of the ultimate number of EBITDA Contingent Warrants that may be exercised was dependent on Basic’s achieving certain levels of financial performance in 2001 and 2002. The warrants became exercisable, and were not subject to forfeiture for termination, no later than March 31, 2003 based on actual financial performance for 2001 and 2002 and expired on May 1, 2003.

      In 2003, it was determined that Basic did not meet the financial performance objectives as set forth in the EBITDA Contingent Warrant grants. However, the board of directors evaluated other subjective matters regarding these grants and authorized the award of 574,860 warrants to the stockholders and 196,880 warrants to certain members of management even though the performance criteria was not met. As a result, Basic recognized the compensation expense of $911,000 related to the portion of the warrants issued to management in 2003. In 2003, all holders of the warrants exercised all of their rights and acquired common stock of Basic. The value of the warrants associated with the common stock dividend was recorded in 2003 when the number of warrants to be issued was known.

12.     Related Party Transactions

      Basic provided services and products for workover, maintenance and plugging of existing oil and gas wells to Southwest Royalties, Inc., an affiliate of a director and other significant stockholders of Basic, for approximately $0, $140,000, and $1.3 million in 2005, 2004, and 2003, respectively. Basic had no receivables from this related party as of December 31, 2005 or 2004. Basic had receivables from employees totaling $65,000 and $64,900 as of December 31, 2005 and 2004 respectively.

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BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

13.     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 $468,000, $363,000 and $180,000 in 2005, 2004, and 2003, respectively.

14.     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 20% of the participants’ deferrals. 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 $56,000, $0, and $0 in 2005, 2004, and 2003, respectively.

15.     Earnings Per Share

      Basic presents earnings per share information in accordance with the provisions of Statement of Financial Accounting Standards No. 128,“Earnings per Share” (“SFAS No. 128”). Under SFAS No. 128, basic earnings per common share are determined by dividing net earnings applicable to common stock by the weighted average number of common shares actually outstanding during the year. Diluted earnings per common share is based on the increased number of shares that would be outstanding assuming conversion of dilutive outstanding securities using the ’as if converted” method. The following table sets forth the computation of basic and diluted earnings per share. (in thousands, except share data):

		Years Ended December 31,
		2005		2004			2003
Numerator (both basic and diluted):
	Income from continuing operations	$	44,781	$	12,932		$	(1,986	)
	Discontinued operations, net of tax		—		(71	)		22
	Cumulative effect of accounting change		—		—			(151	)
	Net income available to common stockholders	$	44,781	$	12,861		$	(2,115	)
Denominator:
	Weighted average common stock outstanding		28,381,853		28,094,435			22,575,940
	Vested restricted stock		199,058		—			—
	Denominator for basic earnings per share		28,580,911		28,094,435			22,575,940
	Stock options		789,991		389,975			—
	Unvested restricted stock		638,442		837,500			—
	Common stock warrants		3,159,035		1,333,310			—
	Denominator for diluted earnings per share		33,168,379		30,655,220			22,575,940
						��

F1-29

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

		Years Ended December 31,
		2005		2004		2003
Basic earnings per common share:
	Income from continuing operations less preferred stock dividends and accretion	$	1.57	$	0.46	$	(0.09	)
	Discontinued operations, net of tax		—		—		—
	Net income (loss) available to common stockholders	$	1.57	$	0.46	$	(0.09	)
Diluted earnings per common share:
	Income from continuing operations less preferred stock dividends and accretion	$	1.35	$	0.42	$	(0.09	)
	Discontinued operations, net of tax		—		—		—
	Net income (loss) available to common stockholders	$	1.35	$	0.42	$	(0.09	)

      The diluted earnings per share calculation for 2003 excludes the effects of all stock options and common stock warrants as the effects would be anti-dilutive as a result of the net loss.

16.     Assets Held for Sale and Discontinued Operations

      In August, 2003 Basic’s management and board of directors made the decision to dispose of its fluid services operations in Alaska it acquired in the FESCO acquisition prior to closing of the acquisition. After this disposal Basic no longer had any operations in Alaska.

      The following are the results of operations, since their acquisition in October 2003, from the discontinued operations (in thousands):

		Years Ended
		December 31,
		2004			2003
Revenues		$	1,705		$	550
Operating costs			(1,814	)		(515	)
Income taxes — deferred			38			(13	)
	Loss from discontinued operations, net of tax	$	(71	)	$	22

17.     Business Segment Information

      Basic’s reportable business segments are well servicing, fluid services, drilling and completion services and well site construction services. The following is a description of the segments:

     Well Servicing: This business segment encompasses a full range of services performed with a mobile well servicing rig, including the installation and removal of downhole equipment and elimination of obstructions in the well bore to facilitate the flow of oil and gas. These services are performed to establish, maintain and improve production throughout the productive life of an oil and gas well and to plug and abandon a well at the end of its productive life. Basic well servicing equipment and capabilities are essential to facilitate most other services performed on a well.

     Fluid Services: This segment utilizes a fleet of trucks and related assets, including specialized tank trucks, storage tanks, water wells, disposal facilities and related equipment. Basic employs these

F1-30

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

assets to provide, transport, store and dispose of a variety of fluids. These services are required in most workover, drilling and completion projects as well as part of daily producing well operations.

     Drilling and completion Services: This segment focuses on 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. These services are carried out in niche markets for jobs requiring a single truck and lower horsepower.

     Well Site Construction Services: This segment utilizes a fleet of power units, dozers, trenchers, motor graders, backhoes and other heavy equipment. Basic employs these assets to provide services for the construction and maintenance of oil and gas production infrastructure, such as preparing and maintaining access roads and well locations, installation of small diameter gathering lines and pipelines and construction of temporary foundations to support drilling rigs.

      Basic’s management evaluates the performance of its operating segments based on operating revenues and segment profits. Corporate expenses include general corporate expenses associated with managing all reportable operating segments. Corporate assets consist principally of working capital and debt financing costs. The following table sets forth certain financial information with respect to Basic’s reportable segments (in thousands):

							Drilling and			Well Site
	Well			Fluid			Completion			Construction			Corporate
	Servicing			Services			Services			Services			and Other		Total
Year ended December 31, 2005
Operating revenues	$	221,993		$	132,280		$	59,832		$	45,647		$	—	$	459,752
Direct operating costs		(137,392	)		(82,551	)		(30,900	)		(32,000	)		—		(282,843	)
Segment profits	$	84,601		$	49,729		$	28,932		$	13,647		$	—	$	176,909
Depreciation and amortization	$	18,671		$	9,415		$	3,644		$	2,808		$	2,534	$	37,072
Capital expenditures, (excluding acquisitions)	$	42,838		$	21,602		$	8,361		$	6,443		$	3,851	$	83,095
Identifiable assets	$	169,487		$	100,959		$	45,850		$	28,376		$	152,621	$	497,293
Year ended December 31, 2004
Operating revenues	$	142,551		$	98,683		$	29,341		$	40,927		$	—	$	311,502
Direct operating costs		(98,058	)		(65,167	)		(17,481	)		(31,454	)		—		(212,160	)
Segment profits	$	44,493		$	33,516		$	11,860		$	9,473		$	—	$	99,342
Depreciation and amortization	$	14,125		$	8,316		$	2,402		$	1,857		$	1,976	$	28,676
Capital expenditures, (excluding acquisitions)	$	27,918		$	16,436		$	3,670		$	4,748		$	2,902	$	55,674
Identifiable assets	$	126,208		$	87,349		$	24,246		$	24,064		$	105,993	$	367,860
Year ended December 31, 2003
Operating revenues	$	104,097		$	52,810		$	14,808		$	9,184		$	—	$	180,899
Direct operating costs		(73,244	)		(34,420	)		(9,363	)		(6,586	)		—		(123,613	)
Segment profits	$	30,853		$	18,390		$	5,445		$	2,598		$	—	$	57,286
Depreciation and amortization	$	9,100		$	5,201		$	2,575		$	850		$	487	$	18,213
Capital expenditures, (excluding acquisitions)	$	13,217		$	6,298		$	676		$	2,412		$	898	$	23,501
Identifiable assets	$	102,948		$	73,841		$	10,387		$	31,322		$	84,155	$	302,653

F1-31

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

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

	Year Ended December 31,
	2005			2004			2003
Segment profits	$	176,909		$	99,342		$	57,286
General and administrative expenses		(55,411	)		(37,186	)		(22,722	)
Depreciation and amortization		(37,072	)		(28,676	)		(18,213	)
Gain (loss) on disposal of assets		222			(2,616	)		(391	)
Operating income	$	84,648		$	30,864		$	15,960

18.     Accrued Expenses

      The accrued expenses are as follows (in thousands):

	December 31,
	2005		2004
Compensation related	$	10,576	$	6,764
Workers’ compensation self-insured risk reserve		7,461		5,469
Health self-insured risk reserve		2,200		1,490
Accrual for receipts		1,841		903
Authority for expenditure accrual		3,052		879
Ad valorem taxes		935		845
Sales tax		2,407		692
Insurance obligations		673		586
Purchase order accrual		96		409
Professional fee accrual		1,079		392
Diesel tax accrual		385		336
Acquired contingent earnout obligation		—		273
Retainers		1,042		250
Fuel accrual		368		317
Accrued interest		391		232
Contingent liability		1,000		—
Other		42		649
	$	33,548	$	20,486

F1-32

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

19.     Supplemental Schedule of Non-Cash Investing and Financing Activities

	Year Ended December 31,
	2005		2004		2003
	(in thousands)
Capital leases issued for equipment	$	10,334	$	10,472	$	10,782
Preferred stock dividend	$	—	$	—	$	1,525
Preferred stock issued to pay accrued dividends	$	—	$	—	$	902
Accretion of preferred stock discount	$	—	$	—	$	3,424
Common stock issued for FESCO acquisition	$	—	$	—	$	18,827
Common stock issued for preferred stock	$	—	$	—	$	17,029
Vehicle rebate accrual	$	—	$	709	$	—
Asset retirement obligation additions	$	74	$	21	$	—

20. Quarterly Financial Data (Unaudited)

      The following table summarizes results for each of the four quarters in the years ended December 31, 2005 and 2004:

			First		Second		Third		Fourth
			Quarter		Quarter		Quarter		Quarter		Year
Year ended December 31, 2005:
		Total revenues	$	93,813	$	109,818	$	120,771	$	135,350	$	459,752
		Segment profits	$	33,416	$	42,238	$	45,791	$	55,464	$	176,909
		Income from continuing operations	$	5,801	$	10,747	$	12,335	$	15,898	$	44,781
		Net income available to common stockholders	$	5,801	$	10,747	$	12,335	$	15,898	$	44,781
	Basic earnings per share of common stock(a):
		Continuing operations	$	0.21	$	0.38	$	0.44	$	0.54	$	1.57
		Net income available to common stockholders	$	0.21	$	0.38	$	0.44	$	0.54	$	1.57
	Diluted earnings per share of common stock(a):
		Continuing operations	$	0.18	$	0.33	$	0.38	$	0.46	$	1.35
		Net income available to common stockholders	$	0.18	$	0.33	$	0.38	$	0.46	$	1.35
	Weighted average common shares outstanding:
		Basic		28,186		28,328		28,318		29,481		28,581
		Diluted		32,157		32,783		32,802		34,436		33,168
Year ended December 31, 2004:
		Total revenues	$	67,603	$	74,262	$	83,714	$	85,923	$	311,502
		Segment profits	$	21,548	$	23,717	$	26,605	$	27,472	$	99,342
		Income from continuing operations	$	2,633	$	3,369	$	3,800	$	3,130	$	12,932
		Net income available to common stockholders	$	2,685	$	3,405	$	3,641	$	3,130	$	12,861

F1-33

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

		First		Second		Third		Fourth
		Quarter		Quarter		Quarter		Quarter		Year
Basic earnings per share of common stock(a):
	Continuing operations	$	0.09	$	0.12	$	0.14	$	0.11	$	0.46
	Net income available to common stockholders	$	0.10	$	0.12	$	0.13	$	0.11	$	0.46
Diluted earnings per share of common stock(a):
	Continuing operations	$	0.09	$	0.11	$	0.12	$	0.10	$	0.42
	Net income (loss) available to common stockholders	$	0.09	$	0.11	$	0.12	$	0.10	$	0.42
Weighted average common shares outstanding:
	Basic		28,094		28,094		28,094		28,094		28,094
	Diluted		30,391		31,270		31,493		31,789		30,655

(a) The sum of individual quarterly net income per share may not agree to the total for the year to due each period’s computation based on the weighted average number of common shares outstanding during each period.

21. Subsequent Events

          (a) Acquisitions

      On January 31, 2006, Basic acquired all of the outstanding capital stock of LeBus Oil Field Service Co. for an acquisition price of $26 million, subject to adjustments. The acquisition will operate in Basic’s fluid services line of business in theArk-La-Tex division.

      On February 28, 2006, Basic acquired substantially all of the operating assets of G&L Tool, Ltd. for total consideration of $58 million cash. This acquisition will operate in Basic’s drilling and completion line of business. The purchase agreement also contained an earn-out agreement based on annual EBITDA targets.

F1-34

BASIC ENERGY SERVICES, INC.

December 31, 2005, 2004, and 2003

Schedule II — Valuation and Qualifying Accounts

			Additions
	Balance at		Charged to		Charged to					Balance at
	Beginning of		Costs and		Other					End of
Description	Period		Expenses(a)		Accounts(b)		Deductions(c)			Period
	(in thousands)
Year Ended December 31, 2005
Allowance for Bad Debt	$	3,108	$	1,651	$	—	$	(1,984	)	$	2,775
Year Ended December 31, 2004
Allowance for Bad Debt	$	1,958	$	1,200	$	—	$	(50	)	$	3,108
Year Ended December 31, 2003
Allowance for Bad Debt	$	501	$	1,279	$	375	$	(197	)	$	1,958

(a)	Charges relate to provisions for doubtful accounts
(b)	Reflects the impact of acquisitions
(c)	Deductions relate to the write-off of accounts receivable deemed uncollectible

F1-35

Basic Energy Services, Inc.

Consolidated Balance Sheets

(In thousands, except share data)

				June 30,
				2006
				(unaudited)
ASSETS
Current assets:
	Cash and cash equivalents			$	37,540
	Trade accounts receivable, net of allowance of $3,373				117,139
		Accounts receivable — related parties			190
		Inventories			2,007
		Prepaid expenses			3,960
		Other current assets			2,309
		Deferred tax assets			7,783
			Total current assets		170,928
	Property and equipment, net				424,720
	Deferred debt costs, net of amortization				6,491
	Goodwill				80,965
	Other assets				2,634
				$	685,738
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
		Accounts payable		$	12,291
		Accrued expenses			44,833
		Income taxes payable			3,126
		Current portion of long-term debt			9,025
		Other current liabilities			2,840
			Total current liabilities		72,115
	Long-term debt				245,037
	Deferred income				10
	Deferred tax liabilities				61,745
	Other long-term liabilities				2,892
	Commitments and contingencies
	Stockholders’ equity:
		Common stock; $.01 par value; 80,000,000 shares authorized; 33,931,935 shares issued; 33,815,405 shares outstanding at June 30, 2006			339
		Additional paid-in capital			236,415
		Retained earnings			70,195
		Treasury stock, 116,530 shares at June 30, 2006, at cost			(3,010	)
			Total stockholders’ equity		303,939
				$	685,738

See accompanying notes to consolidated financial statements.

F2-1

Basic Energy Services, Inc.

Consolidated Statements of Operations and Comprehensive Income

(Dollars in thousands, except per share amounts)

				Six Months Ended
				June 30,
				2006			2005
				(unaudited)
Revenues:
	Well servicing			$	154,619		$	98,650
	Fluid services				91,982			60,839
	Drilling and completion services				68,394			24,276
	Well site construction services				23,144			19,866
		Total revenues			338,139			203,631
Expenses:
	Well servicing				87,131			61,464
	Fluid services				55,648			39,119
	Drilling and completion services				33,034			12,731
	Well site construction services				16,463			14,663
	General and administrative, including stock-based compensation of $1,633 and $1,359 in six months ended in 2006 and 2005, respectively				38,149			26,463
	Depreciation and amortization				27,959			16,818
	(Gain) loss on disposal of assets				727			(50	)
		Total expenses			259,111			171,208
			Operating income		79,028			32,423
Other income (expense):
	Interest expense				(7,787	)		(6,201	)
	Interest income				914			199
	Loss on early extinguishment of debt				(2,705	)		—
	Other income				55			137
Income from continuing operations before income taxes					69,505			26,558
Income tax expense					(25,337	)		(10,010	)
Net income				$	44,168		$	16,548
Earnings per share of common stock:
	Basic			$	1.32		$	0.58
	Diluted			$	1.15		$	0.51
Comprehensive Income:
Net income				$	44,168		$	16,548
	Unrealized gains (losses) on hedging activities				(236	)		260
Comprehensive Income:				$	43,932		$	16,808

See accompanying notes to consolidated financial statements.

F2-2

Basic Energy Services, Inc.

Consolidated Statements of Stockholders’ Equity

(In thousands, except share data)

																	Accumulated
	Common Stock				Additional												Other			Total
					Paid-In			Deferred			Treasury			Retained			Comprehensive			Stockholders’
	Shares		Amount		Capital			Compensation			Stock			Earnings			Income			Equity
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 Standards No. 123R		—		—		(7,341	)		7,341			—			—			—			—
Amortization of deferred compensation		—		—		1,633			—			—			—			—			1,633
Unrealized gain on interest rate swap agreement		—		—		—			—			—			—			51			51
Settlement of interest rate swap agreement		—		—		—			—			—			—			(287	)		(287	)
Offering costs		—		—		(161	)		—			—			—			—			(161	)
Purchase of treasury stock		—		—		—			—			(3,218	)		—			—			(3,218	)
Exercise of stock options		—		—		3,066			—			2,739			(2,627	)		—			3,178
Net income		—		—		—			—			—			44,168			—			44,168
Balance — June 30, 2006 (Unaudited)		33,931,935	$	339	$	236,415		$	—		$	(3,010	)	$	70,195		$	—		$	303,939

See accompanying notes to consolidated financial statements.

F2-3

Basic Energy Services, Inc.

Consolidated Statements of Cash Flows

(In thousands)

						Six Months Ended
						June 30,
						2006			2005
						(unaudited)
Cash flows from operating activities:
	Net income					$	44,168		$	16,548
		Adjustments to reconcile net income to net cash provided by operating activities:
			Depreciation and amortization				27,959			16,818
			Accretion on asset retirement obligation				43			18
			Change in allowance for doubtful accounts				598			900
			Non-cash interest expense				549			527
			Non-cash compensation				1,633			1,359
			Loss on early extinguishment of debt				2,705			—
			(Gain) loss on disposal of assets				727			(50	)
			Deferred income taxes				(5,388	)		8,274
		Changes in operating assets and liabilities, net of acquisitions:
			Accounts receivable				(24,728	)		(11,222	)
			Inventories				(140	)		(211	)
			Prepaid expenses and other current assets				(874	)		1,325
			Other assets				(204	)		(201	)
			Accounts payable				(2,682	)		(1,103	)
			Excess tax benefits from exercise of employee stock options				(3,066	)		—
			Income tax payable				(2,607	)		1,681
			Deferred income and other liabilities				1,312			(167	)
			Accrued expenses				10,949			10,327
					Net cash provided by operating activities		50,954			44,823
		Cash flows from investing activities:
			Purchase of property and equipment				(48,827	)		(35,488	)
			Proceeds from sale of assets				1,737			877
			Payments for other long-term assets				(4,393	)		(858	)
			Payments for businesses, net of cash acquired				(98,988	)		(9,885	)
					Net cash used in investing activities		(150,471	)		(45,354	)
		Cash flows from financing activities:
			Proceeds from debt				305,041			294
			Payments of debt				(195,715	)		(5,836	)
			Offering costs related to initial public offering				(161	)		—
			Purchase of treasury stock				(3,218	)		—
			Exercise of employee stock options				112			—
			Excess tax benefits from exercise of employee stock options				3,066			—
			Deferred loan costs and other financing activities				(4,913	)		(8	)
					Net cash provided by (used in) financing activities		104,212			(5,550	)
				Net increase (decrease) in cash and equivalents			4,695			(6,081	)
		Cash and cash equivalents — beginning of period					32,845			20,147
		Cash and cash equivalents — end of period				$	37,540		$	14,066

See accompanying notes to consolidated financial statements.

F2-4

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements

1.  Basis of Presentation and Nature of Operations

Basis of Presentation

      The accompanying unaudited consolidated financial statements of Basic Energy Services, Inc. and subsidiaries (“Basic” or the “Company”) have been prepared in accordance with accounting principles generally accepted in the United States for interim financial reporting. Accordingly, they do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been made in the accompanying unaudited financial statements.

Nature of Operations

      Basic provides a range of well site services to oil and gas drilling and producing companies, including well servicing, fluid services, drilling and completion services and well site construction services. These services are primarily provided by Basic’s fleet of equipment. Basic’s operations are concentrated in the major United States onshore oil and gas producing regions in Texas, New Mexico, Oklahoma and Louisiana, and the Rocky Mountain states.

2.  Summary of Significant Accounting Policies

Principles of Consolidation

      The accompanying consolidated financial statements include the accounts of Basic and its wholly-owned subsidiaries. Basic has no interest in any other organization, entity, partnership, or contract that could require any evaluation under FASB Interpretation No. 46R or Accounting Research Bulletin No. 51. All intercompany transactions and balances have been eliminated.

Revenue Recognition

     Well Servicing — Well servicing consists primarily of maintenance services, workover services, completion services and plugging and abandonment services. Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Basic prices well servicing by the hour of service performed.

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

     Drilling and Completion Services — Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Basic prices drilling and completion services by the hour, day, or project depending on the type of service performed. When Basic provides multiple services to a customer, revenue is allocated to the services performed based on the fair values of the services.

     Well Site Construction Services — Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Basic prices well site construction services by the hour, day, or project depending on the type of service performed.

F2-5

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Impairments

      In accordance with Statement of Financial Accounting Standards No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets(“SFAS No. 144”), long-lived assets, such as property, plant, and equipment, and purchased intangibles subject to amortization, are reviewed for impairment at a minimum annually, or whenever, in management’s judgment events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of such assets exceeds the fair value of the assets. Assets to be disposed of would be separately presented in the consolidated balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated. The assets and liabilities, if material, of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the consolidated balance sheet.

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

      Basic had no impairment expense in the six months ended June 30, 2006 or 2005.

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 straight line method, which approximates the effective interest method over the terms of the related debt.

      Deferred debt costs of approximately $6.8 million at June 30, 2006 and $7.0 million at December 31, 2005, respectively, represent debt issuance costs and are recorded net of accumulated amortization of approximately $300,000, and $2.2 million at June 30, 2006 and December 31, 2005, respectively. For the six months ended June 30, 2006 and 2005, amortization of deferred debt costs totaled approximately $549,000 and $527,000, respectively.

Goodwill

      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.

F2-6

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

      Basic has identified its reporting units to be well servicing, fluid services, drilling and completion services and well site construction services. The goodwill allocated to such reporting units as of June 30, 2006 is $13.8 million, $32.6 million, $30.9 million and $3.7 million, respectively. The change in the carrying amount of goodwill for the six months ended June 30, 2006 of $32.7 million relates to goodwill from acquisitions and payments pursuant to contingent earn-out agreements, with approximately $3.9 million, $12.0 million and $16.8 million of goodwill additions relating to the well servicing, fluid services and drilling and completion units, respectively.

Stock-Based Compensation

      On January 1, 2006, Basic adopted Statement of Financial Accounting Standards No. 123 (revised 2004)“Share-Based Payment” (“SFAS No. 123R”). Prior to January 1, 2006, the Company accounted for share-based payments under the recognition and measurement provisions of Accounting Principles Board Opinion No. 25,“Accounting for Stock issued to Employees” (“APB No. 25”) which was permitted by Statement of Financial Accounting Standards No. 123,“Accounting for Stock-Based Compensation” (“SFAS No. 123”).

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

      Under SFAS No. 123R, entities using the minimum value method and the prospective application are not permitted to provide the pro forma disclosures (as was required under Statement of Financial Accounting Standard No. 123,“Accounting for Stock-Based Compensation”(“SFAS No. 123”)) subsequent to adoption of SFAS No. 123R since they do not have the fair value information required by SFAS No. 123R. Therefore, in accordance with SFAS No. 123R, Basic will no longer include pro forma disclosures that were required by SFAS No. 123.

Asset Retirement 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 the six months ended June 30, 2006 (in thousands):

Balance, December 31, 2005	$	569
Additional asset retirement obligations recognized through acquisitions		193
Accretion Expense		43
Increase in asset retirement obligations due to change in estimate		447
Balance, June 30, 2006 (unaudited)	$	1,252

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

F2-7

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

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 6).

Recent Accounting Pronouncements

      In December 2004, the Financial Accounting Standards Board issued SFAS No. 123R. As discussed under Note 2, “Stock-Based Compensation,” Basic adopted the provisions of SFAS No. 123R on January 1, 2006.

      In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation No. 48 (FIN 48),Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109,Accounting for Income Taxes. The interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken, in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties accounting in interim periods, disclosure and transition. The interpretation is effective for fiscal years beginning after December 15, 2006. The Company has not determined the effects that adoption of FIN 48 will have on the Company’s financial position, cash flows and results of operations.

F2-8

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

3.  Acquisitions

      In 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
	Closing Date		(Net of Cash 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	$	24,508
G&L Tool, Ltd.		February 28, 2006		58,000
Arkla Cementing, Inc.		March 27, 2006		5,012
Globe Well Service, Inc.		May 30, 2006		11,468
Total 2006			$	98,988

Contingent Earn-out Arrangements and Final Purchase Price Allocations

      Contingent earn-out arrangements are generally arrangements entered in certain acquisitions to encourage the owner/manager to continue operating and building the business after the purchase transaction. The contingent earn-out arrangements of the related acquisitions are generally linked to certain financial measures and performance of the assets acquired in the various acquisitions. All amounts paid or reasonably accrued for related to the contingent earn-out payments are reflected as increases to the goodwill associated with the acquisition.

      On February 28, 2006, Basic acquired substantially all of the assets of G&L Tool for $58.0 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 earned by Basic 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 fishing and rental tool market operations. The cost of the G&L acquisition was allocated $43.8 million to property and equipment, $14.1 million to goodwill, and $51,000 to non-compete agreements. Revisions to the fair values, which may be significant, will be recorded by the Company as further adjustments to the purchase price allocations.

F2-9

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

      The following unaudited pro-forma results of operations have been prepared as though the G&L Tool acquisition had been completed on January 1, 2005. Pro forma amounts are based on the preliminary 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).

	Six Months Ended
	June 30,
	2006		2005
	(unaudited)
Revenues	$	347,632	$	220,582
Net income	$	46,630	$	19,866
Earnings per common share — basic	$	1.40	$	0.70
Earnings per common share — diluted	$	1.21	$	0.61

      Basic does not believe the pro-forma effect of the remainder of the acquisitions completed in 2005 or 2006 is material, either individually or when aggregated, to the reported results of operations.

4.  Property and Equipment

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

	June 30,		December 31,
	2006		2005
	(unaudited)
Land	$	2,119	$	1,902
Buildings and improvements		11,562		8,634
Well service units and equipment		239,431		199,070
Fluid services equipment		76,965		59,104
Brine and fresh water stations		7,953		7,746
Frac/test tanks		44,592		31,475
Pressure pumping equipment		55,406		31,101
Construction equipment		25,699		24,224
Disposal facilities		23,633		16,828
Vehicles		29,459		23,329
Rental equipment		33,695		6,519
Aircraft		3,236		3,236
Other		8,675		8,602
		562,425		421,770
Less accumulated depreciation and amortization		137,705		112,695
Property and equipment, net	$	424,720	$	309,075

F2-10

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

      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):

	June 30,		December 31,
	2006		2005
	(unaudited)
Light vehicles	$	21,364	$	17,912
Well service units and equipment		201		—
Fluid services equipment		18,557		14,011
Pressure pumping equipment		288		—
Construction equipment		3,231		1,300
		43,641		33,223
Less accumulated amortization		10,850		8,474
	$	32,791	$	24,749

      Amortization of assets held under capital leases of approximately $2,376,000 and $858,000 for the six months ended June 30, 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):

		June 30,		December 31,
		2006		2005
		(unaudited)
Credit Facilities:
	Term B Loan	$	—	$	90,000
	Revolver		—		16,000
7.125% Senior Notes			225,000		—
Capital leases and other notes			29,062		20,887
			254,062		126,887
Less current portion			9,025		7,646
		$	245,037	$	119,241

Senior Notes

      On April 12, 2006 the Company issued $225.0 million of 7.125% Senior Notes due April 2016 in a private placement. Proceeds from the sale of the Senior Notes were used to retire the outstanding balance on the $90.0 million Term B Loan and to pay down approximately $96.0 million under the revolving credit facility, which amounts may be reborrowed to fund future acquisitions or for general corporate purposes. Interest payments on the Senior Notes are due semi-annually, on April 15 and October 15, commencing on October 15, 2006. The Senior Notes are non-convertible, unsecured and guaranteed by all the subsidiaries of the Company. Under the terms of the sale of the Senior Notes,

F2-11

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

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 anticipates completing the exchange offer under the terms of the sale.

      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 and liquidated damages, if any, to the date of redemption. This redemption must occur less than 90 days after the date of the closing of any such Qualified 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 and Liquidated Damages, if any, to the date of repurchase.

      During any period of time that the Senior Notes have a Moody’s rating of Baa3 or higher or an S&P rating of BBB- or higher (each, an “Investment Grade Rating”) and no default has occurred, the Company is not subject to covenants that limit the ability of the Company and its restricted subsidiaries to, among other things: Incur additional debt, incur layered debt, consolidate or merge with or into other companies, comply with limitations on asset sales, limitations on restricted payments, limitations on dividends and other restrictions, limitations on transactions with affiliates, and additional note guarantees. The restrictive covenants are subject to a number of important exemptions and qualifications set forth in the Indenture. As of June 30, 2006, the Senior Notes do not satisfy the rating requirements. Basic is in compliance with the restrictive covenants at June 30, 2006.

      As part of the issuance of the above-mentioned Senior Notes, the Company incurred debt issuance costs of approximately $4.6 million, which are being amortized to interest expense using the straight line method, which approximates the effective interest method over the term of the Senior Notes.

2005 Credit Facility

      On December 15, 2005, Basic entered into a $240 million Third Amended and Restated Credit Agreement with a syndicate of lenders (“2005 Credit Facility”), which refinanced all of its then existing credit facilities. The 2005 Credit Facility, as amended effective March 28, 2006, provides for a $90 million Term B Loan (“2005 Term B Loan”) and a $150 million revolving line of credit (“Revolver”). The commitment under the Revolver allows for (a) the borrowing of funds (b) issuance of up to $30 million of letters of credit and (c) $2.5 million of swing-line loans (next day borrowing). The amounts outstanding under the 2005 Term B Loan require quarterly amortization at various amounts during each quarter with all amounts outstanding on December 15, 2011 being due and payable in full. All the outstanding amounts under the Revolver are due and payable on December 15, 2010. The 2005 Credit Facility is secured by substantially all of Basic’s tangible and intangible assets. Basic incurred approximately $1.8 million in debt issuance costs in obtaining the 2005 Credit Facility.

      At Basic’s option, borrowings under the 2005 Term B Loan bear interest at either the (a) “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus .5% per annum) plus 1% or (b) the LIBOR rate plus 2.0%. At June 30, 2006, Basic had paid outstanding borrowings under the Term B Loan in full; therefore, a Term B Loan weighted average

F2-12

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

interest rate was not calculated. However, at December 31, 2005, Basic’s weighted average interest rate on its Term B Loan was 6.4%.

      At Basic’s option, borrowings under the 2005 Revolver bear interest at either the (a) “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus .5% per annum) plus a margin ranging from .50% to 1.25% or (b) the LIBOR rate plus a margin ranging from 1.5% to 2.25%. The margins vary depending on Basic’s leverage ratio. At March 31, 2006, Basic’s margin on Alternative Base Rates and LIBOR tranches was .75% and 1.75%, respectively. Fees on the letters of credit are due quarterly on the outstanding amount of the letters of credit at a rate ranging from 1.5% to 2.25% for participation fees and .125% for fronting fees. A commitment fee is due quarterly on the available borrowings under the Revolver at rates ranging from .375% to .5%.

      At June 30, 2006, Basic, under its Revolver, had no outstanding borrowings and $9.6 million of letters of credit and no amounts outstanding in swing-line loans. At June 30, 2006 and December 31, 2005 Basic had availability under its Revolver of $140.4 million and $124.4 million, respectively.

      Pursuant to the 2005 Credit Facility, Basic must apply proceeds to reduce principal outstanding under the 2005 Term B Revolver from (a) individual assets sales greater than $2 million or $7.5 million in the aggregate on an annual basis, and (b) 50% of the proceeds from any equity offering. The 2005 Credit Facility required Basic to enter into an interest rate hedge, through May 28, 2006 on at least $65 million of Basic’s then outstanding indebtedness. The March 28, 2006 amendment deletes this requirement upon payoff of the Term B Loans. In April 2006, Basic paid off all outstanding borrowings under the Term B Loan. Paydowns on the 2005 Term B Loan may not be reborrowed.

      The 2005 Credit Facility contains various restrictive covenants and compliance requirements, which include (a) limiting of the incurrence of additional indebtedness, (b) restrictions on mergers, sales or transfers of assets without the lenders’ consent, (c) limitation on dividends and distributions and (d) various financial covenants, including (1) a maximum leverage ratio of 3.5 to 1.0 reducing over time to 3.25 to 1.0, (2) a minimum interest coverage ratio of 3.0 to 1.0 and (e) limitations on capital expenditures in any period of four consecutive quarters in excess of 20% of Consolidated Net Worth unless certain criteria are met. At June 30, 2006 and December 31, 2005, 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.

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

	Six Months
	Ended June 30,
	2006		2005
	(unaudited)
Cash payments for interest	$	3,193	$	5,600
Commitment and other fees paid		321		—
Amortization of debt issuance costs		550		527
Accrued interest on senior notes		3,518		—
Other		205		74
	$	7,787	$	6,201

F2-13

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Losses on Extinguishment of Debt

      In April of 2006, Basic recognized a loss on the early extinguishment of debt. Basic wrote off unamortized debt issuance costs of approximately $2.7 million, which related to the prepayment of the Term B Loan.

6.  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.

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 its24-hour workover rigs and newly manufactured rigs. Basic has deductibles per occurrence for workers’ compensation and medical and dental coverage of $150,000 and $125,000, 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 June 30, 2006 and December 31, 2005, self-insured risk accruals, net of related recoveries/receivables totaled approximately $12.4 million and $9.5 million, respectively.

7.  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

F2-14

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

the purchase, 600,000 common stock warrants were issued in connection with this transaction, the fair value of which was approximately $1.2 million (calculated using an option valuation model). The warrants allow the holder to purchase 600,000 shares of Basic’s common stock at $4 per share. The warrants are exercisable in whole or in part after June 30, 2002 and prior to February 13, 2007.

      In February 2004, Basic granted certain officers and directors 837,500 restricted shares of common stock. The shares vest 25% per year for four years from the award date and are subject to other vesting and forfeiture provisions. The estimated fair value of the restricted shares was $5.8 million at the date of the grant and was recorded as deferred compensation, a component of stockholders’ equity. For the six months ended June 30, 2006 and 2005, the amount charged to expense over the respective vesting period totaled approximately $694,000 and $818,000, respectively.

      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.

      In March 2006, Basic issued 148,720 shares of common stock from treasury stock for the exercise of stock options.

      In June 2006, Basic issued 28,100 shares of common stock from treasury stock for the exercise of stock options.

8.  Incentive Plan

      In May 2003, Basic’s board of directors and stockholders approved the Basic 2003 Incentive Plan (as amended effective April 22, 2005), (the “Plan”) which provides for granting of incentive awards in the form of stock options, restricted stock, performance awards, bonus shares, phantom shares, cash awards and other stock-based awards to officers, employees, directors and consultants of Basic. The Plan assumed awards of the plans of Basic’s successors that were awarded and remained outstanding prior to adoption of the Plan. The Plan provides for the issuance of 5,000,000 shares. The Plan is administered by the Plan committee, and in the absence of a Plan committee, by the Board of Directors, which determines the awards, and the associated terms of the awards and interprets its provisions and adopts policies for implementing the Plan. The number of shares authorized under the Plan and the number of shares subject to an award under the Plan will be adjusted for stock splits, stock dividends, recapitalizations, mergers and other changes affecting the capital stock of Basic.

      On March 15, 2006, the board of directors granted various employees options to purchase 418,000 shares of common stock of Basic at an exercise price of $26.84 per share. All of the 418,000 options granted in 2006 vest over a five-year period and expire 10 years from the date they were granted. Option awards are generally granted with an exercise price equal to the market price of the Company’s stock at the date of grant.

      The fair value of each option award is estimated on the date of grant using the Black-Scholes-Merton option-pricing model that uses the subjective assumptions noted in the following table. Since the Company has only been public since December 2005, expected volatilities are based upon a peer group. When the Company has sufficient historical data to calculate expected volatility, the Company will use its’ own historical data to calculate expected volatility. The expected term of options granted represents the period of time that options granted are expected to be outstanding. 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 six months ended June 30, 2006 and 2005, compensation expense related to share-based arrangements was approximately $1,633,000 and

F2-15

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

$1,359,000, respectively. For compensation expense recognized during the six months ended June 30, 2006 and 2005, Basic recognized a tax benefit of approximately $595,000 and $512,000, respectively.

      The fair value of each option award accounted for under SFAS No. 123R is estimated on the date of grant using the Black-Scholes-Merton option-pricing model that uses the assumptions noted in the following table:

	Six Months
	Ended June 30,
	2006
Risk-free interest rate		4.7	%
Expected term		6.65
Expected volatility		47.0	%
Expected dividend yield		—

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

      The following table reflects the summary of stock options outstanding for the six months ended June 30, 2006 and the changes during the six months then ended:

						Weighted		Aggregate
			Number of			Average		Instrinsic
			Options			Exercise		Value
			Granted			Price		(000’s)
Non-statutory stock options:
	Outstanding, beginning of period			2,445,800		$	5.44		—
		Options granted		418,000		$	26.84		—
		Options forfeited		(56,000	)	$	7.33		—
		Options exercised		(176,820	)	$	4.00		—
	Outstanding, end of period			2,630,980		$	8.89	$	57,029
	Exercisable, end of period			1,249,813		$	4.16	$	33,006
	Expected to vest, end of period			1,346,469		$	12.82	$	23,893

      The following table summarizes information about Basic’s stock options outstanding and options exercisable at June 30, 2006:

	Options Outstanding						Options Exercisable
	Number of		Weighted				Number of		Weighted
	Options		Average		Weighted		Options		Average		Weighted
Range of	Outstanding at		Remaining		Average		Outstanding at		Remaining		Average
Exercise	June 30,		Contractual		Exercise		June 30,		Contractual		Exercise
Prices	2006		Life		Price		2006		Life		Price
$4.00		1,076,480		5.94	$	4.00		1,076,480		5.94	$	4.00
$5.16		310,000		7.98	$	5.16		173,333		7.87	$	5.16
$6.98		790,000		8.67	$	6.98		—		—	$	—
$21.01		37,500		9.46	$	21.01		—		—	$	—
$26.84		417,000		9.71	$	26.84		—		—	$	—
		2,630,980						1,249,813

      The weighted-average grant date fair value of share options granted during the six months ended June 30, 2006 and 2005 was $14.47 and $8.12, respectively. The total intrinsic value of share options

F2-16

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

exercised during the six months ended June 30, 2006 and 2005 was approximately $4.2 million and $0, respectively.

      A summary of the status of the Company’s non-vested share grants at June 30, 2006 and changes during the six months ended June 30, 2006 is presented in the following table:

				Weighted Average
	Number of			Grant Date Fair
Nonvested Shares	Shares			Value Per Share
Nonvested at beginning of period		591,875		$	6.98
Granted during period		—			—
Vested during period		(230,625	)		6.98
Forfeited during period		—			—
Nonvested at end of period		361,250		$	6.98

      As of June 30, 2006, there was $11.1 million of total unrecognized compensation related to non-vested share-based compensation grant date arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 3.53 years. The total grant date fair value of share-based awards vested during the six months ended June 30, 2006 and 2005 was approximately $3.2 million and $2.9 million, respectively.

      Cash received from share option exercises under the incentive plan was approximately $112,000 and $0 for the six months ended June 30, 2006 and 2005, respectively. The actual tax benefit realized for the tax deductions from option exercise is $3.1 million and $0, respectively, for the six months ended June 30, 2006 and 2005.

      The Company has a history of issuing Treasury shares to satisfy share option exercises.

9.  Related Party Transactions

      Basic had receivables from employees of approximately $190,000 and $65,000 as of June 30, 2006 and December 31, 2005, respectively. During the year, 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 ayear-to-year basis unless terminated by either party.

10.  Earnings Per Share

      Basic presents earnings per share information in accordance with the provisions of Statement of Financial Accounting Standards No. 128,“Earnings per Share” (“SFAS No. 128”). Under SFAS No. 128, basic earnings per common share are determined by dividing net earnings applicable to common stock by the weighted average number of common shares actually outstanding during the year. Diluted earnings per common share is based on the increased number of shares that would be

F2-17

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

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:

		Six Months Ended
		June 30,
		2006		2005
		(unaudited)
		(in thousands,
		except share data):
Numerator (both basic and diluted):
	Net income	$	44,168	$	16,548
Denominator:
	Denominator for basic earnings per share		33,347,512		28,406,935
	Stock options		1,080,834		621,937
	Unvested restricted stock		233,824		525,000
	Common stock warrants		3,739,045		2,921,898
	Denominator for diluted earnings per share		38,401,215		32,475,770
Basic earnings per common share:		$	1.32	$	0.58
Diluted earnings per common share:		$	1.15	$	0.51

11.  Business Segment Information

      Basic’s reportable business segments are well servicing, fluid services, drilling and completion services and well site construction services. The following is a description of the segments:

     Well Servicing: This business segment encompasses a full range of services performed with a mobile well servicing rig, including the installation and removal of downhole equipment and elimination of obstructions in the well bore to facilitate the flow of oil and gas. These services are performed to establish, maintain and improve production throughout the productive life of an oil and gas well and to plug and abandon a well at the end of its productive life. Basic well servicing equipment and capabilities are essential to facilitate most other services performed on a well.

     Fluid Services: This segment utilizes a fleet of trucks and related assets, including specialized tank trucks, storage tanks, water wells, disposal facilities and related equipment. Basic employs these assets to provide, transport, store and dispose of a variety of fluids. These services are required in most workover, drilling and completion projects as well as part of daily producing well operations.

     Drilling and Completion Services: This segment focuses on 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. These services are carried out in niche markets for jobs requiring a single truck and lower horsepower.

     Well Site Construction Services: This segment utilizes a fleet of power units, dozers, trenchers, motor graders, backhoes and other heavy equipment. Basic employs these assets to provide services for the construction and maintenance of oil and gas production infrastructure, such as preparing and maintaining access roads and well locations, installation of small diameter gathering lines and pipelines and construction of temporary foundations to support drilling rigs.

      Basic’s management evaluates the performance of its operating segments based on operating revenues and segment profits. Corporate expenses include general corporate expenses associated with managing all reportable operating segments. Corporate assets consist principally of working capital and debt financing costs.

F2-18

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

      The following table sets forth certain financial information with respect to Basic’s reportable segments (in thousands):

							Drilling and			Well Site			Corporate
	Well			Fluid			Completion			Construction			and
	Servicing			Services			Services			Services			Other		Total
Six Months Ended June 30, 2006 (Unaudited)
Operating revenues	$	154,619		$	91,982		$	68,394		$	23,144		$	—	$	338,139
Direct operating costs		(87,131	)		(55,648	)		(33,034	)		(16,463	)		—		(192,276	)
Segment profits	$	67,488		$	36,334		$	35,360		$	6,681		$	—	$	145,863
Depreciation and amortization	$	12,731		$	7,436		$	5,007		$	1,777		$	1,008	$	27,959
Capital expenditures, (excluding acquisitions)	$	22,215		$	12,976		$	8,736		$	3,100		$	1,800	$	48,827
Identifiable assets	$	207,535		$	145,556		$	107,997		$	31,316		$	193,334	$	685,738
Six Months Ended June 30, 2005 (Unaudited)
Operating revenues	$	98,650		$	60,839		$	24,276		$	19,866		$	—	$	203,631
Direct operating costs		(61,464	)		(39,119	)		(12,731	)		(14,663	)		—		(127,977	)
Segment profits	$	37,186		$	21,720		$	11,545		$	5,203		$	—	$	75,654
Depreciation and amortization	$	8,727		$	4,691		$	1,193		$	1,324		$	883	$	16,818
Capital expenditures, (excluding acquisitions)	$	18,399		$	9,889		$	2,515		$	2,791		$	1,894	$	35,488
Identifiable assets	$	147,956		$	93,141		$	28,569		$	25,012		$	112,232	$	406,910

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

	Six Months Ended
	June 30,
	2006			2005
Segment profits	$	145,863		$	75,654
General and administrative expenses		(38,149	)		(26,463	)
Depreciation and amortization		(27,959	)		(16,818	)
Gain (loss) on disposal of assets		(727	)		50
Operating income	$	79,028		$	32,423

F2-19

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

12.  Supplemental Schedule of Cash Flow Information:

      The following table reflects non-cash financing and investing activity during (in thousands):

	Six Months
	Ended June 30,
	2006		2005
Capital leases issued for equipment	$	12,136	$	3,580
Asset retirement obligation additions	$	640	$	—
Exercise of stock options	$	2,627	$	—

      Basic paid income taxes of approximately $31.6 million and $0 during the six months ended June 30, 2006 and 2005, respectively.

13.  Subsequent Events

      On July 6, 2006, Basic acquired substantially all of the operating assets of Hydro-Static Tubing Testers, Inc. for total consideration of $1.2 million cash. This acquisition will operate in Basic’s well servicing line of business in the Northern Rocky Mountain region.

      On August 1, 2006, Basic acquired all of the outstanding capital stock of Hennessey Rental Tools, Inc. for an acquisition price of $8.5 million, subject to adjustments. This acquisition will operate in both Basic’s well servicing and drilling and completion segments in the Mid-Continent region.

      On August 1, 2006, Basic acquired substantially all of the operating assets of Stimulation Services for total consideration of $4.5 million cash. This acquisition will operate in Basic’s drilling and completion line of business in the Ark-La-Tex region.

F2-20

Appendix A

Glossary of Terms

     Acidizing: The process of pumping solvent into the well as a means of dissolving unwanted material.

     Brine water: Water that is heavily saturated with salt used in various well completion and workover activities.

     Cased-hole: A wellbore lined with a string of casing or liner (generally metal casing placed and cemented) to protect the open hole from fluids, pressures, wellbore stability problems or a combination of these. Although the term can apply to any hole section, it is often used to describe techniques and practices applied after a casing or liner has been set across the reservoir zone, such as cased-hole logging or cased-hole testing.

     Casing: Steel pipe placed in an oil or gas well as drilling progresses to prevent the wall of the hole from caving in, to prevent seepage of fluids, and to provide a means of extracting petroleum if the well is productive.

     Drilling mud: The fluid pumped down the drilling string and up the well bore to bring debris from the drilling and workover operators to the surface. Drilling muds also cool and lubricate the bit, protect against blowouts by holding back underground pressures and, in new well drilling, deposit a mud cake on the wall of the borehole to minimize loss of fluid to the formation.

     Electric wireline: Wireline that contains an electrical conduit, thereby enabling the use of downhole electrical sensors to measure pressures and temperatures.

     Fishing: The process of recovering lost or stuck equipment in the wellbore.

     Frac job or fracturing operations: A procedure to stimulate production of oil or gas from a well by pumping fluids from the surface under high pressure into the wellbore to induce fractures in the formation.

     Frac tank: A steel tank used to store fluids at the well location to facilitate completion and workover operations. The largest demand is related to the storage of fluid used in fracturing operations.

     Hot oil truck: A truck mounted pump, tank and heating element used to melt paraffin accumulated in the well bore by pumping heated oil or water through the well.

     Newbuild: A newly built rig, as compared to a refurbished rig that may contain substantially all new components or new derrick but utilizes an older frame.

     Plugging and abandonment activities: Activities to remove production equipment and seal off a well at the end of a well’s economic life.

     Slickline. A form of wireline that lacks an electrical conduit and is used only to perform mechanical tasks such as setting or retrieving various tools.

     Stimulation: The general process of improving well productivity through fracturing or acidizing operations.

     Swab rig: Truck mounted equipment consisting of a hoist and mast used to remove, or “swab,” wellbore fluids by alternatively lowering and raising tools in a well’s tubing or casing.

     Underbalanced drilling: 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.

A-1

     Water cut: The volume of water produced by a well as a percentage of all fluids produced.

     Wellbore: The drilled hole of a well, which may include open hole or uncased portions, and which may also refer to the rock face that bounds the inside diameter of the wall of the drilled hole.

     Well completion: The activities and procedures necessary to prepare a well for the production of oil and gas after the well has been drilled to its targeted depth. Well completions establish a flow path for hydrocarbons between the reservoir and the surface.

     Well servicing: The maintenance work performed on an oil or gas well to improve or maintain the production from a formation already producing. It usually involves repairs to the downhole pump, rods, tubing, and so forth or removal of sand, paraffin or other debris which is preventing or restricting production of oil or gas.

     Well workover: Refers to a broad category of procedures preformed on an existing well to correct a major downhole problem, such as collapsed casing, or to establish production from a formation not previously produced, including deepening the well from its originally completed depth.

     Wireline: A general term used to describe well-intervention operations conducted using single-strand or multistrand wire or cable for intervention in oil or gas wells. Although applied inconsistently, the term is used commonly in association with electric logging and cables incorporating electrical conductors See “slickline” and “electric wireline” for specific types of wireline services.

A-2

Prospectus

September 11, 2006

     Until October 21, 2006, all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.