LeBus Oil Field Service S-4 Registration of securities issued in business combination transactions

As filed with the Securities and Exchange Commission on September 2, 2009

RegistrationNo. 333-      

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form S-4

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Basic Energy Services, Inc.

(Exact name of registrant as specified in its charter)

Delaware	1389	54-2091194
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification No.)

Co-Registrants

(see next page)

500 W. Illinois, Suite 100
Midland, Texas 79701
(432) 620-5500
(Address, including zip code, and telephone number,
including area code, of registrant’s principal executive offices) Kenneth V. Huseman
President
500 W. Illinois, Suite 100
Midland, Texas 79701
(432) 620-5500
(Name, address, including zip code, and
telephone number, including area code of agent for service)

Copy to:

David C. Buck

Andrews Kurth LLP

600 Travis, Suite 4200

Houston, Texas 77002

(713) 220-4200

Approximate date of commencement of proposed sale of the securities to the public:  As soon as practicable following the effectiveness of this registration statement.

If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box.  o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer þ Non-accelerated filer o Smaller reporting company o

(Do not check if a smaller reporting company)

If applicable, place an X in the box to designate the appropriate rule provision relied upon in conducting this transaction:

Exchange ActRule 13e-4(i) (Cross-Border Issuer Tender Offer)	o
Exchange ActRule 14d-1(d) (Cross-Border Third-Party Tender Offer)	o

CALCULATION OF REGISTRATION FEE

			Proposed Maximum			Proposed Maximum		Amount of
Title of Each Class of	Amount		Offering			Aggregate		Registration
Securities to be Registered	to be Registered		Price per Unit			Offering Price		Fee
11.625% Senior Secured Notes due 2014	$	225,000,000		100	%	$	225,000,000	$	12,555	(1)
Guarantees by certain subsidiaries of Basic Energy Services, Inc.*		—		—			—		—	(2)

(1)	The registration fee was calculated pursuant to Rule 457(f) under the Securities Act of 1933. For purposes of this calculation, the offering price per note was assumed to be the stated principal amount of each original note that may be received by the registrant in the exchange transaction in which the notes will be offered.
(2)	Pursuant to Rule 457(n) under the Securities Act of 1933, no separate fee for the guarantees is payable because the guarantees relate to other securities that are being registered concurrently.
*	The guarantor subsidiaries of Basic Energy Services, Inc. are identified on the following page.

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

SUBSIDIARY GUARANTOR CO-REGISTRANTS

	State or Other	Primary Standard
	Jurisdiction of	Industrial
Exact Name of Additional	Incorporation or	Classification		I.R.S. Employer
Registrant as Specified in its Charter	Organization	Code Number		Identification No.
Basic Energy Services GP, LLC(1)	Delaware		1389	54-2091197
Basic Energy Services LP, LLC(1)	Delaware		1389	54-2091195
Basic Energy Services, L.P.(1)	Delaware		1389	75-2441819
Basic ESA, Inc.(1)	Texas		1389	75-1772279
Chaparral Service, Inc.(1)	New Mexico		1389	85-0206424
Basic Marine Services, Inc.(1)	Delaware		1389	20-2274888
First Energy Services Company(1)	Delaware		1389	84-1544437
Hennessey Rental Tools, Inc.(1)	Oklahoma		1389	73-1435063
Oilwell Fracturing Services, Inc.(1)	Oklahoma		1311	73-1142826
Wildhorse Services, Inc.(1)	Oklahoma		1389	06-1641442
LeBus Oil Field Service Co.(1)	Texas		4214	75-2073125
Globe Well Service, Inc.(1)	Texas		1389	75-1634275
SCH Disposal, L.L.C.(1)	Texas		1389	75-2788335
JS Acquisition LLC(1)	Delaware		1389	26-2529500
JetStar Holdings, Inc.(1)	Delaware		1389	74-3144248
Acid Services, LLC(1)	Kansas		1389	48-1180455
JetStar Energy Services, Inc.(1)	Texas		1389	68-0605237
Sledge Drilling Corp.(1)	Texas		1381	20-4223140
Permian Plaza, LLC(1)	Texas		6512	26-0753425
Xterra Fishing & Rental Tools Co.(1)	Texas		1389	76-0647818

(1) The address for such Subsidiary Guarantor is 500 W. Illinois, Suite 100, Midland, Texas 79701.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION DATED SEPTEMBER 2, 2009

Basic Energy Services, Inc.

Offer to exchange up to

$225,000,000 of 11.625% Senior Secured Notes Due 2014

that have been registered under the Securities Act of 1933

for

$225,000,000 of 11.625% Senior Secured Notes Due 2014

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          , 2009, 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 11.625% Senior Secured Notes due 2014, which we refer to as the new notes, for any and all of our $225.0 million aggregate principal amount of unregistered 11.625% Senior Secured Notes due 2014, which we refer to as the old notes, that were issued on July 31, 2009.

•  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 will be substantially identical to those of the outstanding old notes, except that the transfer restrictions, registration rights and liquidated damages provisions relating to the old notes will 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 secured basis by all of our current subsidiaries, other than two immaterial subsidiaries, and by all of our current and certain future material restricted subsidiaries that guarantee any of our other indebtedness.

•  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 15 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          , 2009

TABLE OF CONTENTS

	Page
Prospectus Summary		1
Risk Factors		15
Forward-Looking Statements		25
Use of Proceeds		26
Ratio of Earnings to Fixed Charges		26
Capitalization		27
Selected Historical Financial Data		28
Management’s Discussion and Analysis of Financial Condition and Results of Operations		30
Business		55
Management		70
Security Ownership of Certain Beneficial Owners and Management		73
Compensation Discussion and Analysis		76
Executive Compensation and Corporate Governance Matters		88
Certain Relationships and Related Transactions		100
Description of Other Indebtedness		101
The Exchange Offer		102
Description of the New Notes		113
Global Securities; Book-entry System		156
Material United States Federal Income Tax Consequences		159
Plan of Distribution		159
Legal Matters		160
Experts		160
Where You Can Find More Information		160
Index to Consolidated Financial Statements		F-1
Appendix A — Glossary of Terms		A-1
EX-3.10
EX-3.11
EX-3.12
EX-3.13
EX-3.14
EX-3.15
EX-3.16
EX-3.17
EX-3.18
EX-3.24
EX-3.31
EX-3.32
EX-3.33
EX-3.34
EX-3.35
EX-3.36
EX-3.37
EX-3.38
EX-3.39
EX-3.40
EX-3.41
EX-3.42
EX-5.1
EX-8.1
EX-12.1
EX-21.1
EX-23.1
EX-25.1
EX-99.1
EX-99.2
EX-99.3
EX-99.4
EX-99.5

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 is accurate as of any date other than the date on the front cover of this prospectus.

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., 500 W. ILLINOIS, SUITE 100, MIDLAND, TEXAS 79701; TELEPHONE NUMBER:(432) 620-5500. TO OBTAIN TIMELY DELIVERY, YOU MUST REQUEST THIS INFORMATION NO LATER THAN FIVE BUSINESS DAYS BEFORE YOU MUST MAKE YOUR INVESTMENT DECISION. ACCORDINGLY, YOU SHOULD REQUEST THE INFORMATION NO LATER THAN          , 2009.

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.

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.

Basic Energy Services, Inc.

We provide a wide range of well site services to oil and gas drilling and producing companies, including well servicing, fluid services and well site construction services, completion and remedial services and contract drilling. These services are fundamental to establishing and maintaining the flow of oil and gas throughout the productive life of a well. Our broad range of services enables us to meet multiple needs of our customers at the well site. Our operations are managed regionally and are concentrated in the major United States onshore oil and gas producing regions in Texas, New Mexico, Oklahoma, Arkansas, Kansas and Louisiana and the Rocky Mountain states. We provide our services to a diverse group of over 2,000 oil and gas companies. We operate the third-largest fleet of well servicing rigs (also commonly referred to as workover rigs) in the United States. As of December 31, 2008, our fleet represented 12% of the overall available U.S. fleet, with our two larger competitors controlling approximately 27% and 17%, respectively, according to the AESC and other publicly available data.

Basic’s four operating segments are Well Servicing, Fluid Services, Completion and Remedial Services, and Contract Drilling. The following is a description of these segments:

•  Well Servicing.  Our well servicing segment (34% of our revenues in 2008 and 31% of our revenues in the first six months of 2009) currently operates our fleet of 414 well servicing rigs and related equipment. This business segment encompasses a full range of services performed with a mobile well servicing rig, including the installation and removal of downhole equipment and elimination of obstructions in the well bore to facilitate the flow of oil and gas. These services are performed to establish, maintain and improve production throughout the productive life of an oil and gas well and to plug and abandon a well at the end of its productive life. Our well servicing equipment and capabilities are essential to facilitate most other services performed on a well.

•  Fluid Services.  Our fluid services segment (32% of our revenues in 2008 and 42% of our revenues in the first six months of 2009) currently utilizes our fleet of 805 fluid service trucks and related assets, including specialized tank trucks, storage tanks, water wells, disposal facilities, construction and other related equipment. These assets provide, transport, store and dispose of a variety of fluids, as well as provide well site construction and maintenance services. These services are required in most workover, completion and remedial projects and are routinely used in daily producing well operations.

•  Completion and Remedial Services.  Our completion and remedial services segment (30% of our revenues in 2008 and 24% of our revenues in the first six months of 2009) currently operates our fleet of pressure pumping units, an array of specialized rental equipment and fishing tools, air compressor packages specially configured for underbalanced drilling operations, and cased-hole wireline units. The largest portion of this business segment consists of pressure pumping services focused on cementing, acidizing and fracturing services in niche markets. We entered the rental and fishing tool business through an acquisition in the first quarter of 2006.

•  Contract Drilling.  Our contract drilling segment (4% of our revenues in 2008 and 3% of our revenues in the first six months of 2009) currently operates nine drilling rigs and related equipment. We use these assets to penetrate the earth to a desired depth and initiate production from a well. We greatly increased our presence in this line of business through the Sledge Drilling acquisition in the second quarter of 2007.

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General Industry Overview

Demand for services offered by our industry is a function of our customers’ willingness to make operating and capital expenditures to explore for, develop and produce hydrocarbons in the U.S., which in turn is affected by current and expected levels of oil and gas prices. As oil and gas prices increased in recent years, oil and gas companies increased their drilling and workover activities. The increased activity resulted in increased domestic exploration and production spending year over year for the past four years. In the last part of 2008 there was a rapid decline in oil and gas prices which has resulted in significant decreases in domestic spending during the first half of 2009 compared to 2008 domestic spending.

Increased expenditures for exploration and production activities generally drives the increased demand for our services. Rising oil and gas prices in recent years and the corresponding increase in onshore oil exploration and production spending have led to expanded drilling and well service activity, as the U.S. land-based drilling rig count increased approximately 22% during 2005, 17% during 2006, and 4% during 2007. With the rapid decline in oil and gas prices in the second half of 2008 there was a decrease in the land-based drilling rig count of approximately 15% from the peak of 2008 to the end of the year and 43% during the first half of 2009, according to Baker Hughes. The decrease in oil and gas prices coupled with the buildup of drilling and workover rig counts in recent years is resulting in both lower utilization of those rigs and decreases in the rates being charged.

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 414 well servicing rigs as of June 30, 2009 represents the third-largest fleet in the United States, and our goal is to be one of the top two providers of well site services in each of our core operating areas. Our market position allows us to expand the range of services performed on a well throughout its life, such as drilling, maintenance, workover, completion and plugging and abandonment services.

•  Modern and Active Well Servicing Fleet.  We operate a modern and active fleet of well servicing rigs. We believe over 75% of the active U.S. well servicing rig fleet was built prior to 1985. Greater than 50% of our rigs at December 31, 2008 were either 2000 model year or newer, or have undergone major refurbishments during the last five years. As of March 31, 2009, we had taken delivery of all 134 newbuild well servicing rigs since October 2004 as part of a newbuild commitment, driven by our desire to maintain one of the most efficient, reliable and safest fleets in the industry. In addition to our regular maintenance program, we have an established program to routinely monitor and evaluate the condition of our fleet. We selectively refurbish rigs and other assets to maintain the quality of our service and to provide a safe work environment for our personnel and have made major refurbishments on 70 of our rigs since the beginning of 2004. Since 2003, we have obtained annual independent reviews and evaluations of substantially all of our assets, which confirmed the location and condition of these assets.

•  Extensive Domestic Footprint in the Most Prolific Basins.  Our operations are concentrated in the major United States onshore oil and gas producing regions in Texas, New Mexico, Oklahoma, Arkansas, Kansas and Louisiana and the Rocky Mountain states. We operate in states that accounted for approximately 58% of the approximately 900,000 existing onshore oil and gas wells in the 48 contiguous states and approximately 73% of onshore oil production and 90% of onshore gas production in 2008. We believe that our operations are located in the most active U.S. well services markets, as we currently focus our

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operations on onshore domestic oil and gas production areas that include both the highest concentration of existing oil and gas production activities and the largest prospective acreage for new drilling activity. This extensive footprint allows us to offer our suite of services to more than 2,000 customers who are active in those areas and allows us to redeploy equipment between markets as activity shifts.

•  Diversified Service Offering for Further Revenue Growth.  We believe our range of well site services provides us a competitive advantage over smaller companies that typically offer fewer services. Our experience, equipment and network of 115 area offices position us to market our full range of well site services to our existing customers. By utilizing a wider range of our services, our customers can use fewer service providers, which enables them to reduce their administrative costs and simplify their logistics. Furthermore, offering a broader range of services allows us to capitalize on our existing customer base and management structure to grow within existing markets, generate more business from existing customers, and increase our operating profits as we spread our overhead costs over a larger revenue base.

•  Decentralized Management with Strong Corporate Infrastructure.  Our corporate group is responsible for maintaining a unified infrastructure to support our diversified operations through standardized financial and accounting, safety, environmental and maintenance processes and controls. Below our corporate level, we operate a decentralized operational organization in which our nine regional or division managers are responsible for their operations, including asset management, cost control, policy compliance and training and other aspects of quality control. With an average of over 25 years of industry experience, each regional manager has extensive knowledge of the customer base, job requirements and working conditions in each local market. Below our nine regional or division managers, our area managers are directly responsible for customer relationships, personnel management, accident prevention and equipment maintenance, the key drivers of our operating profitability. This management structure allows us to monitor operating performance on a daily basis, maintain financial, accounting and asset management controls, integrate acquisitions, prepare timely financial reports and manage contractual risk.

Our Business Strategy

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

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

•  Expand Within Our Regional Markets.  We intend to continue strengthening our presence within our existing geographic footprint through internal growth and acquisitions of businesses with strong customer relationships, well-maintained equipment and experienced and skilled personnel. We typically enter into new markets through the acquisition of businesses with strong management teams that will allow us to expand within these markets. Management of acquired companies often remain with us and retain key positions within our organization, which enhances our attractiveness as an acquisition partner. We have a record of successfully implementing this strategy. During the past three fiscal years, we have made 23 acquisitions including:

2006

•  LeBus Oil Field Service Co., a fluid service company operating in our Ark-La-Tex region, and

•  G&L Tool, Ltd., a rental and fishing tool company included in our completion and remedial line of business;

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2007

•  JetStar Consolidated Holdings, Inc., a pressure pumping company operating in our completion and remedial line of business, and

•  Sledge Drilling Holding Corp., a contract drilling company operating in our contract drilling line of business;

2008

•  Azurite Services Company, Inc., Azurite Leasing Company, LLC and Freestone Disposal, L.P. (collectively “Azurite”), a fluid service business operating in our Ark-La-Tex and Mid-Continent regions.

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

•  Pursue Growth Through Selective Capital Deployment.  We intend to continue growing our business through selective acquisitions, continuing a newbuild programand/or upgrading our existing assets. Our capital investment decisions are determined by an analysis of the projected return on capital employed of each of those alternatives. Acquisitions are evaluated for “fit” with our area and regional operations management and are thoroughly reviewed by corporate level financial, equipment, safety and environmental specialists to ensure consideration is given to identified risks. We also evaluate the cost to acquire existing assets from a third party, the capital required to build new equipment and the point in the oil and gas commodity price cycle. Based on these factors, we make capital investment decisions that we believe will support our long-term growth strategy, and these decisions may involve a combination of asset acquisitions and the purchase of new equipment. As the oil and gas commodity cycle has declined in recent quarters, we have taken a disciplined approach to acquisitions, with our last acquisition completed in September 2008. We expect to continue this strategy in order to maintain existing operating assets while this cycle continues.

Our strategies could be affected by any of the risk factors described in “Risk Factors” beginning on page 15.

How You Can Contact Us

Our principle executive offices are located at 500 W. Illinois, Suite 100, Midland, Texas 79701, and our telephone number is (432) 620-5500.

Recent Developments

On July 31, 2009, we completed the sale of $225 million principal amount of the old notes. The net proceeds of $208.4 million were used to repay the $180.0 million of borrowings outstanding under our revolving credit facility as of July 31, 2009. The old notes are jointly and severally, and unconditionally, guaranteed on a senior secured basis initially by all of our current subsidiaries other than two immaterial subsidiaries. The old notes and the related guarantees were offered and sold in private transactions in accordance with Rule 144A and Regulation S under the Securities Act of 1933, as amended.

In connection with the closing of the offering of the old notes, we terminated our revolving credit facility, and we are unable to borrow any amounts under it. We expect to rely on cash on hand, which amounted to $134.3 million as of June 30, 2009, in the near term and to evaluate alternatives with respect to a new revolving credit facility or letter of credit facility in the future to address our long term liquidity requirements.

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Corporate Structure

Below is a chart that illustrates our corporate structure.

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The Exchange Offer

On July 31, 2009, 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 best 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	11.625% Senior Secured Notes due August 1, 2014, which were issued on July 31, 2009.
New Notes	11.625% Senior Secured Notes due August 1, 2014. The terms of the new notes are substantially identical to the terms of the outstanding old notes, except that the transfer restrictions, registration rights and liquidated damages provisions relating to the old notes will 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’s 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          , 2009, 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 Mellon Trust Company, N.A., as registrar and exchange agent, at the address listed under the caption “The Exchange Offer — Exchange Agent”; or
	• 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 Mellon Trust Company, N.A., as registrar and

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	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          , 2009. 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 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 Consequences	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 Consequences” 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.

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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 Mellon 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 inno-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 or an affiliate of any of our subsidiary guarantors; 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 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 will be substantially identical, except that the transfer restrictions, registration rights and liquidated damages provisions relating to the old notes will 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. The new notes are governed by the same indenture as the old notes are.

The following summary contains basic information about the new notes and is not intended to be complete. For a more complete understanding of the new notes, please refer to the section in this prospectus entitled “Description of the New Notes.” When we use the term “notes” in this prospectus, unless the context requires otherwise, the term includes the old notes and the new notes.

Issuer	Basic Energy Services, Inc.
Securities Offered	$225,000,000 aggregate principal amount of our 11.625% Senior Secured Notes due 2014.
Interest	The new notes will accrue interest from the date of their issuance at the rate of 11.625% per year. Interest on the new notes will be payable semi-annually in arrears on each February 1 and August 1, commencing on February 1, 2010.
	We have agreed to make additional interest payments to holders of the new notes under certain circumstances if we do not comply with our obligations under the registration rights agreement.
Maturity Date	August 1, 2014.
Guarantees	The new notes will be guaranteed by all of our current subsidiaries, other than two immaterial subsidiaries. The new notes will be guaranteed by all of our current and certain material future restricted subsidiaries that guarantee any of our other indebtedness.
Collateral	The new notes and the guarantees will be secured by a first-priority lien, subject to limited exceptions, on all of the current and future personal property of our company and our guarantor subsidiaries, except for cash and cash equivalents, accounts receivable, inventory, maritime assets (including our existing inland barge rigs), titled vehicles and the stock or other equity interests of our subsidiaries. As of June 30, 2009, the net book value of the collateral included approximately $509 million of property and equipment, which represents 71% of our total property and equipment.
Ranking	The new notes will be our senior secured indebtedness. Both the new notes and the subsidiary guarantees will rank:
	• equally in right of payment with any of our and the subsidiary guarantors’ existing and future senior indebtedness, including our existing senior notes and the related guarantees; and
	• effectively junior to all existing or future liabilities of our subsidiaries that do not guarantee the notes and to our existing or future indebtedness that is secured by assets other than the collateral securing the new notes to the extent of the value of the collateral therefor.

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	As of June 30, 2009 as adjusted to give effect to the offering of the old notes and the use of the net proceeds from the offering, (i) we and our subsidiaries would have had no secured indebtedness outstanding other than the old notes and related guarantees, $75.3 million of capital lease obligations and letters of credit collateralized by $16.2 million of cash and (ii) we and our subsidiary guarantors would have had $225.0 million of unsecured senior indebtedness outstanding.
Optional Redemption	We may redeem the notes, in whole or in part, at any time on or after February 1, 2012 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.
	At any time before February 1, 2012, 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 111.625% 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 February 1, 2012, 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 then outstanding debt agreements. We cannot assure you that we will have the financial resources to purchase the notes in such circumstances.
Certain Covenants	The indenture contains covenants that, among other things, 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.

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	These and other covenants that are contained in the indenture are subject to important exceptions and qualifications, which are described under “Description of the New Notes.”
Absence of a Public Market for the NewNotes	There is no public trading market for the new notes, and we do not intend to apply for listing of the new notes on any national securities exchange or for quotation of the new notes on any automated dealer quotation system. See “Risk Factors — Risks Relating to the Exchange Offer and the New Notes — An active trading market may not develop for the new notes.”
Risk Factors	See “Risk Factors” beginning on page 15 for discussion of factors you should carefully consider before deciding to participate in the exchange offer.

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Summary Historical Financial Information

The following summary of historical financial data is derived from our audited consolidated financial statements as of and for the years ended December 31, 2008, 2007 and 2006 and our unaudited interim financial statements as of and for the six months ended June 30, 2009 and 2008. The data set forth below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” our consolidated financial statements and the notes thereto and the other financial information included in this prospectus.

	Year Ended December 31,									Six Months Ended June 30,
	2008			2007			2006			2009			2008
	(Dollars in thousands)									(Unaudited)
Statement of Operations Data:
Revenues:
Well servicing	$	343,113		$	342,697		$	323,755		$	85,213		$	169,537
Fluid services		315,768			259,324			245,011			114,065			143,980
Completion and remedial services		304,326			240,692			154,412			66,632			148,037
Contract drilling		41,735			34,460			6,970			7,626			19,841
Total revenues		1,004,942			877,173			730,148			273,536			481,395
Expenses:
Well servicing		215,243			205,132			178,028			64,742			103,759
Fluid services		203,205			165,327			153,445			79,968			94,987
Completion and remedial services		165,574			125,948			74,981			47,378			78,439
Contract drilling		28,629			22,510			8,400			6,607			14,589
General and administrative(1)		115,319			99,042			81,318			56,503			52,663
Depreciation and amortization		118,607			93,048			62,087			65,150			56,764
Loss (gain) on disposal of assets		76			477			277			1,339			(584	)
Goodwill impairment		22,522			—			—			204,014			—
Total expenses		869,175			711,484			558,536			525,701			400,617
Operating income (loss)		135,767			165,689			171,612			(252,165	)		80,778
Other income (expense):
Net interest expense		(24,630	)		(25,136	)		(15,504	)		(11,317	)		(12,630	)
Loss on early extinguishment of debt		—			(230	)		(2,705	)		—			—
Other income (expense)		12,235			176			169			252			(6,431	)
Income (loss) from continuing operations before income taxes		123,372			140,499			153,572			(263,230	)		61,717
Income tax benefit (expense)		(55,134	)		(52,766	)		(54,742	)		59,169			(23,348	)
Net Income (loss)	$	68,238		$	87,733		$	98,830		$	(204,061	)	$	38,369
Statement of Cash Flow Data:
Cash flows from operating activities	$	212,827		$	198,591		$	145,678		$	73,049		$	87,328
Cash flows from investing activities		(197,302	)		(294,103	)		(241,351	)		(25,460	)		(91,840	)
Cash flows from financing activities		3,669			136,088			114,193			(24,420	)		(9,645	)
Capital expenditures:
Acquisitions, net of cash acquired		110,913			199,673			135,568			1,190			51,239
Property and equipment		91,890			98,536			104,574			25,187			45,023
Other Financial Data:
Ratio of earnings to fixed charges		4.7x			5.2x			7.9x			(2	)

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	As of December 31,						As of June 30,
									2009
	2008		2007		2006		2009		(As Adjusted)(3)
	(Dollars in thousands)						(Unaudited)
Balance Sheet Data:
Cash and cash equivalents	$	111,135	$	91,941	$	51,365	$	134,304	$	162,719
Property and equipment, net		740,879		636,924		475,431		714,560		714,560
Total assets		1,310,711		1,143,609		796,260		1,068,393		1,101,290
Long-term debt, including current portion		480,323		423,719		262,743		480,274		513,171
Stockholders’ equity		595,004		524,821		379,250		387,219		387,219

(1)	Includes approximately $4,149,000, $3,964,000, $3,429,000, $2,665,000 and $2,264,000 of non-cash stock compensation expense for the years ended December 31, 2008, 2007 and 2006 and the six months ended June 30, 2009 and 2008, respectively.
(2)	Earnings were inadequate to cover fixed charges for the six months ended June 30, 2009 by $249.3 million.
(3)	Gives effect to the offering of the old notes and the application of the net proceeds therefrom as if each had occurred on June 30, 2009.

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Operating Data

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

•  we charge our well servicing customers on an hourly basis, and 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 that revenue per truck is a more meaningful measure for this segment;

•  in our completion and remedial services segment, we charge different rates for our pressure pumping trucks based on the type of services performed and varying horsepower requirements, making segment profits the most meaningful measure of performance; and

•  in our contract drilling segment, revenues are derived primarily from the drilling of new wells, making rig operating days, revenue per drilling day and segment profits as a percent of revenues the most meaningful measures of performance.

										Six Months Ended
	Year Ended December 31,									June 30,
	2008			2007			2006			2009			2008
Well Servicing:
Weighted average number of rigs		405			376			344			414			398
Rig hours (000’s)		840.2			831.2			868.2			242.8			424.8
Rig utilization rate		72.5	%		77.3	%		88.2	%		41.0	%		74.6	%
Revenue per rig hour	$	408		$	412		$	373		$	351		$	399
Segment profits per rig hour	$	152		$	166		$	168		$	84		$	155
Segment profits as a percent of revenue		37.3	%		40.1	%		45.0	%		24.0	%		38.8	%
Fluid Services:
Weighted average number of fluid service trucks		699			655			588			811			654
Revenue per fluid service truck (000’s)	$	452		$	396		$	417		$	141		$	220
Segment profits per fluid service truck (000’s)	$	161		$	144		$	156		$	42		$	75
Segment profits as a percent of revenue		35.6	%		36.2	%		37.4	%		29.9	%		34.0	%
Completion and Remedial Services:
Segment profits as a percent of revenue		45.6	%		47.7	%		51.5	%		28.9	%		47.0	%
Contract Drilling:
Weighted average number of rigs		9			8			2			9			9
Rig operating days		2,777			2,233			484			562			1,344
Revenue per day (000’s)	$	15		$	15		$	14		$	14		$	15
Profits (loss) per day (000’s)	$	5		$	5		$	(3	)	$	2		$	4
Segment profits as a percent of revenue		31.4	%		34.7	%		(20.5	)%		13.4	%		26.5	%

Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for an analysis of our well servicing, fluid services, completion and remedial services and contract drilling segments.

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RISK FACTORS

Prior to making a decision about participating in the exchange offer, and in consultation with your own financial and legal advisors, you should carefully consider, among other matters, the following risk factors. If any of these risks were to occur, our business, results of operations or financial condition could be materially and adversely affected.

Risks Relating to Our Business

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

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

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

Recent deterioration in the global economic environment has caused the oilfield services industry to cycle into a downturn, and the rate at which it may continue to slow, or return to former levels, is uncertain. Recent adverse changes in capital markets and declines in prices for oil and gas have caused many oil and gas producers to announce reductions in capital budgets for future periods. Limitations on the availability of capital, or higher costs of capital, for financing expenditures have caused and may continue to cause these and other oil and gas producers to make additional reductions to capital budgets in the future even if commodity prices increase from current levels. These cuts in spending will curtail drilling programs as well as discretionary spending on well services, which have resulted in a significant reduction in the demand for our services, the rates we can charge and our utilization and may continue to do so in the future. In addition, certain of our customers could become unable to pay their suppliers, including us. As a result of these conditions, our customers’ spending patterns have become increasingly unpredictable, making it difficult for us to predict our future operating results. Accordingly, our results may differ significantly from our forecasts and those of the investment community. Any of these conditions or events could adversely affect our operating results.

If oil and gas prices remain volatile, remain low or decline further it could have an adverse effect on the demand for our services.

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

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Prices for oil and gas historically have been extremely volatile and are expected to continue to be volatile. Although oil prices exceeded $140 per barrel and natural gas prices exceeded $13 per mcf in 2008, prices fell to below $40 per barrel and $6 per mcf by the end of 2008. The Cushing WTI Spot Oil Price averaged $66.05, $72.34 and $99.67 per barrel in 2006, 2007 and 2008, respectively, and $51.18 per barrel for the first six months of 2009. The average wellhead price for natural gas, as recorded by the Energy Information Agency, was $6.42, $6.38 and $8.07 per mcf for 2006, 2007 and 2008, respectively, and $3.99 per mcf for the first five months of 2009. The speed and severity of the decline in natural gas prices during the fourth quarter of 2008 and the resulting low prices in the first half of 2009 has materially affected and may continue to materially affect the demand for our services and the rates that we are able to charge. Likewise, the overall decline in oil prices from their highest levels in 2008 and the uncertainty regarding the sustainability of current oil prices has materially affected and may continue to materially affect the demand for our services and the rates that we are able to charge.

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

We anticipate that we will continue to make substantial capital investments to purchase additional equipment to expand our services, refurbish our well servicing rigs and replace existing equipment. For the year ended December 31, 2007, we invested approximately $98.5 million in cash for capital expenditures, excluding acquisitions. For the year ended December 31, 2008, we invested approximately $91.9 million in cash for capital expenditures, excluding acquisitions. For the six months ended June 30, 2009, we invested approximately $25.2 million in cash for capital expenditures, excluding acquisitions, and we currently expect our aggregate capital expenditures for 2009 to be approximately $57.5 million. Historically, we have financed these investments through internally generated funds, debt and equity offerings, our capital lease program and our prior senior credit facility, which was terminated on July 31, 2009 in connection with the offering of the old notes. These significant capital investments require cash that we could otherwise apply to other business needs. However, if we do not incur these expenditures while our competitors make substantial fleet investments, our market share may decline and our business may be adversely affected. In addition, if we are unable to generate sufficient cash internally or obtain alternative sources of capital to fund our proposed capital expenditures and acquisitions, take advantage of business opportunities or respond to competitive pressures, it could materially adversely affect our results of operations, financial condition and growth. The recent adverse changes in the capital markets could make it difficult to obtain capital or obtain it at attractive rates.

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

We now have, and will continue to have, a significant amount of indebtedness. As of June 30, 2009, our total debt was $480.3 million, including $180.0 million of borrowings under our prior senior credit facility, the $225.0 million aggregate principal amount due under our 7.125% Senior Notes due 2016 and capital lease obligations in the aggregate amount of $75.3 million. We repaid all borrowings outstanding under our prior senior credit facility on July 31, 2009, with the proceeds from the issuance of the old notes. For the year ended December 31, 2008, we made cash interest payments totaling $24.5 million. For the six months ended June 30, 2009, we made cash interest payments totaling $12.3 million.

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

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

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

•  make us more vulnerable to a downturn in our business, our industry or the economy in general as a substantial portion of our operating cash flow will be required to make principal and interest payments

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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 instruments governing any existing or future indebtedness, we could be in default under the terms of 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 and we or one or more of our subsidiaries could be forced into bankruptcy or liquidation. If our indebtedness is accelerated, or we enter into bankruptcy, we may be unable to pay all of our indebtedness in full.

The indentures governing our 7.125% Senior Notes due 2016 and our 11.625% Senior Secured Notes due 2014 impose, and future credit facilities may impose, restrictions on us that may affect our ability to successfully operate our business.

The indentures governing our 7.125% Senior Notes due 2016 and our 11.625% Senior Secured Notes due 2014 include, and we expect future credit facilities may include, limitations on our ability to take various actions, such as:

•  limitations on the incurrence of additional indebtedness;

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

•  limitation on dividends and distributions.

In addition, a future credit facility could require us to maintain certain financial ratios and to satisfy certain financial conditions, several of which could become more restrictive over time and may require us to reduce our debt or take some other action in order to comply with them. The failure to comply with any of these financial conditions, including the financial ratios or covenants, would cause a default under any such credit facility. A default, if not waived, could result in acceleration of the outstanding indebtedness under any such credit facility, in which case the debt would become immediately due and payable. In addition, a default or acceleration of indebtedness under any such credit facility could result in a default or acceleration of our existing senior notes and senior secured 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 a future credit facility.

At the closing of our offering of the old notes, we pledged cash collateral with respect to the approximately $16.2 million of letters of credit that were outstanding under our revolving credit facility. We terminated the revolving credit facility on July 31, 2009, and we are unable to borrow any amounts under it. We expect to rely on cash on hand in the near term and to evaluate alternatives with respect to a new revolving credit facility or letter of credit facility in the future to address our long term liquidity requirements. The indenture governing the notes limits the amount that we could borrow under a future secured credit facility to the difference between (i) $240 million and (ii) the sum of (a) $212.9 million (the principal amount of the notes, net of offering discount) and (b) our outstanding collateralized letters of credit, subject to possible upward adjustment of the amount in clause (i) based on our consolidated tangible assets. While we have significant available cash after closing our offering of the old notes, our future cash balances could decrease

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and affect our financial condition. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

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 currently exceeds demand, which has resulted 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 and the existence of excess equipment have resulted in lower utilization rates.

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

Our customers consist primarily of major and independent oil and gas companies. During 2007 and 2008, our top five customers accounted for 16% and 18% of our revenues, respectively, and they accounted for 22% of our revenues for the first six months of 2009. 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 may not be able to grow successfully through future acquisitions or successfully manage future growth, and we may not be able to effectively integrate the businesses we do acquire.

Our business strategy includes growth through the acquisitions of other businesses. We may not be able to continue to identify attractive acquisition opportunities or successfully acquire identified targets. In addition, we may not be successful in integrating our current or future acquisitions into our existing operations, which may result in unforeseen operational difficulties or diminished financial performance or require a disproportionate amount of our management’s attention. Even if we are successful in integrating our current or future acquisitions into our existing operations, we may not derive the benefits, such as operational or administrative synergies, that we expected from such acquisitions, which may result in the commitment of our capital resources without the expected returns on such capital. Furthermore, competition for acquisition opportunities may escalate, increasing our cost of making further acquisitions or causing us to refrain from making additional acquisitions.

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. 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.

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

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

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

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

•  personal injury or loss of life;

•  damage to or destruction of property and equipment (including the collateral securing the notes) 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 our being named as a defendant in lawsuits asserting large claims.

We maintain insurance coverage that we believe to be customary in the industry against these hazards. However, we do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. As such, not all of our property is insured. We are also self-insured up to retention limits with regard to workers’ compensation and medical and dental coverage. We maintain accruals in our consolidated balance sheets related to self-insurance retentions by using third-party data and historical claims history. The occurrence of an event not fully insured against, or the failure of an insurer to meet its insurance obligations, could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive. It is likely that, in our insurance renewals, our premiums and deductibles will be higher, and certain insurance coverage either will be unavailable or considerably more expensive than it has been in the recent past. In addition, our insurance is subject to coverage limits, and some policies exclude coverage for damages resulting from environmental contamination.

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

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

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

Risks Relating 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 failing to tender your old notes in the exchange offer, please read “The Exchange Offer — Consequences of Failure to Exchange Outstanding Securities.”

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.

There may not be sufficient collateral to pay all of the new notes.

The new notes and the guarantees are secured by a first-priority lien, subject to limited exceptions, on certain of our current and future assets. See “Description of the New Notes — Security.”

No appraisals of any collateral have been prepared in connection with this exchange offer. Estimating the value of the collateral is a subjective process and subject to considerable uncertainty. As of June 30, 2009, the net book value of the collateral included approximately $509 million of property and equipment. Furthermore, the collateral will likely decline in value over time, though the value of the collateral at any time will depend on market and other economic conditions, including the availability of suitable buyers for the collateral. By its nature, some or all of the collateral may be illiquid and may have no readily ascertainable market value. The value of the assets pledged as collateral for the new notes could be impaired in the future as a result of changing economic conditions, volatility of or further reduction in oil and gas prices, competition or other future trends. As such, the sale value of the collateral may be substantially different from its book value. In the event of a foreclosure, liquidation, bankruptcy or similar proceeding, no assurance can be given that the proceeds from any sale or liquidation of the collateral will be sufficient to pay our obligations under the new notes in full. See “Description of the New Notes — Security.” Accordingly, there may not be sufficient collateral to pay all of the amounts due on the new notes. Any claim for the difference between any amount realized by holders of the new notes from the sale of the collateral securing the new notes and the obligations

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under the new notes will rank equally in right of payment with all of our other senior indebtedness and other unsubordinated obligations, including trade payables.

To the extent that third parties enjoy prior liens, such third parties may have rights and remedies with respect to the property subject to such liens that, if exercised, could adversely affect the value of the collateral. Additionally, the terms of the indenture will allow us to issue additional notes in certain circumstances. The indenture will not require that we maintain the current level of collateral or maintain a specific ratio of indebtedness to asset values. Any additional notes issued pursuant to the indenture will rank pari passu with the new notes and be entitled to the same rights and priority with respect to the collateral. Thus, the issuance of additional notes pursuant to the indenture may have the effect of significantly diluting your ability to recover payment in full from the then existing pool of collateral. Releases of collateral from the liens securing the new notes are permitted under some circumstances. See “Description of the New Notes — Security.”

The collateral is subject to casualty risks.

We are obligated under the collateral arrangements to maintain adequate insurance or otherwise insure against hazards as is usually done by corporations operating assets of a similar nature in the same or similar localities. There are, however, certain losses that may be either uninsurable or not economically insurable, in whole or in part. As a result, it is possible that the insurance proceeds will not compensate us fully for our losses. If there is a total or partial loss of any of the collateral, we cannot assure you that any insurance proceeds received by us will be sufficient to satisfy all of our secured obligations, including the new notes. Please read “— Risks Relating to Our Business — Our operations are subject to inherent risks, some of which are beyond our control. These risks may be self-insured, or may not be fully covered under our insurance policies” above for further discussion of risks to our operations and the collateral securing the new notes.

In the event of a bankruptcy, your ability to realize upon the collateral will be subject to certain bankruptcy law limitations.

The right of the trustee to repossess and dispose of the collateral securing the new notes upon acceleration is likely to be significantly impaired by federal bankruptcy law if bankruptcy proceedings are commenced by or against us prior to or possibly even after the trustee has repossessed and disposed of the collateral. Under the U.S. Bankruptcy Code, a secured creditor, such as the trustee for the new notes, is prohibited from repossessing its security from a debtor in a bankruptcy case, or from disposing of security repossessed from a debtor, without bankruptcy court approval. Moreover, bankruptcy law permits the debtor to continue to retain and to use collateral, and the proceeds, products, rents or profits of the collateral, even though the debtor is in default under the applicable debt instruments, provided that the secured creditor is given “adequate protection.” The meaning of the term “adequate protection” may vary according to circumstances, but it is intended in general to protect the value of the secured creditor’s interest in the collateral and may include cash payments or the granting of additional security, if and at such time as the court in its discretion determines, for any diminution in the value of the collateral as a result of the stay of repossession or disposition or any use of the collateral by the debtor during the pendency of the bankruptcy case. In view of the broad discretionary powers of a bankruptcy court, it is impossible to predict how long payments under the new notes could be delayed following commencement of a bankruptcy case, whether or when the trustee would repossess or dispose of the collateral, or whether or to what extent holders of the new notes would be compensated for any delay in payment of loss of value of the collateral through the requirements of “adequate protection.” Furthermore, in the event the bankruptcy court determines that the value of the collateral is not sufficient to repay all amounts due on the new notes, the holders of the new notes would have “undersecured claims” as to the difference. Federal bankruptcy laws do not permit the payment or accrual of interest, costs and attorneys’ fees for “undersecured claims” during the debtor’s bankruptcy case. Finally, the trustee’s ability to foreclose on the collateral on your behalf may be subject to procedural restrictions, the consent of third parties and practicable problems associated with the realization of the security interest in the collateral.

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Your rights in the collateral may be adversely affected by the failure to perfect security interests in certain collateral existing or acquired in the future.

The security interest in the collateral securing the new notes includes our drilling rigs and well service rigs, whether now owned or acquired in the future, as well as considerable additional assets. There can be no assurance that the trustee will monitor, or that we will inform the trustee of, the future acquisition of assets that constitute collateral, and that the necessary action will be taken to properly perfect the security interest in such after-acquired collateral. The failure to perfect a security interest in respect of such after-acquired collateral may result in the loss of the security interest therein or the priority of the security interest in favor of the new notes against third parties.

If we or any guarantor were to become subject to a bankruptcy proceeding after the issue date of the old notes, any liens recorded or perfected after the issue date of the old notes would face a greater risk of being avoided than if they had been recorded or perfected on the issue date. If a lien is recorded or perfected after the issue date, it may be treated under bankruptcy law as if it were delivered as a preferential transfer to secure previously existing debt. In bankruptcy proceedings commenced within 90 days of lien perfection, a lien given to secure previously existing debt is materially more likely to be avoided as a preference by the bankruptcy court than if delivered and promptly recorded on the issue date of the old notes. Accordingly, if we or a guarantor were to file for bankruptcy after the issue date of the old notes and the liens had been perfected less than 90 days before commencement of such bankruptcy proceeding, the liens securing the notes may be especially subject to challenge as a result of having been delivered after the issue date of the old notes. To the extent that such challenge succeeded, you would lose the benefit of the security that the collateral was intended to provide.

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 our control. We cannot assure you that our business will generate sufficient cash flow from operations 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 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. Although the indenture governing the notes contains 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 Financial Data” and “Description of 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.

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A court could cancel the new notes or the guarantees of the initial or future guarantors and the security interests in the collateral under fraudulent conveyance laws or certain other circumstances.

All of our current subsidiaries, other than two immaterial subsidiaries, and all of our future material restricted subsidiaries that guarantee our other indebtedness, guarantee the notes. If we or such a subsidiary becomes a debtor in a case under the U.S. Bankruptcy Code or encounters other financial difficulty, under federal or state laws governing fraudulent transfer, renewable transactions or preferential payments, a court in the relevant jurisdiction might avoid or cancel its guaranteeand/or the liens created by the security interest in its collateral. The court might do so if it found that, when the subsidiary entered into its guarantee and security arrangement or, in some states, when payments became due thereunder, (a) it received less than reasonably equivalent value or fair consideration for such guaranteeand/or security arrangement and (b) either (i) was or was rendered insolvent, (ii) was left with inadequate capital to conduct its business, or (iii) believed or should have believed that it would incur debts beyond its ability to pay. The court might also avoid such guaranteeand/or security arrangement, without regard to the above factors, if it found that the subsidiary entered into its guaranteeand/or security arrangement with actual or deemed intent to hinder, delay, or defraud our creditors.

Similarly, if we become a debtor in a case under the U.S. Bankruptcy Code or encounter other financial difficulty, a court might cancel our obligations under the notes, if it found that when we issued the notes (or in some jurisdictions, when payments become due under the notes), factors (a) and (b) above applied to us, or if it found that we issued the notes with actual intent to hinder, delay or defraud our creditors.

A court would likely find that a subsidiary did not receive reasonably equivalent value or fair consideration for its guarantee unless it benefited directly or indirectly from the issuance of the notes. If a court avoided such guarantee, holders of the notes would no longer have a claim against such subsidiary. In addition, the court might direct holders of the notes to repay any amounts already received from such subsidiary. If the court were to avoid any guarantee, we cannot assure you that funds would be available to pay the notes from another subsidiary or from any other source.

The indenture states that the liability of each subsidiary on its guarantee and security arrangement is limited to the maximum amount that the subsidiary can incur without risk that the guarantee or security arrangement will be subject to avoidance as a fraudulent conveyance or fraudulent transfer. See “Description of the New Notes — Note Guarantees.” This limitation may not protect the guaranteesand/or security arrangements from a fraudulent conveyance attack or, if it does, the guaranteesand/or security arrangements may not be in amounts sufficient, if necessary, to pay obligations under the notes when due.

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. Any of our future debt agreements may contain provisions relating to the acceleration of indebtedness or restrictions on our ability to repay the notes upon a change in control. If a purchase offer obligation arises under the indenture governing the notes, a similar obligation would likely arise with respect to our outstanding 7.125% Senior Notes due 2016. 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.

In a recent decision, the Chancery Court of Delaware raised the possibility that a change of control put right occurring as a result of a failure to have “continuing directors” comprising a majority of a board of directors may be unenforceable on public policy grounds.

An active trading market may not develop for the new notes.

The new notes are a new issue of securities. There is no active public trading market for the new notes, and the new notes will not be listed on any securities exchange.

We cannot assure you that an active trading market will develop for the new notes or that the new notes will trade as one class with the old notes. In addition, the liquidity of the trading market in the new notes and

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the market prices quoted for the new 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.

You generally are required to accrue income before you receive cash attributable to original issue discount on the notes. Additionally, in the event we enter into bankruptcy, you may not have a claim for all or a portion of any unamortized amount of the original discount on the notes.

The old notes were issued with original issue discount (“OID”) for U.S. federal income tax purposes. Accordingly, if you are an individual or entity subject to U.S. tax, you generally are required to accrue interest in the form of OID on a current basis in respect of the notes, include such accrued interest in income and pay tax accordingly, even before you receive cash attributable to that income. Additionally, a bankruptcy court may not allow a claim for all or a portion of any unamortized amount of the OID on the notes.

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FORWARD-LOOKING STATEMENTS

This prospectus contains “forward-looking statements” as that term is defined in the Private Securities Litigation Reform Act of 1995. The forward-looking statements include statements relating to goals, plans and projections regarding our financial position, results of operations, market position, product development and business strategy under the headings “Prospectus Summary” and “Risk Factors.” These statements are based on management’s current expectations and involve significant risks and uncertainties that may cause results to differ materially from those set forth in the statements.

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

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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.

RATIO OF EARNINGS TO FIXED CHARGES

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

																Six
																Months
																Ended
	Year Ended December 31,															June 30,
	2008			2007			2006			2005			2004			2009
Ratio of earnings to fixed charges		4.7	x		5.2	x		7.9	x		5.6	x		2.8	x		—	(a)

For these ratios, “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.

(a) Earnings were inadequate to cover fixed charges for the six months ended June 30, 2009 by $249.3 million.

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of June 30, 2009:

•  on an actual basis; and

•  on an as adjusted basis to give effect to the offering of our 11.625% Senior Secured Notes due 2014 and the use of proceeds therefrom.

This table should be read in conjunction with “Summary Historical Consolidated Financial Information,” “Selected Historical Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the related notes thereto included elsewhere in this prospectus.

	As of June 30, 2009
	Actual			As Adjusted
	(In thousands)
Cash and cash equivalents	$	134,304		$	162,719
Total long-term debt, including current portion:
Notes payable:
Tranche A and Tranche B loans under revolving credit facility(1)		180,000			—
11.625% Senior Secured Notes due 2014		—			212,897	(2)
7.125% Senior Notes due 2016		225,000			225,000
Other debt and obligations under capital leases		75,274			75,274
Total		480,274			513,171
Stockholders’ equity:
Common stock, $.01 par value, 80,000,000 shares authorized; 42,394,809 shares issued and 40,703,187 shares outstanding		424			424
Additional paid-in capital		328,101			328,101
Deferred compensation		—			—
Retained earnings		72,642			72,642
Treasury stock, 1,691,622 shares, at cost		(13,948	)		(13,948	)
Accumulated other comprehensive income		—			—
Total stockholders’ equity		387,219			387,219
Total capitalization	$	867,493		$	900,390

(1)

As of the closing on July 31, 2009, we had borrowings of an aggregate of $208.8 million under the revolving credit facility, all of which were repaid with the proceeds from the offering. We terminated the revolving credit facility after closing our senior secured notes offering, and we pledged cash collateral with respect to the approximately $16.2 of million letters of credit that were outstanding under the revolving credit facility before closing the senior secured notes offering.

(2)

The $225.0 million of notes are recorded at their discounted amount, with the discount to be amortized over the life of the notes.

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

																Six Months Ended
	Year Ended December 31,															June 30,
	2008			2007			2006			2005			2004			2009			2008
	(Dollars in thousands)															(Unaudited)
Statement of Operations Data:
Revenues:
Well servicing	$	343,113		$	342,697		$	323,755		$	221,993		$	142,551		$	85,213		$	169,537
Fluid services		315,768			259,324			245,011			177,927			139,610			114,065			143,980
Completion and remedial services		304,326			240,692			154,412			59,832			29,341			66,632			148,037
Contract drilling		41,735			34,460			6,970			—			—			7,626			19,841
Total revenues		1,004,942			877,173			730,148			459,752			311,502			273,536			481,395
Expenses:
Well servicing		215,243			205,132			178,028			137,392			98,058			64,742			103,759
Fluid services		203,205			165,327			153,445			114,551			96,621			79,968			94,987
Completion and remedial services		165,574			125,948			74,981			30,900			17,481			47,378			78,439
Contract drilling		28,629			22,510			8,400			—			—			6,607			14,589
General and administrative(a)		115,319			99,042			81,318			55,411			37,186			56,503			52,663
Depreciation and amortization		118,607			93,048			62,087			37,072			28,676			65,150			56,764
Loss (gain) on disposal of assets		76			477			277			(222	)		2,616			1,339			(584	)
Goodwill impairment		22,522			—			—			—			—			204,014			—
Total expenses		869,175			711,484			558,536			375,104			280,638			525,701			400,617
Operating income (loss)		135,767			165,689			171,612			84,648			30,864			(252,165	)		80,778
Other income (expense):
Net interest expense		(24,630	)		(25,136	)		(15,504	)		(12,660	)		(9,550	)		(11,317	)		(12,630	)
Gain (loss) on early extinguishment of debt		—			(230	)		(2,705	)		(627	)		—			—			—
Other income (expense)		12,235			176			169			220			(398	)		252			(6,431	)
Income (loss) from continuing operations before income taxes		123,372			140,499			153,572			71,581			20,916			(263,230	)		61,717
Income tax benefit (expense)		(55,134	)		(52,766	)		(54,742	)		(26,800	)		(7,984	)		59,169			(23,348	)
Income (loss) from continuing operations		68,238			87,733			98,830			44,781			12,932			(204,061	)		38,369
Discontinued operations, net of tax		—			—			—			—			(71	)		—			—
Net income (loss)	$	68,238		$	87,733		$	98,830		$	44,781		$	12,861		$	(204,061	)	$	38,369

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																Six Months Ended
	Year Ended December 31,															June 30,
	2008			2007			2006			2005			2004			2009			2008
	(Dollars in thousands)															(Unaudited)
Other Financial Data:
Cash flows from operating activities	$	212,827		$	198,591		$	145,678		$	99,189		$	46,539		$	73,049		$	87,328
Cash flows from investing activities		(197,302	)		(294,103	)		(241,351	)		(107,679	)		(73,587	)		(25,460	)		(91,840	)
Cash flows from financing activities		3,669			136,088			114,193			21,188			21,498			(24,420	)		(9,645	)
Capital expenditures:
Acquisitions, net of cash acquired		110,913			199,673			135,568			25,378			19,284			1,190			51,239
Property and equipment		91,890			98,536			104,574			83,095			55,674			25,187			45,023

	As of December 31,										As of June 30,
	2008		2007		2006		2005		2004		2009		2008
	(Dollars in thousands)										(Unaudited)
Balance Sheet Data:
Cash and cash equivalents	$	111,135	$	91,941	$	51,365	$	32,845	$	20,147	$	134,304	$	77,784
Property and equipment, net		740,879		636,924		475,431		309,075		233,451		714,560		665,922
Total assets		1,310,711		1,143,609		796,260		496,957		367,601		1,068,393		1,209,776
Long-term debt, including current portion		480,323		423,719		262,743		126,887		182,476		480,274		433,367
Stockholders’ equity		595,004		524,821		379,250		258,575		121,786		387,219		566,683

(a) Includes approximately $4,149,000, $3,964,000, $3,429,000, $2,890,000 and $1,587,000 of non-cash stock compensation expense for the years ended December 31, 2008, 2007, 2006, 2005 and 2004, respectively, and $2,665,000 and $2,264,000 in the six months ended June 30, 2009 and 2008, 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, completion and remedial services and contract drilling. Our results of operations reflect the impact of our acquisition strategy as a leading consolidator in the domestic land-based well services industry. Our acquisitions have increased our breadth of service offerings at the well site and expanded our market presence. In implementing this strategy, we purchased businesses and assets in 40 separate acquisitions from January 1, 2004 to June 30, 2009. Our weighted average number of well servicing rigs increased from 279 in 2004 to 414 in the second quarter of 2009 and our weighted average number of fluid service trucks increased from 386 to 808 in the same period. We added 98 trucks through the acquisition of Azurite Services Company, Inc., Azurite Leasing Company, LLC, and Freestone Disposal, LP (collectively “Azurite”) in the third quarter of 2008. We significantly increased our completion and remedial services segment, principally through the acquisition of JetStar Consolidated Holdings, Inc. in the first quarter of 2007. Our weighted average number of drilling rigs increased from two in the first quarter of 2006 to nine in the fourth quarter of 2008, principally through the acquisition of Sledge Drilling Holding Corp. in the second quarter of 2007. These acquisitions make our revenues, expenses and income not directly comparable between periods.

Basic revised its business segments beginning in the first quarter of 2008, and in connection therewith, restated the corresponding items of segment information for earlier periods. The new operating segments are Well Servicing, Fluid Services, Completion and Remedial Services, and Contract Drilling. These segments were selected based on changes in management’s resource allocation and performance assessment in making decisions regarding the Company. Contract Drilling was previously included in our Well Servicing segment. The Well Site Construction Services segment was consolidated into our Fluid Services segment. These changes reflect Basic’s operating focus in compliance with Statement of Financial Accounting Standards (SFAS) No. 131,“Disclosures about Segments of an Enterprise and Related Information.”

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,
	2008				2007				2006				2009				2008
Revenues:
Well servicing	$	343.1	34	%	$	342.7	39	%	$	323.7	44	%	$	85.2	31	%	$	169.5	35	%
Fluid services		315.8	32	%		259.3	29	%		245.0	34	%		114.1	42	%		144.0	30	%
Completion and remedial		304.3	30	%		240.7	28	%		154.4	21	%		66.6	24	%		148.0	31	%
Contract drilling		41.7	4	%		34.5	4	%		7.0	1	%		7.6	3	%		19.8	4	%
Total revenues	$	1,004.9	100	%	$	877.2	100	%	$	730.1	100	%	$	273.5	100	%	$	481.3	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.

We derive a majority of our revenues from services supporting production from existing oil and gas operations. Demand for these production-related services, including well servicing and fluid services, tends to remain relatively stable, even in moderate oil and gas price environments, as ongoing maintenance spending is required to sustain production. As oil and gas prices fluctuate, demand for all of our services changes correspondingly as our customers must balance maintenance and capital expenditures against their available cash flows. Because our services are required to support drilling and workover activities, we are also subject

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to changes in capital spending by our customers as oil and gas prices increase or decrease. Adverse changes in capital markets also caused a number of oil and gas producers to reduce their capital budgets for the remainder of 2009. Limitations on the availability of capital, or higher costs of capital, for financing expenditures may cause these and other oil and gas producers to make additional reductions to capital budgets in the future even if commodity prices return to historically high levels.

During 2006, our business activity levels increased due to the impact of higher oil and gas prices and the expansion of our equipment fleets. In 2007, natural gas prices declined as an excess supply of natural gas began to occur, mainly due to moderate U.S. weather patterns. Utilization for our services declined from 2006 levels as drilling activity flattened or declined in several of our markets and new equipment entered the marketplace balancing supply and demand for our services. However, pricing for our services improved in 2007 from 2006, mainly reflecting continued increases in labor costs, and offset a portion the effect of the lower utilization of our services on our total revenues. By the middle of 2008, oil and natural gas prices reached historic highs. However, in the second half of 2008 oil and natural gas prices decreased substantially, which caused significantly lower utilization of our services in the fourth quarter of 2008. In the first half of 2009, utilization and pricing for our services continued to decline from the fourth quarter of 2008. For the second half of 2009, we expect oil and gas prices to remain below the levels required to support aggressive capital spending programs by our customers and that their maintenance related spending will be deferred for as long as possible. The reduced spending by our customers in the first half of 2009 is expected to continue in the second half of 2009, which will result in decreased demand for our services and increased competition among the service providers in each of our segments. We anticipate that utilization, revenue and margins in 2009 will be substantially below 2008 levels. As a result of these conditions, our customers’ spending patterns have become increasingly unpredictable, making it difficult for us to predict our future operating results. Accordingly, our results may differ significantly from our forecasts and those of the investment community.

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

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

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

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

•  Contract Drilling —rig operating days, revenue per drilling day and segment profits as a percent of revenues.

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

We will continue to evaluate opportunities to grow our business through selective acquisitions and internal growth initiatives. Our capital investment decisions are determined by an analysis of the projected return on capital employed for 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.

Recent Strategic Acquisitions and Expansions

During the period from 2006 through 2008, we grew significantly through acquisitions and capital expenditures. During 2006, we completed ten acquisitions, of which G&L Tool, Ltd. was considered significant for purposes of SFAS No. 141,“Business Combinations.”During 2007, we completed eight acquisitions, of which JetStar Consolidated Holdings, Inc. and Sledge Drilling Holding Corp. were considered significant for

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purposes of SFAS No. 141. During 2008, we completed five acquisitions, of which Azurite was considered significant for purposes of SFAS No. 141.

We discuss the aggregate purchase prices and related financing issues below in “Liquidity and Capital Resources” and present the pro forma effects of the acquisition of G&L Tool, Ltd., JetStar Consolidated Holdings, Inc., Sledge Drilling Holding Corp., and Azurite in Note 3 of our audited historical consolidated financial statements for the year ended December 31, 2008 included in this prospectus.

Selected 2006 Acquisitions

During 2006, we made several acquisitions that complemented our existing business segments and provided an entry into the rental and fishing tool business. These included, among others:

LeBus Oil Field Service Co.

On January 31, 2006, we acquired all of the outstanding capital stock of LeBus Oil Field Service Co. (“LeBus”) for an acquisition price of $26.0 million, subject to adjustments. This acquisition significantly expanded our fluid services segment in the Ark-La-Tex region. The cash used to acquire LeBus was primarily from borrowings under our senior credit facility.

G&L Tool, Ltd.

On February 28, 2006, we acquired substantially all of the operating assets of G&L Tool, Ltd. (“G&L”) for total consideration of $58.5 million in cash. This acquisition provided an entry into the rental and fishing tool market and operates within our completion and remedial line of business. The purchase agreement also contained an earn-out agreement based on annual EBITDA targets. The cash used to acquire G&L was primarily from borrowings under our senior credit facility.

Chaparral Service, Inc.

On August 15, 2006, we acquired all of the outstanding capital stock and substantially all operating assets of the subsidiaries of Chaparral Service, Inc. (“Chaparral”) for total consideration of $19.0 million in cash, subject to adjustments. This acquisition expanded our well servicing and fluid services capabilities in the eastern New Mexico portion of the Permian Basin. The cash used to acquire Chaparral was primarily from operating cash.

Selected 2007 Acquisitions

During 2007, we made several acquisitions that complemented our existing business segments. These included, among others:

Parker Drilling Offshore USA, LLC

On January 3, 2007, we acquired two barge-mounted workover rigs and related equipment from Parker Drilling Offshore USA, LLC for total consideration of $20.5 million in cash. The acquired rigs operate in the inland waters of Louisiana and Texas as a part of Basic Marine Services.

JetStar Consolidated Holdings, Inc.

On March 6, 2007, we acquired all of the outstanding capital stock of JetStar Consolidated Holdings, Inc. (“JetStar”) for an aggregate purchase price of approximately $127.3 million, including $86.3 million in cash, of which approximately $37.6 million was used for the retirement of JetStar’s outstanding debt. As part of the purchase price, we issued 1,794,759 shares of common stock, at a fair value of $22.86 per share for a total fair value of approximately $41.0 million. This acquisition operates in our completion and remedial business segment.

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Sledge Drilling Holding Corp.

On April 2, 2007, we acquired all of the outstanding capital stock of Sledge Drilling Holding Corp. (“Sledge”) for an aggregate purchase price of approximately $60.8 million, including $50.6 million in cash, of which approximately $19 million was used for the repayment of Sledge’s outstanding debt. As part of the purchase price, we issued 430,191 shares of common stock at a fair value of $23.63 per share for a total fair value of approximately $10.2 million. This acquisition allowed us to expand our drilling operations in the Permian Basin and operates in our contract drilling segment.

Wildhorse Services, Inc.

On June 5, 2007, we acquired all of the outstanding capital stock of Wildhorse Services, Inc. (“Wildhorse”) for an aggregate purchase price of approximately $17.3 million, net of cash acquired. This acquisition allowed us to expand our rental and fishing tool operations in northwestern Oklahoma and the Texas panhandle area. This acquisition operates in our completion and remedial line of business.

Selected 2008 Acquisitions

During the year 2008, we made several acquisitions that complemented our existing lines of business. These included among others:

Xterra Fishing and Rental Tools Co.

On January 28, 2008, we acquired all of the outstanding capital stock of Xterra Fishing and Rental Tools Co. (“Xterra”) for total consideration of $21.5 million cash. This acquisition operates in our completion and remedial services line of business.

Azurite Services Company, Inc.

On September 26, 2008, we acquired substantially all of the operating assets of Azurite for $61.0 million in cash. This acquisition operates in our fluid services line of business.

Segment Overview

Well Servicing

During the first six months of 2009 and in the year ended December 31, 2008, our well servicing segment represented 31% and 34% of our revenues, respectively. Revenue in our well servicing segment is derived from maintenance, workover, completion, and plugging and abandonment services. We provide maintenance-related services as part of the normal, periodic upkeep of producing oil and gas wells. Maintenance-related services represent a relatively consistent component of our business. Workover and completion services generate more revenue per hour than maintenance work, due to the use of auxiliary equipment, but demand for workover and completion services fluctuates more with the overall activity level in the industry.

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

Our fleet increased from a weighted average number of 325 rigs in the first quarter of 2006 to 414 in the second quarter of 2009 through a combination of newbuild purchases and acquisitions and other individual equipment purchases.

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The following is an analysis of our well servicing segment for each of the quarters and years in the years ended December 31, 2006, 2007 and 2008, and the quarters ended March 31, 2009 and June 30, 2009:

		Weighted
	��	Average				Rig			Revenue		Profits
		Number of		Rig		Utilization			per Rig		per Rig		Segment
		Rigs		Hours		Rate			Hour		Hour		Profits %
2006:
First Quarter			325		208,700		89.8	%	$	349	$	157		44.9	%
Second Quarter			337		219,300		91.0	%	$	365	$	165		45.2	%
Third Quarter			351		226,300		90.2	%	$	379	$	175		46.1	%
Fourth Quarter			360		213,900		83.1	%	$	398	$	174		43.8	%
Full Year			344		868,200		88.2	%	$	373	$	168		45.0	%
2007:
First Quarter			364		210,800		81.0	%	$	411	$	174		42.2	%
Second Quarter			371		207,700		78.3	%	$	415	$	163		39.5	%
Third Quarter			383		212,100		77.7	%	$	414	$	166		40.0	%
Fourth Quarter			386		200,600		72.7	%	$	409	$	159		38.8	%
Full Year			376		831,200		77.3	%	$	412	$	166		40.1	%
2008:
First Quarter			392		202,500		72.2	%	$	398	$	158		39.8	%
Second Quarter			403		222,300		77.1	%	$	400	$	152		37.9	%
Third Quarter			412		233,000		79.1	%	$	418	$	156		37.3	%
Fourth Quarter			414		182,400		61.6	%	$	418	$	141		33.8	%
Full Year			405		840,200		72.5	%	$	408	$	152		37.3	%
2009:
First Quarter			414		132,300		44.7	%	$	369	$	90		24.4	%
Second Quarter			414		110,500		37.3	%	$	329	$	78		23.6	%

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

The decrease in oil and gas prices over the last part of 2008, along with prices remaining depressed and volatile through the second quarter of 2009, caused a decrease in rig utilization in the first half of 2009 compared to the same period in 2008, as our customers decreased their capital and maintenance expenditures for our services. The decrease in customer demand was exacerbated by the continued weakness in natural gas prices. This decrease also caused price pressure, and our revenue per rig hour decreased in the first half of 2009 compared to the same period in 2008. Our rates declined faster than our costs, resulting in the decrease in segment profit percentage in the first half of 2009 compared to the same period in 2008. Through our continued cost cutting measures, we were able to minimize the decrease in segment profit percentage to 23.6% in the second quarter of 2009 as compared to the first quarter of 2009.

Fluid Services

During the first six months of 2009 and in the year ended December 31, 2008, our fluid services segment represented 42% and 32% of our revenues, respectively. 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, and well site construction and maintenance services. The fluid services segment has a base level of business consisting of transporting and disposing of salt water produced as a by-product of the production of oil and gas. These services are necessary for our customers and generally have a stable demand but typically produce lower relative segment profits than other parts of our fluid services segment. Fluid services for completion and workover projects typically require fresh or brine water for making drilling mud, circulating fluids or frac fluids used during a job, and all of these fluids require storage tanks and hauling and

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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. Revenues from our well site construction services are derived primarily from preparing and maintaining access roads and well locations, installing small diameter gathering lines and pipelines, constructing foundations to support drilling rigs and providing maintenance services for oil and gas facilities. 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 segment for each of the quarters and years in the years ended December 31, 2006, 2007 and 2008, and the quarters ended March 31, 2009 and June 30, 2009 (dollars in thousands):

	Weighted				Segment
	Average		Revenue		Profits
	Number of		per Fluid		per Fluid
	Fluid Service		Service		Service		Segment
	Trucks		Truck		Truck		Profits %
2006:
First Quarter		529	$	101	$	37		36.4	%
Second Quarter		568	$	109	$	42		38.2	%
Third Quarter		614	$	105	$	38		36.7	%
Fourth Quarter		640	$	103	$	39		38.0	%
Full Year		588	$	417	$	156		37.4	%
2007:
First Quarter		652	$	98	$	37		37.5	%
Second Quarter		657	$	96	$	35		36.1	%
Third Quarter		653	$	97	$	35		35.7	%
Fourth Quarter		656	$	104	$	37		35.7	%
Full Year		655	$	396	$	144		36.2	%
2008:
First Quarter		644	$	111	$	39		35.0	%
Second Quarter		663	$	109	$	36		33.1	%
Third Quarter		683	$	121	$	43		35.8	%
Fourth Quarter		804	$	111	$	42		38.1	%
Full Year		699	$	452	$	161		35.6	%
2009:
First Quarter		814	$	80	$	25		31.4	%
Second Quarter		808	$	61	$	17		27.9	%

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

The decreases in revenue per fluid service truck in the first half of 2009 compared to the same period in 2008 and the decrease in segment profit percentage in the first half of 2009 compared to the same period in 2008 were caused by lower customer demand and rate decreases in all of our market areas.

Completion and Remedial Services

During the first six months of 2009 and in the year ended December 31, 2008, our completion and remedial services segment represented 24% and 30% of our revenues, respectively. Revenues from our completion and remedial services segment are generally derived from a variety of services designed to stimulate oil and gas production or place cement slurry within the wellbores. Our completion and remedial services segment includes pressure pumping, cased-hole wireline services, underbalanced drilling and rental and fishing tool operations.

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Our pressure pumping operations concentrate on providing lower-horsepower cementing, acidizing and fracturing services in selected markets. On March 6, 2007, we acquired all of the outstanding capital stock of JetStar Consolidated Holdings, Inc. This acquisition allowed us to enter into the southwest Kansas market and increased our presence in North Texas. Our total hydraulic horsepower capacity for our pressure pumping operations was approximately 139,000 horsepower at December 31, 2008 compared to 120,000 horsepower at December 31, 2007 and 58,000 horsepower at December 31, 2006. At June 30, 2009 and June 30, 2008, our total hydraulic horsepower capacity for our pressure pumping operations was 139,000 and 128,000, respectively.

We entered the rental and fishing tool business through our acquisition of G&L in the first quarter of 2006. This acquisition consisted of 16 rental and fishing tool stores in the North Texas, West Texas, and Oklahoma markets. We have since further expanded this business line with several acquisitions and had 20 rental and fishing tool stores as of June 30, 2009.

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

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

The following is an analysis of our completion and remedial services segment for each of the quarters and years in the years ended December 31, 2006, 2007 and 2008, and the quarters ended March 31, 2009 and June 30, 2009 (dollars in thousands):

			Segment
	Revenues		Profits %
2006:
First Quarter	$	27,455		49.5	%
Second Quarter	$	40,939		53.1	%
Third Quarter	$	42,109		51.3	%
Fourth Quarter	$	43,909		51.2	%
Full Year	$	154,412		51.5	%
2007:
First Quarter	$	46,137		49.9	%
Second Quarter	$	63,735		47.6	%
Third Quarter	$	66,304		47.6	%
Fourth Quarter	$	64,515		46.2	%
Full Year	$	240,692		47.7	%
2008:
First Quarter	$	68,458		47.7	%
Second Quarter	$	79,579		46.4	%
Third Quarter	$	85,541		45.3	%
Fourth Quarter	$	70,748		43.0	%
Full Year	$	304,326		45.6	%
2009:
First Quarter	$	37,259		30.5	%
Second Quarter	$	29,373		26.9	%

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

The decrease in completion and remedial revenue in the first half of 2009 compared to the same period in 2008 was caused by the decline in oil and gas prices in the last part of 2008 and the first quarter of 2009, and by the continued slowdown in the economy during the second quarter of 2009 along with natural gas prices remaining low, which resulted in lower demand for our services. Demand, particularly in our pressure pumping segment, and rates for our services decreased faster than our costs, resulting in the decrease in segment profit percentage in the first half of 2009 compared to the same period in 2008.

Contract Drilling

During the first six months of 2009 and in the year ended December 31, 2008, our contract drilling segment represented 3% and 4% of our revenues, respectively. Revenues from our contract drilling segment are derived primarily from the drilling of new wells.

Within this segment, we typically charge our drilling rig customers at a “daywork” daily rate, or footage at an established rate per number of feet drilled. We measure the activity level of our drilling rigs on a weekly basis by calculating a rig utilization rate which is based on a seven day work week per rig.

Our contract drilling rig fleet grew from two during the first quarter of 2006 to nine by the fourth quarter of 2008, due to the Sledge acquisition in April 2007. Our contract drilling rig fleet had a weighted average of nine rigs during the four quarters of 2008 and the first and second quarter of 2009.

The following is an analysis of our contract drilling segment for each of the quarters and years in the years ended December 31, 2006, 2007 and 2008, and the quarters ended March 31, 2009 and June 30, 2009 (dollars in thousands):

	Weighted
	Average		Rig		Revenue		Profits
	Number of		Operating		per		(Loss)			Segment
	Rigs		Days		Day		per Day			Profits %
2006:
First Quarter		2		12		N.M.		N.M.			N.M.
Second Quarter		2		104	$	11,700	$	(4,900	)		(45.2	)%
Third Quarter		2		160	$	14,700	$	1,600			10.9	%
Fourth Quarter		3		208	$	13,300	$	(1,600	)		(11.7	)%
Full Year		2		484	$	14,400	$	(3,000	)		(20.5	)%
2007:
First Quarter		3		168	$	11,500	$	(5,200	)		(44.9	)%
Second Quarter		8		594	$	17,200	$	6,900			39.5	%
Third Quarter		9		723	$	15,700	$	6,700			42.4	%
Fourth Quarter		10		748	$	14,600	$	5,300			36.3	%
Full Year		8		2,233	$	15,400	$	5,400			34.7	%
2008:
First Quarter		9		645	$	14,700	$	3,800			25.7	%
Second Quarter		9		699	$	14,800	$	4,000			27.2	%
Third Quarter		9		767	$	15,600	$	5,600			35.6	%
Fourth Quarter		9		666	$	14,900	$	5,400			36.2	%
Full Year		9		2,777	$	15,000	$	4,700			31.4	%
2009:
First Quarter		9		248	$	14,700	$	1,500			10.1	%
Second Quarter		9		314	$	12,700	$	2,100			16.3	%

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We gauge activity levels in our drilling operations based on rig operating days, revenue per day and profits per drilling day. The results of the first quarter 2006 are not considered meaningful, due to thestart-up nature of the drilling operations, and the fact that only twelve operating days were completed in this quarter.

The decrease in segment profits in the first half of 2009 compared to the same period in 2008 was due primarily to the decline in rig operating days.

Operating Cost Overview

Our operating costs are comprised primarily of labor, including workers’ compensation and health insurance, repair and maintenance, fuel and insurance. A majority of our employees are paid on an hourly basis. We also incur costs to employ personnel to sell and supervise our services and perform maintenance on our fleet. These costs are not directly tied to our level of business activity. Compensation for our administrative personnel in local operating yards and in our corporate office is accounted for as general and administrative expenses. Repair and maintenance is performed by our crews, company maintenance personnel and outside service providers. Insurance is generally a fixed cost regardless of utilization and relates to the number of rigs, trucks and other equipment in our fleet, employee payroll and 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 our critical accounting policies is included in note 2 of the notes to our historical audited consolidated financial statements for the year ended December 31, 2008. The following is a discussion of our critical accounting policies and estimates.

Critical Accounting Policies

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

Property and Equipment.  Property and equipment are stated at cost or at estimated fair value at acquisition date if acquired in a business combination. Expenditures for repairs and maintenance are charged to expenses as incurred. We also review the capitalization of refurbishment of workover rigs as described in note 2 of the notes to our historical audited consolidated financial statements for the year ended December 31, 2008.

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 $375,000 and $250,000 respectively. We have lower deductibles per occurrence for automobile liability and general liability. We maintain accruals in our consolidated balance sheets related to self-insurance retentions by using third-party actuarial data and historical claims history.

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

Income Taxes.  We account for income taxes based upon Statement of Financial Accounting Standards (“SFAS”) No. 109,“Accounting for Income Taxes”(“SFAS No. 109”). Under SFAS No. 109, deferred tax

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assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in the period that includes the statutory enactment date. A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized.

Critical Accounting Estimates

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

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

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

Impairment of Goodwill.  Our goodwill is considered to have an indefinite useful economic life and is not amortized. We assess impairment of our goodwill annually as of December 31 or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. SFAS No. 142,“Goodwill and Other Intangible Assets”(“SFAS No. 142”), requires a two-step process for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. If impairment is indicated, then the fair value of the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination. The amount of impairment for goodwill is measured as the excess of its carrying value over its fair value.

In accordance with SFAS No. 142, we performed an assessment of goodwill as of December 31, 2008. In step one of the annual impairment test and due to the adverse equity market conditions affecting the Company’s common stock price and the declines in oil and natural gas prices in the fourth quarter of 2008 and continuing into 2009, the Company tested its four reporting units, well servicing, fluid services, completion and remedial services, and contract drilling, for impairment. To estimate the fair value of the reporting units the Company used a weighting of the discounted cash flow method, the guideline transaction method, and the public company guideline method. The Company weighted the discounted cash flow method 85% in its analysis and the other two methods combined 15% due to differences between the Company’s reporting units and the peer companies size, profitability and diversity of operations. In order to validate the reasonableness of the estimated fair values obtained for the reporting units, a reconciliation of fair value to market capitalization was performed. The control premium used in the reconciliation was derived from a market transaction data study along with historical control premiums from other Basic acquisitions. The measurement date for the stock price for the reconciliation was the closing price on December 31, 2008.

Based on the results of step one, impairment was indicated in the contract drilling reporting unit but not in the other three reporting units. As a result the Company tested the contract drilling reporting unit’s long-lived assets for impairment under SFAS No. 144,“Accounting for the Impairment or Disposal of Long-Lived

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Assets”(“SFAS No. 144”), which indicated no impairment. The Company performed step two for the contract drilling unit by allocating the estimated fair value to the tangible and intangible assets and liabilities, which indicated that the entire value of the goodwill in contract drilling of $22.5 million was impaired. This non-cash charge eliminates the goodwill recorded in connection with the Sledge acquisition in 2007. The goodwill associated with this acquisition has no tax basis, and accordingly, there is no tax benefit derived from recording the impairment charge.

Additionally, in accordance with SFAS No. 142, we performed another assessment of goodwill as of March 31, 2009. A “triggering event” requiring this assessment was deemed to occur because the oil and gas services industry continued to decline in the first quarter and our common stock price declined by 50% from December 31, 2008 to March 31, 2009. For SFAS No. 142 Step One testing purposes, we tested three reporting units for goodwill impairment: well servicing, fluid services, and completion and remedial services. Our contract drilling reporting unit does not carry any goodwill, and is not subject to the test.

To estimate the fair value of the reporting units, we used a weighting of the discounted cash flow method and the public company guideline method of determining fair value of a business unit. We weighted the discounted cash flow method 85% and public company guideline method 15%, due to differences between our reporting units and the peer companies’ size, profitability and diversity of operations. In order to validate the reasonableness of the estimated fair values obtained for the reporting units, a reconciliation of fair value to market capitalization was performed for each unit on a stand-alone basis. A control premium, derived from market transaction data, was used in this reconciliation to ensure that fair values were reasonably stated in conjunction with the our capitalization. The measurement date for our common stock price and market capitalization was the closing price on March 31, 2009.

Based on the results of SFAS No. 142 Step One, impairment was indicated in all three of the assessed reporting units. As such, we were required to perform Step Two assessment on all three of the reporting units. Step Two requires the allocation of the estimated fair value to the tangible and intangible assets and liabilities of the respective unit. This assessment indicated that $204.1 million was considered impaired as of March 31, 2009. This non-cash charge eliminated all of our goodwill.

Additionally, in accordance with SFAS No. 144, we performed an assessment of our long-lived assets for impairment. This assessment is performed as a comparison of the undiscounted future cash flows of each reporting unit to the carrying value of the assets in each unit. No impairment was indicated by this test.

As of June 30, 2009, we had no goodwill recorded on our balance sheet.

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

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

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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 an acquired company, is required to assess goodwill and certain intangible assets for impairment.

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

Stock-Based Compensation.  We account for stock-based compensation based on Statement of Financial Accounting Standards No. 123 (revised 2004),“Share Based Payment”(“SFAS No. 123R”). Options issued are valued on the grant date using the Black-Scholes-Merton option-pricing model and all awards are adjusted for an expected forfeiture rate. Awards are amortized over the vesting period. Compensation expense of the unvested portion of awards granted as a private company and outstanding as of January 1, 2006 will be based upon the intrinsic value method calculated under Accounting Principles Board Opinion No. 25,“Accounting for Stock Issued to Employees”(“APB No. 25”).

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

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

Asset Retirement Obligations.  SFAS No. 143,“Accounting for Asset Retirement Obligations”(“SFAS No. 143”), requires us to record the fair value of an asset retirement obligation as a liability in the period in which we incur 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 may 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.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008

Revenues.  Revenues decreased by 53% to $118.8 million during the second quarter of 2009 from $251.5 million during the same period in 2008. This decrease was primarily due to lower expenditures by our customers for our services and increased price competition from our competitors due to the continued decline in oil and natural gas prices.

Well servicing revenues decreased by 59% to $36.4 million during the second quarter of 2009 compared to $89.0 million during the same period in 2008. This decrease was due to the decrease in rig utilization to 37.3% during the second quarter of 2009 from 77.1% during the second quarter of 2008, along with a decrease in revenue per rig hour to $329 during the second quarter of 2009 from $400 during the second quarter of 2008. These decreases were due to decreased spending by our customers for our services along with increased price competition from our competitors. Our average number of well servicing rigs increased to 414 during the second quarter of 2009 compared to 403 in the same period in 2008, due to internal expansion from our newbuild rig program and the Triple N Services, Inc. acquisition.

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Fluid services revenues decreased by 32% to $49.1 million during the second quarter of 2009 compared to $72.6 million in the same period in 2008. This decrease was primarily due to decreased rates that we charged to our customers for our services caused by increased price competition from our competitors. These decreases were partially offset by the Azurite acquisition in September 2008 which added 98 fluid service trucks and 632 frac tanks. This acquisition added approximately $6.9 million of revenues during the second quarter of 2009. Our weighted average number of fluid service trucks increased to 808 during the second quarter of 2009 from 663 in the same period in 2008, although our revenue per fluid service truck decreased to $61,000 in the second quarter of 2009 compared to $109,000 in the same period in 2008.

Completion and remedial services revenues decreased by 63% to $29.4 million during the second quarter of 2009 compared to $79.6 million in the same period in 2008. The decrease in revenue between these periods was due to decreased utilization of equipment due to the decline in oil and gas prices. Increased market competition also caused significant rate declines. Total hydraulic horsepower increased to 139,000 at June 30, 2009 from 128,000 at June 30, 2008.

Contract drilling revenues decreased by 61% to $4.0 million during the second quarter in 2009 compared to $10.3 million in the same period in 2008. The number of rig operating days decreased to 314 in second quarter of 2009 compared to 699 in the second quarter of 2008. This decrease was due to lower new well starts in all of our geographic markets.

Direct Operating Expenses.  Direct operating expenses, which primarily consist of labor, including workers compensation and health insurance, fuel and maintenance and repair costs, decreased by 43% to $88.0 million during the second quarter of 2009 from $154.0 million in the same period in 2008. This decrease was due to the lower activity levels in all of our segments.

Direct operating expenses for the well servicing segment decreased by 50% to $27.8 million during the second quarter of 2009 as compared to $55.3 million for the same period in 2008, due primarily to the decrease in rig hours to 110,500 in the second quarter of 2009 from 222,300 for the same period in 2008. Segment profits decreased to 24% of revenues during the second quarter of 2009 compared to 38% for the same period in 2008, which reflects the faster decline in activity levels and rates than in costs.

Direct operating expenses for the fluid services segment decreased by 27% to $35.4 million during the second quarter of 2009 as compared to $48.6 million for the same period in 2008, which is due to lower activity levels being partially offset by the Azurite acquisition in September 2008 which added approximately $5.5 million in direct operating expenses in the second quarter 2009. Segment profits were 28% of revenues during the second quarter of 2009 compared to 33% for the same period in 2008.

Direct operating expenses for the completion and remedial services segment decreased by 50% to $21.5 million during the second quarter of 2009 as compared to $42.7 million for the same period in 2008 due primarily to decreased activity levels. Segment profits decreased to 27% of revenues during the second quarter of 2009 compared to 46% for the same period in 2008, due to activity levels and rates declining faster than costs.

Direct operating expenses for the contract drilling segment decreased by 56% to $3.3 million during the second quarter of 2009 as compared to $7.5 million for the same period in 2008 due primarily to lower activity levels. Segment profits for this segment were 16% of revenues during the second quarter of 2009 compared to 27% for the same period in 2008.

General and Administrative Expenses.  General and administrative expenses increased by 2% to $27.4 million during the second quarter of 2009 from $26.8 million for the same period in 2008, which included $1.3 million and $1.2 million in stock-based compensation expense during the second quarter of 2009 and 2008, respectively. The increase primarily reflects higher salary and office expenses related to businesses acquired during 2008.

Depreciation and Amortization Expenses.  Depreciation and amortization expenses were $32.4 million during the second quarter of 2009 as compared to $28.7 million for the same period in 2008, reflecting the increase in the size of and investment in our asset base, due to acquisitions as well as the internal expansion of our business segments.

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Interest Expense.  Interest expense decreased by 7% to $6.0 million during the second quarter of 2009 compared to $6.5 million for the same period in 2008. The decrease was due primarily to lower interest rates on our revolving line of credit.

Income Tax Expense.  There was an income tax benefit of $13.9 million during the second quarter of 2009 as compared to an income tax expense of $11.6 million for the same period in 2008. Our effective tax rate during the second quarter of 2009 and 2008 was approximately 39% and 38%, respectively.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Revenues.  Revenues decreased by 43% to $273.5 million during the first six months of 2009 from $481.4 million during the same period in 2008. This decrease was primarily due to lower expenditures by our customers for our services and increased price competition from our competitors due to the decline in oil and gas prices.

Well servicing revenues decreased by 50% to $85.2 million during the first six months of 2009 compared to $169.5 million during the same period in 2008. This decrease was due to the decrease in rig utilization to 41% during the first six months of 2009 from 75% during the first six months of 2008, along with a decrease in revenue per rig hour to $351 during the first six months of 2009 from $399 during the first six months of 2008. These decreases were due to decreased expenditures by our customers for our services along with increased price competition from our competitors. Our average number of well servicing rigs increased to 414 during the first six months of 2009 compared to 398 in the same period in 2008, due to internal expansion from our newbuild rig program and the Lackey Construction, LLC and the Triple N Services, Inc. acquisitions.

Fluid services revenues decreased by 21% to $114.1 million during the first six months of 2009 compared to $144.0 million in the same period in 2008. This decrease was primarily due to decreased rates that we charged to our customers for our services caused by increased price competition from our competitors. These decreases were partially offset by the Azurite acquisition in September 2008 which added 98 fluid service trucks and 632 frac tanks. This acquisition added approximately $16.6 million of revenues during the first six months of 2009. Our weighted average number of fluid service trucks increased to 811 during the first six months of 2009 from 654 in the same period in 2008, although our revenue per fluid service truck decreased to $141,000 in the first six months of 2009 compared to $220,000 in the same period in 2008.

Completion and remedial services revenues decreased by 55% to $66.6 million during the first six months of 2009 compared to $148.0 million in the same period in 2008. The decrease in revenue between these periods was due to decreased utilization of equipment due to the decline in oil and gas prices. Increased market competition also caused significant rate declines. Total hydraulic horsepower increased to 139,000 at June 30, 2009 from 128,000 at June 30, 2008.

Contract drilling revenues decreased by 62% to $7.6 million during the first six months in 2009 compared to $19.8 million in the same period in 2008. The number of rig operating days decreased to 562 in first six months of 2009 compared to 1,344 in the first six months of 2008. This decrease was due to lower new well starts in all of our geographic markets.

Direct Operating Expenses.  Direct operating expenses, which primarily consist of labor, including workers compensation and health insurance, fuel and maintenance and repair costs, decreased by 32% to $198.7 million during the first six months of 2009 from $291.8 million in the same period in 2008. This decrease was due to the lower activity levels in all of our segments.

Direct operating expenses for the well servicing segment decreased by 38% to $64.7 million during the first six months of 2009 as compared to $103.8 million for the same period in 2008, due primarily to the decrease in rig hours to 242,800 in the first six months of 2009 from 424,800 for the same period in 2008. Segment profits decreased to 24% of revenues during the first six months of 2009 compared to 39% for the same period in 2008, which reflects the faster decline in activity levels and rates than in costs.

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Direct operating expenses for the fluid services segment decreased by 16% to $80.0 million during the first six months of 2009 as compared to $95.0 million for the same period in 2008, which is due to lower activity levels being partially offset by the Azurite acquisition in September 2008 which added approximately $12.6 million in direct operating expenses in the first six months 2009. Segment profits were 30% of revenues during the first six months of 2009 compared to 34% for the same period in 2008.

Direct operating expenses for the completion and remedial services segment decreased by 40% to $47.4 million during the first six months of 2009 as compared to $78.4 million for the same period in 2008 due primarily to decreased activity levels. Segment profits decreased to 29% of revenues during the first six months of 2009 compared to 47% for the same period in 2008, due to activity levels and rates declining faster than costs.

Direct operating expenses for the contract drilling segment decreased by 55% to $6.6 million during the first six months of 2009 as compared to $14.6 million for the same period in 2008 due primarily to lower activity levels. Segment profits for this segment were 13% of revenues during the first six months of 2009 compared to 26% for the same period in 2008.

General and Administrative Expenses.  General and administrative expenses increased by 7% to $56.5 million during the first six months of 2009 from $52.7 million for the same period in 2008, which included $2.7 million and $2.3 million in stock-based compensation expense during the first six months of 2009 and 2008, respectively. The increase primarily reflects higher salary and office expenses related to businesses acquired during 2008.

Depreciation and Amortization Expenses.  Depreciation and amortization expenses were $65.2 million during the first six months of 2009 as compared to $56.8 million for the same period in 2008, reflecting the increase in the size of and investment in our asset base, due to acquisitions as well as the internal expansion of our business segments.

Goodwill Impairment.  In the first six months of 2009, we recorded a non-cash charge totaling $204.0 million for impairment of all of the goodwill associated with our well servicing, fluid services, and completion and remedial services segments.

Interest Expense.  Interest expense decreased by 15% to $11.7 million during the first six months of 2009 compared to $13.8 million for the same period in 2008. The decrease was due primarily to lower interest rates on our revolving line of credit.

Income Tax Expense.  There was an income tax benefit of $59.2 million during the first six months of 2009 as compared to an income tax expense of $23.3 million for the same period in 2008. Our effective tax rate during the first six months of 2009 and 2008 was approximately 22% and 38%, respectively.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Revenues.  Revenues increased by 15% to $1.0 billion in 2008 from $877.2 million in 2007. This increase was primarily due to acquisitions in the completion and remedial services and fluid services segments, and to the internal expansion of our business segments.

Well servicing revenues increased by less than 1% to $343.1 million in 2008 compared to $342.7 million in 2007. Revenue remained relatively flat due to the increase in rig hours to 840,200 in 2008 as compared to 831,200 in 2007 being offset by a decrease in revenue per rig hour to $408 in 2008 from $412 in 2007. Similarly, an increase in the weighted average number of rigs was offset by lower utilization rates. Our weighted average number of rigs increased to 405 in 2008 from 376 in 2007. The increase was due to the addition of 22 newbuild rigs, 13 rigs from acquisitions and the conversion of one drilling rig to workover mode, offset by the retirement of 9 rigs in 2008. The rig utilization rate for our well servicing rigs declined to 73% in 2008 compared to 77% in 2007.

Fluid services revenues increased by 22% to $315.8 million in 2008 compared to $259.3 million in 2007. This increase was primarily due to the Azurite acquisition and internal growth. The Azurite acquisition added 98 trucks, 632 frac tanks and six disposal wells, which increased revenues by approximately $10.9 million in

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2008. Our weighted average number of fluid service trucks increased to 699 in 2008 compared to 655 in 2007, an increase of approximately 7%. During 2008, our average revenue per fluid service truck was approximately $452,000 as compared to $396,000 in 2007.

Completion and remedial services revenues increased by 26% to $304.3 million in 2008 as compared to $240.7 million in 2007. The increase in revenue between these periods was primarily the result of the acquisition of JetStar in March 2007, Xterra in January 2008 and Triple N Services, Inc. (“Triple N”) in May 2008. The yards associated with the JetStar acquisition added approximately $20.9 million more in revenue in 2008 compared to 2007, the Xterra yards added $17.7 million in revenues for 2008 and the Triple N yards added $4.7 million in revenues for 2008. There was also improved utilization for our services in 2008 due to higher oil and natural gas prices for the majority of 2008.

Contract drilling revenues increased by 21% to $41.7 million in 2008 compared to $34.5 million in 2007. The increase was due mainly to the acquisition of Sledge in April 2007, which added approximately $3.9 million more in revenues in 2008 compared to 2007. There was also an increase in rig operating days to 2,777 in 2008 compared to 2,233 in 2007, an increase of 24%. Revenue per drilling day was $15,000 in 2008 compared to $15,400 in 2007, a decrease of 3%.

Direct Operating Expenses.  Direct operating expenses, which primarily consist of labor, including workers’ compensation and health insurance, and maintenance and repair costs, increased by 18% to $612.6 million in 2008 from $518.9 million in 2007. This increase was primarily due to the acquisitions we completed in 2008, the expansion of our well servicing rig and fluid service truck fleets, and increases in personnel and related benefit costs. Direct operating expenses increased to 61.0% of revenues in 2008 from 59.2% in 2007.

Direct operating expenses for the well servicing segment increased by 5% to $215.2 million in 2008 as compared to $205.1 million in 2007 due primarily to the expansion of our well servicing rig fleet. Segment profits decreased to 37.3% of revenues in 2008 compared to 40.1% in 2007, which reflects higher fuel costs in 2008 and higher labor costs since we generally retain our rig crews during times of lower utilization.

Direct operating expenses for the fluid services segment increased by 23% to $203.2 million in 2008 as compared to $165.3 million in 2007 due primarily to the expansion of our fluid services fleet. The Azurite acquisition added approximately $7.2 million in operating expense in 2008. Segment profits decreased slightly to 35.6% of revenues in 2008 compared to 36.2% in 2007, mainly due to higher fuel costs.

Direct operating expenses for the completion and remedial services segment increased by 31% to $165.6 million in 2008 as compared to $125.9 million in 2007 due primarily to the expansion of our services and equipment, including the JetStar, Xterra and Triple N acquisitions, and higher operating costs. JetStar operating expenses were approximately $18.3 million more in 2008 than in 2007, Xterra operating expenses were $7.6 million in 2008 and Triple N operating expenses were $2.1 million in 2008. Our segment profits decreased to 45.6% of revenues in 2008 from 47.7% in 2007, as we experienced higher fuel costs and increases in costs of the materials used in our pressure pumping operations.

Direct operating expenses for the contract drilling segment increased by 27% to $28.6 million in 2008 as compared to $22.5 million in 2007. The Sledge acquisition added approximately $6.6 million of operating expenses. Our segment profits decreased to 31.4% of revenues in 2008 from 34.7% in 2007, as we experienced increased fuel and transportation expense.

General and Administrative Expenses.  General and administrative expenses increased by 16% to $115.3 million in 2008 from $99.0 million in 2007, which included $4.1 million and $4.0 million of stock-based compensation expense in 2008 and 2007, respectively. The increase primarily reflects higher salary and office expenses related to the expansion of our business.

Depreciation and Amortization Expenses.  Depreciation and amortization expenses were $118.6 million in 2008, as compared to $93.0 million in 2007, reflecting the increase in the size of and investment in our asset base. We invested $110.9 million for acquisitions, $50.7 million for capital leases and an additional $91.9 million for capital expenditures in 2008.

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Goodwill Impairment.  In the fourth quarter of 2008, we recorded a non-cash charge totaling $22.5 million to impair the contract drilling goodwill.

Interest Expense.  Interest expense decreased by 2% to $26.8 million in 2008 from $27.4 million in 2007. The decrease was due primarily to lower interest rates on our revolving line of credit, which was offset by an increase in interest expense due to the $30.0 million draw down on our revolver in September 2008.

Other Income and Expense.  Other income and expense included $18.2 million of merger costs associated with the terminated merger agreement with Grey Wolf, Inc., offset by termination payments received from Grey Wolf, Inc. for $30.0 million.

Income Tax Expense.  Income tax expense was $55.1 million in 2008, as compared to $52.8 million in 2007. Our effective tax rate was approximately 45% in 2008 and 38% in 2007.

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Revenues.  Revenues increased by 20% to $877.2 million in 2007 from $730.1 million in 2006. This increase was primarily due to acquisitions in the completion and remedial services and well servicing segments, and to the internal expansion of our business segments, mainly well servicing.

Well servicing revenues increased by 6% to $342.7 million in 2007 compared to $323.8 million in 2006. The increase was mainly due to internal growth of this segment as we added 45 newbuild rigs to our fleet in 2007. Our weighted average number of well servicing rigs increased to 376 in 2007 compared to 344 in 2006, an increase of approximately 9%. The rig utilization rate for our well servicing rigs declined to 77% in 2007 compared to 88% in 2006. This decline was due to stabilization of industry markets after experiencing significant growth throughout 2005 and 2006. The effect on revenue from this lower rig utilization rate was partially offset by an increase of 10% in our revenue per rig hour from 2006, which increased to $412 per rig hour, and the expansion of our well servicing fleet.

Fluid services revenues increased by 6% to $259.3 million in 2007 compared to $245.0 million in 2006. This increase was primarily due to our internal growth and acquisitions. The Steve Carter Inc. and Hughes Services Inc. acquisition added 22 trucks to our fleet and increased revenues by approximately $2.2 million for the fourth quarter of 2007. Our weighted average number of fluid service trucks increased to 655 in 2007 compared to 588 in 2006, an increase of approximately 11%. During 2007, our average revenue per fluid service truck was approximately $396,000 as compared to $417,000 in 2006.

Completion and remedial services revenues increased by 56% to $240.7 million in 2007 as compared to $154.4 million in 2006. The increase in revenue between these periods was primarily the result of the acquisition of JetStar in March 2007, which added revenues of $57.1 million, and improved pricing and utilization of our services.

Contract drilling revenues increased by 394% to $34.5 million in 2007 compared to $7.0 million in 2006. The increase was due mainly to the acquisition of Sledge, which added revenues of $23.9 million. Revenue per drilling day was $15,400 in 2007 compared to $14,400 in 2006, an increase of 7%.

Direct Operating Expenses.  Direct operating expenses, which primarily consist of labor, including worker’s compensation and health insurance, and maintenance and repair costs, increased by 25% to $518.9 million in 2007 from $414.9 million in 2006. This increase was primarily due to the acquisitions we completed in 2007, the expansion of our well servicing rig and fluid service truck fleets, and increases in personnel and related benefit costs. Direct operating expenses increased to 59.2% of revenues in 2007 from 56.8% in 2006.

Direct operating expenses for the well servicing segment increased by 15% to $205.1 million in 2007 as compared to $178.0 million in 2006 due primarily to the expansion of our well servicing rig fleet. Segment profits decreased to 40.1% of revenues in 2007 compared to 45.0% in 2006, which reflects higher labor costs as we retained our rig crews during times of lower utilization.

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Direct operating expenses for the fluid services segment increased by 8% to $165.3 million in 2007 as compared to $153.4 million in 2006 due primarily to the expansion of our fluid services fleet and higher labor costs. Segment profits decreased to 36.2% of revenues in 2007 compared to 37.4% in 2006.

Direct operating expenses for the completion and remedial services segment increased by 68% to $125.9 million in 2007 as compared to $75.0 million in 2006 due primarily to the expansion of our services and equipment, including the JetStar acquisition, and higher operating costs. JetStar operating expenses were approximately $34.1 million in 2007. Our segment profits decreased to 47.7% of revenues in 2007 from 51.4% in 2006, as we experienced higher labor costs and increases in costs of the materials used in our pressure pumping operations.

Direct operating expenses for the contract drilling segment increased by 168% to $22.5 million in 2007 as compared to $8.4 million in 2006. The increase was primarily due to the acquisition of Sledge, which added $11.7 million of operating expenses.

General and Administrative Expenses.  General and administrative expenses increased by 22% to $99.0 million in 2007 from $81.3 million in 2006, which included $4.0 million and $3.4 million of stock-based compensation expense in 2007 and 2006, respectively. The increase primarily reflects higher salary and office expenses related to the expansion of our business.

Depreciation and Amortization Expenses.  Depreciation and amortization expenses were $93.0 million in 2007 as compared to $62.1 million in 2006, reflecting the increase in the size of and investment in our asset base, particularly due to the Sledge and JetStar acquisitions. We invested $252 million for acquisitions, $26.8 million for capital leases and an additional $98.5 million for capital expenditures in 2007.

Interest Expense.  Interest expense increased by 57% to $27.4 million in 2007 from $17.5 million in 2006. The increase was due to an increase in the amount of long-term debt during the period. In 2007, we used $150 million of our credit revolver for the acquisitions of Sledge, JetStar and Wildhorse.

Income Tax Expense.  Income tax expense was $52.8 million in 2007 as compared to $54.7 million in 2006. Our effective tax rate was approximately 38% in 2007 and 36% in 2006.

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

Liquidity and Capital Resources

As of June 30, 2009, our primary capital resources were net cash flows from our operations, utilization of capital leases as allowed under our Fourth Amended and Restated Credit Agreement, as amended by Amendment and Consent No. 1 thereto (the “Credit Facility”), and availability under our Credit Facility, under which approximately $28.8 million of borrowing capacity was available at June 30, 2009. As of June 30, 2009, we had cash and cash equivalents of $134.3 million compared to $111.1 million as of December 31, 2008. Historically, we have utilized bank and capital lease financing and sales of equity to obtain capital resources. When appropriate, we consider public or private debt and equity offerings and non-recourse transactions to meet our liquidity needs.

On July 31, 2009, we completed the sale of $225 million principal amount of our 11.625% Senior Secured Notes due 2014 (the “Senior Secured Notes”). The net proceeds of $208.4 million were used to repay the $180.0 million of borrowings outstanding under the Credit Facility as of July 31, 2009. The Credit Facility was then terminated, and we are unable to borrow any amounts under it. At the closing of the Senior Secured Notes offering, we also pledged cash collateral with respect to approximately $16.2 million of letters of credit under the Credit Facility. We expect to rely on cash on hand in the near term and to evaluate alternatives with respect to a new revolving credit facility or letter of credit facility in the future to address our long term liquidity requirements. The indenture governing the Senior Secured Notes limits the amount that we could borrow under a future secured credit facility to the difference between (i) $240 million and (ii) the sum of (a) $212.9 million

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(the principal amount of the Senior Secured Notes, net of offering discount) and (b) our outstanding collateralized letters of credit, subject to possible upward adjustment of the amount in clause (i) based on our consolidated tangible assets. We currently believe that our operating cash flows and cash on hand will be sufficient to fund our near-term liquidity requirements.

Net Cash Provided by Operating Activities

Cash flow from operating activities was $73.0 million for the six months ended June 30, 2009 as compared to $87.3 million during the same period in 2008. Operating cash flow was lower due to the decrease in revenues partially offset by a decrease in our accounts receivable.

Capital Expenditures

Capital expenditures are the main component of our investing activities. Cash capital expenditures (including acquisitions) during the first six months of 2009 were $26.4 million as compared to $96.3 million in the same period of 2008. We added $15.4 million of additional assets through our capital lease program during the first six months of 2009 compared to $20.5 million in the same period in 2008.

For 2009, we currently have planned approximately $40.0 million in cash capital expenditures and $17.5 million in capital leases, none of which is planned for acquisitions. We do not budget acquisitions in the normal course of business. The $57.5 million of capital expenditures planned for property and equipment is primarily for (1) purchase of additional equipment to expand our services, (2) continued refurbishment of our well servicing rigs and (3) replacement of existing equipment. We regularly engage in discussions related to potential acquisitions related to the well services industry.

Capital Resources and Financing

We currently believe that our operating cash flows and cash on hand will be sufficient to fund our near term liquidity requirements.

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 and declines in capital and debt markets.

Senior Notes

In April 2006, we completed a private offering of $225 million aggregate principal amount of 7.125% Senior Notes due April 15, 2016 (the “Senior Notes”). The Senior Notes are currently jointly and severally guaranteed by each of our subsidiaries, other than two immaterial subsidiaries that have no indebtedness and have not guaranteed other debt. The net proceeds from the offering were used to retire our outstanding Term B Loan balance and to pay down the outstanding balance under our previous credit facility. Remaining proceeds were used for general corporate purposes, including acquisitions.

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

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

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The indenture governing the Senior Notes 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.

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 Facility

On February 6, 2007, we amended and restated our then-existing credit agreement by entering into the Fourth Amended and Restated Credit Agreement (the “2007 Credit Facility”), which, among other things, created a new class of revolving loans that increased the total revolving commitments from $150 million to $225 million and increased the “Incremental Revolving Commitments” under the 2007 Credit Facility from $75.0 million to an aggregate principal amount of $100 million.

On May 4, 2009, we amended the 2007 Credit Facility with our existing syndicate of lenders. The amendment provided for two tranches whereby the lenders within the syndicate had the option to participate in the extension of the Revolver. Tranche A maintained the current agreement, including the termination date of December 15, 2010, for any lenders who chose not to participate in the extension of the Revolver. Tranche B included all lenders who agreed to extend the Revolver’s termination date to January 31, 2012 for their respective prior commitment. The amount of commitments under the Tranche A Revolving Loans was $80 million and amount under the Tranche B Revolving Loans was $145 million.

On July 31, 2009, in connection with our sale of the Senior Secured Notes, we repaid all of the borrowings outstanding under the Credit Facility, and then we terminated the Credit Facility.

Senior Secured Notes

On July 31, 2009, we completed the issuance and sale of $225,000,000 aggregate principal amount of the Senior Secured Notes. The Senior Secured Notes are jointly and severally, and unconditionally, guaranteed on a senior secured basis initially by all of our current subsidiaries other than two immaterial subsidiaries. The Senior Secured Notes and the related guarantees were offered and sold in private transactions in accordance with Rule 144A and Regulation S under the Securities Act of 1933, as amended.

The purchase price for the Senior Secured Notes and the related guarantees was 92.851% of their principal amount. The net proceeds from the issuance of the Senior Secured Notes were approximately $208.4 million after discounts and estimated offering expenses. We used the net proceeds from the offering,

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along with other funds, to repay all outstanding indebtedness under our revolving credit facility, which we terminated in connection with the offering.

The Senior Secured Notes and the related guarantees were issued pursuant to an indenture dated as of July 31, 2009 (the “Indenture”), by and among us, the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., a national banking association, as trustee. The obligations under the Indenture are secured as set forth in the Indenture and in the Security Agreement (as defined below), in favor of the trustee, by a first-priority lien (other than Permitted Collateral Liens, as defined in the Indenture) in favor of the trustee, on the Collateral (as defined below) described in the Security Agreement.

Interest on the Senior Secured Notes accrues at a rate of 11.625% per year. Interest on the Senior Secured Notes is payable semi-annually in arrears on February 1 and August 1 of each year, commencing on February 1, 2010. The Senior Secured Notes mature on August 1, 2014.

The Indenture contains covenants that, among other things, 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 (including Collateral under the Security Agreement), or consolidate or merge with or into other companies.

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

If we or our restricted subsidiaries sell, transfer or otherwise dispose of assets or other rights or property that constitute Collateral (including the same or issuance of equity interests in a restricted subsidiary that owns Collateral such that it thereafter is no longer a restricted subsidiary, a “Collateral Disposition”), we are required to deposit any cash or cash equivalent proceeds constituting net available proceeds into a segregated account under the sole control of the trustee that includes only proceeds from the Collateral Disposition and interest earned thereon (an “Asset Sale Proceeds Account”). The Asset Sale Proceeds Account will be subject to a first-priority lien in favor of the trustee, and the proceeds are subject to release from the account for specified uses. These permitted uses include:

•  acquiring additional assets of a type constituting Collateral (“Additional Assets”), provided the trustee has or is immediately granted a perfected first-priority security interest (subject only to Permitted Collateral Liens) in such Additional Assets; and

•  repurchasing or redeeming the Senior Secured Notes.

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 Secured Notes then outstanding may declare the entire principal of all the Senior Secured Notes to be due and payable immediately.

We may, at our option, redeem all or part of the Senior Secured Notes, at any time on or after February 1, 2012, 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.

At any time before February 1, 2012, we, at our option, may redeem up to 35% of the aggregate principal amount of the Senior Secured Notes issued under the Indenture with the net cash proceeds of one or more

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qualified equity offerings at a redemption price of 111.625% of the principal amount of the Senior Secured Notes to be redeemed, plus accrued and unpaid interest to the date of redemption, as long as:

•  at least 65% of the aggregate principal amount of the Senior Secured 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.

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

On July 31, 2009, Basic and each of the guarantors party to the Indenture (the “Grantors”) entered into a Security Agreement (the “Security Agreement”) in favor of The Bank of New York Mellon Trust Company, N.A., a national banking association, as trustee under the Indenture, to secure payment of the Senior Secured Notes and related guarantees. The Liens (as defined in the Security Agreement) granted by each of the Grantors under the Security Agreement consist of a security interest in all of the following personal property now owned or at any time thereafter acquired by such Grantor or in which such Grantor now has or at any time in the future may acquire any right, title or interest and whether existing as of the date of the Security Agreement or thereafter coming into existence (together with the Aircraft Collateral (as defined in the Security Agreement), the “Collateral”), as collateral security for the prompt and complete payment and performance when due (whether at the stated maturity, by acceleration or otherwise) of the obligations of the Grantors under the Indenture, the related Senior Secured Notes and the security documents:

(i) all Commercial Tort Claims;

(ii) all Contracts (as defined in the Security Agreement);

(iii) all Documents;

(iv) all Equipment (other than the Aircraft Collateral);

(v) all General Intangibles (excluding Payment Intangibles except to the extent included pursuant to clause (xv) below);

(vi) all Goods (as defined in the Security Agreement);

(vii) all Intellectual Property (as defined in the Security Agreement);

(viii) all Investment Property;

(ix) allLetter-of-Credit Rights (whether or not the letter of credit is evidenced by a writing);

(x) all Supporting Obligations;

(xi) each Asset Sale Proceeds Account (as defined in the Security Agreement) and all deposits, Securities and Financial Assets (as defined in the Security Agreement) therein and interest or other income thereon and investments thereof, and all property of every type and description in which any proceeds of any Collateral Disposition (as defined) or other disposition of Collateral are invested or upon which the trustee is at any time granted, or required to be granted, a Lien to secure the Obligations (as defined in the Security Agreement) as set forth in Section 4.12 of the Indenture and all proceeds and products of the Collateral described in this clause (xi);

(xii) all other personal property (other than Excluded Property), whether tangible or intangible, not otherwise described above;

(xiii) whatever is received (whether voluntary or involuntary, whether cash or non cash, including proceeds of insurance and condemnation awards, rental or lease payments, accounts, chattel paper, instruments, documents, contract rights, general intangibles, equipmentand/or inventory) upon the lease, sale, charter, exchange, transfer, or other disposition of any of the Collateral described in clauses (i) through (xii) above;

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(xiv) all books and records pertaining to the Collateral; and

(xv) to the extent not otherwise included, all Proceeds, Supporting Obligations and products (including, without limitation, any Accounts, Chattel Paper, Instruments or Payment Intangibles constituting Proceeds, Supporting Obligations or products) of any and all of the foregoing and all collateral security and guarantees given by any Person with respect to any of the foregoing;

provided, that notwithstanding the foregoing provisions, Collateral shall not include Excluded Property.

“Excluded Property”means the following, whether now owned or at any time hereafter acquired by any Grantor or in which such Grantor now has or at any time in the future may acquire any right, title or interest and whether now existing or hereafter coming into existence:

•  Maritime Assets (as defined in the Security Agreement);

•  cash and cash equivalents (as such terms are defined by GAAP) other than those maintained in an Asset Sales Proceeds Account;

•  Securities Accounts containing only cash and cash equivalents other than any Asset Sale Proceeds Account and Security Entitlements relating to any such Securities Account;

•  equity interests in any subsidiary of any Grantor;

•  Inventory;

•  trucks, trailers and other motor vehicles covered by a certificate of title law of any state;

•  propertyand/or transactions to which Article 9 of the UCC does not apply pursuant toSection 9-109 thereof;

•  certain computer software and Equipment acquired prior to the date thereof and subject to a lien securing purchase money indebtedness as of the date thereof if (but only to the extent that) the applicable documentation relating to such lien prohibits the granting of a lien on such Equipment;

•  Equipment leased by any Grantor, other than pursuant to a capitalized lease, if (but only to the extent that) the lien securing the Equipment prohibits the granting of a lien on such Equipment;

•  certain General Intangibles, governmental approvals or other rights arising under any contracts, instruments, permits, licenses or other documents if the granting of a security interest therein would cause a breach of a restriction on the granting of a security interest therein or the assignment thereof in favor of a third party, subject to exceptions as set forth in the Security Agreement; and

•  Accounts, Chattel Paper, Instruments and Payment Intangibles to the extent they are not Proceeds, Supporting Obligations or products of the Collateral.

The following capitalized terms are used above are as defined in the Uniform Commercial Code (“UCC”) of the State of New York, or such other jurisdiction as may be applicable under the terms of the Security Agreement) on the date of the Security Agreement: Accounts, Chattel Paper, Commercial Tort Claims, Deposit Account, Documents, Electronic Chattel Paper, Equipment, Financial Assets, General Intangibles, Instruments, Inventory, Investment Property,Letter-of-Credit Rights, Payment Intangibles, Proceeds, Securities, Securities Accounts, Security Entitlements, Supporting Obligations, and Tangible Chattel Paper.

Under the Security Agreement, each Grantor must maintain a perfected security interest in favor of the trustee and take all steps necessary from time to time in order to maintain the trustee’s first-priority security interest (other than Permitted Collateral Liens). If an event of default were to occur under the Indenture, the Senior Secured Notes, the guarantees relating to the Senior Secured Notes, the Security Agreement or any other agreement, instrument or certificate that is entered into to secure payment or performance of the Senior Secured Notes, the trustee would be empowered to exercise all rights and remedies of a secured party under the UCC, in addition to all other rights and remedies under the applicable agreements.

For more information about the Senior Secured Notes, please read “Description of the New Notes.”

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Other Debt

We have a variety of other capital leases and notes payable outstanding that is generally customary in our business. None of these debt instruments is material individually. As of June 30, 2009, we had total capital leases of approximately $75.3 million.

Credit Rating Agencies

In July 2009 our Senior Notes rating was changed from BB- to B- by Standard and Poor’s and from B1 to Caa1 by Moody’s, and our Credit Facility rating was changed from BB+ to BB- by Standard and Poor’s and from Ba1 to Ba2 by Moody’s. Our Senior Secured Notes were rated at BB- by Standard and Poor’s and Ba3 by Moody’s.

Preferred Stock

At June 30, 2009 and December 31, 2008, we had 5,000,000 shares of $0.01 par value preferred stock authorized, of which none was designated, issued or outstanding.

Other Matters

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition or results of operations.

Net Operating Losses

As of June 30, 2009, we had approximately $2.3 million of net operating loss carryforwards related to the pre-acquisition period of a 2003 acquisition, which are subject to an annual limitation of approximately $900,000. The carryforwards begin to expire in 2017.

Recent Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements”(“SFAS No. 157”), which became effective for our financial assets and liabilities on January 1, 2008 and became effective for our non-financial assets and liabilities on January 1, 2009. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements but would apply to assets and liabilities that are required to be recorded at fair value under other accounting standards. This standard was adopted for financial assets and liabilities as of January 1, 2008 and was adopted for non-financial assets and liabilities, including fair value measurements for asset impairments, goodwill and intangible asset impairments, purchase price allocations and asset retirement obligations, on January 1, 2009. The adoption of this standard did not have any impact on the fair value of any of our financial assets or liabilities.

In December 2007, the FASB issued SFAS No. 141R,“Business Combinations”(“SFAS No. 141R”), which became effective for us on January 1, 2009. This Statement requires an acquirer to recognize the assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date at their fair values as of that date. An acquirer is required to recognize assets or liabilities arising from all other contingencies (contractual contingencies) as of the acquisition date, measured at their acquisition-date fair values, only if it is more likely than not that they meet the definition of an asset or a liability in FASB Concepts Statement No. 6,“Elements of Financial Statements.”Any acquisition related costs are to be expensed instead of capitalized. The impact to us from the adoption of SFAS No. 141R in 2009 will vary acquisition by acquisition.

In December 2007, the FASB issued SFAS No. 160,“Noncontrolling Interests in Consolidated Financial Statements”(“SFAS No. 160”), which became effective for us on January 1, 2009. This standard establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in

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a parent’s ownership interest and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. The Statement also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. This pronouncement has not had a significant impact on our results of operation or consolidated financial position since we do not have any noncontrolling interests.

In March 2008, the FASB issued SFAS No. 161,“Disclosures about Derivative Instruments and Hedging Activities”(“SFAS No. 161”), which became effective for us on January 1, 2009. This standard improves financial reporting for derivative instruments and hedging activities by requiring enhanced disclosures to expand on these instruments’ effects on a company’s financial position, financial performance and cash flows. This pronouncement has not had a significant impact on our results of operation or consolidated financial position since we do not have any derivative instruments.

In April 2008, the FASB issued FASB Staff PositionSFAS No. 142-3,“Determination of Useful Life of Intangible Assets”(“FSPNo. 142-3”). FSPNo. 142-3 amends the factors that should be considered in developing the renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142. FSPNo. 142-3 is effective for fiscal years beginning after December 15, 2008. This pronouncement has not had a significant impact on our results of operation or consolidated financial position.

In June 2008, the FASB issued FASB Staff PositionEITF 03-6-1,“Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities”(“FSPEITF 03-6-1”). FSPEITF 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share (“EPS”) under the two-class method described in paragraphs 60 and 61 of SFAS No. 128,“Earnings Per Share.” FSPEITF 03-6-1 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008 and requires retrospective adjustment for all comparable prior periods presented. FSPEITF 03-6-1 has not had a significant impact on our results of operation or consolidated financial position since we do not have any participating securities.

In May 2009, the FASB issued SFAS No. 165,“Subsequent Events” (“SFAS No. 165”), which became effective for us on April 1, 2009. This standard establishes principles and requirements for disclosure of subsequent events. It establishes the period after the balance sheet date during which events or transactions are to be evaluated for potential disclosure. It also establishes the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date. The adoption of this standard requires us to disclose the date through which subsequent events have been reviewed.

In June 2009, the FASB issued SFAS No. 168,“The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162” (“SFAS No. 168”), which became effective for us on July 1, 2009. SFAS No. 168 establishes the FASB Accounting Standards Codification as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP. SFAS No. 168 is not expected to change GAAP and will not have a material impact on our consolidated financial statements.

Impact of Inflation on Operations

Management is of the opinion that inflation has not had a significant impact on our business, other than increases in fuel costs and personnel expenses during 2008.

Quantitative and Qualitative Disclosures about Market Risk

As of June 30, 2009, we had $180.0 million outstanding under the revolving portion of our credit facility subject to variable interest rate risk. The impact of a 1% increase in interest rates on this amount of debt would have resulted in increased interest expense of approximately $1.8 million annually and a decrease in net income of approximately $1.1 million.

On July 31, 2009, we terminated the credit facility in connection with the issuance of our Senior Secured Notes, and we have no other variable rate indebtedness.

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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 and well site construction services, completion and remedial services and contract drilling. These services are fundamental to establishing and maintaining the flow of oil and gas throughout the productive life of a well. Our broad range of services enables us to meet multiple needs of our customers at the well site. Our operations are managed regionally and are concentrated in the major United States onshore oil and gas producing regions in Texas, New Mexico, Oklahoma, Arkansas, Kansas and Louisiana and the Rocky Mountain states. We provide our services to a diverse group of over 2,000 oil and gas companies. We operate the third-largest fleet of well servicing rigs (also commonly referred to as workover rigs) in the United States. As of December 31, 2008, our fleet represented 12% of the overall available U.S. fleet, with our two larger competitors controlling approximately 27% and 17%, respectively, according to the AESC and other publicly available data.

Basic revised its business segments beginning in the first quarter of 2008, and in connection therewith restated the corresponding items of segment information for earlier periods. The new operating segments are Well Servicing, Fluid Services, Completion and Remedial Services, and Contract Drilling. These segments were selected based on changes in management’s resource allocation and performance assessment in making decisions regarding the Company. Contract Drilling was previously included in our Well Servicing segment. Well Site Construction Services is consolidated with our Fluid Services segment. These changes reflect Basic’s operating focus in compliance with Statement of Financial Accounting Standards (SFAS) No. 131,“Disclosures about Segments of an Enterprise and Related Information.” The following is a description of the segments:

•  Well Servicing.  Our well servicing segment (34% of our revenues in 2008 and 31% of our revenues in the first six months of 2009) currently operates our fleet of 414 well servicing rigs and related equipment. This business segment encompasses a full range of services performed with a mobile well servicing rig, including the installation and removal of downhole equipment and elimination of obstructions in the well bore to facilitate the flow of oil and gas. These services are performed to establish, maintain and improve production throughout the productive life of an oil and gas well and to plug and abandon a well at the end of its productive life. Our well servicing equipment and capabilities are essential to facilitate most other services performed on a well.

•  Fluid Services.  Our fluid services segment (32% of our revenues in 2008 and 42% of our revenues in the first six months of 2009) currently utilizes our fleet of 805 fluid service trucks and related assets, including specialized tank trucks, storage tanks, water wells, disposal facilities, construction and other related equipment. These assets provide, transport, store and dispose of a variety of fluids, as well as provide well site construction and maintenance services. These services are required in most workover, completion and remedial projects and are routinely used in daily producing well operations.

•  Completion and Remedial Services.  Our completion and remedial services segment (30% of our revenues in 2008 and 24% of our revenues in the first six months of 2009) currently operates our fleet of pressure pumping units, an array of specialized rental equipment and fishing tools, air compressor packages specially configured for underbalanced drilling operations, and cased-hole wireline units. The largest portion of this business segment consists of pressure pumping services focused on cementing, acidizing and fracturing services in niche markets. We entered the rental and fishing tool business through an acquisition in the first quarter of 2006.

•  Contract Drilling.  Our contract drilling segment (4% of our revenues in 2008 and 3% of our revenues in the first six months of 2009) currently operates nine drilling rigs and related equipment. We use these assets to penetrate the earth to a desired depth and initiate production from a well. We greatly increased our presence in this line of business through the Sledge Drilling acquisition in the second quarter of 2007.

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Our Competitive Strengths

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

•  Significant Market Position.  We maintain a significant market share for our well servicing operations in our core operating areas throughout Texas and a growing market share in the other markets that we serve. Our fleet of 414 well servicing rigs as of June 30, 2009 represents the third-largest fleet in the United States, and our goal is to be one of the top two providers of well site services in each of our core operating areas. Our market position allows us to expand the range of services performed on a well throughout its life, such as drilling, maintenance, workover, completion and plugging and abandonment services.

•  Modern and Active Well Servicing Fleet.  We operate a modern and active fleet of well servicing rigs. We believe over 75% of the active U.S. well servicing rig fleet was built prior to 1985. Greater than 50% of our rigs at December 31, 2008 were either 2000 model year or newer, or have undergone major refurbishments during the last five years. As of March 31, 2009, we had taken delivery of all 134 newbuild well servicing rigs since October 2004 as part of a newbuild commitment, driven by our desire to maintain one of the most efficient, reliable and safest fleets in the industry. In addition to our regular maintenance program, we have an established program to routinely monitor and evaluate the condition of our fleet. We selectively refurbish rigs and other assets to maintain the quality of our service and to provide a safe work environment for our personnel and have made major refurbishments on 70 of our rigs since the beginning of 2004. Since 2003, we have obtained annual independent reviews and evaluations of substantially all of our assets, which confirmed the location and condition of these assets.

•  Extensive Domestic Footprint in the Most Prolific Basins.  Our operations are concentrated in the major United States onshore oil and gas producing regions in Texas, New Mexico, Oklahoma, Arkansas, Kansas and Louisiana and the Rocky Mountain states. We operate in states that accounted for approximately 58% of the approximately 900,000 existing onshore oil and gas wells in the 48 contiguous states and approximately 73% of onshore oil production and 90% of onshore gas production in 2008. We believe that our operations are located in the most active U.S. well services markets, as we currently focus our operations on onshore domestic oil and gas production areas that include both the highest concentration of existing oil and gas production activities and the largest prospective acreage for new drilling activity. This extensive footprint allows us to offer our suite of services to more than 2,000 customers who are active in those areas and allows us to redeploy equipment between markets as activity shifts.

•  Diversified Service Offering for Further Revenue Growth.  We believe our range of well site services provides us a competitive advantage over smaller companies that typically offer fewer services. Our experience, equipment and network of 115 area offices position us to market our full range of well site services to our existing customers. By utilizing a wider range of our services, our customers can use fewer service providers, which enables them to reduce their administrative costs and simplify their logistics. Furthermore, offering a broader range of services allows us to capitalize on our existing customer base and management structure to grow within existing markets, generate more business from existing customers, and increase our operating profits as we spread our overhead costs over a larger revenue base.

•  Decentralized Management with Strong Corporate Infrastructure.  Our corporate group is responsible for maintaining a unified infrastructure to support our diversified operations through standardized financial and accounting, safety, environmental and maintenance processes and controls. Below our corporate level, we operate a decentralized operational organization in which our nine regional or division managers are responsible for their operations, including asset management, cost control, policy compliance and training and other aspects of quality control. With an average of over 25 years of industry experience, each regional manager has extensive knowledge of the customer base, job requirements and working conditions in each local market. Below our nine regional or division managers, our area managers are directly responsible for customer relationships, personnel management,

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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. We typically enter into new markets through the acquisition of businesses with strong management teams that will allow us to expand within these markets. Management of acquired companies often remain with us and retain key positions within our organization, which enhances our attractiveness as an acquisition partner. We have a record of successfully implementing this strategy. During the past three fiscal years, we have made 23 acquisitions including:

2006

•  LeBus Oil Field Service Co., a fluid service company operating in our Ark-La-Tex region, and

•  G&L Tool, Ltd., a rental and fishing tool company included in our completion and remedial line of business;

2007

•  JetStar Consolidated Holdings, Inc., a pressure pumping company operating in our completion and remedial line of business, and

•  Sledge Drilling Holding Corp., a contract drilling company operating in our contract drilling line of business;

2008

•  Azurite Services Company, Inc., Azurite Leasing Company, LLC and Freestone Disposal, L.P., a fluid service business operating in our Ark-La-Tex and Mid-Continent regions.

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

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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 programand/or upgrading our existing assets. Our capital investment decisions are determined by an analysis of the projected return on capital employed of each of those alternatives. Acquisitions are evaluated for “fit” with our area and regional operations management and are thoroughly reviewed by corporate level financial, equipment, safety and environmental specialists to ensure consideration is given to identified risks. We also evaluate the cost to acquire existing assets from a third party, the capital required to build new equipment and the point in the oil and gas commodity price cycle. Based on these factors, we make capital investment decisions that we believe will support our long-term growth strategy, and these decisions may involve a combination of asset acquisitions and the purchase of new equipment. As the oil and gas commodity cycle has declined in recent quarters, we have taken a disciplined approach to acquisitions, with our last acquisition completed in September 2008. We expect to continue this strategy in order to maintain existing operating assets while this cycle continues.

General Industry Overview

Demand for services offered by our industry is a function of our customers’ willingness to make operating and capital expenditures to explore for, develop and produce hydrocarbons in the U.S., which in turn is affected by current and expected levels of oil and gas prices. As oil and gas prices increased in recent years, oil and gas companies increased their drilling and workover activities. The increased activity resulted in increased domestic exploration and production spending year over year for the past four years. In the last part of 2008, there was a rapid decline in oil and gas prices which has resulted in significant decreases in domestic spending during the first half of 2009 compared to 2008 domestic spending.

The table below sets forth average daily closing prices for the Cushing WTI Spot Oil Price and the Energy Information Agency average wellhead price for natural gas since 2004:

	Cushing WTI Spot		Average Wellhead Price
Period	Oil Price ($/bbl)		Natural Gas ($/mcf)
1/1/04 — 12/31/04	$	41.51	$	5.49
1/1/05 — 12/31/05		56.64		7.51
1/1/06 — 12/31/06		66.05		6.42
1/1/07 — 12/31/07		72.34		6.38
1/1/08 — 12/31/08		99.67		8.07
1/1/09 — 6/30/09 (5/31/09 for Natural Gas)		51.18		3.99

Source: U.S. Department of Energy

Increased expenditures for exploration and production activities generally drives the increased demand for our services. Rising oil and gas prices in recent years and the corresponding increase in onshore oil exploration and production spending have led to expanded drilling and well service activity, as the U.S. land-based drilling rig count increased approximately 22% during 2005, 17% during 2006, and 4% during 2007. With the rapid decline in oil and gas prices in the second half of 2008 there was a decrease in the land-based drilling rig count of approximately 15% from the peak of 2008 to the end of the year and 43% during the first half of 2009, according to Baker Hughes. The decrease in oil and gas prices coupled with the buildup of drilling and workover rig counts in recent years is resulting in both lower utilization of those rigs and decreases in the rates being charged.

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

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

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

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

Overview of Our Segments and Services

Well Servicing Segment

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

•  maintenance work involving removal, repair and replacement of down-hole equipment and returning the well to production after these operations are completed;

•  hoisting tools and equipment required by the operation into and out of the well, or removing equipment from the well bore, to facilitate specialized production enhancement and well repair operations performed by other oilfield service companies; and

•  plugging and abandonment services when a well has reached the end of its productive life.

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

Our fleet included 414 well servicing rigs as of December 31, 2008, including 132 newbuilds since October 2004 and 70 rebuilds since the beginning of 2004. Our well servicing rigs operate from facilities in Texas, Wyoming, Oklahoma, North Dakota, New Mexico, Louisiana, Colorado, Utah and Montana. Our well servicing rigs are mobile units that generally operate within a radius of approximately 75 to 100 miles from their respective bases. Prior to December 2004, our well servicing segment consisted entirely of land-based equipment. During December 2004, we acquired three inland barges, two of which were equipped with rigs, which were refurbished and were placed into service in the second quarter of 2005. In January 2007, we acquired two additional inland barges equipped with rigs from Parker Drilling Offshore USA, LLC. Inland barges are used to service wells in shallow water marine environments, such as coastal marshes and bays.

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The following table sets forth the location, characteristics and number of the well servicing rigs that we operated at December 31, 2008. We categorize our rig fleet by the rated capacity of the mast, which indicates the maximum weight that the rig is capable of lifting. This capability is the limiting factor in our ability to provide services.

			Market Area
			Permian		South		Ark-La-		Mid-		Rocky
Rig Type	Rated Capacity		Basin		Texas		Tex		Continent		Mountain		Total
Swab		N/A		3		1		6		4		0		14
Light Duty		<90 tons		5		2		0		17		1		25
Medium Duty		³90<125 tons		133		38		29		58		54		312
Heavy Duty		³125 tons		29		4		6		4		8		51
24-Hour		³125 tons		2		3		0		2		1		8
Inland Barge		³125 tons		0		0		4		0		0		4
Total				172		48		45		85		64		414

We operate a total of 414 well servicing rigs, the third largest fleet in the United States. Based on their most recent publicly available information, Key Energy Services is our largest competitor with an estimated total of 943 domestic rigs and Nabors is the second largest with an estimated 592 domestic rigs at year end. Our only other competitors operating more than 100 rigs is Complete Production Services with an estimated 267 domestic rigs and Forbes Energy Services with an estimated 169 domestic rigs. Excluding the rigs operated by Nabors in California where we do not compete, we have the second largest rig fleet in the United States.

The total number of rigs owned by us and the four other largest companies referenced above is approximately 2,385, or 69% of the available fleet owned by member companies of the AESC, the major trade association of well site service providers. The remaining 31% of the well servicing rigs are owned by more than 100 local and regional companies. The December 2008 monthly activity survey conducted by the AESC indicated that 68% of the rigs owned were active.

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

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

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

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

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

New Well Completion.  New well completion services involve the preparation of newly drilled wells for production. The completion process may involve selectively perforating the well casing in the productive zones to allow oil or gas to flow into the well bore, stimulating and testing these zones and installing the production string and other downhole equipment. We provide well service rigs to assist in this completion process. Newly drilled wells are frequently completed by well servicing rigs to minimize the use of higher cost drilling rigs in the completion process. The completion process typically requires a few days to several weeks, depending on the nature and type of the completion, and generally requires additional auxiliary equipment. Accordingly, completion services require 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, storage and construction services. These services are required in most workover, completion and remedial projects and are routinely used in daily producing well operations. These services include:

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

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

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

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

•  preparation, construction and maintenance of access roads, drilling locations, and production facilities.

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This segment utilizes our fleet of fluid service trucks and related assets, including specialized tank trucks, portable storage tanks, water wells, disposal facilities and related equipment. The following table sets forth the type, number and location of the fluid services equipment that we operated at December 31, 2008:

	Market Area
	Rocky		Permian		Ark-La-		South		Mid-
	Mountain		Basin		Tex		Texas		Continent		Total
Fluid Service Trucks		94		262		259		125		79		819
Salt Water Disposal Wells		0		19		24		8		10		61
Fresh/Brine Water Stations		0		37		0		2		0		39
Fluid Storage Tanks		268		499		1,119		230		224		2,340

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

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

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

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

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

Fluid Services.  We currently own and operate 805 fluid service trucks equipped with a fluid hauling capacity of up to 150 barrels. Each fluid service truck is equipped to pump fluids from or into wells, pits, tanks and other storage facilities. The majority of our fluid service trucks are also used to transport water to fill frac tanks on well locations, including frac tanks provided by us and others, to transport produced salt water to disposal wells, including injection wells owned and operated by us, and to transport drilling and completion fluids to and from well locations. In conjunction with the rental of our frac tanks, we generally use our fluid service trucks to transport water for use in fracturing operations. Following completion of fracturing

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operations, our fluid service trucks are used to transport the flowback produced as a result of the fracturing operations from the well site to disposal wells. Fluid service trucks are generally provided to oilfield operators within a50-mile radius of our nearest yard.

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

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

Fluid Storage Tanks.  Our fluid storage tanks can store up to 500 barrels of fluid and are used by oilfield operators to store various fluids at the well site, including fresh water, brine and acid for frac jobs, flowback, temporary production and mud storage. We transport the tanks on our trucks to well locations that are usually within 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 5 to 50 frac tanks.

Construction Services.  We utilize a fleet of power units, including dozers, trenchers, motor graders, backhoes and other heavy equipment used in road construction. In addition, we own rock pits in some markets in our Rocky Mountain operations to ensure a reliable source of rock to support our construction activities. Contracts for well site construction services are normally awarded by our customers on the basis of competitive bidding and may range in scope from several days to several months in duration.

Completion and Remedial Services Segment

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

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

•  rental and fishing tools;

•  cased-hole wireline services; and

•  underbalanced drilling in low pressure and fluid sensitive reservoirs.

This segment currently operates 142 pressure pumping units, with approximately 139,000 of horsepower capacity, to conduct a variety of services designed to stimulate oil and gas production or to enable cement slurry to be placed in or circulated within a well. As of December 31, 2008, we also operated 46 air compressor packages, including foam circulation units, for underbalanced drilling and 15 wireline units for cased-hole measurement and pipe recovery services.

Just as a well servicing rig is required to perform various operations over the life cycle of a well, there is a similar need for equipment capable of pumping fluids into the well under varying degrees of pressure. During the drilling and completion phase, the well bore is lined with large diameter steel pipe called casing. Casing is cemented into place by circulating slurry into the annulus created between the pipe and the rock

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

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

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

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

The following table sets forth the type, number and location of the completion and remedial services equipment that we operated at December 31, 2008:

	Market Area
	Ark-La-		Mid-		Rocky		Permian
	Tex		Continent		Mountain		Basin		Total
Pressure Pumping Units		21		118		3		0		142
Coiled Tubing Units		0		4		0		0		4
Air/Foam Packages		0		6		34		6		46
Wireline Units		0		15		0		0		15
Rental and Fishing Tool Stores		0		9		3		8		20

Our pressure pumping business focuses primarily on lower horsepower cementing, acidizing and fracturing services markets. Currently, there are several pressure pumping companies that provide their services on a national basis. For the most part, these companies have concentrated their assets in markets characterized by complex work with higher horsepower requirements. This has created an opportunity in the markets for pressure pumping services in mature areas with less complex characteristics and lower horsepower requirements. We, along with a number of smaller, regional companies, have concentrated our efforts on these markets. Two of our major well servicing competitors also participate in the pressure pumping business, but primarily outside our core areas of operations for pumping services.

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

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

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

Cased-hole wireline services typically utilize a single truck equipped with a spool of wireline that is used to lower and raise a variety of specialized tools in and out of a cased wellbore. These tools can be used to measure pressures and temperatures as well as the condition of the casing and the cement that holds the casing in place. Other applications for wireline tools include placing equipment in or retrieving equipment from the wellbore, or perforating the casing and cutting off pipe that is stuck in the well so that the free section can be recovered. Electric wireline contains a conduit that allows signals to be transmitted to or from tools located in the well. A simpler form of wireline, slickline, lacks an electrical conduit and is used only to perform mechanical tasks such as setting or retrieving various tools. Wireline trucks are often used in place of a well servicing rig when there is no requirement to remove tubulars from the well in order to make repairs. Wireline trucks, like well servicing rigs, are utilized throughout the life of a well.

Underbalanced drilling services, unlike pressure pumping and wireline services, are not utilized universally throughout oil and gas operations. Underbalanced drilling is a technique that involves maintaining the pressure in a well at or slightly below that of the surrounding formation using air, nitrogen, mist, foam or lightweight drilling fluids instead of conventional drilling fluid. The most common method of reducing the weight of drilling fluid is to mix it with air as the fluid is pumped into the well. By varying the volume of air pumped with the fluid, the net hydrostatic pressure can be adjusted to the desired level. In extreme cases, air alone can be used to circulate rock cuttings from the well.

Contract Drilling Segment

Our contract drilling segment employs drilling rigs and related equipment to penetrate the earth to a desired depth and initiate production.

We own and operate nine land drilling rigs, which are currently deployed in the Permian Basin of Texas and New Mexico. A land drilling rig generally consists of engines, a drawworks, a mast, pumps to circulate the drilling fluid (mud) under various pressures, blowout preventers, drill string, and related equipment. The engines power the different pieces of equipment, including a rotary table or top drives that turns the drill string, causing the drill bit to bore through the subsurface rock layers. These jobs are typically bid by “daywork” contracts, in which an agreed upon rate per day is charged to the customer, or “footage” contracts, in which an agreed upon rate per the number of feet drilled is charged to the customer. The demand for drilling services is highly dependent on the availability of new drilling locations available to well operators, as well as sensitivity to expectations relating to and changes in oil and gas prices.

Our drilling rig services grew significantly in 2007 with the acquisition of Sledge Drilling in April. We acquired six drilling rigs in this acquisition.

Properties

Our principal executive offices are located at 500 W. Illinois, Suite 100, Midland, Texas 79701. We currently conduct our business from 115 area offices, 59 of which we own and 56 of which we lease. Each office typically includes a yard, administrative office and maintenance facility. Of our 115 area offices, 72 are

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located in Texas, 11 are in Oklahoma, nine are in New Mexico, six are in Wyoming, four are in Colorado, four are in Louisiana, three are in North Dakota, two are in Montana, two are in Kansas, one is in Arkansas and one is in Utah.

Customers

We serve numerous major and independent oil and gas companies that are active in our core areas of operations. During 2008, no single customer comprised over 5% of our total revenues. The majority of our business is with independent oil and gas companies. Based on current lower utilization rates and the current market environment, we may not be able to redeploy equipment if we lost any material customers, and such loss could have an adverse effect on our business until the equipment is redeployed.

Operating Risks and Insurance

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

•  personal injury or loss of life;

•  damage to or destruction of property and equipment (including the collateral securing the notes) and the environment; and

•  suspension of operations.

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

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

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

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

Competition

Our competition includes small regional contractors as well as larger companies with international operations. We believe our two largest competitors, Key Energy Services, Inc. and Nabors Well Services Co., combined own approximately 44% of the U.S. marketable well servicing rigs according to the most recent publicly available data including the Guiberson-AESC well service rig count. Both of these competitors are public companies or subsidiaries of public companies that operate in most of the large oil and gas producing regions in the U.S. These competitors have centralized management teams that direct their operations and decision-making primarily from corporate and regional headquarters. In addition, because of their size, these companies market a large portion of their work to the major oil and gas companies.

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

Safety Program

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

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

Environmental Regulation

Our operations are subject to stringent federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, commonly referred to as the “EPA,” 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. We are currently involved in negotiations with the District Attorney’s office in Jefferson County, Texas, regarding an alleged unauthorized discharge into or adjacent to waters in the state from one of our land farms in Jefferson County that could result in criminal sanctions, but we do not believe that this matter will have a material effect on our results of operations or financial condition. 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. While acknowledging the current proceeding in Jefferson County, Texas, 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.

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These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances that have been released at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the costs of some health studies. In addition, companies that incur liability frequently confront additional claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

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

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

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

The federal Clean Water Act and the federal Oil Pollution Act of 1990, which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States, require some owners or 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

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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.

The Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources in the United States. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. We believe we are in sufficient compliance with the Clean Air Act.

There are a variety of regulatory developments arising in the United States that are focused on restricting the emission of carbon dioxide, methane and other greenhouse gases that may be contributing to warming of the Earth’s atmosphere. Among these developments are the Regional Greenhouse Gas Initiative or “RGGI” in the Northeastern United States, the Western Regional Climate Action Initiative in the Western United States, including partners states New Mexico, Utah, and Montana and observer states Colorado and Wyoming, and legislation — the American Clean Energy and Security Act of 2009 — that has already been passed by the House of Representatives in Congress that, if adopted, could restrict the emission of greenhouse gases. Also, in 2007, the U.S. Supreme Court held inMassachusetts, et al. v. EPAthat greenhouse gases are an “air pollutant” under the federal Clean Air Act and thus subject to future regulation by the EPA. These developments could curtail the demand for fossil fuels such as oil and gas in areas of the United States where our customers operate and thus adversely affect demand for our services.

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, or “OSHA,” and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

Employees

As of June 30, 2009, we employed approximately 3,900 people, with approximately 80% 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.

Legal Proceedings

From time to time, we are a party to litigation or other legal proceedings that we consider to be a part of the ordinary course of business. We are not currently involved in any legal proceedings that we consider probable or reasonably possible, individually or in the aggregate, to result in a material adverse effect on our financial condition, results of operations or liquidity.

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MANAGEMENT

Executive Officers and Directors

The following table sets forth certain information with respect to our executive officers and directors. As of August 28, 2009, their respective ages and positions are as follows:

Name	Age		Position
Kenneth V. Huseman		57	President, Chief Executive Officer and Director
Alan Krenek		54	Senior Vice President, Chief Financial Officer, Treasurer and Secretary
T.M. “Roe” Patterson		35	Senior Vice President — Rig and Truck Operations
James F. Newman		45	Group Vice President — Completion and Remedial Services
Stephen J. McCoy		54	Vice President — Contract Drilling
Charles W. Swift		61	Vice President — Gulf Coast Region
Mark D. Rankin		56	Vice President — Risk Management
James E. Tyner		59	Vice President — Human Resources
Steven A. Webster		57	Chairman of the Board
Sylvester P. Johnson, IV		53	Director
William E. Chiles		60	Director
Robert F. Fulton		58	Director
James S. D’Agostino		63	Director
Thomas P. Moore, Jr.		70	Director
Antonio O. Garza, Jr.		50	Director

Kenneth V. Huseman (President — Chief Executive Officer and Director)has 30 years of well servicing experience. He has been our President and Chief Executive Officer and a Director since 1999. Prior to joining Basic, he was Chief Operating Officer at Key Energy Services from 1996 to 1999. He was a Divisional Vice President at WellTech, Inc., from 1993 to 1996. From 1978 to 1993, he was employed at Pool Energy Services Co., where he managed operations throughout the United States, including drilling operations in Alaska. Mr. Huseman graduated with a B.B.A. degree in Accounting from Texas Tech University.

Alan Krenek (Senior Vice President, Chief Financial Officer, Treasurer and Secretary)has 21 years of related industry experience. He has been our Vice President, Chief Financial Officer and Treasurer since January 2005. He became Senior Vice President and Secretary in May 2006. From October 2002 to January 2005, he served as Vice President and Controller of Fleetwood Retail Corp., a subsidiary in the manufactured housing division of Fleetwood Enterprises, Inc. He worked in various financial management positions at Pool Energy Services Co. from 1980 to 1993 and at Noble Corporation from 1993 to 1995. Mr. Krenek graduated with a B.B.A. degree in Accounting from Texas A&M University and is a certified public accountant.

T. M. “Roe” Patterson (Senior Vice President — Rig and Truck Operations)has 14 years of related industry experience. He has been our Senior Vice President of Rig and Truck operations since September 2008, and has been the Vice President of various different groups within Basic since February 2006. Prior to joining us, he was president of his own manufacturing and oilfield service company, TMP Companies, Inc., from 2000 to 2006. He was a Contracts/Sales Manager for the Permian Division of Patterson Drilling Company from 1996 to 2000. He was an Engine Sales Manager for West Texas Caterpillar from 1995 to 1996. Mr. Patterson graduated with a B.S. degree in Biology from Texas Tech University.

James F. Newman (Group Vice President — Completion and Remedial Services)has 24 years of related industry experience and has been our Group Vice President of Completion and Remedial Services since September 2008. Prior to joining Basic, he co-founded Triple N Services in 1986 and served as its President thru May 2008. He initially served Basic as an Area Manager in the plugging and abandonment operations.

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Mr. Newman is a registered Professional Engineer and is active in the Society of Professional Engineers. Mr. Newman graduated with a BSc in Petroleum Engineering from Colorado School of Mines.

Stephen J. McCoy (Vice President — Contract Drilling)has 33 years of related industry experience. Mr. McCoy has served as our Vice President — Contract Drilling since February 2009 after serving as our Vice President — Contracts since joining the company in June 2008. Prior to joining us, he was the Chief Operating Officer of H&M Resources from August 2007 to June 2008 and handled various operating duties in drilling and operating wells in the Permian Basin. He served as Vice President of Marketing for Patterson-UTI over their Permian Basin Division and in other various capacities from November 1996 until July of 2007 after Patterson Drilling purchased Gene Sledge Drilling Company. Mr. McCoy started with the Western Company in January 1978 before joining Cactus Drilling Corporation as a Contract Representative in October 1978 until May 1991. He joined Ranchland Rental Tools as Vice President of Marketing in 1991 and worked there through the mergers of Triumph Tools and Total Energy and then as District Manager for Enterra’s drilling tool division until joining Nabors Drilling as a Contracts Manager in January 1996. Mr. McCoy graduated with a B.B.A. degree in Business Management from Texas Tech University.

Charles W. Swift (Vice President — Gulf Coast Region)has 36 years of related industry experience, including 27 years specifically in the domestic well service business. Mr. Swift has been our Vice President — Gulf Coast Region since March 2009. He served as Senior Vice President — Operations Support from November 2008 until March 2009. He was our Senior Vice President — Rig and Truck Operations from July 2006 to November 2008. He has served as a Vice President since 1997 and was involved in integrating several acquisitions during our expansion phase in late 1997. He was a co-owner of S&N Well Service from 1986 to 1997 and expanded the business to 17 rigs at the time of sale of the Company to us. From 1980 to 1986, he worked at Pool Energy Services Co. where he managed well service and fluid services businesses. Mr. Swift graduated with a B.B.A. degree in International Trade from Texas Tech University.

Mark D. Rankin (Vice President — Risk Management)has 31 years of related industry experience. He has been a Vice President since 2004. From 1997 to 2004, he was a consultant to oil and gas companies and was involved in operations research and work process redesign. From 1985 to 1995, he acted as Director of International Marketing and Marketing for U.S. Operations and a District Manager at Pool Energy Services Co. He was an International Sales Manager and Director of Planning and Market Research at Zapata Off-Shore Company from 1979 to 1985. From 1977 to 1979, he was a Contract Manager at Western Oceanic, Inc. He graduated with a B.A. in Political Science from Texas A&M University.

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

Steven A. Webster (Chairman of the Board).  Mr. Webster has served as a director of Basic Energy Services since 2001. Mr. Webster has served as Co-Managing Partner and President of Avista Capital Holdings, L.P., a private equity firm focused on investments in the energy, media and healthcare sectors, since July 1, 2005. From 2000 until June 30, 2005, Mr. Webster served as Chairman of Global Energy Partners, a specialty group within Credit Suisse’s Alternative Capital Division that made investments in energy companies. 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 Company, both offshore drilling contractors. Mr. Webster serves as Chairman of Carrizo Oil & Gas, Inc. and as a director of SEACOR Holdings Inc., Hercules Offshore, Inc., Camden Property Trust, Geokinetics, Inc. and various privately held companies. Mr. Webster was the founder and an original shareholder of Falcon, a predecessor to Transocean, Inc., and was a co-founder and original shareholder of Carrizo. Mr. Webster holds a B.S.I.M. from Purdue University and an M.B.A. from Harvard Business School.

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Sylvester P. Johnson, IV (Director).  Mr. Johnson has served as a director of Basic Energy Services since 2001. Mr. Johnson has served as President and 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 director of Pinnacle Gas Resources, Inc. Mr. Johnson is a Registered Petroleum Engineer and has a B.S. in Mechanical Engineering from the University of Colorado.

William E. Chiles (Director).  Mr. Chiles has served as a director of Basic Energy Services since 2003. Mr. Chiles has served as the Chief Executive Officer and President and a director of Bristow Group Inc. (formerly 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).  Mr. Fulton has served as a director of Basic Energy Services since 2001. Mr. Fulton has served as President and Chief Executive Officer of Frontier Drilling ASA, an offshore oil and gas drilling and production contractor, since September 2002. From December 2001 to August 2002, Mr. Fulton managed personal investments. Prior to December 2001, Mr. Fulton spent most of his business career in the energy service and contract drilling industry. 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 with 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.

James S. D’Agostino (Director).  Mr. D’Agostino has served as a director of Basic Energy Services since 2004. Mr. D’Agostino serves as Chairman of the Board, President and Chief Executive Officer of Encore Bancshares, Inc., a banking, wealth management and insurance services holding company currently listed on the NASDAQ Global Market, and has served in such capacities for its subsidiary, Encore Bank, N.A., since November 1999. From 1998 to 1999, Mr. D’Agostino served as Vice Chairman and Group Executive, and from 1997 until 1998, he served as President, Member of the Office of Chairman and a 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.

Thomas P. Moore, Jr. (Director).  Mr. Moore has served as a director of Basic Energy Services since 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 holds an M.B.A. degree from Harvard Business School.

Antonio O. Garza, Jr. (Director).  Mr. Garza was appointed as a director of Basic Energy Services in 2009. Mr. Garza joined ViaNovo, a management and communications consultancy, as a partner in June 2009 and also serves as the chair of its new business enterprise, ViaNovo Ventures. Additionally, Mr. Garza currently acts as Counsel in the Mexico City office of White & Case, an international practice law firm. Prior to joining ViaNovo and White & Case, Mr. Garza served as U.S. Ambassador to Mexico from the summer of 2002 to May 2009. In 1998, Mr. Garza was elected to the Texas Railroad Commission and served as Chairman of the Commission from 1999 to 2002. Mr. Garza holds a B.B.A. from The University of Texas at Austin and a J.D. from Southern Methodist University School of Law.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the number of shares of common stock beneficially owned as of August 28, 2009 by (1) all persons who beneficially own more than 5% of the outstanding voting securities of the Company, to the knowledge of the Company’s management, (2) each current director, (3) each executive officer named in the Summary Compensation Table and (4) all current directors and executive officers as a group.

	Amount and
	Nature of		Percent of
	Beneficial		Shares
Name	Ownership		Outstanding
DLJ Merchant Banking Partners III, L.P. and affiliated funds(1)		18,059,424		44.4	%
FMR LLC(2)		4,000,000		9.8	%
Barclays Global Investors, NA.(3)		2,372,189		5.8	%
Kenneth V. Huseman(4)		882,873		2.2	%
Alan Krenek(5)		182,290		*
Charles W. Swift(6)		193,006		*
T.M. “Roe” Patterson(7)		63,360		*
James E. Tyner(8)		36,477		*
James F. Newman(9)		28,475		*
Mark D. Rankin(10)		55,881		*
Douglas B. Rogers(11)		24,749		*
Stephen J. McCoy(12)		5,488		*
Steven A. Webster(13)(14)		302,750		*
James S. D’Agostino, Jr.(13)(15)		84,950		*
William E. Chiles(13)(16)		20,750		*
Robert F. Fulton(13)(17)		100,750		*
Sylvester P. Johnson, IV(13)(17)		100,750		*
Thomas P. Moore, Jr.(13)(18)		105,000		*
Antonio O. Garza, Jr.(19)		37,500		*
Directors and Executive Officers as a Group (16 persons)(20)		2,225,049		5.4	%

*	Less than one percent.
(1)	Includes 18,059,424 shares of common stock owned by DLJ Merchant Banking and its affiliates as follows: DLJ Merchant Banking Partners III, L.P. (12,650,117 shares); DLJ ESC II, L.P. (1,493,185 shares); DLJ Offshore Partners III, C.V. (884,531 shares); DLJ Offshore Partners III-1, C.V. (228,284 shares); DLJ Offshore Partners III-2, C.V. (162,622 shares); DLJMB Partners III GmbH & Co. KG (107,898 shares); DLJMB Funding III, Inc. (132,220 shares); Millennium Partners II, L.P. (21,516 shares); MBP III Plan Investors, L.P. (2,379,051 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 of CS-USA and form part of Credit Suisse’s Alternative Capital Division. 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 Alternative Capital Division, from 1999 until June 30, 2005.
	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.

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(2)	Fidelity Management & Research Company (“Fidelity”), a wholly-owned subsidiary of FMR LLC, is the beneficial owner of all 4,000,000 shares as a result of acting as investment adviser to various investment companies registered under Section 8 of the Investment Company Act of 1940. The ownership of one investment company, Fidelity Low Priced Stock Fund, amounted to 4,000,000 shares of common stock. Edward C. Johnson 3d and FMR LLC, through its control of Fidelity, and the funds each has sole power to dispose of the 4,000,000 shares owned by Fidelity.
	Members of the family of Edward C. Johnson 3d, Chairman of FMR LLC, are the predominant owners, directly or through trusts, of Series B voting common shares of FMR LLC, representing 49% of the voting power of FMR LLC. The Johnson family group and all other Series B shareholders have entered into a shareholders’ voting agreement under which all Series B voting common shares will be voted in accordance with the majority vote of Series B voting common shares. Accordingly, through their ownership of voting common shares and the execution of the shareholders’ voting agreement, members of the Johnson family may be deemed, under the Investment Company Act of 1940, to form a controlling group with respect to FMR LLC. Neither FMR LLC nor Edward C. Johnson 3d, Chairman of FMR LLC, has the sole power to vote or direct the voting of the shares owned directly by the Fidelity Funds, which power resides with the Funds’ Boards of Trustees. Fidelity carries out the voting of the shares under written guidelines established by the Funds’ Boards of Trustees. FMR LLC’s address is 82 Devonshire Street, Boston, Massachusetts 02109
(3)	Includes 969,239 shares beneficially owned by Barclays Global Investors, NA.; 1,387,267 shares beneficially owned by Barclays Global Fund Advisors; and 15,683 shares beneficially owned by Barclays Global Investors, Ltd.
(4)	Includes 390,948 shares of restricted stock, a portion of which are subject to forfeiture and generally vest over the next four years. Includes 268,200 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 100,000 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan. Includes 476,415 shares owned subject to bank pledges.
(5)	Includes 70,840 shares of restricted stock, a portion of which are subject to forfeiture and generally vest over the next four years. Includes 111,250 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 30,000 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.
(6)	Includes 81,376 shares of restricted stock, a portion of which are subject to forfeiture and generally vest over the next four years. Includes 96,750 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 25,250 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.
(7)	Includes 48,060 shares of restricted stock, a portion of which are subject to forfeiture and generally vest over the next four years. Includes 8,750 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 11,250 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.
(8)	Includes 23,477 shares of restricted stock, a portion of which are subject to forfeiture and generally vest over the next four years. Includes 12,500 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 10,000 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.
(9)	Includes 10,975 shares of restricted stock, a portion of which are subject to forfeiture and generally vest over the next four years.
(10)	Includes 15,381 shares of restricted stock, a portion of which are subject to forfeiture and generally vest over the next four years. Includes 40,000 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 10,000 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.
(11)	Includes 20,592 shares of restricted stock, a portion of which are subject to forfeiture and generally vest over the next four years.

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(12)	Includes 5,488 shares of restricted stock, a portion of which are subject to forfeiture and generally vest over the next four years.
(13)	Includes 12,000 shares of restricted stock, a portion of which are subject to forfeiture and generally vest over the next four years.
(14)	Includes 88,750 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 8,750 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.
(15)	Includes 68,750 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 8,750 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.
(16)	Includes 8,750 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 8,750 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.
(17)	Includes 88,750 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 8,750 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.
(18)	Includes 40,000 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 2,500 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.
(19)	Includes 37,500 shares of restricted stock, all of which are subject to forfeiture and generally vest over the next three years.
(20)	Includes an aggregate of 776,637 restricted shares, of which 453,071 remain subject to vesting, and an aggregate of 921,200 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 232,750 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.

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COMPENSATION DISCUSSION AND ANALYSIS

The following discussion and analysis addresses compensation with respect to fiscal 2008 for our named executive officers.

Overview of Our Compensation Philosophy and Objectives.  The Company’s overall philosophy on compensation of the Company’s executive officers is to provide competitive salary levels and compensation incentives that:

•  attract, reward and retain individuals of the highest quality in these key positions;

•  recognize individual performance and the performance of the Company relative to the performance of other companies of comparable size, complexity and quality;

•  provide motivation toward, and reward the accomplishment of, corporate annual objectives;

•  align the executive officers’ compensation to shareholder interests; and

•  align the executives’ incentives with both the short-term and long-term goals of the Company.

We also have the following compensation objectives when setting the compensation programs for our executive officers:

•  provide a significant percentage of long-term equity compensation that is at-risk based on predetermined performance criteria;

•  maintain an opportunity for increased equity ownership by the Company’s executives; and

•  set compensation levels that are competitive within the market in which positions are located.

In addition, the Compensation Committee considers the anticipated tax treatment of the Company’s executive compensation program.

Elements of Compensation.  The executive compensation program for our named executive officers and other senior executives included five principal elements that, taken together, constitute a flexible and balanced method of establishing total compensation. These elements are:

•  base salary;

•  quarterly incentive bonus plan cash awards to certain executive officers (excluding our CEO and CFO);

•  annual cash incentive bonuses;

•  long-term incentive awards (which during 2008 consisted solely of restricted stock awards); and

•  beginning in 2008, a performance-based incentive program (the “Three-Year PB Incentive Program”) which reflects a three-year performance period and is based on performance factors contained in the 2003 Incentive Plan; if the performance measures are met, the participants will “earn” their restricted stock awards, which shares of restricted stock will then be issued and remain subject to time-based vesting in one-third increments in each of the subsequent three years.

In addition to these principal elements, special 2008 bonuses were granted by the Committee to executive officers, including two named executive officers, in connection with work and sacrifices made related to the proposed Grey Wolf merger. The compensation program for our named executive officers during the periods covered under the Summary Compensation Table below included only very limited additional perquisites not offered to employees generally.

The Company’s executive compensation program is consistent with the Company’s philosophy of tying a significant portion of each executive’s compensation to performance because this aligns the executive officers’ compensation to shareholder interests. Under the performance-based Three-Year PB Incentive Program, executive compensation is based on the Company achieving pre-established targets relative to its selected peer group. Similarly, the quarterly incentive bonus plan ties the compensation of the area, region, and division-level employees directly to the financial return on assets employed within their particular operations and ties

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corporate-level bonuses to the Company’s net income. Annual cash incentive bonuses and long-term incentive awards also take into account a set of Company and individual performance metrics used by the Compensation Committee.

The performance-based awards and discretionary restricted stock and stock option grants also provide retention benefits because the executive officers must remain in the employ of the Company throughout the applicable vesting period to receive the full benefit, subject to exceptions as applicable under certain agreements for termination of executives by the Company not for cause, termination by executives for good reason, the death or disability of the executives, or, under certain agreements and with additional limitations, the retirement of the executives. These time-based awards also provide an opportunity for increased equity ownership by the executives to further the link between the executive officers’ interests, shareholder interests and the short-term and long-term goals of the Company.

In addition, the Company uses market survey data from comparable companies to set base salary and total compensation levels that are competitive within the market.

Selection of Elements to Provide Competitive Levels of Compensation.  The Compensation Committee generally attempts to provide the Company’s senior executives with a total compensation package that is competitive and reflective of the performance achieved by the Company compared to the performance achieved by the Company’s peers. During the periods covered by the Summary Compensation Table included in this prospectus, the Compensation Committee has attempted to weight compensation generally toward long-term incentives. The Committee has determined a competitive level of compensation for each executive based on information drawn from a variety of sources, including proxy statements of other companies and surveys. The Company initially engaged Pearl Meyer & Partners during 2005 to perform an executive compensation review, and the Compensation Committee has continued to engage them for compensation consulting since that time.

For the periods from2006-2008, the peer groups used by Pearl Meyer & Partners have been comprised of a combination of the Company’s direct competitors and other energy and energy services companies that experience similar market forces and are looked at similarly by the investment community. Compensation norms for the group were adjusted for comparability of revenue size to the Company, and data is trended forward based on what Pearl Meyer & Partners believes is occurring with other companies. These reviews have been used by the Compensation Committee in establishing executive base salaries, the range for potential cash incentive bonuses, and aggregate long-term incentive plan payouts and equity awards.

During 2008, the Company continued to make equity grant levels somewhat higher than the median, particularly with respect to its CEO, as part of its objective to weight compensation generally toward long-term incentives. With respect to cash bonuses for 2007 paid in 2008, the total cash paid to officers was generally determined to be at or slightly above the survey midpoints for officers other than our CEO, whose total cash was below the mid-point due to desired equity weighting for his compensation. For 2008 bonuses paid in 2009 and new salaries and equity grants made in 2009, Pearl Meyer noted certain wage freezes being implemented by certain energy companies, and this information and industry conditions were reflected in decisions made by the Compensation Committee and the Company in March 2009. While the targeted value of an executive’s compensation package may be competitive, its actual value may exceed or fall below market average levels depending on performance, as discussed below.

The Company also engaged Pearl Meyer & Partners during 2006 to review the terms of the employment agreements for its named executive officers and other senior executives, and to recommend changes to these agreements. New agreements with the executive officers were entered into effective December 31, 2006. The principal effect of these new agreements was to streamline severance and non-competition provisions among our executive officers into three tiers, with our CEO in one tier, our CFO and Senior Vice President — Rig and Truck Operations in a second tier, and our other Vice Presidents in a third tier. Severance benefits are discussed below under “— Severance Benefits.” In November 2008, in connection with the promotion of Thomas M. Patterson to Senior Vice President — Rig and Truck Operations, Mr. Patterson’s employment agreement was amended to make his terms consistent with the second tier described above. Mr. Swift, the

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prior Senior Vice President — Rig and Truck Operations, remains our current Vice President — Gulf Coast Region.

Mix and Allocation of Compensation Components.  As noted above, the salary for our named executive officers can represent 100% of compensation in any given year when incentives do not pay out or long-term awards are not made. However, the general mix of compensation for individual performance in the annual incentive plans, plus the net annualized present value of long-term compensation grants, can range as follows, depending upon the executive. The following general percentage mix would apply to the typical approach in establishing the total compensation for the Company’s executives at 2008 performance. It is important to note that the influences of the timing of awards, availability of stock, company financial performance and stock price performance could significantly change the basic mix of compensation components as a percentage of total compensation:

For the CEO:	Base pay = 25% to 30% Bonus compensation at target = 20% to 30% Long-term compensation annualized = 40% to 50%
For the other named executives:	Base pay = 35% to 45% Bonus compensation at target = 20% to 25% (excluding special 2008 bonuses) Long-term compensation annualized = 30% to 45%

Base Salaries.  The Compensation Committee periodically reviews and establishes executive base salaries. Generally, base salaries are based on (1) the scope and complexity of the position held, (2) market survey data from comparable companies and (3) the incumbent’s competency level based on overall experience and past performance. In February 2008, our Compensation Committee, based on its review of peer group data and discussion with its compensation consultant, increased base salaries for each of our executive officers, including our named executive officers, for 2008. In March 2009, our Compensation Committee, based on its review of peer group data and discussion with its compensation consultant, initially approved base salaries for each of our named executive officers that remained the same as their then-current salaries (including Mr. Swift, whose salary had been previously reduced in connection with his change in position). Subsequently, in connection with wage and salary reductions announced throughout the Company effective March 30, 2009, these salaries were reduced 10% for our CEO, 7-8% for three of our other named executive officers and 0% for one named executive officer whose salary had already been decreased due to a change in position.

Quarterly Incentive Bonus Plans.  The Company has maintained three individual Quarterly Incentive Bonus Plans for management and administrative personnel. These plans address (1) area-level personnel, (2) non-administrative region- and division-level personnel and (3) non-administrative corporate-level personnel, except for the CEO and CFO. The Company also maintained an annual incentive bonus plan for executive officers. Employees participating under these plans were eligible for cash bonuses. Compensation potential and actual compensation received from all the plans are part of the cash compensation review process.

The purpose of the area, region, and division-level plans is to tie the compensation of the respective employees directly to the financial return on assets employed within their particular operations. During 2008, corporate-level bonuses were tied to the Company’s region and division-level bonuses.

Messrs. Huseman and Krenek have not participated in any of the Quarterly Incentive Bonus Plans during the periods included in the Summary Compensation Table in this prospectus. Mr. Swift participated in the division-level Quarterly Incentive Bonus Plan in 2007 and 2008, which payments were factored into his annual cash bonuses received by him in early 2008 and 2009. Messrs. Patterson and Tyner each participated in the corporate-level Quarterly Incentive Bonus Plans in 2007 and 2008, which payments were factored into annual cash bonuses received by them in early 2008 and 2009.

Annual Cash Bonuses (Non-Equity Incentive Plan Compensation) and Special Bonuses.  The purpose of annual cash bonuses under our Third Amended and Restated 2003 Incentive Plan (the “2003 Incentive Plan”) is to provide motivation toward, and reward the accomplishment of, corporate annual objectives and to provide a competitive compensation package that will attract, reward and retain individuals of the highest quality. The annual cash bonus awards to our named executive officers for 2008 were paid as non-equity incentive plan

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compensation based upon the achievement of corporate performance objectives. The special 2008 bonuses were paid as cash bonus compensation.

2008 Annual Cash Bonuses.  During 2008, the Compensation Committee of the Company utilized a set of metrics, which we refer to as our 2008 annual incentive compensation plan, for determining aggregate annual bonuses for our senior executive officers, including each of our named executive officers, consisting of (including relative weighting):

•  earnings per share (25%);

•  peer-group prior3-year average return on capital employed (25%);

•  safety record (based on total reportable incident rates) (10%);

•  preventable motor vehicle accident rate (10%);

•  revenue growth (10%); and

•  personal performance, based on board discretion (20%).

Target bonus award levels for the Company’s executive officers during 2008 were established by senior management working with the Compensation Committee. Target levels represent the award level attainable when the plans are performed fully to expectations or plan and individual performance is rated accordingly. Potential annual cash awards for 2008 for our CEO ranged from zero to 90% of base salary, with a target level of 60%. Potential annual cash awards for 2008 for our Tier II named executive officers (Messrs. Krenek, Patterson and Swift) ranged from zero to 75% of base salary, with a target level of 50%. Potential annual cash awards for 2008 for our Tier III named executive officer (Mr. Tyner) ranged from zero to 60% of base salary, with a target level of 40%. Payments made under our Quarterly Incentive Bonus Plan offset the annual bonus awards.

The earnings per share factor used by the Compensation Committee in 2008 included the net cash received by the Company as the termination fee in connection with the Grey Wolf merger and excluded the impact of goodwill impairment, for an actual result of $2.18 compared to a target of $2.23. The actual result for three-year average ROCE was 21% compared to a 20% target. The total reportable incident rate and preventable motor vehicle accident rate were higher than target levels, thus resulting in lower than target factor allocations. Mr. Huseman received a target-level annual cash bonus for 2008. Messrs. Krenek, Patterson Swift and Tyner received annual cash bonuses for 2008 equal to approximately 57%, 55%, 30% and 42% of base salary, respectively. These annual cash bonuses (reduced by amounts paid for prior payments under the Quarterly Incentive Bonus Plan, as applicable) were paid during the first quarter of 2009. Payments under these metrics were not “qualified performance based compensation” within the meaning of Section 162(m) of the Code.

Special 2008 Bonuses.  In addition to the annual cash bonuses, special bonuses were granted and paid during 2008 by the Committee to Messrs. Krenek and Tyner in connection with the terminated Grey Wolf merger. These bonuses reflected extraordinary time, effort and sacrifices made in connection with the transaction, which was terminated but resulted in the payment of a termination fee to the Company.

2008 Equity Awards.  In addition to the annual cash bonus awards discussed above, the Compensation Committee used the same metrics to determine the potential value of equity incentive rewards in the form of 2009 performance-based restricted stock or restricted stock, which targeted a range from zero to 250% for our CEO, zero to 200% for our CFO and Senior Vice President — Rig and Truck Operations, and zero to 100% for the other named executive officers. These awards were issued in March 2009 based on 2008 performance.

Equity awards granted in March 2008 were based on metrics used by the Compensation Committee in 2007 to determine the potential value of equity incentive rewards in the form of 2008 performance-based restricted stock or restricted stock, which targeted a range from zero to 250% for our CEO, zero to 200% for our CFO and Senior Vice President — Rig and Truck Operations, and zero to 100% for other named executive officers. These awards were issued in March 2008 based on 2007 performance. The set of 2007 metrics used by the Committee were used as guidelines, generally without employing specific quantitative targets or

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thresholds, for determining aggregate annual bonuses for our senior executive officers, including each of our named executive officers. Certain factors in 2007, including the JetStar and Sledge acquisitions, materially changed the Company’s business and caused the Company’s initial budget for 2007 and historical metrics for evaluating executive compensation to no longer be useful or directly comparable. The metrics used as guidelines consisted of:

•  EBITDA return on capital employed (EBITDA/net debt and equity);

•  accident record, including both the overall frequency rates and levels of preventable accidents;

•  revenue growth;

•  return on equity; and

•  individual performance, including extraordinary efforts and results.

The Company’s annual performance measures for officers for 2008 were recommended by the Chief Executive Officer and used by the Compensation Committee. The Compensation Committee also based its determination of CEO compensation and levels of annual performance measures based on input from its compensation consultant and, with respect to the CEO’s personal performance, based on additional input from members of the Nominating and Governance Committee and other board members. Annual cash bonuses for 2008 were paid to each of our executive officers during March of 2009. The Compensation Committee periodically monitors the award target levels and variances to assure their competitiveness and that they mesh with compensation strategy for incentives and for total compensation.

During March 2009, the Compensation Committee of the Company discussed the potential utilization of a new set of metrics for use in our 2009 annual incentive compensation plan in light of current industry conditions and matters of specific interest to the Company. The Committee has not formalized the weighting of these metrics or approved the targets, but these metrics would include: (i) revenue; (ii) EBITDA; (iii) earnings per share (fully diluted); (iv) return on average capital employed; (v) turnover rate; (vi) safety record (based on total reportable incident rate); (vii) preventable motor vehicle accident rate; and (viii) personal performance, based on board discretion.

2008 and 2009 Long-Term Incentive Programs.  During 2007, the Compensation Committee engaged Pearl Meyer & Associates to assist it in designing a new long-term incentive program under the 2003 Incentive Plan, including the development of performance measures to determine ultimate payouts. After due consideration, pursuant to its authorization under the 2003 Incentive Plan, the Compensation Committee approved and implemented in March 2008 a comprehensive long-term incentive plan, which we refer to as our 2008 Long-Term Incentive Program and discuss further below, consisting of:

•  a performance-based plan looking at a three-year performance period, which we refer to as our Three-Year PB Incentive Program, that is based on performance factors contained in the 2003 Incentive Plan; and

•  discretionary, time-based restricted stock awards.

The performance-based Three-Year PB Incentive Program represents approximately 50% of total potential long-term incentive compensation, with approximately 50% of our long-term compensation (including time-based restricted stock grants) remaining discretionary.

During March 2009, the Compensation Committee and the Board continued this performance-based Three-Year PB Incentive Program along with discretionary, time-based restricted stock awards as part of its 2009 Long-Term Incentive Program, which awards are also discussed further below.

Long-Term Incentive Program.  The long-term incentive program is used to focus management attention on Company performance over a period of time longer than one year in recognition of the long-term horizons for return on investments and strategic decisions in the energy services industry. The program is designed to motivate management to assist the Company in achieving a high level of long-term performance and serves to link this portion of executive compensation to long-term stockholder value. The Compensation Committee generally attempts to provide the Company’s executives, including Mr. Huseman, with a total compensation

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package that is competitive and reflective of the performance achieved by the Company compared to its peers, and is typically weighted toward long-term incentives. Aggregate stock or option holdings of the executive have no bearing on the size of a performance award.

The Company’s 2003 Incentive Plan, which was adopted by the board and has been approved by the Company’s stockholders as amended, covers stock awards issued under the Company’s original 2003 Incentive Plan and predecessor equity plan. The 2003 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. In fiscal 2006, the Committee made grants of stock options, which vest ratably over a four-year period beginning in 2008. In fiscal 2007, the Committee made a combination of stock option grants and restricted stock awards, which each vest ratably over a four-year period beginning in 2009. In fiscal 2008, the Committee made grants of restricted stock, which vest ratably over a four-year period beginning in 2010.

All non-employee directors and employees of, or consultants to, the Company or any of its affiliates are eligible for participation under the 2003 Incentive Plan. The 2003 Incentive Plan is administered by the Compensation Committee. The Compensation Committee directly oversees the plan as it relates to officers of the Company and oversees the plan in general, its funding and award components, the type and terms of the awards to be granted and interprets and administers the 2003 Incentive Plan for all participants. No awards may be granted under the 2003 Incentive Plan after April 12, 2014.

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 representing more than 10% of the total combined voting power of all classes of the Company’s stock or any of it 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 after five years from 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 the Company may take for compensation paid in excess of $1,000,000 to certain of the Company’s “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. Prior stockholder approval of the 2003 Incentive Plan (assuming no further material modifications of the plan) will satisfy the stockholder approval requirements of Section 162(m) for the transition period beginning with the Company’s initial public offering in December 2005 and ending not later than the Company’s annual meeting of stockholders in 2009. While the Compensation Committee reserves the right to grant ad hoc or special awards at any time that are subject to the limits of deductibility, the main awards under the plan are administered consistent with the requirements of 162(m) for performance based compensation.

Three-Year PB Incentive Program.  Under the Three-Year PB Incentive Program initially implemented during March 2008 and continued during March 2009, the executive officers and certain middle management personnel (total of 17 participants for 2008 awards and a total of 19 participants for 2009 awards) may earn restricted stock at the end of a one-year period, based on the Company’s performance over a three-year period. The performance measures are based on the Company achieving pre-established targets relative to its selected peer group (the “PB Peer Group”) based on the following factors/metrics:

•  earnings per share (“EPS”) growth (50% of performance-based awards), subject to forfeiture or a negative adjustment of 100% if the Company either (i) has EPS growth less than the worst performing PB Peer Group member or (ii) incurs a net loss based on the Company’s average EPS for the three-year period; and

•  return on capital employed (“ROCE”) (50% of performance-based awards), subject to forfeiture or a negative adjustment of 100% if (i) the Company’s ROCE for the three-year period is equal to or less than the worst performing PB Peer Group member and (ii) the Company’s ROCE is less than 75% of the next lowest PB Peer Group member.

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If the performance measures are met, the plan participants will “earn” their restricted stock awards, which will then remain subject to time-based vesting in one-third increments in each of the subsequent three years. The combination of the performance period and the vesting schedule results in the awards being realized by the executive over a period of 4 years from the initial award date.

Achievement of the maximum goals will require superior performance of the executives and the Company relative to the Company’s peer group, and the relative difficulty of achieving this performance may be affected by certain risk factors outside the control of the Company and the executives, including risk factors disclosed in the Company’sForm 10-K and other periodic filings.

Target award levels for 2008 and in 2009 were set for each participant based on a multiple of the recommended annual base salary of each executive officer. In determining the number of restricted shares to award, the Compensation Committee used a $10 price applicable on the date the proposed grant schedule was prepared, compared to a lower price on the date of the Committee’s March 11, 2008 meeting at which the awards were actually approved. In determining the number of shares of restricted stock to award, the Committee used this same price.

For awards in each of 2008 and 2009, the PB Peer Group consisted of each of the following companies: (1) Pioneer Drilling Co.; (2) Bronco Drilling Company, Inc.; (3) Tetra Technologies, Inc.; (4) Oil States International, Inc.; (5) Union Drilling, Inc.; (6) Superior Well Services, Inc.; (7) Complete Production Services, Inc.; (8) Allis-Chalmers Energy, Inc. (which also represents the substitute for W-H Energy Services, Inc. as set forth in the 2008 Award Agreement in accordance with its terms due to the merger of W-H Energy Services during 2008); (9) Superior Energy Services, Inc.; and (10) Key Energy Services, Inc.

In general terms, if we rank first among our applicable peer group for both the EPS growth and ROCE measures, our executive officers will earn all of their restricted shares, equal to 150% of the target shares, in each case subject to further time-based vesting. In the event our performance is between the minimum (resulting in forfeiture) and maximum limits, our executive officers may earn a percentage of restricted shares between50-100%.

The total maximum number of shares for all participants for the Three-Year PB Incentive Program awards granted in March 2008 (150% of target) was 152,250 shares, which earned shares would then remain subject to time-based vesting over a three-year period. Of these shares, 84,750 was the maximum number of shares which may be earned by the named executive officers if the Company ranks as the highest in its PB Peer Group for both the EPS growth and ROCE performance measures. Based on peer performance data and the Company’s actual performance for the year, the Committee determined in March 2009 that an aggregate of 56,500 shares (100% of target) were actually earned by the named executive officers under these 2008 awards.

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The following LTIP payout grid shows the actual effect of2006-2008 and the percentage earned based on our ranking within the PB Peer Group (including ourselves):

LTIP Payout Grids — Percentage of Equity Compensation
that may be Retained Based on Relative EPS growth/ROCE Ranking
Peer EPS Change

Peer ROCE Performance

The total maximum number of shares for all participants for the Three-Year PB Incentive Program awards granted in March 2009 (150% of target) was 397,500 shares, which earned shares will then remain subject to time-based vesting in increments over a three-year period. Of these shares, 230,250 is the maximum number of shares which may be earned by the named executive officers if the Company ranks as the highest in its PB Peer Group for both the EPS growth and ROCE performance measures. Annual awards earned are not determinable by the Committee until peer performance data is available. When available, the data will be compiled and compared to the Company’s EPS growth and ROCE performance measures in light of the Company’s actual performance for the year.

The 2008 and 2009 awards under the Three-Year PB Incentive Program, including performance-based awards, do not comply with the provisions of Internal Revenue Code Section 162(m) due to the use of performance periods prior to the grant date.

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Similar to the Quarterly Incentive Bonus Plan, the Three-Year PB Incentive Program is consistent with the Company’s philosophy of tying a significant portion of each executive’s compensation to performance because this aligns the executive officers’ compensation to shareholder interests. This program differs from the Quarterly Incentive Bonus Plan in that it also provides retention benefits, because the executive officers must remain in the employ of the Company for four years from the grant date (including three years of vesting after shares are “earned”) to receive the full benefit, subject to exceptions for termination of executives not for cause, termination for good reason, termination due to death or disability and termination due to change in control.

Discretionary Restricted Stock Grants.  The Committee has used traditional discretionary grants of restricted stock to supplement the Three-Year PB Incentive Program for approximately 50% of total potential awards. Because any awards of restricted stock earned under the Three-Year PB Incentive Program will not begin to vest until the second year after the date of grant of the restricted stock in order to provide continued long-term incentives that are competitive, the Committee determined in March 2008 to make a special grant of restricted stock to the executive officers, which grant is consistent with the equity awards to comparable positions at our peer companies. These time-based awards also provide an opportunity for increased equity ownership by the executives to further the link between the creation of shareholder value and long term incentive compensation. This restricted stock grant will vest in four equal portions beginning two years from the date of the grant.

All restricted stock earned under the Three-Year PB Incentive Program and the special non-performance based restricted stock grant, as is the case with the earlier grants of restricted stock and stock options, will be forfeited if they are not vested prior to the date the executive officer terminates his employment, except in the cases of termination of executives not for cause, termination for good reason, termination due to death or disability and termination due to change in control.

Compensation for our Named Executive Officers.  The 2008 and current 2009 salaries of our named executive officers, including our CEO, were established by the entire Board of Directors at the recommendation of the Compensation Committee. The basis for selecting the severance benefits of each of the named executive officers, including our CEO, as of December 31, 2008 is discussed below under “— Severance Benefits.”

CEO Compensation.  A separate process of evaluating Mr. Huseman was conducted for purposes of determining his 2008 annual bonus paid during March 2009. Specifically, the Committee’s considerations included: (1) earnings per share; (2) three-year average return on capital employed compared to our peer group; (3) our safety record based on total reportable incident rates; (4) our preventable motor vehicle accident rate; (5) our revenue growth; and (6) Mr. Huseman’s personal performance, including Mr. Huseman’s individual goals for fiscal 2008. Based on these considerations, Mr. Huseman was granted an annual cash bonus for 2008 performance of $330,000, equal to approximately 60% of his base salary in effect on December 31, 2008, which bonus was paid during the first quarter of 2009.

Compensation of Other Named Executive Officers.  The Committee reviewed the recommendations of the CEO regarding 2008 bonuses and awards. The Committee’s considerations included the same general Company performance-based factors as well as the individual performance of each of the officers. The annual cash bonuses paid to each of the other named executive officers for 2008 performance was equal to between approximately 30% to 57% of his base salary in effect on December 31, 2008.

During 2008 and continuing into 2009, the Compensation Committee has elected to use restricted stock awards as the primary component of long-term compensation for our executive officers. The rationale behind this shift to use restricted stock awards is that we believe that restricted stock awards provide stronger retention benefits than stock options, especially in slower economic markets. Also, we believe that restricted stock awards more closely align the interests of management with the interests of our other shareholders. Finally, we undertake to provide a compensation package to our executive officers that is competitive with our peers, and the use of restricted stock as long-term incentive compensation has increased among our peer group compared to prior years.

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In 2008, the Committee approved and implemented the 2008 Long-Term Incentive Program consisting of the Three-Year PB Incentive Program and discretionary, time-based restricted stock awards. The rationale behind this was to create a program consistent with the Company’s philosophy of tying a significant portion of each executive’s compensation to performance because this aligns the executive officers’ compensation to shareholder interests, while maintaining an opportunity for increased equity ownership by the executives to further the link between the creation of shareholder value and long term incentive compensation.

In 2009, the Committee approved and implemented its 2009 Long-Term Incentive Program consisting of substantially the same Three-Year PB Incentive Program and discretionary, time-based restricted stock awards for the same rationale.

Perquisites.  The Company provides limited perquisites to its senior executives. Perquisites may include vehicle allowances, club memberships and long-term disability insurance. During 2008, those perquisites were provided to senior management based on individual employment agreements. Each category of perquisites and amounts are set forth in the footnotes to the Summary Compensation Table below under “Executive Compensation and Corporate Governance Matters.”

Severance Benefits.  We entered into amended and restated employment agreements with each of our named executive officers as of December 31, 2006. In addition, in November 2008, in connection with the promotion of officers into new positions, new agreements were entered into with Charles W. Swift, our Senior Vice President — Operations Support (now currently our Vice President — Gulf Coast Region, who executed an amended and restated agreement in March 2009 containing the lower Tier III severance terms as set forth below), and Thomas Monroe Patterson, our Senior Vice President — Rig and Truck Operations. Pursuant to these agreements, each of the named executive officers are entitled to severance payments in the event the officer is terminated at any time by us without “Cause” as defined in the agreements or by the officer for “Good Reason.” In addition, each of the named executive officers is entitled to severance payments in the event of achange-in-control if the officer’s employment is terminated for certain reasons within the six months preceding or the twelve months following a change in control of our company.

The severance payments outside achange-in-control are based on a multiple (for Mr. Huseman — 3.0 times; for Messrs. Krenek and Patterson — 1.5 times; and for Mr. Tyner and (currently) Mr. Swift — 0.75 times) of the sum of the officer’s base salary plus his current annual incentive target bonus for the full year in which the termination of employment occurred.

The severance payments associated with achange-in-control are based on a multiple (for Mr. Huseman — 3.0 times; for Messrs. Krenek and Patterson — 2.0 times; and for Mr. Tyner and (currently) Mr. Swift — 1.0 times) of the sum of the officer’s base salary plus the higher of (i) his current annual incentive target bonus for the full year in which the termination of employment occurred or (ii) the highest annual incentive bonus received by him for any of the last three fiscal years. Mr. Huseman’s current agreement reduced his previous enhancedchange-in-control benefit level that was agreed upon while the Company was a private, controlled company prior to its initial public offering.

The officers’ employment agreements were initially effective through December 31, 2008 (other than those of Messrs. Huseman, Swift and Patterson, whose remain effective through December 31, 2009) and automatically renew for subsequent one year periods unless notice of termination is properly given by us or the officer. In the event that the employment agreement of Messrs. Huseman, Krenek, Swift or Patterson is not renewed by us and a new employment agreement has not been entered into, the officer will be entitled to the same severance benefits described above. We believe this severance requirement is reasonable and not uncommon for persons in the offices and rendering the level of services performed by these individuals.

We selected higher multiples for terminations associated with achange-in-control to provide additional reasonable protections and benefits to the officers in such event, while basing thesechange-in-control termination payments on a “double trigger” requiring additional reasons such as Good Reason or the officer being terminated without Cause. We believe that providing higher multiples forchange-in-control terminations for up to a one-year period after a change in control will provide for their commitment to the Company or its

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potential acquirer through achange-in-control event providing a continuity of leadership and preserving the shareholders’ interests before and after a transaction.

The employment agreements for Messrs. Huseman, Krenek, Swift and Patterson also provide for gross up payments to the extent Section 280G of the Internal Revenue Code would apply to such payments as excess “parachute” payments. The employment agreement for the other named executive officer does not contain these provisions.

For information regarding thechange-in-control benefits to our chief executive officer based on a hypothetical termination date of December 31, 2008, see “Executive Compensation and Corporate Governance Matters — Potential Payments upon Termination orChange-in-Control.”

Board Process.  The Compensation Committee of the Board of Directors reviews all compensation and awards to executive officers. The Compensation Committee on its own, based on input from the Nominating and Governance Committee and discussions with other persons and advisors as it deems appropriate, reviews the performance and compensation of the CEO and approves his level of compensation. For the other executive officers, the Compensation Committee receives recommendations from the CEO. These recommendations are generally approved with minor adjustments. The Compensation Committee grants options and restricted stock, generally based on recommendations from the CEO, pursuant to its authority under the Compensation Committee Charter and the Company’s 2003 Incentive Plan.

Compensation of Directors.  The Compensation Committee is also responsible for determining the annual retainer, meeting fees, stock options and other benefits for members of the Board of Directors. The Compensation Committee’s objective with respect to director compensation is to provide compensation incentives that attract and retain individuals of outstanding ability.

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Directors who are Company employees do not receive a retainer or fees for service on the board or any committees. The Company pays non-employee members of the board for their service as directors. Directors who are not employees received in 2008 and continue to receive as of August 2009:

Annual director fee:	$35,000
Committee Chairmen annual fees:
Audit Committee	$15,000
Compensation Committee	$10,000
Nominating and Corporate Governance Committee	$10,000
Attendance fees (per meeting):
Board	$2,000 (whether in person or telephonic)
Committee	$2,000 (whether in person or telephonic)
Equity-based compensation:
Upon election	37,500 shares of the Company’s common stock at the market price on the date of grant that vest ratably over three years. This prior policy remains subject to change whenever applicable for future directors based on the stock price at such time.
Annual awards	In March 2008, each non-employee director was granted 4,000 shares of restricted stock that vest ratably in four increments of 1,000 shares on March 15, 2010, 2011, 2012 and 2013. In March 2009, each non-employee director was granted 4,000 shares of restricted stock that vest ratably in four increments of 1,000 shares on March 15, 2011, 2012, 2013 and 2014. Our Chairman was also granted an additional 4,000 shares of restricted stock in each of March 2008 and 2009 that was vested upon issuance as consideration for services in his capacity as Chairman and in lieu of the 2008 and 2009 annual director fees, respectively.

Directors are also 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. Director compensation currently in effect for 2009 was based in part on a review and recommendations by Pearl Meyer & Partners.

Compensation Committee Report

The Compensation Committee has reviewed and discussed the above Compensation Discussion and Analysis with management and, based on such review and discussions, the Compensation Committee recommended to the Board of Directors that the Compensation Discussion and Analysis be included in the Proxy Statement filed by the Company on April 24, 2009.

This report of the Compensation Committee shall not be deemed “soliciting material,” or to be “filed” with the Securities and Exchange Commission or subject to Regulation 14A or 14C or to the liabilities of Section 18 of the Securities Exchange Act of 1934 (the “Exchange Act”), except to the extent that the Company specifically requests that the information be treated as soliciting material or specifically incorporates it by reference into a document filed under the Securities Act of 1933 (the “Securities Act”) or the Exchange Act.

William E. Chiles, Chairman
James S. D’Agostino, Jr.
H. H. Wommack, III

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EXECUTIVE COMPENSATION AND CORPORATE GOVERNANCE MATTERS

Summary Compensation Table

The following information relates to compensation paid by the Company for fiscal 2008, 2007 and 2006 to the Company’s Chief Executive Officer, Chief Financial Officer and each of the other three most highly compensated executive officers in fiscal 2008, 2007 and 2006:

Summary Compensation Table

													Change in
													Pension
													Value and
											Non-Equity		Nonqualified
											Incentive		Deferred
							Stock		Option		Plan		Compensation		All Other
			Salary		Bonus		Awards		Awards		Compensation		Earnings		Compensation		Total
Name and Principal Position	Year		($)(1)		($)(2)		($)(3)		($)(3)		($)(4)		($)		($)(5)		($)
Kenneth V. Huseman,		2008	$	550,000		—	$	380,585	$	449,536	$	330,000	$	—	$	9,200	$	1,719,321
President and Chief		2007	$	515,384		—	$	799,460	$	322,565	$	400,000	$	—	$	8,800	$	2,046,209
Executive Officer		2006	$	382,692		—	$	785,250	$	256,281	$	400,000	$	—	$	16,142	$	1,840,365
Alan Krenek,		2008	$	300,000	$	50,000	$	161,516	$	142,579	$	170,000	$	—	$	9,200	$	833,295
Senior Vice President,		2007	$	258,462		—	$	28,704	$	244,738	$	240,000	$	—	$	8,800	$	780,704
Chief Financial Officer, Treasurer and Secretary		2006	$	227,308		—	$	—	$	235,719	$	240,000	$	—	$	10,619	$	713,646
Charles W. Swift,		2008	$	250,000		—	$	140,765	$	116,962	$	75,000	$	—	$	20,796	$	603,523
Senior Vice President,		2007	$	200,000		—	$	104,474	$	87,058	$	160,000	$	—	$	10,597	$	562,129
Operations Support		2006	$	176,154		—	$	87,250	$	76,067	$	200,000	$	—	$	12,081	$	551,552
T.M. “Roe” Patterson,		2008	$	243,846		—	$	109,553	$	57,663	$	150,000	$	—	$	20,233	$	581,295
Senior Vice President,		2007	$	167,692		—	$	17,224	$	32,051	$	140,000	$	—	$	18,764	$	375,731
Rig and Truck Operations		2006	$	118,462		—	$	—	$	34,079	$	140,000	$	—	$	4,542	$	297,083
James E. Tyner		2008	$	190,000	$	30,000	$	55,228	$	57,297	$	80,000	$	—	$	9,546	$	422,071
Vice President,		2007	$	158,462		—	$	11,480	$	35,937	$	80,000	$	—	$	7,219	$	293,098
Human Resources		2006	$	135,891		—	$	—	$	60,313	$	140,000	$	—	$	6,484	$	342,688

(1)	Under the terms of their employment agreements, Messrs. Huseman, Krenek, Swift, Patterson and Tyner are entitled to the compensation described under “Employment Agreements” below.
(2)	Reflects special bonuses paid during 2008 relating to the terminated merger with Grey Wolf, Inc.
(3)	Reflects the dollar amounts recognized for financial reporting purposes with respect to the fiscal year in accordance with FAS 123R. For Stock Awards, includes performance-based awards granted in March 2008 that were earned and issued in March 2009 at 100% of target shares. During 2008 it was estimated that 85% of the target shares would be granted in March 2009. There were no forfeitures in 2008. For Option Awards, assumptions made in the valuation are included in Note 10 to the Company’s audited financial statements for the year ended December 31, 2008.
(4)	Reflects aggregate bonus payments made utilizing metrics under our annual incentive compensation plan and division-level Quarterly Incentive Bonus Plan. Messrs. Huseman and Krenek did not participate in any of the Quarterly Incentive Bonus Plans during 2006, 2007 or 2008 and received only an annual cash bonus in early 2007, 2008 and 2009, respectively. Mr. Swift participated in the division-level Quarterly Incentive Bonus Plan for the first three quarters of 2006 and received an annual cash bonus in early 2007 and participated in the Quarterly Incentive Bonus Plan in the third and fourth quarters of 2007 and all of 2008 and received an annual cash bonus in early 2008 and 2009. Messrs. Patterson and Tyner each participated in the Quarterly Incentive Bonus Plans in 2006, 2007 and 2008 and received an annual cash bonus in early 2007, 2008 and 2009, respectively.
(5)	Includes employer contributions to Executive Deferred Compensation Plan for 2006 as follows: for Huseman, $16,142; for Krenek, $10,619; for Swift, $2,481; and for Tyner, $6,484. Includes employer contributions to Executive Deferred Compensation Plan for 2007 as follows: for Huseman, $8,800; for Krenek, $8,800; for Swift, $457; for Patterson, $8,624; and for Tyner, $7,219. Includes employer contributions to Executive Deferred Compensation Plan for 2008 as follows: for Huseman, $9,200; for Krenek, $9,200; for Swift, $9,936; for Patterson, $9,373; and for Tyner, $9,546. Includes vehicle allowance of $9,600 for 2006, $10,140 for 2007 and $10,860 for 2008 for Mr. Swift and of $4,542 for 2006, $10,140 for 2007 and $10,860 for 2008 for Mr. Patterson.

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Grants of Plan-Based Awards

The following table sets forth information concerning grants of awards to each of our named executive officers under our 2003 Incentive Plan during fiscal 2008:

Grants of Plan-Based Awards — 2008

																All Other		All Other
																Stock		Option
																Awards:		Awards:
				Estimated Future Payouts						Estimated Future Payouts						Number of		Number of		Exercise or		Grant Date
				Under Non-Equity Incentive						Under Equity Incentive						Shares of		Securities		Base Price		Fair Value
				Plan Awards						Plan Awards						Stock or		Underlying		of Option		of Stock
	Grant			Threshold		Target		Maximum		Threshold		Target		Maximum		Units		Options		Awards		and Option
Name	Date			($)		($)		($)		(#)		(#)		(#)		(#)		(#)		($/Sh)		Awards
(a)	(b)			(c)		(d)		(e)		(f)		(g)		(h)		(i)		(j)		(k)		(l)
Kenneth V. Huseman		03/18/08	(1)	$	—	$	—	$	—		—		45,000		—		—		—		—	$	927,900
		03/11/08	(2)	$	—	$	—	$	—		—		22,500		33,750		—		—		—	$	404,876
		03/11/08	(3)	$	0	$	330,000	$	495,000		—		—		—		—		—		—	$	—
Alan Krenek		03/18/08	(1)	$	—	$	—	$	—		—		22,500		—		—		—		—	$	463,950
		03/11/08	(2)	$	—	$	—	$	—		—		12,000		18,000		—		—		—	$	215,934
		03/11/08	(3)	$	0	$	150,000	$	225,000		—		—		—		—		—		—	$	—
Charles W. Swift		03/18/08	(1)	$	—	$	—	$	—		—		17,500		—		—		—		—	$	360,850
		03/11/08	(2)	$	—	$	—	$	—		—		10,000		15,000		—		—		—	$	179,945
		03/11/08	(3)	$	0	$	125,000	$	187,500		—		—		—		—		—		—	$	—
T.M. “Roe” Patterson		03/18/08	(1)	$	—	$	—	$	—		—		16,500		—		—		—		—	$	340,230
		03/11/08	(2)	$	—	$	—	$	—		—		8,000		12,000		—		—		—	$	143,956
		03/11/08	(3)	$	0	$	137,500	$	206,250		—		—		—		—		—		—	$	—
James E. Tyner		03/18/08	(1)	$	—	$	—	$	—		—		7,000		—		—		—		—	$	144,340
		03/11/08	(2)	$	—	$	—	$	—		—		4,000		6,000		—		—		—	$	71,978
		03/11/08	(3)	$	0	$	76,000	$	142,500		—		—		—		—		—		—	$	—

(1)	Shares of restricted stock were granted by our Compensation Committee to certain of our employees, including our named executive officers, on March 18, 2008. The shares of restricted stock vest in one-fourth increments on each of March 15, 2010, 2011, 2012 and 2013. The shares of restricted stock were granted pursuant to our 2003 Incentive Plan.
(2)	Performance-based stock awards approved by our Compensation Committee to certain members of management including our named executive officers on March 11, 2008. The performance-based awards consist of the Company achieving certain earnings per share growth targets and certain return on capital employed performance, over the performance period from January 1, 2006 through December 31, 2008 as compared to other member of a defined peer group. The number of shares to be issued could have ranged from 0% to 150% of the target number of shares depending on the performance noted above. The number of target shares set forth for each named executive officer was earned and issued in March 2009. These shares will vest in one-third increments on each of March 15, 2010, 2011, and 2012.
(3)	Cash incentive bonuses are determined by our Compensation Committee utilizing a set of metrics along with board discretion. These bonuses for 2008 performance were paid in March 2009. Performance targets were communicated to the named executive officers and other members of management that participate in the bonus on March 11, 2008. Potential annual cash awards for our CEO ranged from zero to 90% of base pay with a target level of 60%. Potential annual cash awards for our Tier II named executive officers (Messrs. Krenek, Swift and Patterson) ranged from zero to 75% of base salary, with a target level of 50%. Potential annual cash awards for our Tier III named executive officer (Mr. Tyner) ranged from zero to 60% of base salary, with a target level of 40%.

Employment Agreements

Pursuant to our employment agreement with Kenneth V. Huseman, our President and Chief Executive Officer, Mr. Huseman is entitled to an initial annual base salary of $400,000. Mr. Huseman is also entitled to an annual performance bonus if certain performance criteria are met. In addition, Mr. Huseman is eligible from time to time to receive grants of stock options and other long-term equity incentive compensation under our equity compensation plan. If Mr. Huseman’s employment were to be terminated for certain reasons, he

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would be entitled to a lump sum severance payment equal to three times the sum of his base salary plus his current annual incentive target bonus for the full year in which the termination of employment occurred. Additionally, if Mr. Huseman’s employment were to be terminated for certain reasons within the six months preceding or the twelve months following a change in control of our company, he would be entitled to a lump sum severance payment equal to three times the sum of his base salary plus the higher of (i) his current annual incentive target bonus for the full year in which the termination of employment occurred or (ii) the highest annual incentive bonus received by him for any of the last three fiscal years. Mr. Huseman’s employment agreement is effective through December 31, 2009 and will automatically renew for subsequent one year periods unless notice of termination is properly given by us or Mr. Huseman. In the event that Mr. Huseman’s employment agreement is not renewed by us for any reason other than cause and a new employment agreement has not been entered into prior to the expiration of the then-current term, Mr. Huseman will be entitled to the same severance benefits described above.

We have also entered into employment agreements with Alan Krenek, our Senior Vice President, Chief Financial Officer, Treasurer and Secretary, Charles W. Swift, our Vice President — Gulf Coast Region, and Thomas Monroe Patterson, our Senior Vice President — Rig and Truck Operations. Pursuant to their agreements, Messrs. Krenek, Swift and Patterson are entitled to initial base salaries of $240,000, $250,000 and $275,000, respectively. Each of Messrs. Krenek, Swift and Patterson is also entitled to an annual performance bonus if certain performance criteria are met. In addition, each of Messrs. Krenek, Swift and Patterson is eligible from time to time to receive grants of stock options and other long-term equity incentive compensation under our equity compensation plan. If the employment of any of these officers was to be terminated for certain reasons, he would be entitled to a lump sum severance payment equal to 1.5 times the sum of his base salary plus his current annual incentive target bonus for the full year in which the termination of employment occurred. Additionally, if the employment of any of these officers was to be terminated for certain reasons within the six months preceding or the twelve months following a change in control of our company, he would be entitled to a lump sum severance payment equal to two times the sum of his base salary plus the higher of (i) his current annual incentive target bonus for the full year in which the termination of employment occurred or (ii) the highest annual incentive bonus received by him for any of the last three fiscal years. Each of these employment agreements is effective through December 31, 2009 and will automatically renew for subsequent one year periods unless notice of termination is properly given by us or the officer. In the event that any of these employment agreements is not renewed by us for any reason other than cause and a new employment agreement has not been entered into prior to the expiration of the then-current term, the officer will be entitled to the same severance benefits described above. In March 2009, Mr. Swift’s position was changed from Senior Vice President — Operations to Vice President — Gulf Coast Region.

The employment agreements for Messrs. Huseman, Krenek, Swift and Patterson also provide for gross up payments to the extent Section 280G of the Internal Revenue Code would apply to such payments as excess “parachute” payments.

We have also entered into an employment agreement with James E. Tyner, our Vice President — Human Resources. Pursuant to his agreement, Mr. Tyner is entitled to an initial base salary of $140,000. Mr. Tyner is also entitled to an annual performance bonus if certain performance criteria are met. In addition, Mr. Tyner is eligible from time to time to receive grants of stock options and other long-term equity incentive compensation under our equity incentive plan. If Mr. Tyner’s employment was to be terminated for certain reasons, he would be entitled to a lump sum severance payment equal to 0.75 times the sum of his base salary plus his current annual incentive target bonus for the full year in which the termination of employment occurred. Additionally, if Mr. Tyner’s employment was to be terminated for certain reasons within the six months preceding or the twelve months following a change in control of our company, he would be entitled to a lump sum severance payment equal to one times the sum of his base salary plus the higher of (i) his current annual incentive target bonus for the full year in which the termination of employment occurred or (ii) the highest annual incentive bonus received by him for any of the last three fiscal years. Mr. Tyner’s employment agreement is effective through December 31, 2009 and will automatically renew for subsequent one year periods unless notice of termination is properly given by us or Mr. Tyner. In the event that within the six months preceding or the twelve months following a change in control of our company, Mr. Tyner’s employment agreement is not

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renewed by us for any reason other than cause and a new employment agreement has not been entered into prior to the expiration of the then-current term, Mr. Tyner will be entitled to the change of control severance benefits described above.

As consideration for us entering into the above employment agreements, each of Messrs. Huseman, Krenek, Swift, Tyner and Patterson has agreed in his employment agreement that, for a period of 6 months following the termination of his employment by us without cause or by him for good reason, and for a period of two years following the termination of his employment for retirement or any other reason, he will not, among other things, engage in any business competitive with ours, render services to any entity that is competitive with us or solicit business from certain of our customers or potential customers. These non-competition restrictions will not apply in the event that such termination is within 12 months of a change of control of our company. Additionally, each officer has agreed not to solicit any of our employees to terminate, reduce or otherwise adversely affect his or her employment with us for a period of two years from such officer’s termination of employment for any reason.

The Board initially approved 2009 base salaries for our named executive officers as follows: Huseman — $550,000; Krenek — $300,000; Patterson — $275,000; Swift — $200,000; and Tyner — $190,000. In connection with salary and wage reductions for employees throughout the company that were effective March 30, 2009, the 2009 base salaries for our named executive officers other than Mr. Swift were reduced to: Huseman — $495,000; Krenek — $276,000; Patterson — $253,000; and Tyner — $176,700.

Outstanding Equity Awards at Fiscal Year-End

The following table sets forth information concerning unexercised stock options and unvested restricted stock of each of our named executive officers as of December 31, 2008:

Outstanding Equity Awards at Fiscal Year-End — 2008

	Option Awards										Stock Awards
																	Equity
																	Incentive
																	Plan
															Equity		Awards:
					Equity										Incentive		Market
					Incentive										Plan		or Payout
					Plan										Awards:		Value of
					Awards:								Market		Number of		Unearned
	Number of		Number of		Number of						Number of		Value of		Unearned		Shares,
	Securities		Securities		Securities						Shares		Shares or		Shares,		Units or
	Underlying		Underlying		Underlying						or Units of		Units of		Units or		Other
	Unexercised		Unexercised		Unexercised		Option				Stock That		Stock That		Other Rights		Rights
	Options		Options		Unearned		Exercise		Option		Have Not		Have Not		that Have		That Have
	(#)		(#)		Options		Price		Expiration		Vested		Vested		Not Vested		Not Vested
Name	Exercisable		Unexercisable		(#)		($)		Date		(#)		($)		(#)		($)
(a)	(b)		(c)		(d)		(e)		(f)		(g)		(h)		(i)		(j)
Kenneth V. Huseman
5/5/2003		148,200		—		—	$	4.00		5/4/2013		—		—		—		—
3/2/2005(1)		50,000		50,000		—	$	6.98		3/1/2015		—		—		—		—
3/15/2006(2)		15,000		45,000		—	$	26.84		3/14/2016		—		—		—		—
3/15/2007(3)		—		—		—	$	—		—		5,000	$	65,200		—		—
3/15/2007(4)		—		60,000		—	$	22.66		3/15/2017		—		—		—		—
3/11/2008(5)		—		—		—	$	—		—		22,500	$	293,400		—		—
3/18/2008(6)		—		—		—	$	—		—		45,000	$	586,800		—		—
Alan Krenek
1/26/2005		76,250		—		—	$	5.16		1/25/2015		—		—		—		—
3/2/2005(1)		12,500		12,500		—	$	6.98		3/1/2015		—		—		—		—
3/15/2006(2)		6,250		18,750		—	$	26.84		3/14/2016		—		—		—		—
3/15/2007(3)		—		—		—	$	—		—		10,000	$	130,400		—		—
3/15/2007(4)		—		15,000		—	$	22.66		3/15/2017		—		—		—		—
3/11/2008(5)		—		—		—	$	—		—		12,000	$	156,480		—		—
3/18/2008(6)		—		—		—	$	—		—		22,500	$	293,400		—		—

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	Option Awards										Stock Awards
																	Equity
																	Incentive
																	Plan
															Equity		Awards:
					Equity										Incentive		Market
					Incentive										Plan		or Payout
					Plan										Awards:		Value of
					Awards:								Market		Number of		Unearned
	Number of		Number of		Number of						Number of		Value of		Unearned		Shares,
	Securities		Securities		Securities						Shares		Shares or		Shares,		Units or
	Underlying		Underlying		Underlying						or Units of		Units of		Units or		Other
	Unexercised		Unexercised		Unexercised		Option				Stock That		Stock That		Other Rights		Rights
	Options		Options		Unearned		Exercise		Option		Have Not		Have Not		that Have		That Have
	(#)		(#)		Options		Price		Expiration		Vested		Vested		Not Vested		Not Vested
Name	Exercisable		Unexercisable		(#)		($)		Date		(#)		($)		(#)		($)
(a)	(b)		(c)		(d)		(e)		(f)		(g)		(h)		(i)		(j)
Charles W. Swift
8/13/2001		10,000		—		—	$	4.00		8/12/2011		—		—		—		—
5/5/2003		50,000		—		—	$	4.00		5/4/2013		—		—		—		—
3/2/2005(1)		17,500		17,500		—	$	6.98		3/1/2015		—		—		—		—
3/15/2006(2)		3,750		11,250		—	$	26.84		3/14/2016		—		—		—		—
3/15/2007(3)		—		—		—	$	—		—		6,000	$	78,240		—		—
3/15/2007(4)		—		12,000		—	$	22.66		3/15/2017		—		—		—		—
3/11/2008(5)		—		—		—	$	—				10,000	$	130,400		—		—
3/18/2008(6)		—		—		—	$	—		—		17,500	$	228,200		—		—
T.M. “Roe” Patterson
3/15/2006(2)		3,750		11,250		—	$	26.84		3/14/2016		—		—		—		—
3/15/2007(3)		—		—		—	$	—		—		6,000	$	78,240		—		—
3/15/2007(4)		—		5,000		—	$	22.66		3/15/2017		—		—		—		—
3/11/2008(5)		—		—		—		—		—		8,000	$	104,320		—		—
3/18/2008(6)		—		—		—	$	—		—		16,500	$	215,160		—		—
James E. Tyner
3/2/2005(1)		5,000		5,000		—	$	6.98		3/1/2015		—		—		—		—
3/15/2006(2)		3,750		11,250		—	$	26.84		3/14/2016		—		—		—		—
3/15/2007(3)		—		—		—	$	—		—		4,000	$	52,160		—		—
3/11/2008(5)		—		—		—	$	—		—		4,000	$	52,160		—		—
3/18/2008(6)		—		—		—	$	—		—		7,000	$	91,280		—		—

(1)	One half of the unvested options vested on January 1, 2009. The remainder will vest on January 1, 2010.
(2)	One third of the unvested options vested on January 1, 2009. The remainder will vest in equal increments on January 1, 2010 and 2011.
(3)	One fourth of the unvested shares of restricted stock vested on March 15, 2009. The remainder will vest in equal increments on March 15, 2010, 2011 and 2012.
(4)	One fourth of the unvested options vested on January 1, 2009. The remainder will vest in equal increments on January 1, 2010, 2011 and 2012.
(5)	Unvested shares of restricted stock will vest in three equal increments on March 15, 2010, 2011 and 2012.
(6)	Unvested shares of restricted stock will vest in four equal increments on March 15, 2010, 2011, 2012 and 2013.

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Option Exercises and Stock Vested

The following table sets forth information concerning exercises of stock options and vesting of restricted stock of each of our named executive officers during fiscal 2008:

Option Exercises and Stock Vested — 2008

	Option Awards				Stock Awards
	Number of				Number of
	Shares		Value		Shares		Value
	Acquired		Realized on		Acquired		Realized on
	on Exercise		Exercise		on Vesting		Vesting
Name	(#)		($)		(#)		($)
(a)	(b)		(c)		(d)		(e)
Kenneth V. Huseman		316,205	$	6,345,422		112,500	$	2,352,375
Alan Krenek		11,750	$	187,330		—	$	—
Charles W. Swift		23,225	$	534,392		12,500	$	261,375
T.M. “Roe” Patterson		—	$	—		—	$	—
James E. Tyner		500	$	9,010		—	$	—

Nonqualified Deferred Compensation Plans

The following table sets forth information concerning the nonqualified deferred compensation of our named executive officers during fiscal 2008:

Nonqualified Deferred Compensation — 2008

	Executive		Registrant		Aggregate			Aggregate		Aggregate
	Contributions		Contributions		Earnings in			Withdrawals/		Balance at
	in Last FY		in Last FY		Last FY			Distributions		Last FY
Name	($)		($)		($)			($)		($)
(a)	(b)(1)		(c)(2)		(d)			(e)		(f)(3)
Kenneth V. Huseman	$	85,308	$	9,200	$	(147,114	)	$	—	$	170,398
Alan Krenek	$	46,192	$	9,200	$	(60,580	)	$	—	$	96,128
Charles W. Swift	$	39,205	$	9,936	$	(44,085	)	$	—	$	84,226
T.M. “Roe” Patterson	$	20,798	$	9,373	$	(14,277	)	$	—	$	36,055
James E. Tyner	$	99,591	$	9,546	$	(105,606	)	$	—	$	170,843

(1)	Executive contributions during 2008 are included in the executive’s salary and bonus amounts, as applicable, as reported in the Summary Compensation Table.
(2)	Registrant contributions during 2008 are included in all other compensation in the Summary Compensation Table.
(3)	All amounts were previously reported as compensation in the Summary Compensation Tables for previous years.

Each of our named executive officers is permitted to participate in our Executive Deferred Compensation Plan. An executive permitted to participate in this plan may defer a portion of his compensation, up to a maximum of 50% of his annual salary and 100% of his annual cash bonus, into his plan account. We make an annual matching contribution to each participating executive’s plan account, with the Company matching 100% of the first 3% of the executive’s salary that is deferred, and 50% of the next 2% of the executive’s salary that is deferred, up to a plan-year maximum of $9,200. We may also make discretionary contributions into an executive’s plan account from time to time as we deem appropriate. Subject to certain exceptions, our matching and discretionary contributions vest in one-fourth increments determined by the executive’s years of service, with vesting beginning after two years of service, and full vesting occurring after five years of service. Each executive is always fully vested in his own contributions to his plan account. Earnings on an executive’s plan account for

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any given year are dependent upon the investment options chosen by the executive for such plan account. Generally, participants under this plan may elect when and how distributions of vested amounts in a plan account will be made, including whether such distributions are in annual installments or a lump sum. However, certain key employees, including our named executive officers, may not receive distributions before a date six months after the date their employment with us is terminated for any reason other than death or disability.

Potential Payments upon Termination orChange-in-Control

Each of our named executive officers is party to an employment agreement as described above. Pursuant to these agreements, these officers are entitled to certain severance benefits. In addition, the grant agreements relating to our executives’ stock option and restricted stock awards provide for accelerated vesting under certain circumstances. The tables below quantify amounts that would have been paid assuming the following events took place on December 31, 2008:

Potential Post-employment Payments as of December 31, 2008 — Kenneth V. Huseman

													CIC with
													Termination
							Termination		Termination		Change in		for Good
							by Company		by Executive		Control		Reason or
	Voluntary				Termination		Except for		for Good		without		without
	Termination		Retirement(1)		for Cause(2)		Cause		Reason(3)		Termination(4)		Cause		Death		Disability
Compensation:
Severance(5)	$	—		N/A	$	—	$	2,640,000	$	2,640,000	$	—	$	2,850,000	$	—	$	—
Bonus(6)	$	—	$	330,000	$	—	$	330,000	$	330,000	$	—	$	330,000	$	330,000	$	330,000
Long-term Incentive(7)
Acceleration of Unvested Stock Options	$	—	$	—	$	—	$	—	$	—	$	—	$	303,000	$	—	$	—
Acceleration of Unvested Restricted Stock	$	—	$	—	$	—	$	880,200	$	—	$	1,092,100	$	1,092,100	$	945,400	$	945,400
Benefits & Perquisites(8):
Employer Contributions to Executive Deferred Compensation Plan	$	—		N/A	$	—	$	—	$	—	$	—	$	—	$	—	$	—
COBRA Continuation		N/A		N/A		N/A	$	21,062	$	21,062		N/A	$	21,062	$	—	$	—
280G TaxGross-up		N/A		N/A		N/A		N/A		N/A		N/A	$	—		N/A		N/A
Total	$	—	$	330,000	$	—	$	3,871,262	$	2,991,062	$	1,092,100	$	4,596,162	$	1,275,400	$	1,275,400

Potential Post-employment Payments as of December 31, 2008 — Alan Krenek

													CIC with
													Termination
							Termination		Termination		Change in		for Good
					Termination		by Company		by Executive		Control		Reason or
	Voluntary				for		Except for		for Good		without		without
	Termination		Retirement(1)		Cause(2)		Cause		Reason(3)		Termination(4)		Cause		Death		Disability
Compensation:
Severance(5)	$	—		N/A	$	—	$	675,000	$	675,000	$	—	$	1,080,000	$	—	$	—
Bonus(6)	$	—	$	150,000	$	—	$	150,000	$	150,000	$	—	$	150,000	$	150,000	$	150,000
Long-term Incentive(7)
Acceleration of Unvested Stock Options	$	—	$	—	$	—	$	—	$	—	$	—	$	75,750	$	—	$	—
Acceleration of Unvested Restricted Stock	$	—	$	—	$	—	$	449,880	$	—	$	658,520	$	658,520	$	580,280	$	580,280
Benefits & Perquisites(8):
Employer Contributions to Executive Deferred Compensation Plan	$	—	$	10,071	$	—	$	—	$	—	$	—	$	10,071	$	10,071	$	10,071
COBRA Continuation		N/A		N/A		N/A	$	21,062	$	21,062		N/A	$	21,062	$	—	$	—
280G TaxGross-up		N/A		N/A		N/A		N/A		N/A		N/A	$	—		N/A		N/A
Total	$	—	$	160,071	$	—	$	1,295,942	$	846,062	$	658,520	$	1,995,403	$	740,351	$	740,351

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Potential Post-employment Payments as of December 31, 2008 — Charles W. Swift

													CIC with
													Termination
							Termination		Termination		Change in		for Good
					Termination		by Company		by Executive		Control		Reason or
	Voluntary				for		Except for		for Good		without		without
	Termination		Retirement(1)		Cause(2)		Cause		Reason(3)		Termination(4)		Cause		Death		Disability
Compensation:
Severance(5)	$	—		N/A	$	—	$	562,500	$	562,500	$	—	$	900,000	$	—	$	—
Bonus(6)	$	—	$	125,000	$	—	$	125,000	$	125,000	$	—	$	125,000	$	125,000	$	125,000
Long-term Incentive(7)
Acceleration of Unvested Stock Options	$	—	$	—	$	—	$	—	$	—	$	—	$	106,050	$	—	$	—
Acceleration of Unvested Restricted Stock	$	—	$	—	$	—	$	358,600	$	—	$	502,040	$	502,040	$	436,840	$	436,840
Benefits & Perquisites(8):
Employer Contributions to Executive Deferred Compensation Plan	$	—		N/A	$	—	$	—	$	—	$	—	$	—	$	—	$	—
COBRA Continuation		N/A		N/A		N/A	$	15,096	$	15,096		N/A	$	15,096	$	—	$	—
280G TaxGross-up		N/A		N/A		N/A		N/A		N/A		N/A	$	—		N/A		N/A
Total	$	—	$	125,000	$	—	$	1,061,196	$	702,596	$	502,040	$	1,648,186	$	561,840	$	561,840

Potential Post-employment Payments as of December 31, 2008 — T.M. “Roe” Patterson

													CIC with
													Termination
							Termination		Termination		Change in		for Good
					Termination		by Company		by Executive		Control		Reason or
	Voluntary				for		Except for		for Good		without		without
	Termination		Retirement(1)		Cause(2)		Cause		Reason(3)		Termination(4)		Cause		Death		Disability
Compensation:
Severance(5)	$	—		N/A	$	—	$	618,750	$	618,750	$	—	$	830,000	$	—	$	—
Bonus(6)	$	—	$	137,500	$	—	$	137,500	$	137,500	$	—	$	137,500	$	137,500	$	137,500
Long-term Incentive(7)
Acceleration of Unvested Stock Options	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Acceleration of Unvested Restricted Stock	$	—	$	—	$	—	$	319,480	$	—	$	449,880	$	449,880	$	397,720	$	397,720
Benefits & Perquisites(8):
Employer Contributions to Executive Deferred Compensation Plan	$	—	$	9,570	$	—	$	—	$	—	$	—	$	9,570	$	9,570	$	9,570
COBRA Continuation		N/A		N/A		N/A	$	21,062	$	21,062		N/A	$	21,062	$	—	$	—
280G TaxGross-up		N/A		N/A		N/A	$	N/A	$	N/A		N/A	$	395,583	$	—	$	—
Total	$	—	$	147,070	$	—	$	1,096,792	$	777,312	$	449,880	$	1,843,595	$	544,790	$	544,790

Potential Post-employment Payments as of December 31, 2008 — James E. Tyner

														CIC with
														Termination
							Termination			Termination		Change in		for Good
					Termination		by Company			by Executive		Control		Reason or
	Voluntary				for		Except for			for Good		without		Without
	Termination		Retirement(1)		Cause(2)		Cause			Reason(3)		Termination(4)		Cause		Death		Disability
Compensation:
Severance(5)	$	—		N/A	$	—	$	199,500		$	199,500	$	—	$	330,000	$	—	$	—
Bonus(6)	$	—	$	76,000	$	—	$	76,000		$	76,000	$	—	$	76,000	$	76,000	$	76,000
Long-term Incentive(7)
Acceleration of Unvested Stock Options	$	—	$	—	$	—	$	—		$	—	$	—	$	30,300	$	—	$	—
Acceleration of Unvested Restricted Stock	$	—	$	—	$	—	$	143,440		$	—	$	221,680	$	221,680	$	195,600	$	195,600
Benefits & Perquisites(8):
Employer Contributions to Executive Deferred Compensation Plan	$	—	$	5,337	$	—	$	—		$	—	$	—	$	5,337	$	5,337	$	5,337
COBRA Continuation		N/A		N/A		N/A	$	15,096		$	15,096		N/A	$	15,096	$	—	$	—
									��
Total	$	—	$	81,337	$	—	$	434,036		$	290,596	$	221,680	$	678,413	$	276,937	$	276,937

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(1)	Retirement.  “Retirement” is defined for purposes of Mr. Huseman’s employment agreement as his voluntary termination of his employment after attaining age 60 and accruing five years of service with us, and for purposes of each other executive’s employment agreement, as such executive’s voluntary termination of his employment after attaining age 65 and accruing ten years of service with us. For purposes of the acceleration of unvested stock options, “Retirement” means the voluntary termination of his employment by an executive after he has attained the age of 65.
(2)	Cause.  Under each executive’s employment agreement, the definition of “Cause” includes, among other things, conviction of the executive of a crime involving moral turpitude or a felony, commission by the executive of fraud upon, or misappropriation of funds of, the Company, knowing engagement by the executive in any activity in direct competition with the Company, and a material breach by the executive of such employment agreement. For purposes of the acceleration of unvested stock options, “Cause” has the same meaning as it has for purposes of the 2003 Incentive Plan. For purposes of the acceleration of unvested restricted stock, “Cause” has the same meaning as it has for purposes of the executive’s employment agreement.
(3)	Good Reason.  Under each executive’s employment agreement, the definition of “Good Reason” includes, among other things, a reduction in the executive’s base salary or bonus opportunity, a relocation of more than fifty miles of the executive’s principal office, a substantial and adverse change in the executive’s duties, control, authority, status or position, the failure of the Company to continue in effect any pension plan, life insurance plan,health-and-accident plan, retirement plan, disability plan, stock option plan, deferred compensation plan or executive incentive compensation plan under which the executive was receiving material benefits, or the Company’s material reduction of the executive’s benefits under any such plan, and any material breach by the Company of any other material provision of such employment agreement. Prior to terminating his employment for Good Reason, the executive must comply with the notice provisions of his employment agreement. For purposes of the acceleration of unvested stock options, “Good Reason” has the same meaning as it has for purposes of the 2003 Incentive Plan, except that any reduction in the executive’s salary, bonus opportunity or benefit must follow a change in control. For purposes of the acceleration of unvested restricted stock, “Good Reason” has the same meaning as it has for purposes of the executive’s employment agreement.
(4)	Change in Control.  Under each executive’s employment agreement, the definition of “Change in Control” (or “CIC”) includes, subject to certain exceptions, (i) acquisition by any individual, entity or group of beneficial ownership of 50% or more of either the then outstanding shares of common stock of the Company or the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors, (ii) approval by the shareholders of the Company of a merger, unless immediately following such merger, substantially all of the holders of the Company’s securities immediately prior to merger beneficially own more than 50% of the common stock of the corporation resulting from such merger, and (iii) the sale or other disposition of all or substantially all of the assets of the Company. For purposes of the acceleration of unvested stock options, “Change in Control” has the same meaning as it has for purposes of the 2003 Incentive Plan. For purposes of the acceleration of unvested restricted stock, “Change in Control” has the same meaning as it has for purposes of the executive’s employment agreement. For purposes of the executive deferred compensation plan, “Change in Control” means, subject to certain exceptions, (i) the acquisition by any person other than DLJ Merchant Banking and its affiliates of 40% or more of the combined voting power of the Company’s securities, (ii) the directors serving on the Company’s Board of Directors at the time the plan was adopted ceasing to constitute a majority of the Company’s Board of Directors, or (iii) the liquidation or dissolution of, or the sale of substantially all of the assets of, the Company.
(5)	Severance.
	Termination except for Cause or termination of his own employment for Good Reason or Retirement
	Each executive would be entitled to a lump sum severance payment equal to a multiple of the sum of his base salary plus his current annual incentive target bonus for the full year in which the termination of employment occurred. For Mr. Huseman, the multiple is three, for Messrs. Krenek, Swift and Patterson, the multiple is 1.50, and for Mr. Tyner, the multiple is 0.75. During 2008, the annual incentive target

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	bonus for our named executive officers utilized was 60% for Mr. Huseman, 50% for Messrs. Krenek, Swift and Patterson and 40% for Mr. Tyner, in each case of their annual salary as of the end of the fiscal year. We paid annual incentive bonuses to our named executive officers of between approximately 30% and 60% of their annual salaries as of the end of the fiscal year.
	Termination except for Cause, or termination of his own employment for Good Reason or Retirement, within the six months preceding or the twelve months following a Change in Control
	Each executive would be entitled to a lump sum severance payment equal to a multiple of the sum of his base salary plus the higher of (i) his current annual incentive target bonus for the full year in which the termination of employment occurred or (ii) the highest annual incentive bonus received by him for any of the last three fiscal years. For Mr. Huseman, the multiple is three, for Messrs. Krenek, Swift and Patterson, the multiple is two, and for Mr. Tyner, the multiple is one.
(6)	Bonus.  In addition to severance payments, the named executive officers are entitled to a pro rata portion of their estimated bonus upon certain events of termination. The above tables reflect the annual incentive target bonus for the named executive officers for 2008.
(7)	Long-Term Incentive.
	Stock Options
	In the event of a termination of the executive by the Company for Cause or voluntary termination by the executive (other than for Retirement), all vested and unvested stock options expire on the termination date. In the event of Retirement, all unvested stock options expire on the termination date and all vested options expire six months after the termination date. In the event of death or disability, all unvested stock options expire on the termination date and all vested options expire one year after the termination date. In the event of any other involuntary or voluntary termination, all unvested stock options expire on the termination date and all vested options expire 90 days after the termination date. If the executive’s employment is terminated by the Company other than for Cause or terminated by the executive for Good Reason, in either case within two years after a Change in Control, all unvested stock options will immediately vest pursuant to the terms of the grant agreement and the 2003 Incentive Plan.
	Restricted Stock
	All unvested shares of restricted stock will be forfeited by the executive if the executive’s employment is terminated by the Company for Cause or by the executive other than for Good Reason or as a result of a Change in Control. For awards granted after March 1, 2005, if the executive’s employment is terminated by the Company other than for Cause or terminated by the executive for Good Reason, in either case within two years after a Change in Control, all unvested shares of restricted stock will immediately vest pursuant to the terms of the grant agreement. For awards on or prior to March 1, 2005, in the event of a Change in Control, all unvested shares of restricted stock will immediately vest pursuant to the 2003 Incentive Plan.
(8)	Other Benefits and Perquisites.
	Employer Contributions to Executive Deferred Compensation Plan
	Each executive will become fully vested in all unvested matching and discretionary contributions made by the Company into his plan account upon (i) obtaining the age of 65, (ii) his death or disability or (iii) a termination for any reason whatsoever within 24 months following a Change in Control. Otherwise, each executive will forfeit any unvested portion of his plan account upon a termination for any reason. Additionally, certain key employees, including the named executive officers, may not receive distributions before a date six months after the date they separate service from the Company for any reason other than death or disability.
	COBRA Continuation
	In addition to the above cash benefits paid pursuant to each executive’s employment agreement, the Company will continue to provide the executive and his dependents with health benefits for up to 18 months.
	280G TaxGross-up
	The employment agreements for Messrs. Huseman, Krenek, Swift and Patterson provide for gross up payments to the extent Section 280G of the Internal Revenue Code would apply to any payments as excess “parachute” payments. The employment agreement for Mr. Tyner does not contain this provision.

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Any benefits payable as described above are payable in a cash lump sum not later than 60 calendar days following the termination date. The employment agreements of the named executive officers also contain certain non-competition and non-solicitation provisions. For additional information regarding these employment agreements, see “Executive Compensation and Corporate Governance Matters — Employment Agreements.”

Director Compensation

The following table sets forth information concerning the 2008 compensation of each of our directors other than Kenneth V. Huseman, who is a named executive officer and receives no compensation for serving as a director:

Director Compensation — 2008

									Change in
									Pension Value
	Fees								and
	Earned or						Non-Equity		Nonqualified
	Paid in		Stock		Option		Incentive Plan		Deferred		All Other
	Cash		Awards		Awards		Compensation		Compensation		Compensation		Total
Name	($)		($)		($)		($)		Earnings		($)		($)
(a)	(b)		(c)(1)		(d)(2)		(e)		(f)		(g)		(h)
Steven A. Webster	$	8,000	$	114,639	$	44,337	$	—	$	—	$	—	$	166,976
H.H. Wommack, III(3)	$	59,000	$	29,959	$	44,337	$	—	$	—	$	—	$	133,296
Sylvester P. Johnson, IV	$	67,000	$	29,959	$	44,337	$	—	$	—	$	—	$	141,296
William E. Chiles	$	77,000	$	29,959	$	44,337	$	—	$	—	$	—	$	151,296
Robert F. Fulton	$	49,000	$	29,959	$	44,337	$	—	$	—	$	—	$	123,296
James S. D’Agostino, Jr.	$	69,000	$	29,959	$	44,337	$	—	$	—	$	—	$	143,296
Thomas P. Moore, Jr.	$	82,000	$	29,959	$	75,012	$	—	$	—	$	—	$	186,971

(1)	The grant date fair value of stock awards granted in 2008 were as follows: Steven A. Webster: $169,360; all other directors: $84,680 each. Each of our directors had the following aggregate number of restricted stock awards outstanding at December 31, 2008: Steven A. Webster: 16,000; H. H. Wommack, III: 8,000; Sylvester P. Johnson, IV: 8,000; William E. Chiles: 8,000; Robert F. Fulton: 8,000; James S. D’Agostino, Jr.: 8,000; and Thomas P. Moore, Jr.: 8,000.
(2)	Each of our directors had the following aggregate number of option awards outstanding at December 31, 2008: Steven A. Webster: 97,500; H. H. Wommack, III: 97,500; Sylvester P. Johnson, IV: 97,500; William E. Chiles: 17,500; Robert F. Fulton: 97,500; James S. D’Agostino, Jr.: 77,500; and Thomas P. Moore, Jr.: 42,500.
(3)	Effective June 3, 2009, Mr. Wommack resigned from the board of directors.

For additional information regarding fees earned for services as a director in 2008, including annual retainer fees, committee and chairmanship fees, and meeting fees, see “ Board of Directors — Compensation.” For additional information regarding fees earned for services as a director effective beginning in 2007, see “Compensation Discussion and Analysis — Board Process — Compensation of Directors.”

Board of Directors

Compensation

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. For 2008, directors who were not employees received an annual fee of $35,000. In addition, the chairman of each committee received the following annual fees: Audit Committee — $15,000; Compensation Committee — $10,000; and Nominating and Corporate Governance Committee — $10,000. Directors who were not employees received a fee of $2,000 for each Board meeting attended whether in person or telephonically. For committee meetings, directors who were not employees received a fee of $2,000 for each committee meeting attended whether in

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person or 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, and the option vests ratably over three years.

In 2008, based in part on a review and recommendations by Pearl Meyer & Partners, our independent compensation consultants, and our Compensation Committee, and consistent with compensation for 2007, each non-employee director received an annual grant of 4,000 shares of restricted stock that vest ratably over four years. Our Chairman was also granted additional shares of restricted stock in 2007 and in 2008 that vested upon issuance as consideration for services in his capacity as Chairman and in lieu of his annual director fees. For additional information regarding fees earned for services as a director effective in 2007 and 2008, see “Compensation Discussion and Analysis — Board Process — Compensation of Directors.” 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.

Independence

Our Board of Directors currently consists of eight members, including five members determined by our Board to be independent — Messrs. D’Agostino, Chiles, Garza, Johnson, and Moore.

For 2008, the Board determined that Messrs. D’Agostino, Chiles, Johnson, Moore and Wommack were independent as that term is defined by rules of the New York Stock Exchange and, in the case of the Audit Committee, rules of the Securities and Exchange Commission. In determining that each of these directors was independent, the Board considered that the Company and its subsidiaries in the ordinary course of business sell products and services to other companies, including those at which certain directors serve (or recently served) as executive officers or directors. In particular, Carrizo Oil & Gas, Inc., a company for which Mr. Johnson serves as President and Chief Executive Officer and a director, used the services of the Company, but such services represented less than 2% of Carrizo’s revenues in 2007 and 2008. Affiliates of Mr. Wommack also used services of the Company, but such services also represented less than 2% of such affiliates’ revenues. In each case, the transactions and contributions did not automatically disqualify the directors from being considered independent under the NYSE rules. The Board also determined that these transactions were not otherwise material to the Company or to the other company involved in the transactions and that none of our directors had a material interest in the transactions with these companies. Based upon its review, the Board of Directors affirmatively determined that each of these directors was independent during 2008 and that none of these independent directors had a material relationship with the Company. Effective June 3, 2009, Mr. Wommack resigned from the Board.

Compensation Committee Interlocks and Insider Participation

Messrs. Chiles (Chairman), D’Agostino and Wommack served as the members of our Compensation Committee during 2008. None of our executive officers serves 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. Effective June 3, 2009, Mr. Wommack resigned from the Board.

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Transactions with Related Persons.  Basic had receivables from employees of approximately $138,000 and $148,000 as of June 30, 2009 and December 31, 2008, respectively. During 2006, Basic entered into a lease agreement with Darle Vuelta Cattle Co., LLC, an affiliate of the Chief Executive Officer, for approximately $69,000. The term of the lease is five years and will continue on ayear-to-year basis unless terminated by either party.

Review, Approval or Ratification of Transactions with Related Persons.  Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for establishing procedures for the approval of all related party transactions between the Company and any officer or director that would potentially require disclosure. The Board of Directors has adopted a written policy regarding related party transactions that is to be administered by the Audit Committee. The policy applies generally to transactions, arrangements or relationships in which the Company was, is or will be a participant, in which the amount involved exceeds $60,000 and in which any related person had, has or will have a direct or indirect material interest. Related persons include, among others, directors and officers of the Company, beneficial owners of 5% or more of the Company’s voting securities, immediate family members of the foregoing persons, and any entity in which the foregoing persons are employed, are a principal or in which such person has more than a 10% beneficial ownership interest. The Company’s Chief Financial Officer is responsible for submitting related person transactions to the Audit Committee for approval by the committee at regularly scheduled meetings, or, if such approval is not practicable, to the Chairman of the Audit Committee for approval between such meetings. When considering related person transactions, the Audit Committee, or where submitted to the Chairman, the Chairman, will consider all of the relevant facts available, including, but not limited to: the benefits of the transaction to the Company; the impact on a director’s independence in the event the related person is a director; the availability of other sources for comparable products or services; the terms of the transaction; and the terms of comparable transactions available to unrelated third parties or to employees of the Company generally. The Company is not aware of any transaction that was required to be reported in its filings with the SEC where such policies and procedures either did not require review or were not followed.

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DESCRIPTION OF OTHER INDEBTEDNESS

Credit Facility

On July 31, 2009, in connection with the closing of $225.0 principal amount of our 11.625% Senior Secured Notes due 2014, we repaid all of the borrowings under and terminated our revolving credit facility, and we are unable to borrow any amounts under it. The indenture governing our Senior Secured Notes limits the amount that we could borrow under a future secured credit facility to the difference between (i) $240 million and (ii) the sum of (a) $212.9 million (the principal amount of the Senior Secured Notes, net of offering discount) and (b) our outstanding collateralized letters of credit, subject to possible upward adjustment of the amount in clause (i) based on our consolidated tangible assets.

7.125% Senior Notes Due 2016

Our $225 million aggregate principal amount of 7.125% Senior Notes due April 15, 2016 were issued 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. The Senior Notes are jointly and severally guaranteed by each of our subsidiaries, other than Basic Energy Services International, LLC and ESA de Mexico, S.A. de C.V., two immaterial subsidiaries that have no indebtedness and have not guaranteed other debt.

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

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

•  incur additional indebtedness;

•  pay dividends or repurchase or redeem capital stock;

•  make certain investments;

•  incur liens;

•  enter into certain types of transactions with affiliates;

•  limit dividends or other payments by restricted subsidiaries; and

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

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

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

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

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.

Other Debt

At the closing of our Senior Secured Notes offering, we pledged cash collateral with respect to the approximately $16.2 million of letters of credit that were outstanding under our revolving credit facility.

We have a variety of other capital leases and notes payable outstanding that is generally customary in our business. None of these debt instruments are material individually or in the aggregate. As of June 30, 2009, we had total capital leases of approximately $75.3 million.

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THE EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

On July 31, 2009, we sold $225.0 million in aggregate principal amount 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 best 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 new notes.

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 their advisors, 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 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 one of our or our subsidiary guarantor’s “affiliates,” as defined in Rule 405 of the Securities Act;

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

•  if you are a broker-dealer that will receive new notes for your own account in exchange for old notes acquired as a result of market-making or other trading activities, you will deliver a prospectus in connection with any resale of the 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 11.625% Senior Secured Notes due 2014 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 $2,000 and any integral multiple of $1,000 in excess of $2,000.

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;

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

•  the new notes being issued in the exchange offer will not contain the liquidated damages provisions relating to the old notes.

Expiration, Extension and Amendment

The expiration time of the exchange offer is 5:00 P.M., New York City time, on          , 2009. 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 at which the exchange offer expires, after any extension by us (if applicable). 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 Mellon 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 or an affiliate of any of our subsidiary guarantors, 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 must represent that it is not engaged in, and does not intend to engage in, a distribution of the new notes, and 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 made to the

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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 ofRule 17Ad-15 under the Exchange Act.

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

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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.

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.

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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. 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:

•  a 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 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 July 31, 2009. 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;

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•  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 the exchange offer, whether or not any old notes have been 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 the 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;

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•  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 the 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 the exchange offer, with the acceptance of old notes for exchange or with the exchange of old notes for new notes.

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 the 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;

•  completeand/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.

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 in no-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 holders’ business;

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

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•  the holders are not “affiliates” of ours or of any of our subsidiary guarantors within the meaning of Rule 405 under the Securities Act; and

•  the holders are not broker-dealers 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 a no-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 any of our subsidiary guarantors 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 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 Mellon 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,

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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 MELLON TRUST COMPANY, N.A.

By Facsimile
(for Eligible Institutions):
(212) 298-1915
Attention:           By Mail/Overnight Delivery/Hand:
The Bank of New York Mellon
Corporate Trust Operations
Reorganization Unit
101 Barclay Street - 7 East
New York, NY 10286
Attention:           Confirm By
Telephone:
(212) 815-XXXX

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.

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.

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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

As used below in this “Description of the New Notes” section, the “Issuer” means Basic Energy Services, Inc., a Delaware corporation, and its successors, but not any of its subsidiaries. The Issuer issued the old notes under an Indenture, dated as of July 31, 2009 (the “Indenture”), among the Issuer, the Guarantors and The Bank of New York Mellon Trust Company, N.A., as trustee (the “Trustee”). The Issuer will issue the new notes under the same Indenture, and the new notes will represent the same debt as the old notes for which they are exchanged. References to the “Notes” in this section are to the new notes. The terms of the Notes will include those set forth in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act. You may obtain a copy of the Indenture from the Issuer at its address set forth elsewhere in this prospectus.

The following is a summary of the material terms and provisions of the Notes and the Security Documents described herein. The following summary does not purport to be a complete description of the Notes and the Security Documents and is subject to the detailed provisions of, and qualified in its entirety by reference to, the Indenture. You can find definitions of certain terms used in this description under the heading “— Certain Definitions.”

Principal, Maturity and Interest

The Notes will mature on August 1, 2014. The Notes will bear interest at the rate of 11.625% per year, payable in cash semi-annually in arrears on February 1 and August 1 of each year, commencing on February 1, 2010, to Holders of record at the close of business on the January 15 or July 15, 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.

The Issuer will pay Liquidated Damages to Holders of the Notes if it fails to complete this exchange offer by April 27, 2010 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 $2,000 and integral multiples of $1,000 in excess of $2,000.

The aggregate principal amount of Notes being issued in this exchange offer is $225.0 million. Subject to compliance with the covenant described under “— Certain Covenants — Limitations on Additional Indebtedness,” the Issuer may issue Additional Notes having identical terms and conditions to the Notes being issued in this exchange offer, except for issue date, issue price and first interest payment date,providedthat the aggregate principal amount (net of OID) any such Additional Notes shall not exceed $12,102,750.

Methods of Receiving Payments on the Notes

If a Holder of Notes in certificated form 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.

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Ranking

The Notes will be senior obligations of the Issuer, secured by a first priority Lien on the Collateral described herein (subject only to Permitted Collateral Liens). 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 and pari passu in right of payment with all existing and future obligations of the Issuer that are not so subordinated. Each Note Guarantee (as defined below) will be a senior obligation of the applicable Guarantor, secured by a Lien on Collateral owned by such Guarantor, 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 and pari passu in right of payment with all existing and future obligations of such Guarantor that are not so subordinated.

The Notes and each Note Guarantee will be effectively subordinated to Indebtedness of the Issuer and any applicable Guarantor that is secured by assets other than Collateral, to the extent of the value of the assets securing such Indebtedness.

The Notes will 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, 2009, the Issuer’s non-guarantor subsidiaries did not have any outstanding indebtedness.

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

Payment of the principal of, premium, if any, and interest on the Notes, when and as the same become due and payable, will be fully and unconditionally guaranteed, jointly and severally, on a senior secured basis (the “Note Guarantees”) by the Guarantors. Initially, all of the Issuer’s current Subsidiaries will be Guarantors, other than two immaterial subsidiaries that have no indebtedness and have not guaranteed other debt of the Issuer. In the future, in the circumstances described under “— Certain Covenants — Additional Note Guarantees,” the Issuer will cause certain additional Restricted Subsidiaries to enter into a supplemental indenture pursuant to which each such Restricted Subsidiary will guarantee the Issuer’s obligations under the Notes jointly and severally with any other Guarantors. 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 (other than those that own or hold Collateral) 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 any Credit Facility) 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

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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 Exchange Offer and the New Notes — A court could cancel the new notes or the guarantees of the initial or future guarantors and the security interests in the collateral under fraudulent conveyance laws or certain other circumstances.”

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

A Subsidiary Guarantor will 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.

Security

The obligations under the Notes and the Note Guarantees will be secured pursuant to the Security Documents by first priority Liens (subject to Permitted Collateral Liens) granted to the Trustee for the benefit of the Holders of the Notes, in all of the following property (collectively, the “Collateral”):

(1) subject to limited exceptions, on all of the current and future personal property of the Issuer and the Guarantors, excluding cash and cash equivalents, accounts receivable, inventory, maritime assets (including existing inland barge rigs), titled vehicles and the stock or other equity interests of the Issuer’s subsidiaries;

(2) any assets substituted for such Collateral as provided for in the Security Documents; and

(3) any proceeds of the foregoing.

Subject to the covenant described under “— Certain Covenants — Limitations on Liens,” the Indenture permits the Issuer to encumber any of its assets or those of the Guarantors not constituting Collateral in order to secure other Indebtedness.

Unless an Event of Default under the Indenture shall have occurred and be continuing, the Issuer and the relevant Guarantors have the right to remain in possession and retain exclusive control of the Collateral (other than Collateral deposited with the Trustee in the Asset Sale Proceeds Account described below under “— Certain Covenants — Limitations on Asset Sales and Collateral Dispositions” and other than as set forth in the Security Documents), to freely operate the Collateral and to collect, invest and dispose of any income thereon or therefrom. Upon an Event of Default, these rights will cease and the Trustee will be entitled to foreclose upon and sell the Collateral or any part thereof as provided in the Security Documents.

There can be no assurance that the Trustee will be able to sell the Collateral without substantial delays or that the proceeds obtained will be sufficient to pay all amounts owed to the Trustee, Holders of Notes and

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holders of Permitted Collateral Liens, if any. The Collateral release provisions of the Indenture and the Security Documents permit the release of Collateral without substitution of collateral of equal value under certain circumstances.

Subject to the provisions of the Indenture and the Security Documents, the Trustee in its sole discretion and without the consent of the Holders of the Notes, on behalf of such Holders, may take all actions it deems necessary or appropriate in order to:

(a) enforce any of the terms of the Security Documents; and

(b) collect and receive any and all amounts payable in respect of the obligations of the Issuer or any Guarantor under the Notes, the Indenture and the Security Documents.

The Security Documents provide that the Collateral will be released:

(1) upon payment in full of all outstanding Notes and all other amounts due under the Indenture;

(2) upon satisfaction and discharge of the Indenture as set forth under the caption “— Satisfaction and Discharge;”

(3) upon a Legal Defeasance or Covenant Defeasance as set forth under the caption “— Legal Defeasance and Covenant Defeasance;”

(4) as to any Collateral that constitutes all or substantially all of the Collateral, with the consent of the Holders of 100% in principal amount of the Notes;

(5) as to any Collateral (i) that is sold or otherwise disposed of by the Issuer or any Guarantor (other than to the Issuer or a Guarantor) in compliance with the Indenture, subject to the limitations set forth under the caption “— Certain Covenants — Limitations on Asset Sales and Collateral Dispositions,” (ii) that constitutes a portion of the Asset Sale Proceeds Account that is to be applied or distributed as described under the caption “— Certain Covenants — Limitations on Asset Sales and Collateral Dispositions,” or (iii) that constitutes Excess Collateral Proceeds which have been offered to, but not accepted by, the Holders of Notes and are released as set forth in the covenant described below under the caption “— Certain Covenants — Limitations on Asset Sales and Collateral Dispositions;” or

(6) in connection with a substitution of Collateral of equal or greater value and utility (assuming the substituted Collateral is in the condition required by the Indenture and the Security Documents) in accordance with the Security Documents.

The Security Documents provide that the Issuer and the Guarantors party thereto will, and will cause each of their Subsidiaries to, do or cause to be done all acts and things which may be required, or which the Trustee from time to time may reasonably request, to assure and confirm that the Trustee holds, for the benefit of the Holders of Notes, valid, enforceable and perfected first priority Liens (subject to Permitted Collateral Liens) upon the Collateral as contemplated by the Indenture and Security Documents.

Optional Redemption

General

At any time or from time to time on or after February 1, 2012, 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 February 1, of the years indicated:

	Optional
	Redemption
Year	Price
2012		105.813	%
2013		102.906	%
2014 and thereafter		100.000	%

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Redemption with Proceeds from Equity Offerings

At any time or from time to time prior to February 1, 2012, 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 111.625% 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 February 1, 2012 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 February 1, 2012 (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 February 1, 2012, 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 weekly average yield to maturity at the time of computation of United States Treasury securities with a constant maturity (as compiled and published 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 of similar market data)) equal to the period from the redemption date to February 1, 2012;provided, however, that if the period from the redemption date to February 1, 2012 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) between the weekly average yields of the United States Treasury securities that have a constant maturity closest to and greater than the period from the redemption date to February 1, 2012 and the United States Treasury securities that have a constant maturity closest to and less than the period from the redemption date to February 1, 2012 for which such yields are given, except that if the period from the redemption date to February 1, 2012 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.

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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 a pro rata basis, by lot or by such method as the Trustee shall deem fair and appropriate;provided,however, that no Notes of a principal amount of $2,000 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 a pro rata basis or on as nearly a pro rata basis 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 $2,000 or an integral multiple of $1,000 in excess 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 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, the Issuer 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.

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The provisions described above that require the Issuer 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 properties or 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 properties or 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 ofRule 14e-1 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 will 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.

Certain Covenants

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 $100.0 million;

(2) Indebtedness under (a) the old Notes and the old Note Guarantees issued on the Issue Date and (b) the 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 old Notes (other than Indebtedness referred to in clause (1), (2) or (5));

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(4) Indebtedness under Hedging Obligations entered into for bona fide hedging 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 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)

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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 (provided that 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) (a) 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 (b) the Consolidated Leverage Ratio exceeds 3.00 to 1.00; 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 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,

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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 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 Collateral Dispositions” 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

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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 $10.0 million in any fiscal year or $25.0 million in aggregate amount since the Issue Date;

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.

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 Security Documents, 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 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;

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(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 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;provided that 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

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(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 Issuerand/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;”

(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 will not, and will not permit any Restricted Subsidiary to, directly or indirectly, incur or permit to exist any Lien of any nature whatsoever securing Indebtedness or trade payables (i) on any Collateral, except pursuant to a Security Document and except for Permitted Collateral Liens or (ii) on any of their respective assets or properties (including Equity Interests of a Restricted Subsidiary) that are not Collateral, except for Permitted Liens.

Limitations on Asset Sales and Collateral Dispositions

The Issuer will not, and will not permit any Restricted Subsidiary to, directly or indirectly, consummate any Asset Sale (including a Collateral Disposition that is also an 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.

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The Issuer will not, and will not permit any Restricted Subsidiary to, directly or indirectly, consummate any Collateral Disposition, whether or not constituting an Asset Sale, unless the Trustee has or is immediately granted a perfected first-priority security interest (subject only to Permitted Collateral Liens) in all assets or property received by the Issuer or any Restricted Subsidiary as consideration therefor (excluding any cash or Cash Equivalents) as additional Collateral under the Security Documents to secure the Note Obligations, and, in the case of cash or Cash Equivalents constituting Net Available Proceeds, such cash or Cash Equivalents must be deposited into a segregated account under the sole control of the Trustee that includes only proceeds from the Collateral Disposition and interest earned thereon (an“Asset Sale Proceeds Account”), which proceeds shall be subject to release from the Asset Sale Proceeds Account for the uses described below in this covenant with respect to Collateral Dispositions, as provided for in the Security Documents.

Except with respect to a Collateral Disposition, 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;

(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, except with respect to a Collateral Disposition, 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 a Restricted Subsidiary consummates a Collateral Disposition, then the Issuer or the Restricted Subsidiary shall, no later than 330 days following the consummation thereof, use the Net Available Proceeds thereof (i) to acquire additional assets of a type constituting Collateral,providedthat the Trustee has or is immediately granted a perfected first-priority security interest (subject only to Permitted Collateral Liens) in such additional assets, or (ii) to repurchase or redeem Notes. The amount of Net Available Proceeds from a Collateral Disposition that are not so applied shall constitute “Excess Collateral Proceeds.” On the 331st day following such a Collateral Disposition, if there are Excess Collateral Proceeds, or earlier if the Issuer so determines, the Issuer must make an offer to purchase from all Holders of Notes, on a pro rata basis, an aggregate principal amount of Notes equal to the amount of such Excess Collateral Proceeds (a“Collateral

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Proceeds Offer”), in accordance with the procedures set forth in the Indenture, at an offer price payable in cash in an amount equal to 100% of the principal amount of the Notes tendered pursuant to a Collateral Proceeds Offer, plus accrued and unpaid interest and Liquidated Damages thereon, if any, to the date such Collateral Proceeds Offer is consummated. If the aggregate amount of Notes validly tendered and not withdrawn by Holders thereof exceeds the amount of Excess Collateral Proceeds, Notes will be purchased from tendering Holders on a pro rata basis. Upon completion of such Collateral Proceeds Offer, and purchase of Notes tendered thereunder as required, the amount of Excess Collateral Proceeds with respect to which such Collateral Proceeds Offer was made shall be deemed to be zero. To the extent that the Excess Collateral Proceeds exceeds the aggregate principal amount of Notes tendered for purchase pursuant to the relevant Collateral Proceeds Offer, the Issuer may use such excess funds for any purposes not otherwise prohibited by the provisions of the Indenture.

If the Issuer or any Restricted Subsidiary engages in an Asset Sale other than a Collateral Disposition, 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 any Credit Facility 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 of an Asset Sale other than a Collateral Disposition 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 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;

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(3) if the aggregate Offered Price of Notes validly tendered and not withdrawn by Holders thereof exceeds the pro rata portion of the Payment Amount allocable to the Notes, Notes to be purchased will be selected on a pro rata basis; 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 ofRule 14e-1 under the Exchange Act and any other applicable laws and regulations in connection with the purchase of Notes pursuant to a Collateral Proceeds Offer or a Net Proceeds Offer. To the extent that the provisions of any securities laws or regulations conflict with the “Limitations on Asset Sales and Collateral Dispositions” 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 and Collateral Dispositions” 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 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;

(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; and

(5) does not own or hold any Collateral.

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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 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, the Security Documents 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.

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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, the Security Documents to which such Guarantor is a party 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 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.

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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. In addition to the foregoing, the Issuer shall cause any Restricted Subsidiary that owns or holds Collateral and is not already a Guarantor to become a Guarantor by executing a supplemental indenture in the manner contemplated by the Indenture.

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.

Maintenance of Equipment Collateral; Insurance

The Issuer will, and will cause its Restricted Subsidiaries to, maintain all equipment constituting Collateral in good condition and repair, reasonable wear and tear excepted, and shall as quickly as commercially practicable make or cause to be made all repairs, replacements and other improvements that are necessary or appropriate in the conduct of the Issuer’s ordinary course of business. Specifically in connection with the foregoing, the Issuer will not, and will cause its Restricted Subsidiaries not to, remove or separate any part, accessory or accession that is part of or affixed to an item of Collateral (whether a part of or affixed to such Collateral on the Issue Date or thereafter becoming a part thereof or affixed thereto) unless such part, accessory or accession is damaged, worn-out or obsolete (in which case the same shall promptly be replaced by a working part, accessory or accession of the same function) or unless separated and remains Collateral affixed to other Collateral, or such part, accessory or accession is sold or otherwise disposed of in accordance with the Indenture.

The Issuer will, and will cause its Restricted Subsidiaries to, maintain adequate insurance or otherwise insure against hazards as is usually done by corporations operating assets of a similar nature in the same or similar localities.

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 onForms 10-Q and10-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

(2) all current reports that would be required to be filed with the SEC onForm 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

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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 or any Guarantor to comply with any other agreement or covenant in the Indenture or any Security Document 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;

(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); or

(9) any Security Document or any Lien purported to be created or granted thereby on any one or more items of Collateral is held in any judicial proceeding to be unenforceable or invalid, in whole or part, or ceases for any reason (other than pursuant to a release that is delivered or becomes effective as set forth in the Indenture or any Security Documents) to be fully enforceable and perfected.

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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 immediately;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, the Security Documents 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.

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.

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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) and (8) and (9) 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 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,

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(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 the Issuer’s 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:

(1) (a) 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 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

(b) 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,

(2) the Issuer has paid all other sums payable by it under the Indenture, and

(3) 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.

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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, the Security Documents 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 optional redemption of the Notes or change the date on which any Notes are subject to optional redemption or waive any payment with respect to the optional redemption of the Notes or modify any obligation of the Issuer under the covenant described above under the caption “— Change of Control;”

(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;

(10) except as expressly provided in the Indenture or any Security Document, release all or substantially all of the Liens on the Collateral; or

(11) make any change in these amendment and waiver provisions.

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Notwithstanding the foregoing, the Issuer and the Trustee may amend the Indenture, the Security Documents, 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 add Collateral for or further 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 Notes to the extent that such provision in this Description of the Notes was intended to be a verbatim recitation of a provision of the Indenture, the Security Documents, the Note Guarantees or the Notes;

(10) to provide for the issuance of Additional Notes in accordance with the Indenture; or

(11) with respect to the Security Documents, to effect the release of Collateral in accordance with the terms thereof and the Indenture, or as otherwise provided therein or in 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 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, the Security Documents or the Indenture or of any Guarantor under its Note Guarantee or the Security Documents 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 Mellon 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.

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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 is, and 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 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

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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 or the Security Documents 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;

(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 cashand/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.

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“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 (provided that 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;

(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 or S&P 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 inRules 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.

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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.

“Collateral Disposition”means any sale, transfer or other disposition to the extent involving assets or other rights or property that constitute Collateral under the Security Documents. The sale or issuance of Equity Interests in a Restricted Subsidiary that owns Collateral such that it thereafter is no longer a Restricted Subsidiary shall be deemed to be a Collateral Disposition of the Collateral owned by such Restricted Subsidiary.

“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, 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

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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 properly in pro forma financial statements prepared in accordance withRegulation 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),

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(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 Leverage Ratio”means, at the time of determination, the ratio of the total Indebtedness of the Issuer and its Restricted Subsidiaries, determined on a consolidated basis in accordance with GAAP, to Consolidated Cash Flow during the most recent four consecutive full fiscal quarters for which financial statements are available ending on or prior to the date of the event giving rise to the determination (with Consolidated Cash Flow being calculated for such purpose on a pro forma basis in the same manner as it would be calculated for purposes of the definition of Consolidated Interest Coverage Ratio).

“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;

(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

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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 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 Fourth Amended and Restated Credit Agreement dated as of October 3, 2003 and as amended and restated as of February 6, 2007 by and among the Issuer, as Borrower, the subsidiary guarantors party thereto, Bank of America, N.A. as syndication agent, Capital One, National Association 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, but excluding for purposes of clarification, the Indenture) 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.

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“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 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 and Collateral Dispositions,” 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 new notes and the old notes as required pursuant to the provisions described under “— Change of Control” and “— Certain Covenants — Limitations on Asset Sales and Collateral Dispositions,” 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.

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“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), totake-or-pay, or to maintain 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 other than Basic Energy Services International, LLC, 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 new notesand/or the old 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;

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(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.

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);

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(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 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 of original issuance of the old notes.

“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 or Collateral Disposition, 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 or Collateral Disposition, 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 or Collateral Disposition;

(2) provisions for taxes payable as a result of such Asset Sale or Collateral Disposition (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 Collateral Disposition 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 or Collateral Disposition; 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 or Collateral Disposition and retained by the Issuer or any Restricted Subsidiary, as the case may be, after such Asset Sale or Collateral Disposition, including pensions and other postemployment benefit liabilities, liabilities related to environmental matters and liabilities under any indemnification obligations associated with such Asset Sale or Collateral Disposition, 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.

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“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 the new notes and old 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.

“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 ranks pari passu in 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 Collateral Liens”means Liens described in clauses (1), (2), (3), (5), (6) and (12) of “Permitted Liens.”

“Permitted Holder”means Credit Suisse, a Swiss Bank, Credit Suisse Group, Credit Suisse Holdings (USA), Inc., Credit Suisse (USA), Inc. 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 for bona fide hedging 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;

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(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 or Collateral Disposition made in compliance with the covenant described under “— Certain Covenants — Limitations on Asset Sales and Collateral Dispositions;”

(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;

(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) after the Issue Date, that does not exceed $20.0 million;

(13) Investments existing on the Issue Date;

(14) repurchases of, or other Investments in, the new notes or old 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;

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(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;

(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 new notes and old notes and Liens securing any guarantee of the new notes or old notes;

(13) Liens securing Hedging Obligations entered into for bona fide hedging 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;

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(16) Liens securing Indebtedness incurred under the Credit Facilities or with respect to other obligations that do not exceed in the aggregate the greater of (a) $15.0 million or (b) 3.0% of the Issuer’s Consolidated Tangible Assets at any time outstanding;

(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.

(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; and

(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.

“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.

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“principal”means, with respect to the new notes and old notes, the principal of, and premium, if any, on the new notes and old 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 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 new notes and old notes to be redeemed are received by the Issuer as a capital contribution immediately prior to such redemption.

“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 old 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 and pro rata dividends 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.

“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.

“Security Documents”means any one or more security agreements, pledge agreements, collateral assignments, mortgages, deeds of covenants, assignments of earnings and insurances, share pledges, collateral

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agency agreements, deeds of trust or other grants or transfers for security executed and delivered by the Issuer, the Guarantors or any other obligor under the Indenture creating, or purporting to create, a Lien upon Collateral in favor of the Trustee for the benefit of the Holders of the new notes and old notes, in each case as amended, modified, renewed, restated or replaced, in whole or part, from time to time, in accordance with its terms.

“Significant Subsidiary”means (1) any Restricted Subsidiary that owns Collateral or that would be a “significant subsidiary” as defined inRegulation 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. For purposes of the covenant described under “— Certain Covenants — Limitations on Restricted Payments,” the Issuer’s outstanding 7.125% Senior Notes due 2016 and any Refinancing Indebtedness issued with respect to such outstanding senior notes will be deemed to be “Subordinated Indebtedness.”

“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 new 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 new 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 new notes, DTC or such nominee will be considered the sole owner or holder of such new notes represented by such global securities for all purposes under the indenture and under the new 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 of the old notes), 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 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

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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 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

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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 insame-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 forsame-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;

•  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.

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MATERIAL UNITED STATES FEDERAL INCOME TAX CONSEQUENCES

The following discussion of the material U.S. federal income tax consequences relevant to the exchange of new notes for old notes pursuant to the exchange offer does not purport to be a complete analysis of all potential tax effects. The discussion 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 consequences.

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.

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          , 2009, 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 the over-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 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

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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.

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 and related financial statement schedules of Basic Energy Services, Inc. and subsidiaries as of December 31, 2008 and 2007, and for each of the years in the three-year period ended December 31, 2008, and management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2008 have been included in this prospectus and in the registration statement in reliance upon the reports of KPMG LLP, 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 on the effectiveness of internal control over financial reporting as of December 31, 2008, contains an explanatory paragraph that states that the Company acquired substantially all of the assets of Azurite Services Company, Inc., Azurite Leasing Company, LLC and Freestone Disposal, L.P. (collectively “Azurite”) during 2008, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008 Azurite’s internal control over financial reporting associated with total assets of approximately $60.2 million and total revenues of approximately $10.9 million included in the consolidated financial statements of Basic Energy Services, Inc. and subsidiaries as of and for the year ended December 31, 2008. KPMG LLP’s audit of internal control over financial reporting of Basic Energy Services, Inc. also excluded an evaluation of the internal control over financial reporting of Azurite.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement onForm S-4, including exhibits and schedules, under the Securities Act with respect to the offer to exchange our senior secured 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, 500 W. Illinois, Suite 100, Midland, Texas 79701,(432) 620-5500.

160

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Audited Consolidated Financial Statements
Management’s Report on Internal Control Over Financial Reporting		F-2
Report of Independent Registered Public Accounting Firm		F-3
Consolidated Balance Sheets as of December 31, 2008 and 2007		F-5
Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2008, 2007 and 2006		F-6
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2008, 2007 and 2006		F-7
Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006		F-8
Notes to Consolidated Financial Statements		F-9
Financial Statement Schedule II — Valuation and Qualifying Accounts		F-37
Unaudited Consolidated Financial Statements
Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008		F-38
Consolidated Statements of Operations and Comprehensive Income for the three months and six months ended June 30, 2009 and 2008		F-39
Consolidated Statements of Stockholders’ Equity for the six months ended June 30, 2009		F-40
Consolidated Statements of Cash Flows for the six months ended June 30, 2009 and 2008		F-41
Notes to Consolidated Financial Statements		F-42

F-1

MANAGEMENT’S REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Basic Energy Services, Inc. (“Basic” or “the Company”) is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting for the Company. As defined by the Securities and Exchange Commission(Rule 13a-15(f) under the Exchange Act of 1934, as amended), internal control over financial reporting is a process designed by, or under the supervision of Basic’s principal executive and principal financial officers and effected by its Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles.

The Company’s internal control over financial reporting is supported by written policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the Company’s transactions and dispositions of the Company’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorization of the Company’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the consolidated financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In connection with the preparation of the Company’s annual consolidated financial statements, management has undertaken an assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO Framework). Management’s assessment included an evaluation of the design of the Company’s internal control over financial reporting and testing of the operational effectiveness of those controls.

Based on this assessment, management has concluded that as of December 31, 2008, the Company’s internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles.

The Company acquired substantially all of the assets of Azurite Services Company, Inc., Azurite Leasing Company, LLC and Freestone Disposal, L.P. (collectively “Azurite”) during 2008, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008 any internal control evaluation over financial reporting the associated total assets of approximately $60.2 million and total revenues of approximately $10.9 million included in the consolidated financial statements of Basic Energy Services Inc. and subsidiaries as of and for the year ended December 31, 2008.

KPMG LLP, the independent registered public accounting firm that audited the Company’s consolidated financial statements included in this report, has issued an audit report on the effectiveness of internal control over financial reporting.

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

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Basic Energy Services, Inc.:

We have audited Basic Energy Services, Inc’s (the Company) internal control over financial reporting as of December 31, 2008, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Basic Energy Services, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established inInternal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

The Company acquired substantially all of the assets of Azurite Services Company, Inc., Azurite Leasing Company, LLC, and Freestone Disposal, L.P. (collectively, “Azurite”) during 2008, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008, Azurite’s internal control over financial reporting associated with total assets of $60.2 million and total revenues of $10.9 million included in the consolidated financial statements of Basic Energy Services, Inc. and subsidiaries as of and for the year ended December 31, 2008. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of Azurite.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Basic Energy Services, Inc. and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2008, and our report dated March 6, 2009 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

Dallas, Texas

March 6, 2009

F-3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Basic Energy Services, Inc.:

We have audited the accompanying consolidated balance sheets of Basic Energy Services, Inc. and subsidiaries (the Company) as of December 31, 2008 and 2007, and the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2008. In connection with our audits of the consolidated financial statements, we also have audited the accompanying financial statement schedule. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Basic Energy Services, Inc. and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Basic Energy Services, Inc.’s internal control over financial reporting as of December 31, 2008, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 6, 2009 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

KPMG LLP

Dallas, Texas

March 6, 2009

F-4

BASIC ENERGY SERVICES, INC.

Consolidated Balance Sheets

	December 31,
	2008			2007
	(In thousands, except
	share data)
ASSETS
Current assets:
Cash and cash equivalents	$	111,135		$	91,941
Trade accounts receivable, net of allowance of $5,838 and $6,090, respectively		172,930			138,384
Accounts receivable — related parties		148			91
Federal income tax receivable		3,324			1,130
Inventories		11,937			11,034
Prepaid expenses		6,838			6,999
Other current assets		6,508			6,353
Deferred tax assets		11,081			10,593
Total current assets		323,901			266,525
Property and equipment, net		740,879			636,924
Deferred debt costs, net of amortization		5,132			6,100
Goodwill		202,749			204,963
Other intangible assets		36,004			26,975
Other assets		2,046			2,122
Total assets	$	1,310,711		$	1,143,609
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	28,291		$	22,146
Accrued expenses		47,139			51,003
Current portion of long-term debt		26,063			17,413
Other current liabilities		658			1,474
Total current liabilities		102,151			92,036
Long-term debt		454,260			406,306
Deferred tax liabilities		149,591			114,604
Other long-term liabilities		9,705			5,842
Commitments and contingencies
Stockholders’ equity:
Preferred stock; $.01 par value; 5,000,000 shares authorized; none designated or issued at December 31, 2008 and December 31, 2007, respectively		—			—
Common stock; $.01 par value; 80,000,000 shares authorized; 41,734,485 shares issued and 40,851,862 shares outstanding at December 31, 2008; and 40,925,530 shares issued and 40,896,217 shares outstanding at December 31, 2007		417			409
Additional paid-in capital		325,785			314,705
Retained earnings		277,173			209,707
Treasury stock, 882,623 and 29,313 shares at December 31, 2008 and 2007, respectively		(8,371	)		—
Total stockholders’ equity		595,004			524,821
Total liabilities and stockholders’ equity	$	1,310,711		$	1,143,609

See accompanying notes to consolidated financial statements.

F-5

BASIC ENERGY SERVICES, INC.

Consolidated Statements of Operations and Comprehensive Income

	Years Ended December 31
	2008			2007			2006
	(Dollars in thousands, except
	per share amounts)
Revenues:
Well servicing	$	343,113		$	342,697		$	323,755
Fluid services		315,768			259,324			245,011
Completion and remedial services		304,326			240,692			154,412
Contract drilling		41,735			34,460			6,970
Total revenues		1,004,942			877,173			730,148
Expenses:
Well servicing		215,243			205,132			178,028
Fluid services		203,205			165,327			153,445
Completion and remedial services		165,574			125,948			74,981
Contract drilling		28,629			22,510			8,400
General and administrative, including stock-based compensation of $4,149, $3,964 and $3,429 in 2008, 2007 and 2006, respectively		115,319			99,042			81,318
Depreciation and amortization		118,607			93,048			62,087
Loss on disposal of assets		76			477			277
Goodwill impairment		22,522			—			—
Total expenses		869,175			711,484			558,536
Operating income		135,767			165,689			171,612
Other income (expense):
Interest expense		(26,766	)		(27,416	)		(17,466	)
Interest income		2,136			2,280			1,962
Loss on early extinguishment of debt		—			(230	)		(2,705	)
Other income		12,235			176			169
Income from continuing operations before income taxes		123,372			140,499			153,572
Income tax expense		(55,134	)		(52,766	)		(54,742	)
Net income		68,238			87,733			98,830
Basic earnings per share of common stock:
Net income available to common stockholders	$	1.67		$	2.19		$	2.87
Diluted earnings per share of common stock:
Net income available to common stockholders	$	1.64		$	2.13		$	2.56
Comprehensive income:
Net income	$	68,238		$	87,733		$	98,830
Unrealized gains on hedging activities		—			—			51
Less: reclassification adjustment for gain included in net income		—			—			(287	)
Comprehensive income:	$	68,238		$	87,733		$	98,594

See accompanying notes to consolidated financial statements.

F-6

BASIC ENERGY SERVICES, INC.

Consolidated Statements of Stockholders’ Equity

																	Accumulated
					Additional									Retained			Other			Total
	Common Stock				Paid-In			Deferred			Treasury			Earnings			Comprehensive			Stockholders’
	Shares		Amount		Capital			Compensation			Stock			(Deficit)			Income			Equity
	(In thousands, except share data)
Balance — December 31, 2005		33,931,935	$	339	$	239,218		$	(7,341	)	$	(2,531	)	$	28,654		$	236		$	258,575
Adoption of Statement of Financial Accounting Standard No. 123R		—		—		(7,341	)		7,341			—			—			—			—
Amortization of deferred compensation		—		—		3,429			—			—			—			—			3,429
Unrealized gain on interest rate swap agreement		—		—		—			—			—			—			51			51
Settlement of interest rate swap agreement		—		—		—			—			—			—			(287	)		(287	)
Offering costs		—		—		(227	)		—			—			—			—			(227	)
Exercise of stock warrants		4,350,000		44		17,357			—			—			—			—			17,401
Purchase of treasury stock		—		—		—			—			(3,218	)		—			—			(3,218	)
Exercise of stock options		15,670		—		4,091			—			5,749			(5,144	)		—			4,696
Net income		—		—		—			—			—			98,830			—			98,830
Balance — December 31, 2006		38,297,605		383		256,527			—			—			122,340			—			379,250
Issuance of restricted stock		229,100		2		(2	)		—			—			—			—			—
Amortization of share based compensation		—		—		3,873			—			—			—			—			3,873
Stock issued as compensation to Chairman of the Board		4,000		—		91			—			—			—			—			91
Stock issued in JetStar Consolidated Holdings, Inc. acquisition		1,794,759		18		41,011			—			—			—			—			41,029
Stock issued in Sledge Drilling Holding Corp acquisition		430,191		4		10,161			—			—			—			—			10,165
Purchase of treasury stock		—		—					—			(462	)		—			—			(462	)
Exercise of stock options		169,875		2		3,044			—			462			(366	)		—			3,142
Net income		—		—					—			—			87,733			—			87,733
Balance — December 31, 2007		40,925,530		409		314,705			—			—			209,707			—			524,821
Issuances of restricted stock		361,700		4		(25	)		—			21			—			—			—
Amortization of share based compensation		—		—		4,064			—			—			—			—			4,064
Treasury stock issued as compensation to Chairman of the Board		—		—		—			—			89			(4	)		—			85
Purchase of treasury stock		—		—		—			—			(9,994	)		—			—			(9,994	)
Exercise of stock options		447,255		4		7,041			—			1,513			(768	)		—			7,790
Net income		—		—		—			—			—			68,238			—			68,238
Balance — December 31, 2008		41,734,485	$	417	$	325,785		$	—		$	(8,371	)	$	277,173		$	—		$	595,004

See accompanying notes to consolidated financial statements.

F-7

BASIC ENERGY SERVICES, INC.

Consolidated Statements of Cash Flows

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

See accompanying notes to consolidated financial statements.

F-8

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements

December 31, 2008, 2007, and 2006

1.   Nature of Operations

Basic Energy Services, Inc. provides a range of well site services to oil and gas drilling and producing companies, including well servicing, fluid services, completion and remedial services and contract drilling. These services are primarily provided by Basic’s fleet of equipment. Basic’s operations are concentrated in the major United States onshore oil and gas producing regions in Texas, New Mexico, Oklahoma, Kansas, Arkansas and Louisiana, and the Rocky Mountain states.

Basic revised its reportable business segments beginning in the first quarter of 2008, and in connection therewith restated the corresponding items of segment information for earlier periods. The new operating segments are Well Servicing, Fluid Services, Completion and Remedial Services, and Contract Drilling. These segments were selected based on changes in management’s resource allocation and performance assessment in making decisions regarding the Company. Contract Drilling was previously included in our Well Servicing segment. Well Site Construction Services is consolidated with our Fluid Services segment. These changes reflect Basic’s operating focus in compliance with SFAS No. 131,“Disclosures about Segments of an Enterprise and Related Information.”

2.   Summary of Significant Accounting Policies

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Basic and its wholly-owned subsidiaries. Basic has no interest in any other organization, entity, partnership, or contract that could require any evaluation under FASB Interpretation No. 46R or Accounting Research Bulletin No. 51. All intercompany transactions and balances have been eliminated.

Estimates, Risks and Uncertainties

Preparation of the accompanying consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amount of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Areas where critical accounting estimates are made by management include:

•  Depreciation and amortization of property and equipment and intangible assets

•  Impairment of property and equipment, goodwill and intangible assets

•  Allowance for doubtful accounts

•  Litigation and self-insured risk reserves

•  Fair value of assets acquired and liabilities assumed

•  Stock-based compensation

•  Income taxes

•  Asset retirement obligation

Oil and gas prices decreased significantly in the second half of 2008 which resulted in lower utilization of the Company’s services in the fourth quarter of 2008. For 2009, the Company expects oil and gas prices to remain substantially below the levels required to support aggressive capital spending programs by its customers and that maintenance related spending by customers will be deferred as long as possible. The Company

F-9

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

expects the reduced spending level by its customers will result in lower demand for its services and increased price competition among service providers in all segments of its business which will negatively affect the Company’s revenue and gross margins.

Revenue Recognition

Well Servicing — Well servicing consists primarily of maintenance services, workover services, completion services and plugging and abandonment services. Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Basic prices well servicing by the hour or by the day of service performed.

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

Completion and Remedial Services (formerly Drilling and Completion Services) — Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Basic prices completion and remedial services by the hour, day, or project depending on the type of service performed. When Basic provides multiple services to a customer, revenue is allocated to the services performed based on the fair values of the services.

Contract Drilling — Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Basic prices these jobs by “daywork” contracts, in which an agreed upon rate per day is charged to the customer, or “footage” contracts, in which an agreed upon rate per the number of feet drilled is charged to the customer.

Taxes assessed on sales transactions are presented on a net basis and are not included in revenue.

Cash and Cash Equivalents

Basic considers all highly liquid instruments purchased with a maturity of three months or less to be cash equivalents. Basic maintains its excess cash in various financial institutions, where deposits may exceed federally insured amounts at times.

Fair Value of Financial Instruments

The carrying value amount of cash, accounts receivable, accounts payable and accrued liabilities approximate fair value due to the short maturity of these instruments. The carrying amount of long-term debt approximates fair value because Basic’s current borrowing rate is based on a variable market rate of interest.

Inventories

For rental and fishing tools, inventories consisting mainly of grapples, controls, and drill bits are stated at the lower of cost or market, with cost being determined on the average cost method. Other inventories, consisting mainly of rig components, repair parts, drilling and completion materials and gravel, are held for use in the operations of Basic and are stated at the lower of cost or market, with cost being determined on 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

F-10

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

additions and improvements that significantly extend the lives of the assets are capitalized. Upon sale or other retirement of depreciable property, the cost and accumulated depreciation and amortization are removed from the related accounts and any gain or loss is reflected in operations. All property and equipment are depreciated or amortized (to the extent of estimated salvage values) on the straight-line method and the estimated useful lives of the assets are as follows:

Building and improvements	20-30 years
Well servicing units and equipment	3-15 years
Fluid services equipment	5-10 years
Brine and fresh water stations	15 years
Frac/test tanks	10 years
Pressure pumping equipment	5-10 years
Construction equipment	3-10 years
Contract drilling equipment	3-10 years
Disposal facilities	10-15 years
Vehicles	3-7 years
Rental equipment	3-15 years
Aircraft	20 years
Software and computers	3 years

The components of a well servicing rig generally require replacement or refurbishment during the well servicing rig’s life and are depreciated over their estimated useful lives, which ranges from 3 to 15 years. The costs of the original components of a purchased or acquired well servicing rig are not maintained separately from the base rig.

Impairments

In accordance with Statement of Financial Accounting Standards No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets(“SFAS No. 144”), long-lived assets, such as property, plant, and equipment, and purchased intangibles subject to amortization, are reviewed for impairment at a minimum annually, or whenever, in management’s judgment events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of such assets exceeds the fair value of the assets. Assets to be disposed of would be separately presented in the consolidated balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated. The assets and liabilities, if material, of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the consolidated balance sheet. These assets are normally sold within a short period of time through a third party auctioneer.

Deferred Debt Costs

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

Deferred debt costs were approximately $7.6 million net of accumulated amortization of $2.4 million, and $7.6 million net of accumulated amortization of $1.5 million at December 31, 2008 and December 31, 2007,

F-11

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

respectively. Amortization of deferred debt costs totaled approximately $968,000, $962,000 and $804,000 for the years ended December 31, 2008, 2007 and 2006, respectively.

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

Goodwill and Other Intangible Assets

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

In step one of the annual impairment test and due to the adverse equity market conditions affecting the Company’s common stock price and the declines in oil and natural gas prices in the fourth quarter of 2008 and continuing into 2009, the Company tested its four reporting units, well servicing, fluid services, completion and remedial services, and contract drilling, for impairment. To estimate the fair value of the reporting units, the Company used a weighting of the discounted cash flow method, the guideline transaction method, and the public company guideline company method. The Company weighted the discounted cash flow method 85% in its analysis and the other two methods combined 15% due to differences between the Company’s reporting units and the peer companies size, profitability and diversity of operations. In order to validate the reasonableness of the estimated fair values obtained for the reporting units, a reconciliation of fair value to market cap was performed. The control premium used in the reconciliation was derived from a market transaction data study along with historical control premiums from the Company’s other acquisitions. The measurement date for the stock price for the reconciliation was the closing price on December 31, 2008.

Based on the results of step one, impairment was indicated in the contract drilling reporting unit but not in the other three reporting units. As a result, the Company tested the contract drilling reporting unit’s long-lived assets for impairment under SFAS No. 144, which indicated no impairment. The Company performed step two for the contract drilling unit by allocating the estimated fair value to the tangible and intangible assets and liabilities, which indicated that the entire value of the goodwill in contract drilling of $22.5 million was impaired. This non-cash charge eliminates the goodwill recorded in connection with the Sledge acquisition in 2007. The goodwill associated with this acquisition has no tax basis, and accordingly, there is no tax benefit derived from recording the impairment charge. Further declines in the Company’s stock price and general market conditions may be considered as a triggering event for the first quarter of 2009. If this is the case, the Company will analyze its goodwill as of March 31, 2009 and potentially record further goodwill impairments in its well servicing, fluid services and/or completion and remedial services reporting units.

Intangible assets subject to amortization under SFAS No. 142 consist of customer relationships and non-compete agreements. The gross carrying amount of customer relationships subject to amortization was $35.4 million and $23.8 million as of December 31, 2008 and 2007, respectively. The gross carrying amount of non-compete agreements subject to amortization totaled approximately $4.4 million and $5.2 million at December 31, 2008 and 2007, respectively. Accumulated amortization related to these intangible assets totaled approximately $3.8 and $2.1 million at December 31, 2008 and 2007, respectively. Amortization expense for the years ended December 31, 2008, 2007 and 2006 was approximately $2.8 million, $773,000, and $650,000, respectively. Amortization expense

F-12

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

for the next five succeeding years is estimated to be approximately $3.2 million, $3.1 million, $3.0 million, $2.6 million, and $2.4 million in 2009, 2010, 2011, 2012, and 2013, respectively.

Amortizable Intangible Assets at December 31, 2008 (in thousands):
Customer Relationships	$	35,441
Accumulated Amortization Customer Relationships		(1,879	)
Non-Compete Agreements		4,392
Accumulated Amortization Non-Compete Agreements		(1,950	)
Total Amortizable Intangible Assets	$	36,004

Customer relationships are amortized over a 15 year life. Non-Compete Agreements are amortized over a five year life.

Basic has identified its reporting units to be well servicing, fluid services, completion and remedial services and contract drilling. The goodwill allocated to such reporting units as of December 31, 2008 was $29.9 million, $49.3 million, $123.5 million, and $0, respectively. The change in the carrying amount of goodwill for the year ended December 31, 2008 of $2.2 million relates to goodwill from acquisitions and payments pursuant to contingent earn-out agreements and impairments, with approximately $3.1 million, $6.1 million and $12.0 million of goodwill additions relating to the well servicing, fluid services, and completion and remedial units, respectively. There was a decrease in the carrying amount of goodwill for the year ended December 31, 2008 of $23.4 million related to contract drilling. The decrease in the carrying amount of goodwill for contract drilling is due primarily to the impairment of $22.5 million. Other intangibles net of accumulated amortization allocated to reporting units as of December 31, 2008 was $454,000, $3.3 million, $26.3 million and $5.9 million for well servicing, fluid services, completion and remedial services, and contract drilling, respectively.

Stock-Based Compensation

On January 1, 2006, Basic adopted Statement of Financial Accounting Standards No. 123 (revised 2004) “Share-Based Payment”(“SFAS No. 123R”). Prior to January 1, 2006, the Company accounted for share-based payments under the recognition and measurement provisions of Accounting Principles Board Opinion No. 25,“Accounting for Stock issued to Employees”(“APB No. 25”) which was permitted by Statement of Financial Accounting Standards No. 123,“Accounting for Stock-Based Compensation”(“SFAS No. 123”).

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

Under SFAS No. 123R, entities using the minimum value method and the prospective application are not permitted to provide the pro forma disclosures (as was required under SFAS No. 123) subsequent to adoption of SFAS No. 123R since they do not have the fair value information required by SFAS No. 123R. Therefore, in accordance with SFAS No. 123R, Basic no longer includes pro forma disclosures that were required by SFAS No. 123.

Income Taxes

Basic accounts for income taxes based upon Statement of Financial Accounting Standards No. 109,“Accounting for Income Taxes”(“SFAS 109”). Under SFAS No. 109, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying

F-13

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

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 2008, 2007, or 2006.

Derivative Instruments and Hedging Activities

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 133,“Accounting for Derivative Instruments and Hedging Activities”(“SFAS No. 133”), which establishes standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires that an entity recognize all derivative as either assets or liabilities on the balance sheet and measure those instruments at fair value. It establishes conditions under which a derivative may be designated as a hedge, and establishes standards for reporting changes in the fair value of a derivative. Basic adopted SFAS No. 133, as amended by SFAS No. 138, on January 1, 2001. Basic adopted the additional amendments pursuant to SFAS No. 149 for contracts entered or modified after June 30, 2003, if any. At inception, Basic formally documents the relationship between the hedging instrument and the underlying hedged item as well as risk management objective and strategy. Basic assesses, both at inception and on an ongoing basis, whether the derivative used in hedging transition is highly effective in offsetting changes in the fair value of cash flows of the respective hedged item.

In May 2004, Basic implemented a cash flow hedge to protect itself from fluctuation in cash flows associated with its credit facility. Changes in fair value of the hedging derivative were initially recorded in other comprehensive income, then recognized in income in the same period(s) in which the hedged transaction affected income. Ineffective portions of a cash flow hedging derivative’s change in fair value were recognized currently in earnings. Basic had no ineffectiveness related to its cash flow hedge in 2005. The March 28, 2006 amendment to the 2005 credit facility deleted the requirement to maintain the cash flow hedge upon payoff of the Term B Loans. In April 2006, Basic paid off all outstanding borrowings under the Term B Loan (See note 5). Accordingly in April 2006, the interest rate swap was terminated and the balance remaining in accumulated comprehensive income was recognized in earnings.

Asset Retirement Obligations

As of January 1, 2003, Basic adopted Statement of Financial Accounting Standards No. 143,“Accounting for Asset Retirement Obligation”(“SFAS No. 143”). SFAS No. 143 requires Basic to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets and capitalize an equal amount as a cost of the asset depreciating it over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each quarter to reflect the passage of time, changes in the estimated future cash flows underlying the obligation, acquisition or construction of assets, and settlements of obligations.

F-14

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Basic owns and operates salt water disposal sites, brine water wells, gravel pits and land farm sites, each of which is subject to rules and regulations regarding usage and eventual closure. The following table reflects the changes in the liability during years ended December 31, 2008 and 2007 (in thousands):

Balance, December 31, 2006	$	1,336
Additional asset retirement obligations recognized through acquisitions		101
Accretion expense		115
Balance, December 31, 2007	$	1,552
Additional asset retirement obligations recognized through acquisitions		143
Accretion expense		131
Settlements		(30	)
Balance, December 31, 2008	$	1,796

Environmental

Basic is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require Basic to remove or mitigate the adverse environmental effects of disposal or release of petroleum, chemical and other substances at various sites. Environmental expenditures are expensed or capitalized depending on the future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessmentand/or remediation is probable and the costs can be reasonably estimated.

Litigation and Self-Insured Risk Reserves

Basic estimates its reserves related to litigation and self-insured risks based on the facts and circumstances specific to the litigation and self-insured claims and its past experience with similar claims in accordance with Statement of Financial Accounting Standard No. 5“Accounting for Contingencies.” Basic maintains accruals in the consolidated balance sheets to cover self-insurance retentions (See note 7).

Comprehensive Income

Basic follows the provisions of Statement of Financial Accounting Standards No. 130,“Reporting of Comprehensive Income”(“SFAS No. 130”). SFAS No. 130 establishes standards for reporting and presentation of comprehensive income and its components. SFAS No. 130 requires all items that are required to be recognized under accounting standards as components of comprehensive income to be reported in a financial statement that is displayed with the same prominence as other financial statements. In accordance with the provisions of SFAS No. 130, gains and losses on cash flow hedging derivatives, to the extent effective, are included in other comprehensive income (loss).

Reclassifications

Certain reclassifications of prior year financial statement amounts have been made to conform to current year presentations.

Recent Accounting Pronouncements

In September 2006, the FASB issuedSFAS No. 157, Fair Value Measurements (SFAS 157), which became effective for financial assets and liabilities of the Company on January 1, 2008 and non-financial assets and liabilities of the Company on January 1, 2009. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS 157 does not require any new

F-15

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

fair value measurements but would apply to assets and liabilities that are required to be recorded at fair value under other accounting standards. The impact, if any, to the Company from the adoption of SFAS 157 in 2009 will depend on the Company’s assets and liabilities at that time that are required to be measured at fair value.

In February 2007, the FASB issuedSFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS 159), which became effective for the Company on January 1, 2008. This standard permits companies to choose to measure many financial instruments and certain other items at fair value and report unrealized gains and losses in earnings. Such accounting is optional and is generally to be applied instrument by instrument.

In December 2007, the FASB issuedSFAS No. 141R, Business Combinations (SFAS 141R), which becomes effective for the Company on January 1, 2009. This Statement requires an acquirer to recognize the assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date be measured at their fair values as of that date. An acquirer is required to recognize assets or liabilities arising from all other contingencies (contractual contingencies) as of the acquisition date, measured at their acquisition-date fair values, only if it is more likely than not that they meet the definition of an asset or a liability in FASB Concepts Statement No. 6, Elements of Financial Statements. Any acquisition related costs are to be expensed instead of capitalized. The impact to the Company from the adoption of SFAS 141R in 2009 will depend on acquisitions at the time.

In December 2007, the FASB issuedSFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements (SFAS 160), which becomes effective for the Company on January 1, 2009. This standard establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. The Statement also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. The Company does not anticipate that this pronouncement will have a material impact on its results of operations or consolidated financial position.

In March 2008, the FASB issuedSFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities(SFAS 161), which became effective for the Company on January 1, 2009. This standard improves financial reporting for derivative instruments and hedging activities requiring enhanced disclosures to expand on these instruments’ effects on the Company’s financial position, financial performance and cash flows. The Company does not anticipate that this pronouncement will have a material impact on its results of operations or consolidated financial position.

In April 2008, the FASB issued FSP SFAS No. 142-3,Determination of Useful Life of Intangible Assets (“FSP 142-3”). FSP 142-3 amends the factors that should be considered in developing the renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS 142. FSP 142-3 is effective for fiscal years beginning after December 15, 2008. Earlier adoption is not permitted. We are currently evaluating the potential impact the adoption of FSP 142-3 will have on our consolidated financial statements.

In May 2008, the FASB issuedSFAS No. 162,The Hierarchy of Generally Accepted Accounting Principles(SFAS 162), which becomes effective for the Company 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411,The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles. This standard identifies the sources of accounting principles and the framework for selecting the principles used in preparation of financial statements that are presented in conformity with generally accepted accounting principles (GAAP). The Company does not anticipate that this pronouncement will have a material impact on its results of operations or consolidated financial position.

In June 2008, the FASB issued Staff PositionEITF 03-6-1“Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities”(“FSPEITF 03-6-1”). FSPEITF 03-6-1 addresses

F-16

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

whether instruments granted in share based payment transactions are participating securities prior to vesting and, therefore, need to be included in earnings allocation in computing earnings per share (“EPS”) under the two-class method described in paragraphs 60 and 61 of SFAS No. 128, “Earnings Per Share”. FSPEITF 03-6-1 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008 and requires retrospective adjustment for all comparable prior periods presented. The Company does not anticipate that the adoption of FSPEITF 03-6-1 will have a material impact on its EPS disclosures.

3.   Acquisitions

In 2008, 2007 and 2006, Basic acquired either substantially all of the assets or all of the outstanding capital stock of each of the following businesses, each of which were accounted for using the purchase method of accounting (in thousands):

			Total Cash Paid
			(Net of Cash
	Closing Date		Acquired)
LeBus Oil Field Services Co.		January 31, 2006	$	24,618
G&L Tool, Ltd.		February 28, 2006		58,514
Arkla Cementing, Inc.		March 27, 2006		5,012
Globe Well Service, Inc.		May 30, 2006		11,674
Hydro-Static Tubing Testers, Inc.		July 6, 2006		1,143
Hennessey Rental Tools, Inc.		August 1, 2006		8,205
Stimulation Services, LLC		August 1, 2006		4,500
Chaparral Service, Inc.		August 15, 2006		17,605
Reddline Services, LLC		August 24, 2006		1,900
Rebel Testers, Ltd.		September 14, 2006		2,397
Total 2006			$	135,568
Parker Drilling Offshore USA, LLC		January 3, 2007		20,594
Davis Tool Company, Inc.		January 17, 2007		4,164
JetStar Consolidated Holdings, Inc.		March 6, 2007		86,316
Sledge Drilling Holding Corp.		April 2, 2007		50,632
Eagle Frac Tank Rentals, LP		May 30, 2007		3,813
Wildhorse Services, Inc.		June 1, 2007		17,283
Bilco Machine, Inc.		June 21, 2007		600
Steve Carter Inc. and Hughes Services Inc.		September 26, 2007		19,041
Total 2007			$	202,443
Xterra Fishing and Rental Tools Co.		January 28, 2008	$	21,110
Lackey Construction, LLC		January 30, 2008		4,328
B&S Disposal, LLC and B&S Equipment, Ltd		April 30, 2008		7,067
Triple N Services, Inc.		May 27, 2008		17,315
Azurite Services Company, Inc., Azurite Leasing Company, LLC and Freestone Disposal, L.P. (collectively, “Azurite”)		September 26, 2008		60,155
Total 2008			$	109,975

F-17

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

The operations of each of the acquisitions listed above are included in Basic’s statement of operations as of each respective closing date. The acquisition of G&L Tool, Ltd. in 2006, JetStar Consolidated Holdings, Inc. and Sledge Drilling Holding Corp. in 2007 and Azurite in 2008 have been deemed significant and are discussed below in further detail.

G&L Tool, Ltd.

On February 28, 2006, Basic acquired substantially all of the assets of G&L Tool, Ltd. (“G&L”) for $58.5 million plus a contingent earn-out payment not to exceed $21.0 million. The contingent earn-out payment will be equal to fifty percent of the amount by which the annual EBITDA (as defined in the purchase agreement) earned by the G&L assets exceeds an annual targeted EBITDA. There is no guarantee or assurance that the targeted EBITDA will be reached. This acquisition provided a platform to expand into the rental and fishing tool market. The cost of the G&L acquisition was allocated $40.8 million to property and equipment, $5.2 million to inventory, $12.5 million to goodwill, all of which is expected to be deductible for tax purposes, and $51,000 to non-compete agreements.

JetStar Consolidated Holdings, Inc.

On March 6, 2007, Basic acquired all of the capital stock of JetStar Consolidated Holdings, Inc. (“JetStar”). The results of JetStar’s operations have been included in the financial statements since that date. The aggregate purchase price was approximately $127.3 million, including $86.3 million in cash which included the retirement of JetStar’s outstanding debt. Basic issued 1,794,759 shares of common stock, at a fair value of $22.86 per share for a total fair value of approximately $41 million. The value of the 1,794,759 shares issued was determined based on the average market price of Basic’s common shares over the2-day period before and after the date the number of shares were determined. This acquisition allowed us to enter into the Kansas market and increased our presence in North Texas. JetStar will operate in Basic’s completion and remedial segment. The following table summarizes the final fair value of the assets acquired and liabilities assumed at the date of acquisition for JetStar (in thousands):

Current Assets	$	12,547
Property and Equipment		58,785
Amortizable Intangible Assets(1)		17,857
Goodwill(2)		61,720
Total Assets Acquired		150,909
Current Liabilities		(4,581	)
Deferred Income Taxes		(18,649	)
Current and Long Term Debt(3)		(37,563	)
Total Liabilities Assumed		(60,793	)
Net Assets Acquired	$	90,116

(1)	Consists of Customer Relationship of $17,543, amortizable over 15 years, and Non-Compete Agreements of $314, amortizable over 5 years.
(2)	Approximately $25,955 is expected to be deductible for tax purposes
(3)	Total balance was paid by Basic on the closing date

F-18

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Sledge Drilling Holding Corp.

On April 2, 2007, Basic acquired all of the capital stock of Sledge Drilling Holding Corp. (“Sledge”). The results of Sledge’s operations have been included in the financial statements since that date. The aggregate purchase price was approximately $60.8 million, including $50.6 million in cash which included the retirement of Sledge’s outstanding debt. Basic issued 430,191 shares of common stock at a fair value of $23.63 per share for a total fair value of approximately $10.2 million. The value of the 430,191 shares issued was determined based on the average market price of Basic’s common shares over the2-day period before and after the date the number shares were determined. This acquisition allowed Basic to expand its drilling operations in the Permian Basin. The following table summarizes the final fair value of the assets acquired and liabilities assumed at the date of acquisition for Sledge (in thousands):

Current Assets	$	6,807
Property and Equipment		30,638
Intangible Assets(1)		6,365
Goodwill(2)		22,522
Total Assets Acquired		66,332
Current Liabilities		(587	)
Deferred Income Taxes		(3,804	)
Current and Long Term Debt(3)		(19,093	)
Total Liabilities Assumed		(23,484	)
Net Assets Acquired	$	42,848

(1)	Consists of Customer Relationship of $6,269, amortizable over 15 years, and Non-Compete Agreements of $96, amortizable over 5 years.
(2)	None of which is expected to be deducted for tax purposes
(3)	Total balance was paid by Basic on the closing date

Azurite

On September 26, 2008, Basic acquired substantially all of the assets of Azurite Services Company, Inc., Azurite Leasing Company, LLC, and Freestone Disposal, L.P. (collectively, “Azurite”) for $60.2 million in cash. This acquisition operates in our fluid services line of business and allowed us to expand our operations in the east Texas markets. The following table summarizes the preliminary estimated fair value of the assets acquired and liabilities assumed at the date of acquisition for Azurite (in thousands):

Property and Equipment	$	53,127
Intangible Assets(1)		1,862
Goodwill(2)		5,166
Total Assets Acquired	$	60,155

(1)	Consists of customer relationship of $1,832, amortizable over 15 years, and non-compete agreements of $30, amortizable over five years.
(2)	All of which is expected to be deductible for tax purposes.

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

F-19

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

The following unaudited pro-forma results of operations have been prepared as though the JetStar, Sledge, and Azurite acquisitions had been completed on January 1, 2007. Pro forma amounts are based on the purchase price allocations of the significant acquisitions and are not necessarily indicative of the results that may be reported in the future (in thousands, except per share data).

	Twelve Months Ended December 31,
	2008		2007
Revenues	$	1,040,160	$	933,697
Net income	$	70,680	$	92,064
Earnings per common share — basic	$	1.73	$	2.28
Earnings per common share — diluted	$	1.70	$	2.22

Basic does not believe the pro-forma effect of the remainder of the acquisitions completed in 2007 or 2008 is material, either individually or when aggregated, to the reported results of operations.

Contingent Earn-out Arrangements and Final Purchase Price Allocations

Contingent earn-out arrangements are generally arrangements entered into on certain acquisitions to encourage the owner/manager to continue operating and building the business after the purchase transaction. The contingent earn-out arrangements of the related acquisitions are generally linked to certain financial measures and performance of the assets acquired in the various acquisitions. Contingent earn-out payments that are based on continued employment with the Company are recorded as compensation expense, in accordance with EITFNo. 95-8,“Accounting for Contingent Consideration Paid to the Shareholders of an Acquired Enterprise in Purchase Business Combinations.”All other amounts paid or reasonably accrued for related to the contingent earn-out payments are reflected as increases to the goodwill associated with the acquisitions of New Force Energy Services, Rolling Plains, Premier Vacuum Services and G&L Tool. Payments related to contingent earn-out agreements on Chaparral Services will be reflected as compensation expense when paid or accrued.

The following presents a summary of acquisitions that have a contingent earn-out arrangement in effect as of December 31, 2008 (in thousands):

		Maximum
		Exposure of
	Termination Date of	Contingent			Amount Paid or
	Contingent Earn-Out	Earn-Out			Accrued through
Acquisition	Arrangement	Arrangement			December 31, 2008
Rolling Plains	April 30, 2009			*	$	6,732
Chaparral Services, Inc.	August 31, 2011	$	1,000			—
G&L Tool, Ltd.	February 28, 2011		21,000			5,093
		$	22,000		$	11,825

* Basic will pay to the sellers an amount for each of the five consecutive12-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.

F-20

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

4.   Property and Equipment

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

	December 31,		December 31,
	2008		2007
Land	$	4,689	$	3,475
Buildings and improvements		29,913		21,655
Well service units and equipment		379,167		328,468
Fluid services equipment		136,814		91,830
Brine and fresh water stations		10,203		8,964
Frac/test tanks		128,845		85,649
Pressure pumping equipment		156,406		132,746
Construction equipment		22,483		28,798
Contract drilling equipment		60,340		59,231
Disposal facilities		49,878		27,790
Vehicles		41,129		36,440
Rental equipment		36,898		33,381
Aircraft		4,119		4,119
Other		21,758		15,858
		1,082,642		878,404
Less accumulated depreciation and amortization		341,763		241,480
Property and equipment, net	$	740,879	$	636,924

Basic is obligated under various capital leases for certain vehicles and equipment that expire at various dates during the next five years. The gross amount of property and equipment and related accumulated amortization recorded under capital leases and included above consists of the following (in thousands):

	December 31,		December 31,
	2008		2007
Light vehicles	$	30,141	$	25,768
Well service units and equipment		1,194		1,016
Fluid services equipment		56,010		34,668
Pressure pumping equipment		20,492		4,540
Construction equipment		3,679		4,440
Software		9,464		6,308
Other		705		—
		121,685		76,740
Less accumulated amortization		37,370		22,660
	$	84,315	$	54,080

Amortization of assets held under capital leases of approximately $14.7 million, $8.9 million and $5.3 million for the years ended December 31, 2008, 2007 and 2006, respectively, is included in depreciation and amortization expense in the consolidated statements of operations.

F-21

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

5.   Long-Term Debt

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

	December 31,		December 31,
	2008		2007
2007 Credit Facility	$	180,000	$	150,000
7.125% Senior Notes		225,000		225,000
Capital leases and other notes		75,323		48,719
		480,323		423,719
Less current portion		26,063		17,413
	$	454,260	$	406,306

Senior Notes

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

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

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

Pursuant to the Indenture, the Company is subject to covenants that limit the ability of the Company and its restricted subsidiaries to, among other things: incur additional indebtedness, pay dividends, make certain other payments repurchase or redeem capital stock, make certain investments, incur liens, enter into certain types of transactions with affiliates, limit dividends or other payments by restricted subsidiaries, and sell assets or consolidate or merge with or into other companies. These limitations are subject to a number of important qualifications and exceptions set forth in the Indenture. The Company was in compliance with the restrictive covenants at December 31, 2008.

As part of the issuance of the above-mentioned Senior Notes, the Company incurred debt issuance costs of approximately $4.6 million, which are being amortized to interest expense using the effective interest method over the term of the Senior Notes.

F-22

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

The Senior Notes are jointly and severally guaranteed by the Company and all of its restricted subsidiaries. Basic Energy Services, Inc., the ultimate parent company, does not have any independent operating assets or operations. Subsidiaries other than the restricted subsidiaries that are guarantors are minor.

2007 Credit Facility

On February 6, 2007, Basic entered into a $225 million Fourth Amended and Restated Credit Agreement with a syndicate of lenders (the “2007 Credit Facility”), which refinanced all of the existing credit facilities. Under the 2007 Credit Facility, Basic Energy Services, Inc. is the sole borrower and each of its subsidiaries is a subsidiary guarantor. The 2007 Credit Facility provides for a $225 million revolving line of credit (“Revolver”). The 2007 Credit Facility includes provisions allowing us to request an increase in commitments of up to $100 million aggregate principal amount subject to meeting certain tangible value requirements and subject to lender participation at the time of the request. Additionally, the 2007 Credit Facility permits us to make greater expenditures for acquisitions, capital expenditures and capital leases and to incur greater purchase money obligations, acquisition indebtedness and general unsecured indebtedness. The commitment under the Revolver provides for (1) the borrowing of funds, (2) the issuance of up to $30 million of letters of credit and (3) $2.5 million of swing-line loans. All of the outstanding amounts under the Revolver are due and payable on December 15, 2010. The 2007 Credit Facility is secured by substantially all of our tangible and intangible assets. Basic incurred approximately $0.7 million in debt issuance costs in connection with the 2007 Credit Facility.

At Basic’s option, borrowings under the Revolver bears interest at either (1) the “Alternative Base Rate” (i.e., the higher of the bank’s prime rate or the federal funds rate plus .50% per year) plus a margin ranging from 0.25% to 0.5% or (2) an “Adjusted LIBOR Rate” (equal to (a) the London Interbank Offered Rate (the “LIBOR rate”) as determined by the Administrative Agent in effect for such interest period divided by (b) one minus the Statutory Reserves, if any, for such borrowing for such interest period) plus a margin ranging from 1.25% to 1.5%. The margins vary depending on our leverage ratio. Fees on the letters of credit are due quarterly on the outstanding amount of the letters of credit at a rate ranging from 1.25% to 1.5% for participation fees and 0.125% for fronting fees. A commitment fee is due quarterly on the available borrowings under the Revolver at a rate of 0.375%.

At December 31, 2008, Basic, under its Revolver, had outstanding $180 million of borrowings and $16.2 million of letters of credit and no amounts outstanding in swing-line loans. At December 31, 2008, Basic had availability under its Revolver of $28.8 million.

Pursuant to the 2007 Credit Facility, Basic must apply proceeds from certain specified events to reduce principal outstanding borrowings under the Revolver, from (a) assets sales greater than $2.0 million individually or $7.5 million in the aggregate on an annual basis, (b) 100% of the net cash proceeds from any debt issuance, including certain permitted unsecured senior or senior subordinated debt, but excluding certain other permitted debt issuances and (c) 50% of the net cash proceeds from any equity issuance (including equity issued upon the exercise of any warrant or option).

The 2007 Credit Facility contains various restrictive covenants and compliance requirements, which include (a) limitations on the incurrence of additional indebtedness, (b) restrictions on mergers, sales or transfer of assets without the lenders’ consent (c) limitations on dividends and distributions and (d) various financial covenants, including (1) a maximum leverage ratio of 3.25 to 1.00, and (2) a minimum interest coverage ratio of 3.00 to 1.00. At December 31, 2008, Basic was in compliance with its covenants.

Other Debt

Basic has a variety of other capital leases and notes payable outstanding that are generally customary in its business. None of these debt instruments are material individually or in the aggregate.

F-23

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

As of December 31, 2008 the aggregate maturities of debt, including capital leases, for the next five years and thereafter are as follows (in thousands):

	Debt		Capital Leases
2009	$	—	$	26,063
2010		180,000		21,985
2011		—		14,307
2012		—		10,450
2013		—		2,518
Thereafter		225,000		—
	$	405,000	$	75,323

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

	Years Ended December 31,
	2008			2007		2006
Cash payments for interest	$	24,484		$	25,594	$	12,587
Commitment and other fees paid		211			249		566
Amortization of debt issuance costs		968			962		804
Accrued interest		1,157			540		3,384
Other		(54	)		71		125
	$	26,766		$	27,416	$	17,466

Losses on Extinguishment of Debt

In February 2007 and April 2006, Basic recognized a loss on the early extinguishment of debt. In February 2007, Basic wrote off unamortized debt issuance costs of approximately $0.2 million, which related to the 2005 credit facility. In April 2006, Basic wrote off unamortized debt issuance costs of approximately $2.7 million, which related to the prepayment of the Term B Loan.

6.   Income Taxes

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

	Years Ended December 31,
	2008		2007		2006
Current:
Federal	$	20,533	$	33,157	$	50,499
State		4,436		5,160		1,632
Total	$	24,969	$	38,317	$	52,131
Deferred:
Federal	$	28,792	$	14,207	$	3,594
State		1,373		242		(983	)
Total	$	30,165	$	14,449	$	2,611
Total income tax expense	$	55,134	$	52,766	$	54,742

F-24

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Basic paid Federal income taxes of $22.0 million during 2008, $44.1 million during 2007 and $40.2 million during 2006.

Reconciliation between the amount determined by applying the Federal statutory rate of 35% to income from continuing operations with the provision for income taxes is as follows (in thousands):

	Years Ended December 31,
	2008			2007			2006
Statutory federal income tax	$	43,180		$	49,174		$	53,750
Meals and entertainment		542			532			430
State taxes, net of federal benefit		4,726			4,062			778
Impairment of non-deductible goodwill		7,883			—			—
Changes in estimates and other		(1,197	)		(1,002	)		(216	)
	$	55,134		$	52,766		$	54,742

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are as follows (in thousands):

	December 31,
	2008			2007
Deferred tax assets:
Receivables allowance	$	2,151		$	2,314
Inventory		42			41
Asset retirement obligation		331			283
Accrued liabilities		8,696			8,044
Operating loss carryforward		788			1,100
Deferred compensation		3,497			2,648
Total deferred tax assets		15,505			14,430
Deferred tax liabilities:
Property and equipment		(135,354	)		(104,476	)
Goodwill and intangibles		(18,541	)		(13,846	)
Prepaid expenses		(120	)		(119	)
Total deferred tax liabilities		(154,015	)		(118,441	)
Net deferred tax liability	$	(138,510	)	$	(104,011	)
Recognized as:
Deferred tax assets — current		11,081			10,593
Deferred tax liabilities — non-current		(149,591	)		(114,604	)
Net deferred tax liability	$	(138,510	)	$	(104,011	)

Basic provides a valuation allowance when it is more likely than not that some portion of the deferred tax assets will not be realized. There was no valuation allowance necessary as of December 31, 2008 or 2007.

Effective January 1, 2007, Basic adopted the provisions of the FASB issued Interpretation No. 48 (“FIN 48”),Accounting for Uncertainty in Income Taxes. Our adoption of FIN 48 in January 2007 did not result in any change to retained earnings or any additional unrecognized tax benefit. Interest is recorded in interest expense and penalties are recorded in income tax expense. We had no interest or penalties related to

F-25

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

an uncertain tax positions during 2008. Basic files federal income tax returns and state income tax returns in Texas and other state tax jurisdictions. In general, the Company’s tax returns for fiscal years after 2003 currently remain subject to examination by appropriate taxing authorities. None of the Company’s income tax returns are under examination at this time.

As of December 31, 2008, Basic had approximately $2.3 million of net operating loss carryforwards (“NOL”) for U.S. federal income tax purposes related to the preacquisition period of FESCO (acquired in 2003), which are subject to an annual limitation of approximately $892,000. The carryforwards begin to expire in 2017.

7.   Commitments and Contingencies

Environmental

Basic is subject to various federal, state and local environmental laws and regulations that establish standards and requirements for protection of the environment. Basic cannot predict the future impact of such standards and requirements which are subject to change and can have retroactive effectiveness. Basic continues to monitor the status of these laws and regulations. Management believes that the likelihood of the disposition of any of these items resulting in a material adverse impact to Basic’s financial position, liquidity, capital resources or future results of operations is remote.

Currently, Basic has not been fined, cited or notified of any environmental violations that would have a material adverse effect upon its financial position, liquidity or capital resources. However, management does recognize that by the very nature of its business, material costs could be incurred in the near term to bring Basic into total compliance. The amount of such future expenditures is not determinable due to several factors including the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions which may be required, the determination of Basic’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnification.

Litigation

From time to time, Basic is a party to litigation or other legal proceedings that Basic considers to be a part of the ordinary course of business. Basic is not currently involved in any legal proceedings that it considers probable or reasonably possible, individually or in the aggregate, to result in a material adverse effect on its financial condition, results of operations or liquidity.

Operating Leases

Basic leases certain property and equipment under non-cancelable operating leases. The term of the operating leases generally range from 12 to 60 months with varying payment dates throughout each month.

As of December 31, 2008, the future minimum lease payments under non-cancelable operating leases are as follows (in thousands):

Year Ended December 31,
2009	$	4,543
2010		4,257
2011		3,588
2012		2,550
2013		2,164
Thereafter		5,220

F-26

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Rent expense approximated $20.3 million, $17.4 million, and $13.9 million for 2008, 2007 and 2006, 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 December 31, 2006 through December 31, 2009, amended February 27, 2008, Mr. Huseman will be entitled to an annual salary of $550,000. Under this employment agreement, Mr. Huseman is eligible from time to time to receive grants of stock options and other long-term equity incentive compensation under our Amended and Restated 2003 Incentive Plan. In addition, upon a qualified termination of employment, Mr. Huseman would be entitled to three times his base salary plus his current annual incentive target bonus for the full year in which the termination of employment occurred. If employment is terminated for certain reasons within the six months preceding or the twelve months following the change of control of our Company, Mr. Huseman would be entitled to a lump sum severance payment equal to three times the sum of his base salary plus the higher of (i) his current incentive target bonus for the full year in which the termination of employment occurred or (ii) the highest annual incentive bonus received by him for any of the last three fiscal years.

Basic has entered into employment agreements with various other executive officers of Basic that range in term up through December 2009. Under these agreements, if the officer’s employment is terminated for certain reasons, he would be entitled to a lump sum severance payment equal to amounts ranging from 1.5 times to 0.75 times the sum of his base salary plus his current annual incentive target bonus for the full year in which the termination occurred . If employment is terminated for certain reasons within the six months preceding or the twelve months following the chance of control of our Company, he would be entitled to a lump sum severance payment equal to three times the sum of his base salary plus the higher of (i) his current incentive target bonus for the full year in which the termination of employment occurred or (ii) the highest annual incentive bonus received by him for any of the last three fiscal years.

Self-Insured Risk Accruals

Basic is self-insured up to retention limits as it relates to workers’ compensation and medical and dental coverage of its employees. Basic, generally, maintains no physical property damage coverage on its workover rig fleet, with the exception of certain of its24-hour workover rigs and newly manufactured rigs. Basic has deductibles per occurrence for workers’ compensation and medical and dental coverage of $375,000 and $180,000, respectively. Basic has lower deductibles per occurrence for automobile liability and general liability. Basic maintains accruals in the accompanying consolidated balance sheets related to self-insurance retentions by using third-party data and claims history. In 2008 Basic classified the worker’s compensation self-insured risk reserve between short-term and long-term, with $4.0 million being allocated to short-term and $5.0 million being allocated to long-term.

At December 31, 2008 and December 31, 2007, self-insured risk accruals totaled approximately $15.4 million, net of $992,000 receivable for medical and dental coverage, and $15.1 million, net of $0 receivable for medical and dental coverage, respectively.

F-27

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

8.   Stockholders’ Equity

Common Stock

At December 31, 2008 and 2007, Basic had 80,000,000 shares of Basic’s common stock, par value $.01 per share, authorized.

In February 2002, a group of related investors purchased a total of 3,000,000 shares of Basic’s common stock at a purchase price of $4 per share, for a total purchase price of $12 million. As part of the purchase, 600,000 common stock warrants were issued in connection with this transaction, the fair value of which was approximately $1.2 million (calculated using an option valuation model). The warrants allowed the holder to purchase 600,000 shares of Basic’s common stock at $4 per share. The warrants were exercisable in whole or in part after June 30, 2002 and prior to February 13, 2007.

In June of 2002 Basic granted 3,750,000 common stock warrants to acquire a total of 3,750,000 shares of common stock at a price of $4 per share, exercisable in whole or in part from June 30, 2002 through June 30, 2007.

In February 2004, Basic granted certain officers and directors 837,500 restricted shares of common stock. The shares vest 25% per year for four years from the award date and are subject to other vesting and forfeiture provisions. The estimated fair value of the restricted shares was $5.8 million at the date of the grant. This amount is being charged to expense over the respective vesting period and totaled approximately $182,000, $1.2 million and $1.3 million for the years ended December 31, 2008, 2007 and 2006.

In December 2005, Basic issued 5,000,000 shares of common stock during the Company’s Initial Public Offering to a group of investors for $100 million or $20 per share. After deducting fees, this resulted in net proceeds to Basic totaling approximately $91.5 million.

On October 5, 2006, all outstanding warrants were exercised to purchase an aggregate of 4,350,000 shares of Basic’s common stock. In connection with the exercise of the warrants, Basic received an aggregate of $17.4 million from the Holders in satisfaction of the exercise price of the warrants (representing an exercise price of $4.00 per share of Basic’s common stock acquired).

In March and April 2007, Basic issued 1,794,759 and 430,191 shares of common stock in connection with the acquisitions of JetStar Consolidated Holding, Inc. and Sledge Drilling Holding Corp., respectively. (See note 3)

In March 2007, Basic granted various employees 217,100 unvested shares of common stock which vest over a five year period. Also, in March 2007, Basic granted the Chairman of the Board 4,000 shares of common stock. In July 2007, Basic granted a vice president 12,000 shares of restricted common stock which vest over a four year period.

In March 2008, Basic granted various employees 361,700 unvested shares of common stock which vest over a five-year period. Also, in March 2008, Basic granted the Chairman of the Board 4,000 shares of common stock which vested immediately in lieu of annual cash director fees. In October 2008, Basic granted a vice president 5,000 shares of restricted common stock which vest over a three year period.

During the year ended 2008, Basic issued 138,675 shares of common stock from treasury stock for the exercise of stock options. Also, Basic issued 447,255 shares of newly-issued common stock for the exercise of stock options.

Treasury Stock

On October 13, 2008, Basic announced that its Board of Directors authorized the repurchase of up to $50.0 million of Basic’s shares of common stock from time to time in open market or private transactions, at

F-28

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Basic’s discretion. The number of shares purchased and the timing of purchases is based on several factors, including the price of the common stock, general market conditions, available cash and alternative investment opportunities. As of December 31, 2008, Basic repurchased 897,558 shares at a total price of $8.8 million (an average of $9.82 per share), inclusive of commissions and fees.

Basic also acquired treasury shares through net share settlements for payment of payroll taxes upon the vesting of restricted stock. We repurchased a total of 52,877 and 20,388 shares through net share settlements during 2008 and 2007, respectively.

Preferred Stock

At December 31, 2008 and 2007, Basic had 5,000,000 shares of preferred stock, par value $.01 per share, authorized, of which none was designated, issued or outstanding.

9.   Stockholders’ Agreement

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

The Stockholders’ Agreement provides for participation rights of the other stockholders to require affiliates of DLJ Merchant Banking to offer to include a specified percentage of their shares whenever affiliates of DLJ Merchant Banking sell their shares for value in a transaction or series of transactions involving 10% or more of the then-outstanding shares of Basic’s common stock, other than a public offering or a sale in which all of the parties to the Stockholders’ Agreement agree to participate. The Stockholders’ Agreement also contains “drag-along” rights. The “drag-along” rights entitle the affiliated of DLJ Merchant Banking to require the other stockholders who are a party to this agreement to sell a portion of their shares of common stock and common stock equivalents in the sale in any proposed to sale of shares of common stock and common stock equivalents representing more than 50% of such equity interest held by the affiliates of DLJ Merchant Banking to a person or persons who are not an affiliate of them.

The Stockholders’ Agreement also provides for demand and piggyback registration rights to parties who continue to hold “Registrable Securities” as defined in the agreement.

10.   Incentive Plan

In May 2003, Basic’s board of directors and stockholders approved the Basic 2003 Incentive Plan (as amended effective April 22, 2005) (the “Plan”), which provides for granting of incentive awards in the form of stock options, restricted stock, performance awards, bonus shares, phantom shares, cash awards and other stock-based awards to officers, employees, directors and consultants of Basic. The Plan assumed the awards of the plans of Basic’s predecessors that were awarded and remained outstanding prior to adoption of the Plan. The Plan provides for the issuance of 5,000,000 shares. Of these shares, approximately 816,000 shares are available for grant as of December 31, 2008. The Plan is administered by the Plan committee, and in the absence of a Plan committee, by the Board of Directors, which determines the awards and the associated terms of the awards and interprets its provisions and adopts policies for implementing the Plan. The number of shares authorized under the Plan and the number of shares subject to an award under the Plan will be adjusted for stock splits, stock dividends, recapitalizations, mergers and other changes affecting the capital stock of Basic.

On March 15, 2006, the Board of Directors granted various employees and directors options to purchase 418,000 shares of common stock of Basic at an exercise price of $26.84 per share. All of the 418,000 options granted in 2006 vest over a five-year period and expire 10 years from the date they were granted. These option awards were granted with an exercise price equal to the market price of the Company’s stock at the date of grant. On March 15, 2007, the board of directors granted various employees options to purchase 92,000 shares of common stock of Basic at an exercise price of $22.66 per share. All of the 92,000 options granted in 2007

F-29

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

vest over a five-year period and expire 10 years from the date they were granted. These option awards were granted with an exercise price equal to the market price of the Company’s stock at the date of grant. There were no options granted during 2008.

The fair value of each option award is estimated on the date of grant using the Black-Scholes-Merton option-pricing model that uses the subjective assumptions noted in the following table. Since the Company has only been public since December 2005, expected volatility for options granted during 2006 is a volatility based upon a peer group. Expected volatility for options granted during 2007 is a combination of the Company’s historical data and volatility based upon a peer group. The expected term of options granted represents the period of time that options granted are expected to be outstanding. For options granted in 2007 and 2006, the Company used the simplified method to calculate the expected term. For options granted in 2007 and 2006, the risk-free rate for periods within the contractual life of the options is based on the U.S. Treasury yield curve in effect at the time of grant. The estimates involve inherent uncertainties and the application of management judgment. In addition, we are required to estimate the expected forfeiture rate and only recognize expense for those options expected to vest. During the years ended December 31, 2008, 2007 and 2006, compensation expense related to share-based arrangements was approximately $4.1 million, $3.9 million and $3.4 million, respectively. For compensation expense recognized during the years ended December 31, 2008, 2007 and 2006 Basic recognized a tax benefit of approximately $1.9 million, $1.5 million and $1.2 million, respectively.

The fair value of each option award accounted for under SFAS No. 123R is estimated on the date of grant using the Black-Scholes-Merton option-pricing model that uses the assumptions noted in the following table:

	Years Ended December 31,
	2007			2006
Risk-free interest rate		4.5	%		4.7	%
Expected term		6.65			6.65
Expected volatility		45.3	%		47.0	%
Expected dividend yield		—			—

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

The following table reflects the summary of stock options outstanding at December 31, 2008 and the changes during the twelve months then ended:

						Weighted
				Weighted		Average		Aggregate
	Number of			Average		Remaining		Intrinsic
	Options			Exercise		Contractual		Value
	Granted			Price		Term (Years)		(000’s)
Non-statutory stock options:
Outstanding, beginning of period		2,257,355		$	9.58
Options granted		—		$	—
Options forfeited		(53,750	)	$	15.29
Options exercised		(585,930	)	$	4.65
Options expired		(9,000	)	$	21.32
Outstanding, end of period		1,608,675		$	11.11		5.76	$	8,714
Exercisable, end of period		957,925		$	7.44		5.03	$	6,782
Vested or expected to vest, end of period		1,584,425		$	10.88		5.73	$	8,714

F-30

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

The weighted-average grant date fair value of share options granted during the years ended December 31, 2007 and 2006 was $11.85 and $14.47, respectively. The total intrinsic value of share options exercised during the years ended December 31, 2008, 2007 and 2006 was approximately $12.2 million, $3.6 million and $7.1 million, respectively.

On March 11, 2008, the Compensation Committee of our Board of Directors approved grants of performance-based stock awards to certain members of management. The performance-based awards consist of the Company achieving certain earnings per share growth targets and certain return on capital employed performance, over the performance period from January 1, 2006 through December 31, 2008 as compared to other members of a defined peer group. The number of shares to be issued will range from 0% to 150% of the target number of shares of 101,500 depending on the performance noted above. Any shares earned at the end of the performance period will then remain subject to vesting over a three-year period, with the first shares vesting March 15, 2010.

A summary of the status of the Company’s non-vested share grants at December 31, 2008 and changes during the year ended December 31, 2008 is presented in the following table:

				Weighted
				Average
				Grant Date
	Number of			Fair Value
Nonvested Shares	Shares			per Share
Nonvested at beginning of period		378,000		$	15.74
Granted during period		456,975			20.85
Vested during period		(178,300	)		7.90
Forfeited during period		(57,350	)		21.55
Nonvested at end of period		599,325		$	21.41

As of December 31, 2008, there was $11.9 million of total unrecognized compensation related to non-vested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 2.65 years. The total fair value of share-based awards vested during the years ended December 31, 2008, 2007 and 2006 was approximately $10.3 million, $11.3 million and $12.3 million, respectively. The actual tax benefit realized for the tax deduction from vested share-based awards was $1.5 million, $1.6 million and $2.1 million, respectively for the years ended December 31, 2008, 2007 and 2006.

Cash received from share option exercises under the incentive plan was approximately $2.7 million, $975,000 and $674,000 for the years ended December 31, 2008, 2007 and 2006, respectively. The actual tax benefit realized for the tax deductions from options exercised was $5.6 million, $1.4 million and $4.0 million, respectively, for the years ended December 31, 2008, 2007 and 2006.

The Company has a history of issuing Treasury and newly-issued shares to satisfy share option exercises.

11.   Related Party Transactions

Basic had receivables from employees of approximately $148,000 and $91,000 as of December 31, 2008 and December 31, 2007, respectively. During 2006, Basic entered into a lease agreement with Darle Vuelta Cattle Co., LLC, an affiliate of the Chief Executive Officer, for approximately $69,000. The term of the lease is five years and will continue on ayear-to-year basis unless terminated by either party.

F-31

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

12.   Profit Sharing Plan

Basic has a 401(k) profit sharing plan that covers substantially all employees. Employees may contribute up to their base salary not to exceed the annual Federal maximum allowed for such plans. Basic makes a matching contribution proportional to each employee’s contribution. Employee contributions are fully vested at all times. Employer matching contributions vest incrementally, with full vesting occurring after five years of service. Employer contributions to the 401(k) plan approximated $4.1 million, $3.0 million, and $2.5 million in 2008, 2007 and 2006, respectively.

13.   Deferred Compensation Plan

In April 2005, Basic established a deferred compensation plan for certain employees. Participants may defer up to 50% of their salary and 100% of any cash bonuses. Basic makes matching contributions of 100% of the first 3% of the participants’ deferred pay and 50% of the next 2% of the participants’ deferred pay to a maximum match of $9,200 per year. Employer matching contributions and earnings thereon are subject to a five-year vesting schedule with full vesting occurring after five years of service. Employer contributions to the deferred compensation plan net of earnings approximated a $563,000 gain in 2008 and a $216,000, and $199,000 expense in 2007 and 2006, respectively.

14.   Earnings Per Share

Basic presents earnings per share information in accordance with the provisions of Statement of Financial Accounting Standards No. 128,“Earnings per Share”(“SFAS No. 128”). Under SFAS No. 128, basic earnings per common share are determined by dividing net earnings applicable to common stock by the weighted average number of common shares actually outstanding during the year. Diluted earnings per common share is based on the increased number of shares that would be outstanding assuming conversion of dilutive outstanding securities using the “as if converted” method. The following table sets forth the computation of basic and diluted earnings per share (in thousands, except share data):

	Years Ended December 31,
	2008		2007		2006
Numerator (both basic and diluted):
Net income available to common stockholders	$	68,238	$	87,733	$	98,830
Denominator:
Denominator for basic earnings per share		40,754,890		40,013,054		34,471,771
Stock options		682,958		831,026		1,054,040
Unvested restricted stock		225,842		268,324		244,153
Common stock warrants		—		—		2,823,029
Denominator for diluted earnings per share		41,663,690		41,112,404		38,592,993
Basic earnings per common share:
Net income available to common stockholders	$	1.67	$	2.19	$	2.87
Diluted earnings per common share:
Net income available to common stockholders	$	1.64	$	2.13	$	2.56

The number of antidilutive shares at December 31, 2008, 2007 and 2006 was 413,000, 442,000 and 401,000, respectively.

F-32

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

15.   Business Segment Information

Basic revised its reportable business segments beginning in the first quarter of 2008 and in connection therewith restated the corresponding items of segment information for earlier periods. The new operating segments are Well Servicing, Fluid Services, Completion and Remedial Services, and Contract Drilling. These segments have been selected based on changes in management’s resource allocation and performance assessment in making decisions regarding the Company. Contract Drilling was previously included in our Well Servicing segment. Well Site Construction Services is now consolidated with our Fluid Services segment. These changes reflect Basic’s operating focus in compliance withSFAS No. 131,“Disclosures about Segments of an Enterprise and Related Information.”The following is a description of the segments:

Well Servicing:  This business segment encompasses a full range of services performed with a mobile well servicing rig, including the installation and removal of downhole equipment and elimination of obstructions in the well bore to facilitate the flow of oil and gas. These services are performed to establish, maintain and improve production throughout the productive life of an oil and gas well and to plug and abandon a well at the end of its productive life. Basic well servicing equipment and capabilities are essential to facilitate most other services performed on a well.

Fluid Services:  This segment utilizes a fleet of trucks and related assets, including specialized tank trucks, storage tanks, water wells, disposal facilities and related equipment. Basic employs these assets to provide, transport, store and dispose of a variety of fluids. These services are required in most workover, completion and remedial projects as well as part of daily producing well operations. Also included in this segment is our construction services which provide services for the construction and maintenance of oil and gas production infrastructures.

Completion and Remedial Services:  This segment utilizes a fleet of pressure pumping units, air compressor packages specially configured for underbalanced drilling operations, cased-hole wireline units and an array of specialized rental equipment and fishing tools. The largest portion of this business consists of pressure pumping services focused on cementing, acidizing and fracturing services in niche markets.

Contract Drilling:  This segment utilizes shallow and medium depth rigs and associated equipment for drilling wells to a specified depth for customers on a contract basis.

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.

F-33

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):

							Completion
	Well			Fluid			and Remedial			Contract			Corporate
	Servicing			Services			Services			Drilling			and Other		Total
Year ended December 31, 2008
Operating revenues	$	343,113		$	315,768		$	304,326		$	41,735		$	—	$	1,004,942
Direct operating costs		(215,243	)		(203,205	)		(165,574	)		(28,629	)		—		(612,651	)
Segment profits	$	127,870		$	112,563		$	138,752		$	13,106		$	—	$	392,291
Depreciation and amortization	$	45,298		$	33,629		$	27,473		$	6,816		$	5,391	$	118,607
Capital expenditures, (excluding acquisitions)	$	35,094		$	26,054		$	21,285		$	5,281		$	4,176	$	91,890
Identifiable assets	$	310,964		$	262,377		$	334,120		$	47,027		$	356,223	$	1,310,711
Year ended December 31, 2007
Operating revenues	$	342,697		$	259,324		$	240,692		$	34,460		$	—	$	877,173
Direct operating costs		(205,132	)		(165,327	)		(125,948	)		(22,510	)		—		(518,917	)
Segment profits	$	137,565		$	93,997		$	114,744		$	11,950		$	—	$	358,256
Depreciation and amortization	$	37,586		$	23,858		$	21,138		$	6,433		$	4,033	$	93,048
Capital expenditures, (excluding acquisitions)	$	39,803		$	25,266		$	22,384		$	6,813		$	4,270	$	98,536
Identifiable assets	$	284,058		$	207,380		$	284,321		$	73,787		$	294,063	$	1,143,609
Year ended December 31, 2006
Operating revenues	$	323,755		$	245,011		$	154,412		$	6,970		$	—	$	730,148
Direct operating costs		(178,028	)		(153,445	)		(74,981	)		(8,400	)		—		(414,854	)
Segment profits	$	145,727		$	91,566		$	79,431		$	(1,430	)	$	—	$	315,294
Depreciation and amortization	$	26,992		$	19,692		$	11,070		$	1,938		$	2,395	$	62,087
Capital expenditures, (excluding acquisitions)	$	29,677		$	33,167		$	18,646		$	19,050		$	4,034	$	104,574
Identifiable assets	$	226,566		$	193,927		$	129,471		$	17,112		$	229,184	$	796,260

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

	Year Ended December 31,
	2008			2007			2006
Segment profits	$	392,291		$	358,256		$	315,294
General and administrative expenses		(115,319	)		(99,042	)		(81,318	)
Depreciation and amortization		(118,607	)		(93,048	)		(62,087	)
Gain (loss) on disposal of assets		(76	)		(477	)		(277	)
Goodwill Impairment (Contract drilling segment)		(22,522	)		—			—
Operating income	$	135,767		$	165,689		$	171,612

F-34

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

16.   Accrued Expenses

The accrued expenses are as follows (in thousands):

	December 31,
	2008		2007
Compensation related	$	19,832	$	16,790
Workers’ compensation self-insured risk reserve		4,248		9,326
Health self-insured risk reserve		6,690		6,054
Accrual for receipts		4,976		3,955
Authority for expenditure accrual		543		211
Ad valorem taxes		137		73
Sales tax		588		1,140
Insurance obligations		2,474		995
Purchase order accrual		38		45
Professional fee accrual		185		424
Contingent earnout obligation		1,438		1,158
Retainers		—		172
Fuel accrual		897		1,692
Accrued interest		5,083		3,926
Contingent liability		—		1,296
Franchise Tax Payable		—		3,704
Other		10		42
	$	47,139	$	51,003

17.   Supplemental Schedule of Cash Flow Information

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

	Year Ended December 31,
	2008		2007		2006
	(In thousands)
Capital leases issued for equipment	$	50,730	$	26,814	$	26,420
Value of shares that may be issued	$	—	$	2,194	$	—
Contingent earnout accrual	$	183	$	1,032	$	2,256
Asset retirement obligation additions	$	143	$	101	$	767
Value of common stock issued in business combinations	$	—	$	51,193	$	—

Basic paid income taxes of approximately $27.2 million, $44.1 million and $43.2 million during the years ended December 31, 2008, 2007 and 2006, respectively.

F-35

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

18.   Quarterly Financial Data (Unaudited)

The following table summarizes results for each of the four quarters in the years ended December 31, 2008 and 2007:

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Year
Year ended December 31, 2008:
Total revenues	$	229,873	$	251,522	$	277,575	$	245,972	$	1,004,942
Segment profits	$	92,126	$	97,495	$	108,980	$	93,690	$	392,291
Income from continuing operations	$	19,656	$	18,713	$	25,942	$	3,927	$	68,238
Net income available to common stockholders	$	19,656	$	18,713	$	25,942	$	3,927	$	68,238
Basic earnings per share of common stock(a):
Net income available to common stockholders	$	0.48	$	0.46	$	0.63	$	0.10	$	1.67
Diluted earnings per share of common stock(a):
Net income (loss) available to common stockholders	$	0.47	$	0.45	$	0.62	$	0.10	$	1.64
Weighted average common shares outstanding:
Basic		40,577		40,721		40,988		40,731		40,755
Diluted		41,464		41,659		41,787		41,100		41,664
Year ended December 31, 2007:
Total revenues	$	198,930	$	223,256	$	229,232	$	225,755	$	877,173
Segment profits	$	82,785	$	91,235	$	94,280	$	89,956	$	358,256
Income from continuing operations	$	22,073	$	21,692	$	24,426	$	19,541	$	87,733
Net income available to common stockholders	$	22,073	$	21,692	$	24,426	$	19,541	$	87,733
Basic earnings per share of common stock(a):
Net income available to common stockholders	$	0.57	$	0.54	$	0.60	$	0.48	$	2.19
Diluted earnings per share of common stock(a):
Net income available to common stockholders	$	0.56	$	0.52	$	0.59	$	0.47	$	2.13
Weighted average common shares outstanding:
Basic		38,521		40,493		40,516		40,517		40,013
Diluted		39,661		41,621		41,591		41,551		41,112

(a) The sum of individual quarterly net income per share may not agree to the total for the year due to each period’s computation being based on the weighted average number of common shares outstanding during each period.

19.   Subsequent Events

On October 13, 2008, Basic announced that its Board of Directors had authorized the repurchase of up to $50.0 million of Basic’s common shares from time to time in open market or private transactions, at Basic’s discretion. From January 1, 2009 through February 27, 2009, Basic has repurchased 622,700 common shares at a total price of $4.9 million (an average of $7.92 per share).

F-36

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

			Additions
	Balance at		Charged to		Charged to					Balance at
	Beginning of		Costs and		Other					End of
Description	Period		Expenses(a)		Accounts(b)		Deductions(c)			Period
			(In thousands)
Year Ended December 31, 2008
Allowance for Bad Debt	$	6,090	$	2,331	$	—	$	(2,583	)	$	5,838
Year Ended December 31, 2007
Allowance for Bad Debt	$	3,963	$	3,251	$	—	$	(1,124	)	$	6,090
Year Ended December 31, 2006
Allowance for Bad Debt	$	2,775	$	1,909	$	—	$	(721	)	$	3,963

(a)	Charges relate to provisions for doubtful accounts
(b)	Reflects the impact of acquisitions
(c)	Deductions relate to the write-off of accounts receivable deemed uncollectible

F-37

Basic Energy Services, Inc.

Consolidated Balance Sheets

	June 30,			December 31,
	2009			2008
	(Unaudited)
	(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	134,304		$	111,135
Trade accounts receivable, net of allowance of $6,396 and $5,838, respectively		98,997			172,930
Accounts receivable — related parties		138			148
Income tax receivable		27,052			3,324
Inventories		11,279			11,937
Prepaid expenses		4,615			6,838
Other current assets		5,648			6,508
Deferred tax assets		28,076			11,081
Total current assets		310,109			323,901
Property and equipment, net		714,560			740,879
Deferred debt costs, net of amortization		7,058			5,132
Goodwill		—			202,749
Other intangible assets, net of amortization		34,381			36,004
Other assets		2,285			2,046
Total assets	$	1,068,393		$	1,310,711
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	17,784		$	28,291
Accrued expenses		37,950			47,139
Current portion of long-term debt		28,316			26,063
Other current liabilities		401			658
Total current liabilities		84,451			102,151
Long-term debt		451,958			454,260
Deferred tax liabilities		135,079			149,591
Other long-term liabilities		9,686			9,705
Commitments and contingencies
Stockholders’ equity:
Preferred stock; $.01 par value; 5,000,000 shares authorized; none designated or issued at June 30, 2009 and December 31, 2008, respectively		—			—
Common stock; $.01 par value; 80,000,000 shares authorized; 42,394,809 shares issued; and 40,703,187 shares outstanding at June 30, 2009; 41,734,485 shares issued; and 40,851,862 shares outstanding at December 31, 2008		424			417
Additional paid-in capital		328,101			325,785
Retained earnings		72,642			277,173
Treasury stock, at cost, 1,691,622 and 882,623 shares at June 30, 2009 and December 31, 2008, respectively		(13,948	)		(8,371	)
Total stockholders’ equity		387,219			595,004
Total liabilities and stockholders’ equity	$	1,068,393		$	1,310,711

See accompanying notes to consolidated financial statements.

F-38

Basic Energy Services, Inc.

Consolidated Statements of Operations and Comprehensive Income

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
	(Unaudited)						(Unaudited)
	(In thousands, except per share amounts)
Revenues:
Well servicing	$	36,399		$	89,018		$	85,213		$	169,537
Fluid services		49,088			72,581			114,065			143,980
Completion and remedial services		29,373			79,579			66,632			148,037
Contract drilling		3,988			10,344			7,626			19,841
Total revenues		118,848			251,522			273,536			481,395
Expenses:
Well servicing		27,825			55,293			64,742			103,759
Fluid services		35,381			48,554			79,968			94,987
Completion and remedial services		21,484			42,651			47,378			78,439
Contract drilling		3,338			7,529			6,607			14,589
General and administrative, including stock-based compensation of $1,290 and $1,184 in three months ended June 30, 2009 and 2008, and $2,665 and $2,264 in the six months ended June 30, 2009 and 2008, respectively		27,424			26,811			56,503			52,663
Depreciation and amortization		32,413			28,732			65,150			56,764
(Gain) loss on disposal of assets		474			(809	)		1,339			(584	)
Goodwill impairment		(82	)		—			204,014			—
Total expenses		148,257			208,761			525,701			400,617
Operating income (loss)		(29,409	)		42,761			(252,165	)		80,778
Other income (expense):
Interest expense		(5,974	)		(6,453	)		(11,710	)		(13,802	)
Interest income		173			471			393			1,172
Other income (expense)		118			(6,469	)		252			(6,431	)
Income (loss) from continuing operations before income taxes		(35,092	)		30,310			(263,230	)		61,717
Income tax benefit (expense)		13,856			(11,597	)		59,169			(23,348	)
Net income (loss)	$	(21,236	)	$	18,713		$	(204,061	)	$	38,369
Earnings per share of common stock:
Basic	$	(0.54	)	$	0.46		$	(5.13	)	$	0.94
Diluted	$	(0.54	)	$	0.45		$	(5.13	)	$	0.92

See accompanying notes to consolidated financial statements.

F-39

Basic Energy Services, Inc.

Consolidated Statements of Stockholders’ Equity

					Additional									Total
	Common Stock				Paid-In			Treasury			Retained			Stockholders’
	Shares		Amount		Capital			Stock			Earnings			Equity
	(In thousands, except share data)
Balance — December 31, 2008		41,734,485	$	417	$	325,785		$	(8,371	)	$	277,173		$	595,004
Issuances of restricted stock		660,324		7		(7	)		431			(431	)		—
Amortization of share based compensation		—		—		2,640			—			—			2,640
Treasury stock issued as compensation to Chairman of the Board		—		—		—			43			(19	)		24
Purchase of treasury stock		—		—		—			(6,104	)		—			(6,104	)
Exercise of stock options/vesting of restricted stock		—		—		(317	)		53			(20	)		(284	)
Net loss		—		—		—			—			(204,061	)		(204,061	)
Balance — June 30, 2009 (unaudited)		42,394,809	$	424	$	328,101		$	(13,948	)	$	72,642		$	387,219

See accompanying notes to consolidated financial statements.

F-40

Basic Energy Services, Inc.

Consolidated Statements of Cash Flows

	Six Months Ended June 30,
	2009			2008
	(Unaudited)
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	(204,061	)	$	38,369
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		65,150			56,764
Goodwill impairment		204,014			—
Accretion on asset retirement obligation		73			63
Change in allowance for doubtful accounts		558			(483	)
Amortization of deferred financing costs		630			482
Non-cash compensation		2,665			2,264
(Gain) loss on disposal of assets		1,339			(584	)
Deferred income taxes		(31,507	)		7,666
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable		73,385			(23,934	)
Inventories		658			402
Prepaid expenses and other current assets		3,380			5,177
Other assets		(219	)		(198	)
Accounts payable		(10,507	)		991
Excess tax expense (benefit) from exercise of employee stock options/vesting of restricted stock		317			(1,583	)
Income tax payable		(24,213	)		1,015
Other liabilities		(243	)		(3,414	)
Accrued expenses		(8,370	)		4,331
Net cash provided by operating activities		73,049			87,328
Cash flows from investing activities:
Purchase of property and equipment		(25,187	)		(45,023	)
Proceeds from sale of assets		1,912			6,470
Payments for other long-term assets		(995	)		(2,048	)
Payments for businesses, net of cash acquired		(1,190	)		(51,239	)
Net cash used in investing activities		(25,460	)		(91,840	)
Cash flows from financing activities:
Payments of debt		(15,475	)		(10,874	)
Purchase of treasury stock		(6,104	)		(1,149	)
Excess tax (expense) benefit from exercise of employee stock options/vesting of restricted stock		(317	)		1,583
Tax withholding from exercise of stock options		(5	)		(842	)
Exercise of employee stock options		37			1,637
Deferred loan costs and other financing activities		(2,556	)		—
Net cash used in financing activities		(24,420	)		(9,645	)
Net increase (decrease) in cash and equivalents		23,169			(14,157	)
Cash and cash equivalents — beginning of period		111,135			91,941
Cash and cash equivalents — end of period	$	134,304		$	77,784

See accompanying notes to consolidated financial statements.

F-41

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements

June 30, 2009 (unaudited)

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 Energy Services, Inc. provides a range of well site services to oil and gas drilling and producing companies, including well servicing, fluid services, completion and remedial services, and contract drilling. These services are primarily provided by Basic’s fleet of equipment. Basic’s operations are concentrated in the major United States onshore oil and gas producing regions in Texas, New Mexico, Oklahoma, Arkansas, Kansas and Louisiana, and the Rocky Mountain states.

2.   Summary of Significant Accounting Policies

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Basic and its wholly-owned subsidiaries. Basic has no interest in any other organization, entity, partnership, or contract that could require any evaluation under FASB Interpretation No. 46R or Accounting Research Bulletin No. 51. All intercompany transactions and balances have been eliminated.

Estimates and Uncertainties

Preparation of the accompanying consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Areas where critical accounting estimates are made by management include:

•  Depreciation and amortization of property and equipment and intangible assets

•  Impairment of property and equipment, goodwill and intangible assets

•  Allowance for doubtful accounts

•  Litigation and self-insured risk reserves

•  Fair value of assets acquired and liabilities assumed

•  Stock-based compensation

•  Income taxes

•  Asset retirement obligations

F-42

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Revenue Recognition

Well Servicing — Well servicing consists primarily of maintenance services, workover services, completion services and plugging and abandonment services. Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Basic prices well servicing by the hour or by the day of service performed.

Fluid Services — Fluid services consists primarily of the sale, transportation, storage and disposal of fluids used in drilling, production and maintenance of oil and natural gas wells, and well site construction and maintenance 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 fluid services by the job, by the hour or by the quantities sold, disposed of or hauled.

Completion and Remedial Services — Completion and remedial services consists primarily of pressure pumping services, focused on cementing, acidizing and fracturing, nitrogen units, coiled tubing units, and rental and fishing tools. Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Basic prices completion and remedial services by the hour, day, or project depending on the type of service performed. When Basic provides multiple services to a customer, revenue is allocated to the services performed based on the fair values of the services.

Contract Drilling — Contract drilling consists primarily of drilling wells to a specified depth using shallow and medium depth rigs. Basic recognizes revenues based on either a “daywork” contract, in which an agreed upon rate per day is charged to the customer, or a “footage” contract, in which an agreed upon rate is charged per the number of feet drilled.

Taxes assessed on sales transactions are presented on a net basis and are not included in revenue.

Inventories

For Rental and Fishing Tools, inventories consisting mainly of grapples and drill bits are stated at the lower of cost or market, with cost being determined on the average cost method. Other inventories, consisting mainly of rig components, repair parts, drilling and completion materials and gravel, are held for use in the operations of Basic and are stated at the lower of cost or market, with cost being determined on 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. 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 (“SFAS”) 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

F-43

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

annually, or whenever, in management’s judgment, events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of such assets exceeds the fair value of the assets. Assets to be disposed of would be separately presented in the consolidated balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated. The assets and liabilities, if material, of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the consolidated balance sheet. These assets are normally sold within a short period of time through a third party auctioneer.

Basic’s goodwill is considered to have an indefinite useful economic life and is not amortized. Basic assesses impairment of its goodwill annually as of December 31 or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. SFAS No. 142,“Goodwill and Other Intangible Assets” (“SFAS No. 142”), requires a two-step process for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. If impairment is indicated, then the fair value of the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination. The amount of impairment for goodwill is measured as the excess of its carrying value over its fair value.

In accordance with SFAS No. 142, the Company performed an assessment of goodwill as of March 31, 2009. A “triggering event” requiring this assessment was deemed to occur because the oil and gas services industry continued to decline in the first quarter and the Company’s common stock price declined by 50% from December 31, 2008 to March 31, 2009. For SFAS No. 142 Step One testing purposes, the Company tested three reporting units for goodwill impairment: well servicing, fluid services, and completion and remedial services. The Company’s contract drilling reporting unit does not carry any goodwill, and is not subject to the test.

To estimate the fair value of the reporting units, the Company used a weighting of the discounted cash flow method and the public company guideline method of determining fair value of a business unit. The Company weighted the discounted cash flow method 85% and public company guideline method 15%, due to differences between the Company’s reporting units and the peer companies’ size, profitability and diversity of operations. In order to validate the reasonableness of the estimated fair values obtained for the reporting units, a reconciliation of fair value to market capitalization was performed for each unit on a stand-alone basis. A control premium, derived from market transaction data, was used in this reconciliation to ensure that fair values were reasonably stated in conjunction with the Company’s capitalization. The measurement date for the Company’s common stock price and market capitalization was the closing price on March 31, 2009.

Based on the results of SFAS No. 142 Step One, impairment was indicated in all three of the assessed reporting units. As such, the Company was required to perform Step Two assessment on all three of the reporting units. Step Two requires the allocation of the estimated fair value to the tangible and intangible assets and liabilities of the respective unit. This assessment indicated that $204.1 million was considered impaired as of March 31, 2009. This non-cash charge eliminated all of the Company’s goodwill.

Additionally, in accordance with SFAS No. 144, the Company performed an assessment of the Company’s long-lived assets for impairment. This assessment is performed as a comparison of the undiscounted future cash flows of each reporting unit to the carrying value of the assets in each unit. No impairment was indicated by this test.

F-44

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

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 amortized to interest expense using the effective interest method.

Deferred debt costs were approximately $10.1 million net of accumulated amortization of $3.1 million and $7.6 million net of accumulated amortization of $2.4 million at June 30, 2009 and December 31, 2008, respectively. Amortization of deferred debt costs totaled approximately $391,000 and $242,000 for the three months ended June 30, 2009 and 2008, respectively. For the six months ended June 30, 2009 and 2008, amortization of deferred debt costs totaled approximately $630,000 and $482,000, respectively.

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. 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.

As of June 30, 2009, Basic had no goodwill. All of the Company’s goodwill was considered impaired as of March 31, 2009.

Intangible assets subject to amortization under SFAS No. 142 consist of customer relationships and non-compete agreements. The gross carrying amount of customer relationships subject to amortization was $35.4 million as of June 30, 2009 and December 31, 2008. The gross carrying amount of non-compete agreements subject to amortization totaled approximately $4.2 million and $4.4 million at June 30, 2009 and December 31, 2008, respectively. Accumulated amortization related to these intangible assets totaled approximately $5.3 million and $3.8 million at June 30, 2009 and December 31, 2008, respectively. Amortization expense for the three months ended June 30, 2009 and 2008 was approximately $803,000 and $636,000, respectively. Amortization expense for the six months ended June 30, 2009 and 2008 was approximately $1.6 million and $1.3 million, respectively Other intangibles net of accumulated amortization allocated to reporting units as of June 30, 2009 were $376,000, $3.1 million, $25.2 million and $5.7 million for well servicing, fluid services, completion and remedial services, and contract drilling, respectively.

Customer relationships are amortized over a15-year life. Non-compete agreements are amortized over a five-year life.

Stock-Based Compensation

Basic accounts for stock-based compensation based on SFAS No. 123 (revised 2004),“Share Based Payment”(“SFAS No. 123R”). Options issued are valued on the grant date using the Black-Scholes-Merton option-pricing model and all awards are adjusted for an expected forfeiture rate. Awards are amortized over the vesting period. Compensation expense of the unvested portion of awards granted as a private company and outstanding as of January 1, 2006 will be based upon the intrinsic value method calculated under Accounting Principles Board Opinion No. 25,“Accounting for Stock Issued to Employees”(“APB No. 25”).

Income Taxes

Basic accounts for income taxes based upon SFAS No. 109,“Accounting for Income Taxes”(“SFAS No. 109”). Under SFAS No. 109, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using statutory

F-45

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

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.

Basic recognized an effective tax benefit rate of 22% in the first six months of 2009 compared to a tax rate of 38% in the first six months of 2008. The lower effective tax rate in the first six months of 2009 was primarily due to the $204.0 million goodwill impairment charge. The tax deductibility of the impairment charge was determined by the taxable basis of the goodwill considered to be impaired. A portion of the Company’s goodwill was not tax-deductible.

Interest charges are recorded in interest expense and penalties are recorded in income tax expense.

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. Basic 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 during the three months ended June 30, 2009 or 2008.

Asset Retirement Obligations

As of January 1, 2003, Basic adopted SFAS No. 143,“Accounting for Asset Retirement Obligation”(“SFAS No. 143”). SFAS No. 143 requires Basic to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets and capitalize an equal amount as a cost of the asset depreciating it over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each quarter to reflect the passage of time, changes in the estimated future cash flows underlying the obligation, acquisition or construction of assets, and settlements of obligations.

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 assessmentand/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 SFAS No. 5“Accounting for Contingencies.”Basic maintains accruals in the consolidated balance sheets to cover self-insurance retentions (See note 6).

F-46

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Recent Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”), which became effective for financial assets and liabilities of the Company on January 1, 2008 and became effective for non-financial assets and liabilities of the Company on January 1, 2009. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements but would apply to assets and liabilities that are required to be recorded at fair value under other accounting standards. This standard was adopted for financial assets and liabilities as of January 1, 2008 and was adopted for non-financial assets and liabilities, including fair value measurements for asset impairments, goodwill and intangible asset impairments, purchase price allocations and asset retirement obligations on January 1, 2009. The adoption of this standard did not have any impact on the fair value of any of the Company’s financial assets or liabilities. For further information, see note 13.

In December 2007, the FASB issued SFAS No. 141R,“Business Combinations”(“SFAS No. 141R”), which became effective for the Company on January 1, 2009. This Statement requires an acquirer to recognize the assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date at their fair values as of that date. An acquirer is required to recognize assets or liabilities arising from all other contingencies (contractual contingencies) as of the acquisition date, measured at their acquisition-date fair values, only if it is more likely than not that they meet the definition of an asset or a liability in FASB Concepts Statement No. 6, “Elements of Financial Statements.” Any acquisition related costs are to be expensed instead of capitalized. The impact to the Company from the adoption of SFAS No. 141R in 2009 will vary acquisition by acquisition.

In December 2007, the FASB issued SFAS No. 160,“Noncontrolling Interests in Consolidated Financial Statements”(“SFAS No. 160”), which became effective for the Company on January 1, 2009. This standard establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. The Statement also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. This pronouncement has not had a significant impact on the Company’s results of operation or consolidated financial position since the Company does not have any noncontrolling interests.

In March 2008, the FASB issued SFAS No. 161,“Disclosures about Derivative Instruments and Hedging Activities”(“SFAS No. 161”), which became effective for the Company on January 1, 2009. This standard improves financial reporting for derivative instruments and hedging activities by requiring enhanced disclosures to expand on these instruments’ effects on a company’s financial position, financial performance and cash flows. This pronouncement did not have any impact on the Company’s results of operation or consolidated financial position since the Company does not have any derivative instruments.

In April 2008, the FASB issued FASB Staff PositionSFAS No. 142-3,“Determination of Useful Life of Intangible Assets”(“FSPNo. 142-3”). FSPNo. 142-3 amends the factors that should be considered in developing the renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142. FSPNo. 142-3 is effective for fiscal years beginning after December 15, 2008. This pronouncement has not had a significant impact on the results of operation or consolidated financial position of the Company.

In June 2008, the FASB issued FASB Staff PositionEITF 03-6-1,“Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities”(“FSPEITF 03-6-1”). FSPEITF 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings

F-47

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

per share (“EPS”) under the two-class method described in paragraphs 60 and 61 of SFAS No. 128,“Earnings Per Share.” FSPEITF 03-6-1 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008 and requires retrospective adjustment for all comparable prior periods presented. FSPEITF 03-6-1 has not had a significant impact on the Company’s results of operation or consolidated financial position since the Company does not have any participating securities.

In May 2009, the FASB issued SFAS No. 165,“Subsequent Events” (“SFAS No. 165”), which became effective for the Company on April 1, 2009. This standard establishes principles and requirements for disclosure of subsequent events. It establishes the period after the balance sheet date during which events or transactions are to be evaluated for potential disclosure. It also establishes the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date. The adoption of this standard requires the Company to disclose the date through which subsequent events have been reviewed.

In June 2009, the FASB issued SFAS No. 168,“The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement no. 162” (“SFAS No. 168”), which becomes effective for the Company on July 1, 2009. SFAS No. 168 establishes the FASB Accounting Standards Codification as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP. SFAS No. 168 is not expected to change GAAP and will not have a material impact on the Company’s consolidated financial statements.

3.   Acquisitions

In the first six months of 2009 Basic did not acquire any businesses. In 2008, Basic acquired either substantially all of the assets or all of the outstanding capital stock of each of the following businesses, each of which was accounted for using the purchase method of accounting (in thousands):

		Total Cash Paid
	Closing Date	(Net of Cash Acquired)
Xterra Fishing and Rental Tools Co.	January 28, 2008	$	21,473
Lackey Construction, LLC	January 30, 2008		4,328
B&S Disposal, LLC and B&S Equipment, Ltd	April 30, 2008		7,071
Triple N Services, Inc.	May 27, 2008		17,315
Azurite Services Company, Inc., Azurite Leasing Company, LLC and Freestone Disposal, L.P. (collectively, “Azurite”)	September 26, 2008		60,977
Total 2008		$	111,164

The operations of each of the acquisitions listed above are included in Basic’s statement of operations as of each respective closing date. The acquisition of Azurite in 2008 has been deemed material and is discussed below in further detail.

Contingent Earn-out Arrangements and Purchase Price Allocations

Contingent earn-out arrangements are generally arrangements entered into on certain acquisitions to encourage the owner/manager to continue operating and building the business after the purchase transaction. The contingent earn-out arrangements of the related acquisitions are generally linked to certain financial measures and performance of the assets acquired in the various acquisitions. All amounts paid or reasonably accrued for related to the contingent earn-out payments are reflected as increases to the goodwill associated with the acquisition or compensation expense depending on the terms and conditions of the earn-out arrangement.

F-48

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Azurite

On September 26, 2008, Basic acquired substantially all of the assets of Azurite Services Company, Inc., Azurite Leasing Company, LLC, and Freestone Disposal, L.P. (collectively, “Azurite”) for $61.0 million in cash. This acquisition operates in our fluid services line of business and expands our operations in the East Texas markets. The following table summarizes the preliminary estimated fair value of the assets acquired and liabilities assumed at the date of acquisition for Azurite (in thousands):

Property and Equipment	$	53,127
Intangible Assets(1)		1,862
Goodwill(2)		5,988
Total Assets Acquired	$	60,977

(1)	Consists of customer relationships of $1,832, amortizable over 15 years, and non-compete agreements of $30, amortizable over five years.
(2)	All of which is expected to be deductible for tax purposes.

The following unaudited pro forma results of operations have been prepared as though the Azurite acquisition had been completed on January 1, 2008. Pro forma amounts are based on the purchase price allocations of the significant acquisitions and are not necessarily indicative of the results that may be reported in the future (in thousands, except per share data).

	Six Months Ended
	June 30, 2008
Revenues	$	504,149
Net income	$	40,020
Earnings per common share — basic	$	0.98
Earnings per common share — diluted	$	0.96

Basic does not believe the pro forma effect of the remainder of the acquisitions completed in 2008 are material, either individually or when aggregated, to the reported results of operations.

F-49

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

4.   Property and Equipment

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

	June 30,		December 31,
	2009		2008
Land	$	5,275	$	4,689
Buildings and improvements		31,913		29,913
Well service units and equipment		385,750		379,167
Fluid services equipment		138,671		136,814
Brine and fresh water stations		10,443		10,203
Frac/test tanks		117,514		128,845
Pressure pumping equipment		169,636		156,406
Construction equipment		25,475		22,483
Contract drilling equipment		60,467		60,340
Disposal facilities		55,566		49,878
Vehicles		39,998		41,129
Rental equipment		37,317		36,898
Aircraft		4,119		4,119
Other		29,350		21,758
		1,111,494		1,082,642
Less accumulated depreciation and amortization		396,934		341,763
Property and equipment, net	$	714,560	$	740,879

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 consisted of the following (in thousands):

	June 30,		December 31,
	2009		2008
Light vehicles	$	26,572	$	30,141
Well service units and equipment		1,713		1,194
Fluid services equipment		56,516		56,010
Pressure pumping equipment		27,276		20,492
Construction equipment		1,034		3,679
Software		13,659		9,464
Other		—		705
		126,770		121,685
Less accumulated amortization		38,018		37,370
	$	88,752	$	84,315

Amortization of assets held under capital leases of approximately $5.1 million and $3.2 million for the three months ended June 30, 2009 and 2008 and $10.1 million and $6.6 million for the six months ended June 30, 2009 and 2008, respectively, is included in depreciation and amortization expense in the consolidated statements of operations.

F-50

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

5.   Long-Term Debt

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

	June 30,		December 31,
	2009		2008
Credit Facilities:
Revolver	$	180,000	$	180,000
7.125% Senior Notes		225,000		225,000
Capital leases and other notes		75,274		75,323
		480,274		480,323
Less current portion		28,316		26,063
	$	451,958	$	454,260

Senior Notes

On April 12, 2006, Basic 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. The Senior Notes are unsecured. Under the terms of the sale of the Senior Notes, Basic 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. Basic completed the exchange offer for all of the Senior Notes on October 16, 2006.

The Senior Notes are redeemable at the option of Basic on or after April 15, 2011 at the specified redemption price as described in the Indenture. Prior to April 15, 2011, Basic may redeem the Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the Senior Notes redeemed plus the Applicable Premium as defined in the Indenture.

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

Pursuant to the Indenture, Basic is subject to covenants that limit the ability of Basic and its restricted subsidiaries to, among other things: incur additional indebtedness, pay dividends or repurchase or redeem capital stock, make certain investments, incur liens, enter into certain types of transactions with affiliates, limit dividends or other payments by restricted subsidiaries, and sell assets or consolidate or merge with or into other companies. These limitations are subject to a number of important qualifications and exceptions set forth in the Indenture. Basic was in compliance with the restrictive covenants at June 30, 2009. In the event of a default on the Credit Facility 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.

As part of the issuance of the above-mentioned Senior Notes, Basic incurred debt issuance costs of approximately $4.6 million, which are being amortized to interest expense using the effective interest method over the term of the Senior Notes.

The Senior Notes are jointly and severally guaranteed by Basic and all of its restricted subsidiaries. Basic Energy Services, Inc., the ultimate parent company, does not have any independent operating assets or operations. Subsidiaries other than the restricted subsidiaries that are guarantors are minor.

F-51

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Credit Facility

On May 4, 2009, Basic entered into Amendment and Consent No. 1 (the “Amendment”) to its Fourth Amended and Restated Credit Agreement, dated February 6, 2007 (the “Existing Credit Agreement,” and as amended by the Amendment, the “Credit Facility”).

Under the Credit Facility, Basic Energy Services, Inc. is the sole borrower and each of our subsidiaries is a subsidiary guarantor. The Credit Facility provides for an aggregate $225 million revolving line of credit (the “Revolver”). The Credit Facility includes provisions allowing Basic to request an increase in commitments of up to $100.0 million aggregate principal amount subject to meeting certain tangible value requirements and subject to lender participation at the time of the request. 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.

Under the Credit Facility, certain revolving loans are reclassified as (i) Tranche A Revolving Loans, which have the same maturity date as that of revolving loans under the Existing Credit Agreement (December 15, 2010), and (ii) Tranche B Revolving Loans, which have an extended maturity date of January 31, 2012. Revolving lenders are reclassified into two groups: those who agreed to extend the maturity date for their revolving commitments are deemed Tranche B Revolving Lenders, and the other revolving lenders are deemed Tranche A Revolving Lenders. The amount of commitments under the Tranche A Revolving Loans is $80 million and the amount under the Tranche B Revolving Loans is $145 million.

For Tranche A Revolving Loans and Tranche B Revolving Loans, Alternative Base Rate loans (“ABR Loans”) bear interest at the highest of (i) the bank’s prime rate, (ii) the federal funds rate plus 0.50% per year, and (iii) the adjusted LIBOR rate for an interest period of one month beginning on the day of the ABR Loan plus 100 basis points, plus an applicable margin. The applicable margin for ABR Loans ranges from 0.25% to 0.50% for Tranche A Revolving Loans and ranges from 2.50% to 3.50% for Tranche B Revolving Loans. The applicable margin for Eurodollar revolving loans with respect to any Tranche B Revolving Loan ranges from 3.50% to 4.50%. Furthermore, the applicable commitment fee for the unused portion of any Tranche B revolving commitments, based on average daily unused amounts, is 1.0% per annum, as compared to 0.375% per annum for Tranche A revolving commitments.

At June 30, 2009, Basic had $180.0 million of borrowings, and $16.2 million of letters of credit and no swing-line loans outstanding under the Revolver and remaining availability of $28.8 million.

Pursuant to the Credit Facility, Basic must apply proceeds from certain specified events to reduce principal outstanding borrowings under the Revolver, including (a) assets sales greater than $2.0 million individually or $7.5 million in the aggregate on an annual basis, (b) 100% of the net cash proceeds from any debt issuance, including certain permitted unsecured senior or senior subordinated debt, but excluding certain other permitted debt issuances and (c) 50% of the net cash proceeds from any equity issuance (including equity issued upon the exercise of any warrant or option).

The Credit Facility contains various restrictive covenants and compliance requirements, which include (a) limitations on the incurrence of additional indebtedness, (b) restrictions on mergers, sales or transfer of assets without the lenders’ consent (c) limitations on dividends and distributions and (d) various financial covenants, including (1) a maximum leverage ratio of 3.75 to 1.00 on the effective date of the Amendment and thereafter, and (2) a minimum interest coverage ratio of 3.00 to 1.00. At June 30, 2009, 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 individually material.

F-52

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

See note 14 for discussion of secured senior notes offering.

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

	Six Months Ended
	June 30,
	2009			2008
Cash payments for interest	$	12,263		$	12,935
Commitment and other fees paid		157			51
Amortization of debt issuance costs		630			482
Change in accrued interest		(1,345	)		51
Other		5			283
	$	11,710		$	13,802

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 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 $375,000 and $250,000, 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.

F-53

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

At June 30, 2009 and December 31, 2008, self-insured risk accruals for medical and dental coverage totaled approximately $14.6 million net of a $49,000 receivable and $15.4 million net of a $992,000 receivable, respectively.

7.   Stockholders’ Equity

Common Stock

At June 30, 2009 and December 31, 2008, Basic had 80,000,000 shares of common stock, par value $.01 per share, authorized.

During the year ended December 31, 2008, Basic issued 447,255 shares of newly-issued common stock and 138,675 shares of treasury stock for the exercise of stock options.

In March 2008, Basic granted various employees 361,700 unvested shares of common stock which vest over a five year period. Also, in March 2008, Basic granted the Chairman of the Board 4,000 shares of common stock which vested immediately in lieu of annual cash director fees. In October 2008, Basic granted a vice president 5,000 shares of restricted common stock which vest over a three year period.

In March 2008, the Compensation Committee of Basic’s Board of Directors approved grants of performance-based stock awards to certain members of management. In March 2009, it was determined that 93,500 shares, or 100% of the target number of shares, were earned based on the Company’s achievement of certain earnings per share growth and return on capital employed performance over the performance period from January 1, 2006 through December 31, 2008, as compared to other members of a defined peer group. These shares remain subject to vesting over a three-year period, with the first shares vesting on March 15, 2010.

In March 2009, Basic granted various employees 571,824 unvested shares of common stock which vest over a five-year period. Also, in March 2009, Basic granted the Chairman of the Board 4,000 shares of common stock which vested immediately in lieu of annual cash director fees.

In May 2009, consistent with its director compensation practices, Basic granted a new board member 37,500 shares of restricted common stock which vest over a three-year period.

During the six months ended June 30, 2009, Basic issued 5,000 shares of common stock from treasury stock for the exercise of stock options.

Treasury Stock

On October 13, 2008, Basic announced that its Board of Directors authorized the repurchase of up to $50.0 million of Basic’s shares of common stock from time to time in open market or private transactions, at Basic’s discretion. The number of shares purchased and the timing of purchases are based on several factors, including the price of the common stock, general market conditions, available cash and alternative investment opportunities. During the year ended December 31, 2008, Basic repurchased 897,558 shares at a total price of $8.8 million (an average of $9.82 per share), inclusive of commissions and fees. During the first six months of 2009, Basic repurchased 809,093 shares at a total price of $6.0 million (an average of $7.41 per share), inclusive of commissions and fees.

Basic also acquired treasury shares through net share settlements for payment of payroll taxes upon the vesting of restricted stock. Basic acquired a total of 52,877 shares through net share settlements during 2008 and 13,719 shares through net share settlements during the first six months of 2009.

F-54

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Preferred Stock

At June 30, 2009 and December 31, 2008, Basic had 5,000,000 shares of preferred stock, par value $.01 per share, authorized, of which none was designated, issued or outstanding.

8.   Incentive Plan

In May 2003, Basic’s board of directors and stockholders approved the Basic 2003 Incentive Plan (as amended effective May 26, 2009) (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 7,100,000 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.

The fair value of each option award is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. Basic is required to estimate the expected forfeiture rate and only recognize expense for those options expected to vest. During the three months ended June 30, 2009 and 2008, compensation expense related to share-based arrangements was approximately $1.3 million and $1.2 million, respectively. For compensation expense recognized during the three months ended June 30, 2009 and 2008, Basic recognized a tax benefit of approximately $509,000 and $453,000 respectively. During the six months ended June 30, 2009 and 2008, compensation expense related to share-based arrangements was approximately $2.7 million and $2.3 million, respectively. For compensation expense recognized during the six months ended June 30, 2009 and 2008, Basic recognized a tax benefit of approximately $992,000 and $857,000 respectively.

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

The following table reflects the summary of stock options outstanding at June 30, 2009 and the changes during the six months then ended:

						Weighted
				Weighted		Average		Aggregate
	Number of			Average		Remaining		Instrinsic
	Options			Exercise		Contractual		Value
	Granted			Price		Term (Years)		(000’s)
Non-statutory stock options:
Outstanding, beginning of period		1,608,675		$	11.11
Options granted		—
Options forfeited		(15,500	)	$	14.03
Options exercised		(5,000	)	$	6.98
Options expired		(91,250	)	$	6.05
Outstanding, end of period		1,496,925		$	11.40		5.34	$	1,424
Exercisable, end of period		1,124,050		$	9.18		4.96	$	1,424
Vested or expected to vest, end of period		1,483,175		$	11.27		5.32	$	1,424

F-55

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

The total intrinsic value of share options exercised during the six months ended June 30, 2009 and 2008 was approximately $15,000 and $2.6 million, respectively.

On March 13, 2009, the Compensation Committee of Basic’s Board of Directors approved grants of performance-based stock awards to certain members of management. The performance-based awards are tied to the Company’s achievement of certain earnings per share growth and return on capital employed performance over the performance period from January 1, 2007 through December 31, 2009, as compared to other members of a defined peer group. The number of shares to be issued will range from 0% to 150% of the target number of shares of 265,000 depending on the performance noted above. Any shares earned at the end of the performance period will then remain subject to vesting over a three-year period, with the first shares vesting March 15, 2011. As of June 30, 2009 it was estimated that none of the performance based awards will be earned.

A summary of the status of the Company’s non-vested share grants at June 30, 2009 and changes during the six months ended June 30, 2009 is presented in the following table:

				Weighted
				Average
				Grant Date
	Number of			Fair Value
Nonvested Shares	Shares			per Share
Nonvested at beginning of period		599,325		$	21.41
Granted during period		616,324			6.50
Vested during period		(72,375	)		20.04
Forfeited during period		(39,600	)		16.86
Performance based earned(1)		14,025			21.17
Nonvested at end of period		1,117,699		$	13.44

(1) In March 2008 certain members of management were awarded grants of performance based stock awards. The number of shares to be earned ranged from 0% to 150% of target depending on the Company’s achievement of certain EPS and return on capital employed performance compared to a peer group. The performance period for purposes of these grants was January 1, 2006 through December 31, 2008. As of December 31, 2008 it was estimated that 85% of the target shares would be earned and in March 2009 it was determined that 100% of the target shares had been earned. These shares remain subject to vesting over a three-year period, with the first shares vesting in March 2010.

As of June 30, 2009, there was approximately $12.6 million of total unrecognized compensation related to non-vested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 3.29 years. The total fair value of share-based awards vested during the six months ended June 30, 2009 and 2008 was approximately $3.9 million and $10.0 million, respectively. The actual tax benefit realized for the tax deduction from vested share-based awards was $149,000 and $861,000 for the six months ended June 30, 2009 and 2008, respectively.

Cash received from share option exercises under the Plan was approximately $35,000 and $795,000 for the six months ended June 30, 2009 and 2008, respectively. The actual tax benefit realized for the tax deductions from options exercised was $6,000 and $1.0 million for the six months ended June 30, 2009 and 2008, respectively.

The Company has a history of issuing treasury and newly-issued shares to satisfy share option exercises.

F-56

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

9.   Related Party Transactions

Basic had receivables from employees of approximately $138,000 and $148,000 as of June 30, 2009 and December 31, 2008, respectively. During 2006, Basic entered into a lease agreement with Darle Vuelta Cattle Co., LLC, an affiliate of the Chief Executive Officer, for approximately $69,000. The term of the lease is five years and will continue on 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 SFAS 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 period. 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):

	Three Months Ended June 30,					Six Months Ended June 30,
	2009			2008		2009			2008
	(Unaudited)					(Unaudited)
Numerator (both basic and diluted):
Net income (loss)	$	(21,236	)	$	18,713	$	(204,061	)	$	38,369
Denominator:
Denominator for basic earnings per share		39,574,561			40,721,317		39,773,857			40,649,287
Stock options		—			827,164		—			810,916
Unvested restricted stock		—			110,114		—			197,915
Denominator for diluted earnings per share		39,574,561			41,658,595		39,773,857			41,658,118
Basic earnings per common share:	$	(0.54	)	$	0.46	$	(5.13	)	$	0.94
Diluted earnings per common share:	$	(0.54	)	$	0.45	$	(5.13	)	$	0.92

Stock options and unvested restricted stock shares of approximately 409,000 and 443,000 were excluded in the computation of diluted earnings per share for the three months and six months ended June 30, 2009, respectively as the effect would have been anti-dilutive due to the net loss in each of these periods.

11.   Business Segment Information

Basic’s reportable business segments are Well Servicing, Fluid Services, Completion and Remedial Services, and Contract Drilling. 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. Well servicing equipment and capabilities such as Basic’s 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, construction and other related equipment. Basic employs these assets to provide, transport, store and dispose of a variety of fluids, as well as provide well

F-57

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

site construction and maintenance services. These services are required in most workover, completion and remedial projects and are routinely used in daily producing well operations.

Completion and Remedial Services:  This segment utilizes a fleet of pressure pumping units, coiled tubing units, air compressor packages specially configured for underbalanced drilling operations, cased-hole wireline units and an array of specialized rental equipment and fishing tools. The largest portion of this business consists of pressure pumping services focused on cementing, acidizing and fracturing services in niche markets.

Contract Drilling:  This segment utilizes shallow and medium depth rigs and associated equipment for drilling wells to a specified depth for customers on a contract basis.

Basic’s management evaluates the performance of its operating segments based on operating revenues and segment profits. Corporate expenses include general corporate expenses associated with managing all reportable operating segments. Corporate assets consist principally of working capital and debt financing costs.

The following table sets forth certain financial information with respect to Basic’s reportable segments (in thousands):

							Completion
	Well			Fluid			and Remedial			Contract			Corporate
	Servicing			Services			Services			Drilling			and Other		Total
Three Months Ended June 30, 2009 (Unaudited)
Operating revenues	$	36,399		$	49,088		$	29,373		$	3,988		$	—	$	118,848
Direct operating costs		(27,825	)		(35,381	)		(21,484	)		(3,338	)		—	$	(88,028	)
Segment profits	$	8,574		$	13,707		$	7,889		$	650		$	—	$	30,820
Depreciation and amortization	$	12,127		$	9,131		$	7,653		$	1,803		$	1,699	$	32,413
Capital expenditures, (excluding acquisitions)	$	4,266		$	3,212		$	2,693		$	634		$	598	$	11,403
Three Months Ended June 30, 2008 (Unaudited)
Operating revenues	$	89,018		$	72,581		$	79,579		$	10,344		$	—	$	251,522
Direct operating costs		(55,293	)		(48,554	)		(42,651	)		(7,529	)		—		(154,027	)
Segment profits	$	33,725		$	24,027		$	36,928		$	2,815		$	—	$	97,495
Depreciation and amortization	$	11,492		$	7,046		$	7,041		$	1,853		$	1,300	$	28,732
Capital expenditures, (excluding acquisitions)	$	10,638		$	6,522		$	6,518		$	1,715		$	1,203	$	26,596
Six Months Ended June 30, 2009 (Unaudited)
Operating revenues	$	85,213		$	114,065		$	66,632		$	7,626		$	—	$	273,536
Direct operating costs		(64,742	)		(79,968	)		(47,378	)		(6,607	)		—	$	(198,695	)
Segment profits	$	20,471		$	34,097		$	19,254		$	1,019		$	—	$	74,841
Depreciation and amortization	$	24,375		$	18,353		$	15,383		$	3,624		$	3,415	$	65,150
Capital expenditures, (excluding acquisitions)	$	9,423		$	7,095		$	5,947		$	1,401		$	1,321	$	25,187
Identifiable assets	$	268,207		$	205,577		$	202,563		$	44,544		$	347,502	$	1,068,393

F-58

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

							Completion
	Well			Fluid			and Remedial			Contract			Corporate
	Servicing			Services			Services			Drilling			and Other		Total
Six Months Ended June 30, 2008 (Unaudited)
Operating revenues	$	169,537		$	143,980		$	148,037		$	19,841		$	—	$	481,395
Direct operating costs		(103,759	)		(94,987	)		(78,439	)		(14,589	)		—		(291,774	)
Segment profits	$	65,778		$	48,993		$	69,598		$	5,252		$	—	$	189,621
Depreciation and amortization	$	22,704		$	13,921		$	13,911		$	3,661		$	2,567	$	56,764
Capital expenditures, (excluding acquisitions)	$	18,008		$	11,041		$	11,033		$	2,904		$	2,037	$	45,023
Identifiable assets	$	301,669		$	209,397		$	322,623		$	70,984		$	305,103	$	1,209,776

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Segment profits	$	30,820		$	97,495		$	74,841		$	189,621
General and administrative expenses		(27,424	)		(26,811	)		(56,503	)		(52,663	)
Depreciation and amortization		(32,413	)		(28,732	)		(65,150	)		(56,764	)
Loss on disposal of assets		(474	)		809			(1,339	)		584
Goodwill impairment		82			—			(204,014	)		—
Operating income (loss)	$	(29,409	)	$	42,761		$	(252,165	)	$	80,778

12.   Supplemental Schedule of Cash Flow Information

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

	Six Months Ended
	June 30,
	2009		2008
	(In thousands)
Capital leases issued for equipment	$	15,426	$	20,522
Contingent earnout accrual	$	909	$	1,158
Asset retirement obligation additions	$	12	$	34

Basic paid no income taxes during the six months ended June 30, 2009. Basic paid income taxes of approximately $13.2 million during the six months ended June 30, 2008. Basic paid interest of approximately $12.3 million and $12.9 million during the six months ended June 30, 2009 and 2008, respectively.

13.   Fair Value Measurements

SFAS No. 157 was issued by the FASB in September 2006 and became effective for financial assets and liabilities of the Company on January 1, 2008 and became effective for non-financial assets and liabilities of the Company on January 1, 2009. SFAS No. 157 defines fair value, establishes a framework for measuring fair value under GAAP and expands disclosures about fair value measurements. Fair value is the price that would be received to sell an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market based measurement considered

F-59

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

from the perspective of a market participant. The Company uses market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated, or unobservable. If observable prices or inputs are not available, unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued. The Company primarily applies a market approach for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The Company classifies fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:

Level 1 —Quoted prices in active markets for identical assets or liabilities that the Company has the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 —Inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured.

Level 3 — Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

In valuing certain assets and liabilities, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.

The Company’s asset retirement obligation related to its 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, is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs. The fair value is calculated by taking the present value of the expected cash flow at the time of the closure of the site. The following table reflects the changes in the fair value of the liability during the six months ended June 30, 2009 (in thousands):

	Asset
	Retirement
	Obligation
Balance, December 31, 2008	$	1,796
Additional asset retirement obligation		12
Accretion expense		73
Balance, June 30, 2009	$	1,881

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BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

14.   Subsequent Events

Management performed an evaluation of the Company’s activity through July 31, 2009, the date these financial statements were issued, noting the following subsequent event.

On July 23, 2009, we announced that we had priced a private offering of $225 million of Senior Secured Notes due 2014, which will bear interest at a rate of 11.625% per annum. The notes are being sold at 94.621% of their face amount. We closed the sale of the notes July 31, 2009, and used the net proceeds from the offering to repay all outstanding indebtedness under our revolving credit facility.

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Appendix A

Glossary of Terms

Acidizing:  The process of pumping solvent into the well as a means of dissolving unwanted material.

Brine water:  Water, which is heavily saturated with salt, that is 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.

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.

A-1

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.

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PROSPECTUS

          , 2009

Until          , 2009 (25 days after the date of this prospectus), 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.

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

ITEM 20.   Indemnification of Directors and Officers.

Delaware Corporation Guarantors

Basic Energy Services, Inc., Basic Marine Services, Inc., First Energy Services Company and JetStar Holdings, Inc. are incorporated under the laws of the State of Delaware. Section 145 of the Delaware General Corporation Law (“DGCL”) provides that a corporation may indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation) by reason of the fact that he is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. Section 145 further provides that a corporation similarly may indemnify any such person serving in any such capacity who was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit by or in the right of the corporation to procure a judgment in its favor by reason of the fact that he is or was a director, officer, employee or agent of the corporation or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys’ fees) actually and reasonably incurred in connection with the defense or settlement of such action or suit if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation and except that no indemnification shall be made in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to the corporation unless and only to the extent that the Delaware Court of Chancery or such other court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all of the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the Delaware Court of Chancery or such other court shall deem proper.

Basic Energy Services’ certificate of incorporation and bylaws provide that indemnification shall be to the fullest extent permitted by the DGCL for all current or former directors or officers of Basic Energy Services. As permitted by the DGCL, the certificate of incorporation provides that directors of Basic Energy Services shall have no personal liability to Basic Energy Services or its stockholders for monetary damages for breach of fiduciary duty as a director, except (1) for any breach of the director’s duty of loyalty to Basic Energy Services or its stockholders, (2) for acts or omissions not in good faith or which involve intentional misconduct or knowing violation of law, (3) under Section 174 of the DGCL or (4) for any transaction from which a director derived an improper personal benefit.

We have also entered into indemnification agreements with all of our directors and some of our executive officers (including each of our named 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

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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.

Delaware Limited Liability Company Guarantors

Basic Energy Services GP, LLC, Basic Energy Services LP, LLC and JS Acquisition LLC are organized under the laws of the State of Delaware. Under the Delaware Limited Liability Company Act, a limited liability company may, and shall have the power to, indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever.

Each of the Agreements of Limited Liability Company of these subsidiaries provides that a member shall not be liable to such subsidiary for any act or omission based upon errors of judgment or other fault in connection with the business or affairs of such subsidiary if such member’s conduct does not constitute gross negligence or willful misconduct. Furthermore, a member shall be indemnified and held harmless by such subsidiary to the fullest extent permitted by law, from and against any and all losses, claims, damages and settlements arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which the member is involved, as a party or otherwise, by reason of the management of the affairs of such subsidiary, provided that no member shall be entitled to indemnification for such losses, claims, damages and settlements arising as a result of the gross negligence or willful misconduct of such member.

Texas Corporation Guarantors

Basic ESA, Inc., LeBus Oil Field Service Co., Globe Well Service, Inc., JetStar Energy Services, Inc., Sledge Drilling Corp. and Xterra Fishing and Rental Tools Co. are incorporated under the laws of the State of Texas.Article 2.02-1 of the Texas Business Corporation Act provides that any director or officer of a Texas corporation may be indemnified against judgments, penalties, fines, settlements and reasonable expenses actually incurred by the person in connection with or in defending any action, suit or proceeding, whether civil, criminal, administrative, arbitrative or investigative, in which he was, is, or is threatened to be made a named defendant by reason of his position as a director or officer of the corporation, provided that (i) he conducted himself in good faith, (ii) he reasonably believed that, in the case of conduct in his official capacity as a director or officer of the corporation, such conduct was in the corporation’s best interests; and, in all other cases, that such conduct was at least not opposed to the corporation’s best interests, and (iii) in the case of a criminal proceeding, he had no reasonable cause to believe his conduct was unlawful. If a director or officer is wholly successful, on the merits or otherwise, in connection with such a proceeding, such indemnification is mandatory. In connection with any action, suit or proceeding in which a director or officer is (x) found liable on the basis that personal benefit was improperly received by him, whether or not the benefit resulted from an action taken in his official capacity, or (y) found liable to the corporation, the indemnification is limited to

II-2

reasonable expenses actually incurred by him in connection with the proceeding and will not be made in respect of any proceeding in which he is found liable for willful or intentional misconduct in the performance of his duty to the corporation.

Texas Limited Liability Company Guarantors

SCH Disposal, L.L.C. and Permian Plaza, LLC are organized under the laws of the State of Texas.

Section 2.20 of the Texas Limited Liability Company Act, which governs SCH Disposal, L.L.C., provides that, subject to such standards and restrictions, if any, as are set forth in its articles of organization or in its regulations, a limited liability company shall have the power to indemnify members and managers, officers and other persons and purchase and maintain liability insurance for such persons.

The Texas Business Organizations Code (“TBOC”) governs Permian Plaza, LLC. Section 8.051 of the TBOC states that: (a) An enterprise shall indemnify a governing person, former governing person, or delegate against reasonable expenses actually incurred by the person in connection with a proceeding in which the person is a respondent because the person is or was a governing person or delegate if the person is wholly successful, on the merits or otherwise, in the defense of the proceeding. (b) A court that determines, in a suit for indemnification, that a governing person, former governing person, or delegate is entitled to indemnification under this section shall order indemnification and award to the person the expenses incurred in securing the indemnification.

Section 8.052 of the TBOC states that: (a) On application of a governing person, former governing person, or delegate and after notice is provided as required by the court, a court may order an enterprise to indemnify the person to the extent the court determines that the person is fairly and reasonably entitled to indemnification in view of all the relevant circumstances. (b) This section applies without regard to whether the governing person, former governing person, or delegate applying to the court satisfies the requirements of Section 8.101 or has been found liable: (1) to the enterprise; or (2) because the person improperly received a personal benefit, without regard to whether the benefit resulted from an action taken in the person’s official capacity. (c) The indemnification ordered by the court under this section is limited to reasonable expenses if the governing person, former governing person, or delegate is found liable: (1) to the enterprise; or (2) because the person improperly received a personal benefit, without regard to whether the benefit resulted from an action taken in the person’s official capacity.

Section 8.101 of the TBOC states that: (a) An enterprise may indemnify a governing person, former governing person, or delegate who was, is, or is threatened to be made a respondent in a proceeding to the extent permitted by Section 8.102 if it is determined in accordance with Section 8.103 that: (1) the person: (A) acted in good faith;(B) reasonably believed: (i) in the case of conduct in the person’s official capacity, that the person’s conduct was in the enterprise’s best interests; and (ii) in any other case, that the person’s conduct was not opposed to the enterprise’s best interests; and (C) in the case of a criminal proceeding, did not have a reasonable cause to believe the person’s conduct was unlawful; (2) with respect to expenses, the amount of expenses other than a judgment is reasonable; and (3) indemnification should be paid. (b) Action taken or omitted by a governing person or delegate with respect to an employee benefit plan in the performance of the person’s duties for a purpose reasonably believed by the person to be in the interest of the participants and beneficiaries of the plan is for a purpose that is not opposed to the best interests of the enterprise. (c) Action taken or omitted by a delegate to another enterprise for a purpose reasonably believed by the delegate to be in the interest of the other enterprise or its owners or members is for a purpose that is not opposed to the best interests of the enterprise. (d) A person does not fail to meet the standard under Subsection (a)(1) solely because of the termination of a proceeding by: (1) judgment; (2) order; (3) settlement; (4) conviction; or (5) a plea of nolo contendere or its equivalent.

Section 8.102 of the TBOC states that: (a) Subject to Subsection (b), an enterprise may indemnify a governing person, former governing person, or delegate against: (1) a judgment; and (2) expenses, other than a judgment, that are reasonable and actually incurred by the person in connection with a proceeding. (b) Indemnification under this subchapter of a person who is found liable to the enterprise or is found liable because the person improperly received a personal benefit: (1) is limited to reasonable expenses actually

II-3

incurred by the person in connection with the proceeding; (2) does not include a judgment, a penalty, a fine, and an excise or similar tax, including an excise tax assessed against the person with respect to an employee benefit plan; and (3) may not be made in relation to a proceeding in which the person has been found liable for: (A) willful or intentional misconduct in the performance of the person’s duty to the enterprise; (B) breach of the person’s duty of loyalty owed to the enterprise; or (C) an act or omission not committed in good faith that constitutes a breach of a duty owed by the person to the enterprise. (c) A governing person, former governing person, or delegate is considered to have been found liable in relation to a claim, issue, or matter only if the liability is established by an order, including a judgment or decree of a court, and all appeals of the order are exhausted or foreclosed by law.

Section 8.105(b) of the TBOC states that: An enterprise shall indemnify an officer to the same extent that indemnification is required under this chapter for a governing person.

Oklahoma Guarantors

Oilwell Fracturing Services, Inc., Hennessey Rental Tools, Inc. and Wildhorse Services, Inc. are incorporated under the laws of the State of Oklahoma. Section 1031 of the Oklahoma General Corporation Act authorizes a court to award, or a corporation’s board of directors to grant, indemnity under certain circumstances to directors, officers employees or agents in connection with actions, suits or proceedings, by reason of the fact that the person is or was a director, officer, employee or agent, against expenses and liabilities incurred in such actions, suits or proceedings so long as they acted in good faith and in a manner the person reasonable believed to be in, or not opposed to, the best interests of the company, and with respect to any criminal action if they had no reasonable cause to believe their conduct was unlawful. With respect to suits by or in the right of such corporation, however, indemnification is generally limited to attorneys’ fees and other expenses and is not available if such person is adjudged to be liable to such corporation unless the court determines that indemnification is appropriate.

Kansas Guarantor

Acid Services, LLC is organized under the laws of the State of Kansas.Section 17-7670 of the Kansas General Corporation Law provides that a limited liability company may indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever. Furthermore, if a member, manager, officer, employee or agent has been successful on the merits or otherwise or the defenses of any action, suits or proceeding, or in defense of any issue or matter therein, such person shall be indemnified against expenses actually and reasonably incurred in connection therewith, including attorney fees.

New Mexico Guarantor

Chaparral Service, Inc. is incorporated under the laws of the State of New Mexico. UnderSection 53-11-4.1 of New Mexico Business Corporation Act, a corporation shall have power to indemnify any person made a party to any proceeding by reason of the fact that the person is or was a director if: (i) the person acted in good faith; (ii) the person reasonably believed: (x) in the case of conduct in the person’s official capacity with the corporation, that the person’s conduct was in its best interests; and (y) in all other cases, that the person’s conduct was at least not opposed to its best interests; and (iii) in the case of any criminal proceeding, the person had no reasonable cause to believe the person’s conduct was unlawful. Indemnification may be made against judgments, penalties, fines, settlements and reasonable expenses, actually incurred by the person in connection with the proceeding; except that if the proceeding was by or in the right of the corporation, indemnification may be made only against such reasonable expenses and shall not be made in respect of any proceeding in which the person shall have been adjudged to be liable to the corporation. However, a director shall not be indemnified in respect of any proceeding charging improper personal benefit to the director, whether or not involving action in the director’s official capacity, in which the director shall have been adjudged to be liable on the basis that personal benefit was improperly received by the director. The indemnification authorized bySection 53-11-4.1 is not exclusive of any other rights to which an officer or director may be entitled under the articles of incorporation, the bylaws, an agreement, a resolution of shareholders or directors or otherwise.

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ITEM 21.   Exhibit and Financial Statement Schedules.

(a) Exhibits.

Exhibit
Number			Description
	1	.1	Purchase Agreement dated July 23, 2009, by and among Basic Energy Services, Inc., the guarantors party thereto and the initial purchasers party thereto. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K (SEC FileNo. 001-32693), filed on July 29, 2009)
	2	.1	Agreement and Plan of Merger, dated as of January 8, 2007, by and among Basic Energy Services, Inc. (the “Company”), JS Acquisition LLC and JetStar Consolidated Holdings, Inc. (Incorporated by reference to Exhibit 2.1 of the Company’s Current Report onForm 8-K (SEC FileNo. 001-32693), filed on March 8, 2007)
	2	.2	Amendment to Merger Agreement, dated as of March 5, 2007, by and among Basic Energy Services, Inc., JS Acquisition LLC and JetStar Consolidated Holdings, Inc. (Incorporated by reference to Exhibit 2.2 of the Company’s Current Report onForm 8-K (SEC FileNo. 001-32693), filed on March 8, 2007)
	3	.1	Amended and Restated Certificate of Incorporation of the Company, dated September 22, 2005. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement onForm S-1 (SEC FileNo. 333-127517), filed on September 28, 2005)
	3	.2	Amended and Restated Bylaws of the Company, effective as of December 17, 2007. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report onForm 8-K (SEC FileNo. 001-32693), filed on December 18, 2007)
	3	.3	Certificate of Formation of Basic Energy Services GP, LLC, dated as of January 7, 2003. (Incorporated by reference to Exhibit 3.3 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.4	Limited Liability Company Agreement of Basic Energy Services GP, LLC, dated as of January 7, 2003. (Incorporated by reference to Exhibit 3.4 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.5	Certificate of Formation of Basic Energy Services LP, LLC, dated as of January 7, 2003. (Incorporated by reference to Exhibit 3.5 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.6	Limited Liability Company Agreement of Basic Energy Services LP, LLC, dated as of January 7, 2003. (Incorporated by reference to Exhibit 3.6 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.7	Certificate of Limited Partnership of Basic Energy Services, L.P., dated as of January 24, 2003. (Incorporated by reference to Exhibit 3.7 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.8	Agreement of Limited Partnership of Basic Energy Services, L.P., dated as of January 24, 2003. (Incorporated by reference to Exhibit 3.8 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.9	Articles of Incorporation of Basic ESA, Inc., dated July 10, 1981. (Incorporated by reference to Exhibit 3.9 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.10*	Bylaws of Basic ESA, Inc., as amended.
	3	.11*	Certificate of Formation of JS Acquisition LLC, dated as of January 4, 2007.
	3	.12*	Limited Liability Company Agreement of JS Acquisition LLC.
	3	.13*	Amended and Restated Articles of Organization of Acid Services, LLC, filed April 24, 2006.
	3	.14*	Second Amended and Restated Operating Agreement of Acid Services, LLC.
	3	.15*	Second Amended and Restated Certificate of Incorporation of JetStar Holdings, Inc., dated April 24, 2006.
	3	.16*	Bylaws of JetStar Holdings, Inc.
	3	.17*	Articles of Incorporation of JetStar Energy Services, Inc., dated April 18, 2005.
	3	.18*	Bylaws of JetStar Energy Services, Inc.
	3	.19	Certificate of Incorporation of Basic Marine Services, Inc., as amended, dated January 28, 2005. (Incorporated by reference to Exhibit 3.15 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.20	Bylaws of Basic Marine Services, Inc. (Incorporated by reference to Exhibit 3.16 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)

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Exhibit
Number			Description
	3	.21	Amended and Restated Certificate of Incorporation of First Energy Services Company, dated October 24, 2003. (Incorporated by reference to Exhibit 3.17 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.22	Bylaws of First Energy Services Company. (Incorporated by reference to Exhibit 3.18 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.23	Articles of Incorporation of Oilwell Fracturing Services, Inc., dated November 20, 1981. (Incorporated by reference to Exhibit 3.19 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.24*	Bylaws of Oilwell Fracturing Services, Inc., as amended.
	3	.25	Articles of Incorporation of LeBus Oil Field Service Co., dated December 19, 1985. (Incorporated by reference to Exhibit 3.27 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.26	Bylaws of LeBus Oil Field Service Co. (Incorporated by reference to Exhibit 3.28 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.27	Articles of Incorporation of Globe Well Service, Inc., as amended, dated February 6, 1979. (Incorporated by reference to Exhibit 3.29 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.28	Bylaws of Globe Well Service, Inc. (Incorporated by reference to Exhibit 3.30 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.29	Articles of Organization of SCH Disposal, L.L.C., dated October 30, 1998. (Incorporated by reference to Exhibit 3.31 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.30	Regulations of SCH Disposal, L.L.C., dated as of November 2, 1998. (Incorporated by reference to Exhibit 3.32 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.31*	Articles of Incorporation of Sledge Drilling Corp., dated November 22, 2005.
	3	.32*	Bylaws of Sledge Drilling Corp.
	3	.33*	Certificate of Incorporation of Wildhorse Services, Inc., dated as of July 30, 2002.
	3	.34*	Bylaws of Wildhorse Services, Inc.
	3	.35*	Articles of Incorporation of Xterra Fishing & Rental Tools Co., as amended, dated June 1, 2000.
	3	.36*	Bylaws of Xterra Fishing & Rental Tools Co.
	3	.37*	Articles of Incorporation of Chaparral Service, Inc., dated July 18, 1969.
	3	.38*	Amended and Restated Bylaws of Chaparral Service, Inc.
	3	.39*	Certificate of Incorporation of Hennessey Rental Tools, Inc., dated September 29, 1993.
	3	.40*	Bylaws of Hennessey Rental Tools, Inc.
	3	.41*	Certificate of Formation of Permian Plaza, LLC, dated August 20, 2007.
	3	.42*	Company Agreement of Permian Plaza, LLC.
	4	.1	Specimen Stock Certificate representing common stock of the Company. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement onForm S-1 (SEC FileNo. 333-127517), filed on November 4, 2005)
	4	.2	Indenture dated April 12, 2006, among Basic Energy Services, Inc., the guarantors party thereto, and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report onForm 8-K (SEC FileNo. 001-32693), filed on April 13, 2006)
	4	.3	Form of 7.125% Senior Note due 2016. (Included in the Indenture filed as Exhibit 4.1 of the Company’s Current Report onForm 8-K (SEC FileNo. 001-32693), filed on April 13, 2006)
	4	.4	First Supplemental Indenture dated as of July 14, 2006 to Indenture dated as of April 12, 2006 among the Company, as Issuer, the Subsidiary Guarantors named therein and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report onForm 8-K (SEC FileNo. 001-32693), filed on July 20, 2006)
	4	.5	Second Supplemental Indenture dated as of April 26, 2007 and effective as of March 7, 2007 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report onForm 8-K (SEC FileNo. 001-32693), filed on May 1, 2007)

II-6

Exhibit
Number			Description
	4	.6	Third Supplement Indenture dated as of April 26, 2007 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report onForm 8-K (SEC FileNo. 001-32693), filed on May 1, 2007)
	4	.7	Fourth Supplemental Indenture dated as of February 9, 2009 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Mellon Trust Company, N.A., as Trustee. (Incorporated by reference to Exhibit 4.7 of the Company’s Annual Report onForm 10-K (SEC FileNo. 001-32693), filed March 9, 2009)
	4	.8	Indenture dated as of July 31, 2009, by and among Basic, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as Trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report onForm 8-K (SEC FileNo. 001-32693), filed on August 4, 2009)
	4	.9	Form of 11.625% Senior Secured Note due 2014 (included as Exhibit A to Exhibit 4.1 of the Company’s Current Report onForm 8-K (SEC FileNo. 001-32693), filed on August 4, 2009)
	4	.10	Security Agreement dated as of July 31, 2009, by and between Basic and each of the other Grantors party thereto in favor of The Bank of New York Mellon Trust Company, N.A., as Trustee. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on August 4, 2009)
	5	.1*	Opinion of Andrews Kurth LLP regarding the validity of the new notes
	8	.1*	Opinion of Andrews Kurth LLP regarding certain tax matters
	10	.1†	Form of Indemnification Agreement. (Incorporated by reference to Exhibit 10.1 of the Company’s Registration Statement onForm S-1 (SEC FileNo. 333-127517), filed on September 28, 2005)
	10	.2	Second Amended and Restated Stockholders’ Agreement dated as of April 2, 2004 among the Company and the stockholders listed therein. (Incorporated by reference to Exhibit 10.7 of the Company’s Registration Statement onForm S-1 (SEC FileNo. 333-127517), filed on August 12, 2005)
	10	.3	Stock Purchase Agreement dated as of September 18, 2003, as amended on October 1, 2003, among the Company, FESCO Holdings, Inc. and the sellers named therein. (Incorporated by reference to Exhibit 10.8 of the Company’s Registration Statement onForm S-1 (SEC FileNo. 333-127517), filed on August 12, 2005)
	10	.4	Asset Purchase Agreement dated as of August 14, 2003 among the Company and PWI, Inc. (Incorporated by reference to Exhibit 10.9 of the Company’s Registration Statement onForm S-1 (SEC FileNo. 333-127517), filed on August 12, 2005)
	10	.5	Fourth Amended and Restated Credit Agreement dated as of October 3, 2003, amended and restated as of February 6, 2007, among Basic Energy Services, Inc., the subsidiary guarantors party thereto, Bank of America, N.A., as syndication agent, Capital One, National Association, as documentation agent, BNP Paribas, as documentation agent, UBS AG, Stamford Branch, as issuing bank, administrative agent and collateral agent, and the lenders party thereto. (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report onForm 8-K (SEC FileNo. 001-32693), filed on February 12, 2007)
	10	.6	Amendment and Consent No. 1 to Fourth Amended and Restated Credit Agreement dated May 4, 2009. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K (SEC FileNo. 001-32693), filed on May 7, 2009)
	10	.7†	Fourth Amended and Restated Basic Energy Services, Inc. 2003 Incentive Plan. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K (SEC FileNo. 001-32693), filed on June 1, 2009)
	10	.8†	Form of Non-Qualified Option Grant Agreement (Executive Officer — Pre-March 1, 2005). (Incorporated by reference to Exhibit 10.12 of the Company’s Registration Statement onForm S-1 (SEC FileNo. 333-127517), filed on September 28, 2005)
	10	.9†	Form of Non-Qualified Option Grant Agreement (Executive Officer — Post-March 1, 2005). (Incorporated by reference to Exhibit 10.13 of the Company’s Registration Statement onForm S-1 (SEC FileNo. 333-127517), filed on September 28, 2005)
	10	.10†	Form of Non-Qualified Option Grant Agreement (Non-Employee Director — Pre-March 1, 2005). (Incorporated by reference to Exhibit 10.14 of the Company’s Registration Statement onForm S-1 (SEC FileNo. 333-127517), filed on September 28, 2005)
	10	.11†	Form of Non-Qualified Option Grant Agreement (Non-Employee Director — Post-March 1, 2005). (Incorporated by reference to Exhibit 10.15 of the Company’s Registration Statement onForm S-1 (SEC FileNo. 333-127517), filed on September 28, 2005)
	10	.12†	Form of Restricted Stock Grant Agreement. (Incorporated by reference to Exhibit 10.16 of the Company’s Registration Statement onForm S-1 (SEC FileNo. 333-127517), filed on September 28, 2005)

II-7

Exhibit
Number			Description
	10	.13†	Form of Amendment to Nonqualified Stock Option Agreement, dated as of December 31, 2005, by and between the Company and the optionees party thereto. (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report onForm 8-K (SEC FileNo. 001-32693), filed on January 4, 2006)
	10	.14†	Form of Nonqualified Stock Option Agreement (Director form effective March 2006). (Incorporated by reference to Exhibit 10.13 of the Company’s Annual Report onForm 10-K (SEC FileNo. 001-32693), filed on March 7, 2008)
	10	.15†	Form of Nonqualified Stock Option Agreement (Employee form effective March 2006). (Incorporated by reference to Exhibit 10.14 of the Company’s Annual Report onForm 10-K(SEC File No. 001-32693), filed on March 7, 2008)
	10	.16†	Form of Restricted Stock Grant Agreement (Officers and Employees — Post-March 1, 2007). (Incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report onForm 10-Q(SEC File No. 001-32693), filed on May 10, 2007)
	10	.17†	Form of Restricted Stock Grant Agreement (Non-Employee Directors — Post-March 1, 2007). (Incorporated by reference to Exhibit 10.6 to the Company’s Quarterly Report onForm 10-Q(SEC File No. 001-32693), filed on May 10, 2007)
	10	.18†	Form of Non-Qualified Stock Option Grant Agreement (Post-March 1, 2007). (Incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report onForm 10-Q(SEC File No. 001-32693), filed on May 10, 2007)
	10	.19†	Form of Performance-Based Award Agreement (Officers and Employees). (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on March 17,2008)
	10	.20†	Form of Restricted Stock Grant Agreement (Officers and Employees). (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report onForm 10-Q(SEC File No. 001-32693), filed on May 8, 2008)
	10	.21†	Form of Restricted Stock Grant Agreement (Non-Employee Directors). (Incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report onForm 10-Q(SEC File No. 001-32693), filed on May 8. 2008)
	10	.22†	Form of Performance-Based Award Agreement (effective March 2009) (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32963), filed March 19, 2009)
	10	.23	Workover Unit Package Contract and Acceptance Agreement, dated as of May 17, 2005, between Basic Energy Services, L.P. and Taylor Rigs, LLC. (Incorporated by reference to Exhibit 10.17 of the Company’s Registration Statement onForm S-1(SEC File No. 333-127517), filed on November 4, 2005)
	10	.24	Share Exchange Agreement, dated as of September 22, 2003, among BES Holding Co. and the Stockholders named therein. (Incorporated by reference to Exhibit 10.18 of the Company’s Registration Statement onForm S-1(SEC File No. 333-127517), filed on September 28, 2005)
	10	.25	Form of Share Tender and Repurchase Agreement. (Incorporated by reference to Exhibit 10.19 of the Company’s Registration Statement onForm S-1(SEC File No. 333-127517), filed on November 4, 2005)
	10	.26	Workover Unit Package Contract and Acceptance Agreement, dated as of November 10, 2005, between Basic Energy Services, L.P. and Taylor Rigs, LLC. (Incorporated by reference to Exhibit 10.20 of the Company’s Registration Statement onForm S-1(SEC File No. 333-127517), filed on November 16, 2005)
	10	.27	Asset Purchase Agreement dated as of February 21, 2006 among Basic Energy Services, LP, Basic Energy Services GP, LLC, G&L Tool, Ltd., DLH Management, LLC and LJH, Ltd. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on March 2, 2006)
	10	.28	Contingent Earn Out Agreement dated as of February 28, 2006 among Basic Energy Services, LP and G&L Tool, Ltd. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on March 2, 2006)
	10	.29	Fee Reimbursement Agreement, dated as of July 24, 2006, by and among the Company, Southwest Partners II, L.P., Southwest Partners, III, L.P. and Fortress Holdings, LLC. (Incorporated by reference to Exhibit 10.23 of the Company’s Registration Statement onForm S-1(SEC File No. 333-136019), filed on July 25, 2006)
	10	.30†	Employment Agreement of Kenneth V. Huseman, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on January 4, 2007)

II-8

Exhibit
Number			Description
	10	.31†	Employment Agreement of Alan Krenek, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on January 4, 2007)
	10	.32†	Amended and Restated Employment Agreement of Charles W. Swift, effective as of November 21, 2008. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on November 24, 2008)
	10	.33†	Employment Agreement of Dub William Harrison, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on January 4, 2007)
	10	.34†	Employment Agreement of James E. Tyner, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.5 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on January 4, 2007)
	10	.35†	Amended and Restated Employment Agreement of Thomas Monroe Patterson, effective as of November 21, 2008. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on November 24, 2008)
	10	.36†	Employment Agreement of Mark David Rankin, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.7 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on January 4, 2007)
	10	.37†	First Amendment to Employment Agreement of Kenneth V. Huseman, effective as of January 23, 2007. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on January 29, 2007)
	10	.38	Registration Rights Agreement, dated as of March 6, 2007, by and among Basic Energy Services, Inc. and the JetStar Stockholders’ Representative. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on March 8, 2007)
	10	.39	Registration Rights Agreement, dated as of April 2, 2007, by and among the Company and the Holders named therein. (Incorporated by reference to Exhibit 10.1 of the Company’s current Report onForm 8-K(SEC File No. 001-32693), filed on April 5, 2007)
	10	.40	Registration Rights Agreement dated as of July 31, 2009, by and among Basic, the Guarantors named therein and the initial purchasers party thereto. (Incorporated by reference to Exhibit 4.4 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on August 4, 2009)
	10	.41	Purchase Agreement, dated April 7, 2006, by and among Basic Energy Services, Inc. (the “Company”), UBS Securities LLC as representative for the Initial Purchasers listed therein, and the Subsidiary Guarantors party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K filed on April 13, 2006)
	12	.1*	Statement regarding computation of ratio of earnings to fixed charges
	21	.1*	Subsidiaries of the Company
	23	.1*	Consent of KPMG LLP
	23	.2*	Consent of Andrews Kurth LLP (included in Exhibit 5.1)
	24	.1*	Powers of Attorney (included on signature pages).
	25	.1*	Form T-1 Statement of Eligibility and Qualification under the Trust Indenture Act of 1939 of The Bank of New York Mellon Trust Company, N.A. to act as trustee under the Indenture
	99	.1*	Form of Letter of Transmittal
	99	.2*	Guidelines for Certification of Taxpayer Identification Number on SubstituteForm W-9
	99	.3*	Form of Notice of Guaranteed Delivery
	99	.4*	Form of Letter to Brokers
	99	.5*	Form of Letter to Clients

*	Indicates exhibits filed herewith.
†	Management contract or compensatory plan or arrangement.

(b) With the exception of Schedule II — Valuation and Qualifying Accounts, all other consolidated financial statement schedules have been omitted because they are not required, are not applicable, or the required information has been included elsewhere in thisForm S-4.

II-9

ITEM 22.   Undertakings.

(a) Each undersigned registrant hereby undertakes:

(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(i) To include any prospectus required by section 10(a)(3) of the Securities Act of 1933;

(ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement;

(iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement;

Provided, however,that paragraphs (a)(1)(i) and (a)(1)(ii) of this section do not apply if the registration statement is onForm S-8, and the information required to be included in a post-effective amendment by those paragraphs is contained in reports filed with or furnished to the Commission by the registrant pursuant to section 13 or section 15(d) of the Securities Exchange Act of 1934 that are incorporated by reference in the registration statement; and

Paragraphs (a)(1)(i), (a)(1)(ii) and (a)(1)(iii) of this section do not apply if the registration statement is onForm S-3 orForm F-3 and the information required to be included in a post-effective amendment by those paragraphs is contained in reports filed with or furnished to the Commission by the registrant pursuant to section 13 or section 15(d) of the Securities Exchange Act of 1934 that are incorporated by reference in the registration statement, or is contained in a form of prospectus filed pursuant to Rule 424(b) that is part of the registration statement.

(2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

(4) That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

(5) That, for the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities, in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used

II-10

to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(i) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

(ii) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

(iii) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

(iv) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

(6) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

(b) Each undersigned registrant hereby undertakes to respond to requests for information that is incorporated by reference into the prospectus pursuant to Items 4, 10(b), 11, or 13 of this Form, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.

(c) Each undersigned registrant hereby undertakes to supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

II-11

SIGNATURES

Pursuant to the requirements of the Securities Act, the registrant has duly caused this registration statement onForm S-4 to be signed on its behalf by the undersigned, thereunder duly authorized, in the City of Midland, State of Texas on September 2, 2009.

BASIC ENERGY SERVICES, INC.

By:  /s/  Kenneth V. Huseman

Name:     Kenneth V. Huseman

Title:  President and Chief Executive Officer

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned officers and directors of the Registrant hereby constitutes and appoints Alan Krenek and John Cody Bissett his true and lawful attorney-in-fact and agent, with full power of substitution, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file this registration statement under the Securities Act of 1933, as amended, and any or all amendments (including, without limitation, post-effective amendments), with all exhibits and any and all documents required to be filed with respect thereto, with the Securities and Exchange Commission or any regulatory authority, granting unto such attorney-in-fact and agent, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same, as fully to all intents and purposes as he himself might or could do, if personally present, hereby ratifying and confirming all that said attorney-in-fact and agent, or his substitute or substitutes, may lawfully do or cause to be done.

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/s/  Kenneth V. Huseman Kenneth V. Huseman	President, Chief Executive Officer and Director (Principal Executive Officer)	September 2, 2009
/s/  Alan Krenek Alan Krenek	Senior Vice President, Chief Financial Officer, Treasurer and Secretary (Principal Financial Officer and Principal Accounting Officer)	September 2, 2009
/s/  Steven A. Webster Steven A. Webster	Chairman of the Board	September 2, 2009
/s/  James S. D’Agostino, Jr. James S. D’Agostino, Jr.	Director	September 2, 2009
/s/  William E. Chiles William E. Chiles	Director	September 2, 2009
/s/  Robert F. Fulton Robert F. Fulton	Director	September 2, 2009

II-12

Signature	Title	Date
/s/  Sylvester P. Johnson, IV Sylvester P. Johnson, IV	Director	September 2, 2009
/s/  Thomas P. Moore, Jr. Thomas P. Moore, Jr.	Director	September 2, 2009
/s/  Antonio O. Garza, Jr. Antonio O. Garza, Jr.	Director	September 2, 2009

II-13

SIGNATURES

Pursuant to the requirements of the Securities Act, the registrant has duly caused this registration statement onForm S-4 to be signed on its behalf by the undersigned, thereunder duly authorized, in the City of Midland, State of Texas on September 2, 2009.

Each of the Guarantors Named on

Schedule A-1 Hereto (the “Guarantors”)

By:  /s/  Kenneth V. Huseman

Name:     Kenneth V. Huseman

Title:  President

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned officers and directors of the Registrant hereby constitutes and appoints Alan Krenek and John Cody Bissett his true and lawful attorney-in-fact and agent, with full power of substitution, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file this registration statement under the Securities Act of 1933, as amended, and any or all amendments (including, without limitation, post-effective amendments), with all exhibits and any and all documents required to be filed with respect thereto, with the Securities and Exchange Commission or any regulatory authority, granting unto such attorney-in-fact and agent, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same, as fully to all intents and purposes as he himself might or could do, if personally present, hereby ratifying and confirming all that said attorney-in-fact and agent, or his substitute or substitutes, may lawfully do or cause to be done.

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/s/  Kenneth V. Huseman Kenneth V. Huseman	President and Director (Principal Executive Officer)	September 2, 2009
/s/  Alan Krenek Alan Krenek	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)	September 2, 2009

II-14

Schedule A-1

GUARANTORS

Basic Energy Services GP, LLC

Basic Energy Services, L.P.

Basic ESA, Inc.

Chaparral Service, Inc.

Basic Marine Services, Inc.

First Energy Services Company

Hennessey Rental Tools, Inc.

Oilwell Fracturing Services, Inc.

Wildhorse Services, Inc.

LeBus Oil Field Service Co.

Globe Well Service, Inc.

SCH Disposal, L.L.C.

JS Acquisition LLC

JetStar Holdings, Inc.

Acid Services, LLC

JetStar Energy Services, Inc.

Sledge Drilling Corp.

Permian Plaza, LLC

Xterra Fishing & Rental Tools Co.

II-15

SIGNATURES

Pursuant to the requirements of the Securities Act, the registrant has duly caused this registration statement onForm S-4 to be signed on its behalf by the undersigned, thereunder duly authorized, in the City of Midland, State of Texas on September 2, 2009.

BASIC ENERGY SERVICES LP, LLC

By:  /s/  Jerry Tufly

Name:     Jerry Tufly

Title:  President

Signature	Title	Date
/s/  Jerry Tufly Jerry Tufly	President, Secretary, Treasurer and Sole Manager (Principal Executive Officer, Principal Financial Officer and Principal Accounting Officer)	September 2, 2009

II-16

EXHIBIT INDEX

Exhibit
Number			Description
	1	.1	Purchase Agreement dated July 23, 2009, by and among Basic Energy Services, Inc., the guarantors party thereto and the initial purchasers party thereto. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on July 29, 2009)
	2	.1	Agreement and Plan of Merger, dated as of January 8, 2007, by and among Basic Energy Services, Inc. (the “Company”), JS Acquisition LLC and JetStar Consolidated Holdings, Inc. (Incorporated by reference to Exhibit 2.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on March 8, 2007)
	2	.2	Amendment to Merger Agreement, dated as of March 5, 2007, by and among Basic Energy Services, Inc., JS Acquisition LLC and JetStar Consolidated Holdings, Inc. (Incorporated by reference to Exhibit 2.2 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on March 8, 2007)
	3	.1	Amended and Restated Certificate of Incorporation of the Company, dated September 22, 2005. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement onForm S-1(SEC File No. 333-127517), filed on September 28, 2005)
	3	.2	Amended and Restated Bylaws of the Company, effective as of December 17, 2007. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on December 18, 2007)
	3	.3	Certificate of Formation of Basic Energy Services GP, LLC, dated as of January 7, 2003. (Incorporated by reference to Exhibit 3.3 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.4	Limited Liability Company Agreement of Basic Energy Services GP, LLC, dated as of January 7, 2003. (Incorporated by reference to Exhibit 3.4 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.5	Certificate of Formation of Basic Energy Services LP, LLC, dated as of January 7, 2003. (Incorporated by reference to Exhibit 3.5 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.6	Limited Liability Company Agreement of Basic Energy Services LP, LLC, dated as of January 7, 2003. (Incorporated by reference to Exhibit 3.6 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.7	Certificate of Limited Partnership of Basic Energy Services, L.P., dated as of January 24, 2003. (Incorporated by reference to Exhibit 3.7 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.8	Agreement of Limited Partnership of Basic Energy Services, L.P., dated as of January 24, 2003. (Incorporated by reference to Exhibit 3.8 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.9	Articles of Incorporation of Basic ESA, Inc., dated July 10, 1981. (Incorporated by reference to Exhibit 3.9 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.10*	Bylaws of Basic ESA, Inc., as amended.
	3	.11*	Certificate of Formation of JS Acquisition LLC, dated as of January 4, 2007.
	3	.12*	Limited Liability Company Agreement of JS Acquisition LLC.
	3	.13*	Amended and Restated Articles of Organization of Acid Services, LLC, filed April 24, 2006.
	3	.14*	Second Amended and Restated Operating Agreement of Acid Services, LLC.
	3	.15*	Second Amended and Restated Certificate of Incorporation of JetStar Holdings, Inc., dated April 24, 2006.
	3	.16*	Bylaws of JetStar Holdings, Inc.
	3	.17*	Articles of Incorporation of JetStar Energy Services, Inc., dated April 18, 2005.
	3	.18*	Bylaws of JetStar Energy Services, Inc.
	3	.19	Certificate of Incorporation of Basic Marine Services, Inc., as amended, dated January 28, 2005. (Incorporated by reference to Exhibit 3.15 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.20	Bylaws of Basic Marine Services, Inc. (Incorporated by reference to Exhibit 3.16 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.21	Amended and Restated Certificate of Incorporation of First Energy Services Company, dated October 24, 2003. (Incorporated by reference to Exhibit 3.17 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.22	Bylaws of First Energy Services Company. (Incorporated by reference to Exhibit 3.18 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)

Exhibit
Number			Description
	3	.23	Articles of Incorporation of Oilwell Fracturing Services, Inc., dated November 20, 1981. (Incorporated by reference to Exhibit 3.19 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.24*	Bylaws of Oilwell Fracturing Services, Inc., as amended.
	3	.25	Articles of Incorporation of LeBus Oil Field Service Co., dated December 19, 1985. (Incorporated by reference to Exhibit 3.27 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.26	Bylaws of LeBus Oil Field Service Co. (Incorporated by reference to Exhibit 3.28 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.27	Articles of Incorporation of Globe Well Service, Inc., as amended, dated February 6, 1979. (Incorporated by reference to Exhibit 3.29 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.28	Bylaws of Globe Well Service, Inc. (Incorporated by reference to Exhibit 3.30 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.29	Articles of Organization of SCH Disposal, L.L.C., dated October 30, 1998. (Incorporated by reference to Exhibit 3.31 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.30	Regulations of SCH Disposal, L.L.C., dated as of November 2, 1998. (Incorporated by reference to Exhibit 3.32 of the Company’s Registration Statement onForm S-4 (SEC FileNo. 333-135807), filed on July 17, 2006)
	3	.31*	Articles of Incorporation of Sledge Drilling Corp., dated November 22, 2005.
	3	.32*	Bylaws of Sledge Drilling Corp.
	3	.33*	Certificate of Incorporation of Wildhorse Services, Inc., dated as of July 30, 2002.
	3	.34*	Bylaws of Wildhorse Services, Inc.
	3	.35*	Articles of Incorporation of Xterra Fishing & Rental Tools Co., as amended, dated June 1, 2000.
	3	.36*	Bylaws of Xterra Fishing & Rental Tools Co.
	3	.37*	Articles of Incorporation of Chaparral Service, Inc., dated July 18, 1969.
	3	.38*	Amended and Restated Bylaws of Chaparral Service, Inc.
	3	.39*	Certificate of Incorporation of Hennessey Rental Tools, Inc., dated September 29, 1993.
	3	.40*	Bylaws of Hennessey Rental Tools, Inc.
	3	.41*	Certificate of Formation of Permian Plaza, LLC, dated August 20, 2007.
	3	.42*	Company Agreement of Permian Plaza, LLC.
	4	.1	Specimen Stock Certificate representing common stock of the Company. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement onForm S-1(SEC File No. 333-127517), filed on November 4, 2005)
	4	.2	Indenture dated April 12, 2006, among Basic Energy Services, Inc., the guarantors party thereto, and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on April 13, 2006)
	4	.3	Form of 7.125% Senior Note due 2016. (Included in the Indenture filed as Exhibit 4.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on April 13, 2006)
	4	.4	First Supplemental Indenture dated as of July 14, 2006 to Indenture dated as of April 12, 2006 among the Company, as Issuer, the Subsidiary Guarantors named therein and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on July 20, 2006)
	4	.5	Second Supplemental Indenture dated as of April 26, 2007 and effective as of March 7, 2007 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on May 1, 2007)
	4	.6	Third Supplement Indenture dated as of April 26, 2007 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on May 1, 2007)
	4	.7	Fourth Supplemental Indenture dated as of February 9, 2009 to Indenture dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Mellon Trust Company, N.A., as Trustee. (Incorporated by reference to Exhibit 4.7 of the Company’s Annual Report onForm 10-K(SEC File No. 001-32693), filed March 9, 2009)

Exhibit
Number			Description
	4	.8	Indenture dated as of July 31, 2009, by and among Basic, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as Trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on August 4, 2009)
	4	.9	Form of 11.625% Senior Secured Note due 2014 (included as Exhibit A to Exhibit 4.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on August 4, 2009)
	4	.10	Security Agreement dated as of July 31, 2009, by and between Basic and each of the other Grantors party thereto in favor of The Bank of New York Mellon Trust Company, N.A., as Trustee. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on August 4, 2009)
	5	.1*	Opinion of Andrews Kurth LLP regarding the validity of the new notes
	8	.1*	Opinion of Andrews Kurth LLP regarding certain tax matters
	10	.1†	Form of Indemnification Agreement. (Incorporated by reference to Exhibit 10.1 of the Company’s Registration Statement onForm S-1(SEC File No. 333-127517), filed on September 28, 2005)
	10	.2	Second Amended and Restated Stockholders’ Agreement dated as of April 2, 2004 among the Company and the stockholders listed therein. (Incorporated by reference to Exhibit 10.7 of the Company’s Registration Statement onForm S-1(SEC File No. 333-127517), filed on August 12, 2005)
	10	.3	Stock Purchase Agreement dated as of September 18, 2003, as amended on October 1, 2003, among the Company, FESCO Holdings, Inc. and the sellers named therein. (Incorporated by reference to Exhibit 10.8 of the Company’s Registration Statement onForm S-1(SEC File No. 333-127517), filed on August 12, 2005)
	10	.4	Asset Purchase Agreement dated as of August 14, 2003 among the Company and PWI, Inc. (Incorporated by reference to Exhibit 10.9 of the Company’s Registration Statement onForm S-1(SEC File No. 333-127517), filed on August 12, 2005)
	10	.5	Fourth Amended and Restated Credit Agreement dated as of October 3, 2003, amended and restated as of February 6, 2007, among Basic Energy Services, Inc., the subsidiary guarantors party thereto, Bank of America, N.A., as syndication agent, Capital One, National Association, as documentation agent, BNP Paribas, as documentation agent, UBS AG, Stamford Branch, as issuing bank, administrative agent and collateral agent, and the lenders party thereto. (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on February 12, 2007)
	10	.6	Amendment and Consent No. 1 to Fourth Amended and Restated Credit Agreement dated May 4, 2009. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on May 7, 2009)
	10	.7†	Fourth Amended and Restated Basic Energy Services, Inc. 2003 Incentive Plan. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on June 1, 2009)
	10	.8†	Form of Non-Qualified Option Grant Agreement (Executive Officer — Pre-March 1, 2005). (Incorporated by reference to Exhibit 10.12 of the Company’s Registration Statement onForm S-1(SEC File No. 333-127517), filed on September 28, 2005)
	10	.9†	Form of Non-Qualified Option Grant Agreement (Executive Officer — Post-March 1, 2005). (Incorporated by reference to Exhibit 10.13 of the Company’s Registration Statement onForm S-1(SEC File No. 333-127517), filed on September 28, 2005)
	10	.10†	Form of Non-Qualified Option Grant Agreement (Non-Employee Director — Pre-March 1, 2005). (Incorporated by reference to Exhibit 10.14 of the Company’s Registration Statement onForm S-1(SEC File No. 333-127517), filed on September 28, 2005)
	10	.11†	Form of Non-Qualified Option Grant Agreement (Non-Employee Director — Post-March 1, 2005). (Incorporated by reference to Exhibit 10.15 of the Company’s Registration Statement onForm S-1(SEC File No. 333-127517), filed on September 28, 2005)
	10	.12†	Form of Restricted Stock Grant Agreement. (Incorporated by reference to Exhibit 10.16 of the Company’s Registration Statement onForm S-1(SEC File No. 333-127517), filed on September 28, 2005)
	10	.13†	Form of Amendment to Nonqualified Stock Option Agreement, dated as of December 31, 2005, by and between the Company and the optionees party thereto. (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on January 4, 2006)
	10	.14†	Form of Nonqualified Stock Option Agreement (Director form effective March 2006). (Incorporated by reference to Exhibit 10.13 of the Company’s Annual Report onForm 10-K(SEC File No. 001-32693), filed on March 7, 2008)
	10	.15†	Form of Nonqualified Stock Option Agreement (Employee form effective March 2006). (Incorporated by reference to Exhibit 10.14 of the Company’s Annual Report onForm 10-K(SEC File No. 001-32693), filed on March 7, 2008)

Exhibit
Number			Description
	10	.16†	Form of Restricted Stock Grant Agreement (Officers and Employees — Post-March 1, 2007). (Incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report onForm 10-Q(SEC File No. 001-32693), filed on May 10, 2007)
	10	.17†	Form of Restricted Stock Grant Agreement (Non-Employee Directors — Post-March 1, 2007). (Incorporated by reference to Exhibit 10.6 to the Company’s Quarterly Report onForm 10-Q(SEC File No. 001-32693), filed on May 10, 2007)
	10	.18†	Form of Non-Qualified Stock Option Grant Agreement (Post-March 1, 2007). (Incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report onForm 10-Q(SEC File No. 001-32693), filed on May 10, 2007)
	10	.19†	Form of Performance-Based Award Agreement (Officers and Employees). (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on March 17,2008)
	10	.20†	Form of Restricted Stock Grant Agreement (Officers and Employees). (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report onForm 10-Q(SEC File No. 001-32693), filed on May 8, 2008)
	10	.21†	Form of Restricted Stock Grant Agreement (Non-Employee Directors). (Incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report onForm 10-Q(SEC File No. 001-32693), filed on May 8. 2008)
	10	.22†	Form of Performance-Based Award Agreement (effective March 2009) (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32963), filed March 19, 2009)
	10	.23	Workover Unit Package Contract and Acceptance Agreement, dated as of May 17, 2005, between Basic Energy Services, L.P. and Taylor Rigs, LLC. (Incorporated by reference to Exhibit 10.17 of the Company’s Registration Statement onForm S-1(SEC File No. 333-127517), filed on November 4, 2005)
	10	.24	Share Exchange Agreement, dated as of September 22, 2003, among BES Holding Co. and the Stockholders named therein. (Incorporated by reference to Exhibit 10.18 of the Company’s Registration Statement onForm S-1(SEC File No. 333-127517), filed on September 28, 2005)
	10	.25	Form of Share Tender and Repurchase Agreement. (Incorporated by reference to Exhibit 10.19 of the Company’s Registration Statement onForm S-1(SEC File No. 333-127517), filed on November 4, 2005)
	10	.26	Workover Unit Package Contract and Acceptance Agreement, dated as of November 10, 2005, between Basic Energy Services, L.P. and Taylor Rigs, LLC. (Incorporated by reference to Exhibit 10.20 of the Company’s Registration Statement onForm S-1(SEC File No. 333-127517), filed on November 16, 2005)
	10	.27	Asset Purchase Agreement dated as of February 21, 2006 among Basic Energy Services, LP, Basic Energy Services GP, LLC, G&L Tool, Ltd., DLH Management, LLC and LJH, Ltd. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on March 2, 2006)
	10	.28	Contingent Earn Out Agreement dated as of February 28, 2006 among Basic Energy Services, LP and G&L Tool, Ltd. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on March 2, 2006)
	10	.29	Fee Reimbursement Agreement, dated as of July 24, 2006, by and among the Company, Southwest Partners II, L.P., Southwest Partners, III, L.P. and Fortress Holdings, LLC. (Incorporated by reference to Exhibit 10.23 of the Company’s Registration Statement onForm S-1(SEC File No. 333-136019), filed on July 25, 2006)
	10	.30†	Employment Agreement of Kenneth V. Huseman, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on January 4, 2007)
	10	.31†	Employment Agreement of Alan Krenek, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on January 4, 2007)
	10	.32†	Amended and Restated Employment Agreement of Charles W. Swift, effective as of November 21, 2008. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on November 24, 2008)
	10	.33†	Employment Agreement of Dub William Harrison, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on January 4, 2007)
	10	.34†	Employment Agreement of James E. Tyner, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.5 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on January 4, 2007)

Exhibit
Number			Description
	10	.35†	Amended and Restated Employment Agreement of Thomas Monroe Patterson, effective as of November 21, 2008. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on November 24, 2008)
	10	.36†	Employment Agreement of Mark David Rankin, effective as of December 31, 2006. (Incorporated by reference to Exhibit 10.7 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on January 4, 2007)
	10	.37†	First Amendment to Employment Agreement of Kenneth V. Huseman, effective as of January 23, 2007. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on January 29, 2007)
	10	.38	Registration Rights Agreement, dated as of March 6, 2007, by and among Basic Energy Services, Inc. and the JetStar Stockholders’ Representative. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on March 8, 2007)
	10	.39	Registration Rights Agreement, dated as of April 2, 2007, by and among the Company and the Holders named therein. (Incorporated by reference to Exhibit 10.1 of the Company’s current Report onForm 8-K(SEC File No. 001-32693), filed on April 5, 2007)
	10	.40	Registration Rights Agreement dated as of July 31, 2009, by and among Basic, the Guarantors named therein and the initial purchasers party thereto. (Incorporated by reference to Exhibit 4.4 of the Company’s Current Report onForm 8-K(SEC File No. 001-32693), filed on August 4, 2009)
	10	.41	Purchase Agreement, dated April 7, 2006, by and among Basic Energy Services, Inc. (the “Company”), UBS Securities LLC as representative for the Initial Purchasers listed therein, and the Subsidiary Guarantors party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report onForm 8-K filed on April 13, 2006)
	12	.1*	Statement regarding computation of ratio of earnings to fixed charges
	21	.1*	Subsidiaries of the Company
	23	.1*	Consent of KPMG LLP
	23	.2*	Consent of Andrews Kurth LLP (included in Exhibit 5.1)
	24	.1*	Powers of Attorney (included on signature pages).
	25	.1*	Form T-1 Statement of Eligibility and Qualification under the Trust Indenture Act of 1939 of The Bank of New York Mellon Trust Company, N.A. to act as trustee under the Indenture
	99	.1*	Form of Letter of Transmittal
	99	.2*	Guidelines for Certification of Taxpayer Identification Number on SubstituteForm W-9
	99	.3*	Form of Notice of Guaranteed Delivery
	99	.4*	Form of Letter to Brokers
	99	.5*	Form of Letter to Clients

*	Indicates exhibits filed herewith.
†	Management contract or compensatory plan or arrangement