Edgar Filing: BASIC ENERGY SERVICES INC

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As filed with the Securities and Exchange Commission on August 3, 2006

Registration No. 333-136019

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 1

Form S-1

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.)

400 W. Illinois, Suite 800

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

400 W. Illinois, Suite 800

Midland, Texas 79701

(432) 620-5500

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copy to:

Andrews Kurth LLP

600 Travis, Suite 4200

Houston, Texas 77002

(713) 220-4200

Attn: David C. Buck

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, please 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, please 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(c) 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

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.

The information in this prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell nor does it seek an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion dated August 3, 2006

2,101,641 Shares

Basic Energy Services, Inc.

Common Stock

Basic Energy Services, Inc. is registering 2,101,641 shares of common stock which will be distributed by Fortress Holdings, LLC to its members and by Southwest Partners II, L.P. and Southwest Partners III, L.P. to their partners. We will not receive any of the proceeds from the shares of common stock distributed by the distributing stockholders.

Our common stock is listed on The New York Stock Exchange under the symbol “BAS.” The last reported sales price of our common stock on August 2, 2006 was $27.62 per share.

See “Risk Factors” beginning on page 11 to read about factors you should consider before buying our common stock.

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

Prospectus dated , 2006

1. Well Servicing Rig Preparing to Begin Work

2. Fluid Services Transport Truck

3. 24 Hour Workover Rig

4. Well Site Construction Equipment

5. Saltwater Disposal Facility

6. Frac Tank Utilized for Storage of Fluids

7. Trailer-Mounted Pressure Pumping Equipment

8. Coiled Tubing Unit Used in Pressure Pumping

9. Inland Barge Workover Rig

10. Trailer-Mounted Foam Circulating Unit Used in Underbalanced Workover Operations

TABLE OF CONTENTS


	Page

Prospectus Summary		1
Risk Factors		11
Forward-Looking Statements and Industry Data		20
Plan of Distribution		21
Use of Proceeds		23
Price Range of Common Stock and Dividend Policy		23
Capitalization		24
Selected Historical Financial Data		25
Management’s Discussion and Analysis of Financial Condition and Results of Operations		28
Business		54
Management		72
Certain Relationships and Related Party Transactions		85
Principal Stockholders		87
Distributing Stockholders		91
Description of Capital Stock		92
Shares Eligible for Future Sale		96
Legal Matters		97
Experts		97
Where You Can Find More Information		97
Index to Financial Statements		F-1
Appendix A — Glossary of Terms		A-1
Consent of KPMG LLP

You should rely only on the information contained in this prospectus or to which we have referred you. We have not authorized anyone to provide you with information that is different from what we have provided to you. This document may only be used where it is legal to sell these securities. The information in this document may only be accurate on the date of this document.

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. The term “distributing stockholders” refers collectively to Fortress Holdings, LLC, Southwest Partners II, L.P. and Southwest Partners III, L.P.

-i-

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 investing in our common stock. If you are not familiar with some of the oil and gas industry terms used in this prospectus, please read our Glossary of Terms included as Appendix A to this prospectus.

Our Company

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

We derive a majority of our revenues from services supporting production from existing oil and gas operations. Demand for these production-related services, including well servicing and fluid services, tends to remain relatively stable in moderate oil and gas price environments, as ongoing maintenance spending is required to sustain production. As oil and gas prices reach higher levels, demand for all of our services generally increases as our customers increase spending for drilling new wells and well servicing activities related to maintaining or increasing production from existing wells. The utilization rate for our fleet of well servicing rigs increased from approximately 71% in 2003 to 78% in 2004, 87% in 2005, and 89% in the first quarter of 2006. Because our services are required to support drilling and workover activities, we are also subject to changes in capital spending by our customers as oil and gas prices increase or decrease.

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


	•	*Well Servicing.* Our well servicing segment (48% of our revenues in 2005 and 47% of our revenues in the first quarter of 2006) currently operates our fleet of over 330 well servicing rigs and related equipment. This business segment encompasses a full range of services performed with a mobile well servicing rig, including the installation and removal of downhole equipment and elimination of obstructions in the well bore to facilitate the flow of oil and gas. These services are performed to establish, maintain and improve production throughout the productive life of an oil and gas well and to plug and abandon a well at the end of its productive life. Our well servicing equipment and capabilities are essential to facilitate most other services performed on a well.

	•	*Fluid Services.* Our fluid services segment (29% of our revenues in 2005 and 28% of our revenues in the first quarter of 2006) currently utilizes our fleet of over 550 fluid services trucks and related assets, including specialized tank trucks, storage tanks, water wells, disposal facilities and related equipment. These assets provide, transport, store and


		dispose of a variety of fluids. These services are required in most workover, drilling and completion projects and are routinely used in daily producing well operations.

	•	*Drilling and Completion Services.* Our drilling and completion services segment (13% of our revenues in 2005 and 18% of our revenues in the first quarter of 2006) currently operates our fleet of 70 pressure pumping units, 29 air compressor packages specially configured for underbalanced drilling operations and 10 cased-hole wireline units. These services are designed to initiate or stimulate oil and gas production. The largest portion of this business consists of pressure pumping services focused on cementing, acidizing and fracturing services in niche markets. We also entered the fishing and rental tool business through an acquisition in the first quarter of 2006.

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

Our industry historically has consisted of a large number of small companies, several regional contractors and a few large national companies. Over the last decade, our industry has consolidated, including the consolidation of the well servicing segment of our industry, from nine large competitors (with 50 or more well servicing rigs) to four. However, the industry still remains fragmented with an estimated 120 companies owning approximately 900 remaining well servicing rigs, or approximately 26% of the industry’s total fleet. We have led recent consolidation of this industry by acquiring regional businesses and assets in 40 separate acquisitions from the beginning of 2001 through March 31, 2006. We plan to continue participating in the consolidation of our industry by selectively acquiring additional businesses and assets that complement and expand our existing service offerings and geographic footprint and offer attractive projected rates of return on capital employed. However, we cannot assure you that we can complete such acquisitions.

General Industry Overview

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


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

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


		purchasers typically intensify drilling, workover and well maintenance activities to accelerate production from the newly acquired reserves.

Increased expenditures for exploration and production activities generally involve the deployment of more drilling and well servicing rigs, which often serves as an indicator of demand for our services. Rising oil and gas prices since early 1999 and the corresponding increase in onshore oil exploration and production spending have led to expanded drilling and well service activity, as the U.S. land-based drilling rig count increased approximately 36% from year-end 2002 to year-end 2003, 11% from year-end 2003 to year-end 2004, 22% from year-end 2004 to year-end 2005 and 7% during the first quarter of 2006, according to Baker Hughes. In addition, the U.S. land-based workover rig count increased approximately 13% from year-end 2002 to year-end 2003, 10% from year-end 2003 to year-end 2004, 17% from year-end 2004 to year-end 2005 and 3% during the first quarter of 2006, according to Baker Hughes.

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

Competitive Strengths

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


	•	*Significant Market Position.* We maintain a significant market share for our well servicing operations in our core operating areas throughout Texas and a growing market share in the other markets that we serve. Our fleet of over 330 well servicing rigs represents the third-largest fleet in the United States, and our goal is to be one of the top two providers of well site services in each of our core operating areas. Our market position allows us to expand the range of services performed on a well throughout its life, such as completion, maintenance, workover and plugging and abandonment services.

	•	*Modern and Active Fleet.* We operate a modern and active fleet of well servicing rigs. We believe over 95% of the active US well servicing rig fleet was built prior to 1985. Approximately 98, or 30%, of our rigs at March 31, 2006 were either 2000 model year or newer, or have undergone major refurbishments during the last four years. Since October 2004, we have taken delivery of 45 newbuild well servicing rigs through March 31, 2006 as part of a 102-rig newbuild commitment, driven by our desire to maintain one of the most efficient, reliable and safest fleets in the industry. The remainder of these newbuilds is scheduled to be delivered to us prior to the end of December 2007. Approximately 98% of our fleet was active or available for work and the remainder was awaiting refurbishment at March 31, 2006. Since 2003, we have obtained annual independent reviews and evaluations of substantially all of our assets, which confirmed the location and condition of these assets.

	•	*Extensive Domestic Footprint in the Most Prolific Basins.* Our operations are concentrated in the major United States onshore oil and gas producing regions in Texas, New Mexico, Oklahoma and Louisiana and the Rocky Mountain states. We operate in states that accounted for approximately 57% of the approximately 900,000 existing onshore oil and gas wells in the 48 contiguous states and approximately 77% of onshore oil production and 72% of onshore gas production in 2005. We believe that our operations are located in the most active U.S. well services markets, as we currently focus our operations on onshore domestic oil and gas production areas that include both the highest concentration of existing oil and gas production activities and the largest


		prospective acreage for new drilling activity. This extensive footprint allows us to offer our suite of services to more than 1,000 customers who are active in those areas and allows us to redeploy equipment between markets as activity shifts.

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

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

Our Business Strategy

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


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

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

	•	*Develop Additional Service Offerings Within the Well Servicing Market.* We intend to continue broadening the portfolio of services we provide to our clients by leveraging our well servicing infrastructure. Our rigs are often the first equipment to arrive at the well site and typically the last to leave, providing us the opportunity to offer our customers other complementary services. We believe the fragmented nature of the well servicing market


		creates an opportunity to sell more services to our core customers and to expand our total service offering within each of our markets. We have expanded our suite of services available to our customers and increased our opportunities to cross-sell new services to our core well servicing customers through recent acquisitions and internal growth. We expect to continue to develop or selectively acquire capabilities to provide additional services to expand and further strengthen our customer relationships.

	•	*Pursue Growth Through Selective Capital Deployment.* We intend to continue growing our business through selective acquisitions, continuing a newbuild program and/or upgrading our existing assets. Our capital investment decisions are determined by an analysis of the projected return on capital employed of each of those alternatives, which is substantially driven by the cost to acquire existing assets from a third party, the capital required to build new equipment and the point in the oil and gas commodity price cycle. Based on these factors, we make capital investment decisions that we believe will support our long-term growth strategy.

Our strategies could be affected by any of the risk factors described in “Risk Factors” beginning on page 11.

How You Can Contact Us

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

Recent Developments

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

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

In April 2006, we completed a private offering for $225 million aggregate principal amount of 7.125% Senior Notes due April 15, 2016. The Senior Notes are jointly and severally guaranteed by each of our subsidiaries. The net proceeds from the offering were used to retire the outstanding Term B Loan balance and to pay down the revolving balance under our 2005 Credit Facility. Remaining proceeds will be used for general corporate purposes, including acquisitions. For a description of our 2005 Credit Facility, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facilities.”

The Distribution

The 2,101,641 shares of our common stock are being registered to permit a one-time distribution of controlled securities to the partners of Southwest Partners II, L.P. and Southwest Partners III, L.P. and to the members of Fortress Holdings, LLC. Neither we, nor the distributing stockholders will receive any proceeds from this transaction.

The partners and members of the distributing stockholders who will receive shares of our common stock in this registered offering may sell the shares of common stock directly to purchasers or through underwriters, broker-dealers or agents under Section 4(1) of the Securities Act, except to the extent any such partner or member is deemed to be our “affiliate” under Rule 144 of the Securities Act. After receiving shares of our common stock in this offering, the partners and members of the distributing stockholders, to the extent not deemed to be our “affiliate” under Rule 144 of the Securities Act, will act independently of us, and the distributing stockholders, in making decisions regarding the timing, manner and size of each sale of our common stock.

We are not aware of any plans, arrangements or understandings between the partners or members of the distributing stockholders and any underwriter, broker-dealer or agent regarding the sale of the shares of common stock and we do not assure you that the partners or members of the distributing stockholders will sell any or all of the registered shares of common stock following distribution. In addition, we do not assure you that the partners or members will not transfer, devise or gift the shares of common stock by other means not described in this prospectus. Moreover, any securities covered by this prospectus that qualify for sale pursuant to Rule 144 of the Securities Act may be sold under Rule 144 rather than pursuant to this prospectus.

H.H. Wommack, III, one of our directors and an affiliate of the distributing stockholders, will receive shares of common stock in connection with the distributions.

We will not receive any of the net proceeds from the distribution of shares of our common stock by the distributing stockholders. See “Use of Proceeds” and “Plan of Distribution.”

See “Risk Factors” beginning on page 11 of this prospectus for a discussion of factors that you should carefully consider before deciding to invest in shares of our common stock.

Summary Historical Financial Information

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


												Three Months
												Ended
			Year Ended December 31,									March 31,

			2003			2004			2005			2005			2006

												(unaudited)
			(dollars in thousands, except per share data)
Statement of Operations Data:
Revenues:
	Well servicing		$	104,097		$	142,551		$	221,993		$	44,798		$	73,465
	Fluid services			52,810			98,683			132,280			29,303			43,121
	Drilling and completion services			14,808			29,341			59,832			10,764			27,455
	Well site construction services			9,184			40,927			45,647			8,948			10,265

		Total revenues		180,899			311,502			459,752			93,813			154,306

Expenses:
	Well servicing			73,244			98,058			137,392			28,191			41,610
	Fluid services			34,420			65,167			82,551			19,238			26,305
	Drilling and completion services			9,363			17,481			30,900			5,860			13,854
	Well site construction services			6,586			31,454			32,000			7,108			7,643
	General and administrative(1)			22,722			37,186			55,411			13,091			18,005
	Depreciation and amortization			18,213			28,676			37,072			8,047			12,837
	Loss (gain) on disposal of assets			391			2,616			(222	)		102			(200	)

		Total expenses		164,939			280,638			375,104			81,637			120,054

		Operating income		15,960			30,864			84,648			12,176			34,252
Other income (expense):
	Net interest expense			(5,174	)		(9,550	)		(12,660	)		(2,960	)		(2,779	)
	Loss on early extinguishment of debt			(5,197	)		—			(627	)		—			—
	Other income (expense)			146			(398	)		220			75			27

	Income from continuing operations before income taxes			5,735			20,916			71,581			9,291			31,500
	Income tax expense			(2,772	)		(7,984	)		(26,800	)		(3,490	)		(11,819	)

	Income from continuing operations			2,963			12,932			44,781			5,801			19,681
	Discontinued operations, net of tax			22			(71	)		—			—			—
	Cumulative effect of accounting change, net of tax			(151	)		—			—			—			—

	Net income			2,834			12,861			44,781			5,801			19,681
	Preferred stock dividend			(1,525	)		—			—			—			—
	Accretion of preferred stock discount			(3,424	)		—			—			—			—

	Net income (loss) available to common stockholders		$	(2,115	)	$	12,861		$	44,781		$	5,801		$	19,681

	Net income (loss) per share of common stock:(2)
		Basic	$	(0.09	)	$	0.46		$	1.57		$	0.21		$	0.59
		Diluted	$	(0.09	)	$	0.42		$	1.35		$	0.18		$	0.53


											Three Months
											Ended
		Year Ended December 31,									March 31,

		2003			2004			2005			2005			2006

											(unaudited)
		(dollars in thousands, except per share data)
Statement of Cash Flow Data:
Cash flows from operating activities		$	29,815		$	46,539		$	99,189		$	16,734		$	25,915
Cash flows from investing activities			(84,903	)		(73,587	)		(107,679	)		(19,946	)		(111,584	)
Cash flows from financing activities			79,859			21,498			21,188			(2,817	)		72,777
Capital expenditures:
	Acquisitions, net of cash acquired		61,885			19,284			25,378			3,909			87,520
	Property and equipment		23,501			55,674			83,095			16,083			24,812

Other Financial Data:
EBITDA(3)		$	28,993		$	59,071		$	121,313		$	20,298		$	47,116


	As of December 31,						As of
							March 31,
	2003		2004		2005		2006

							(unaudited)
	(dollars in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	25,697	$	20,147	$	32,845	$	19,953
Property and equipment, net		188,243		233,451		309,075		399,865
Total assets		302,653		367,601		496,957		616,787
Total long-term debt, including current portion		148,509		182,476		126,887		210,047
Total stockholders’ equity		107,295		121,786		258,575		278,241


(1)	Includes approximately $994,000, $1,587,000 and $2,890,000 of non-cash stock-based compensation expense for the years ended December 31, 2003, 2004 and 2005, respectively, and $591,000 and $758,000 for the three months ended March 31, 2005 and 2006, respectively.

(2)	Reflects a 5-for-1 stock split effected as a stock dividend in September 2005.

(3)	EBITDA means earnings before interest, taxes, depreciation and amortization. EBITDA is used as a supplemental financial measure by our management and directors and by external users of our financial statements, such as investors, to assess:


	•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

	•	the ability of our assets to generate cash sufficient to pay interest on our indebtedness; and

	•	our operating performance and return on invested capital as compared to those of other companies in the well services industry, without regard to financing methods and capital structure.

EBITDA has limitations as an analytical tool and should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with generally accepted accounting principles (GAAP). EBITDA excludes some, but not all, items that affect net income and operating income, and these measures may vary among other companies. Limitations to using EBITDA as an analytical tool include:


	•	EBITDA does not reflect our current or future requirements for capital expenditures or capital commitments;

	•	EBITDA does not reflect changes in, or cash requirements necessary to service interest or principal payments on, our debt;

	•	EBITDA does not reflect income taxes;

	•	although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA does not reflect any cash requirements for such replacements; and

	•	other companies in our industry may calculate EBITDA differently than we do, limiting its usefulness as a comparative measure.

The following table presents a reconciliation of EBITDA to net income, which is the most directly comparable GAAP financial performance measure, for each of the periods indicated:


								Three Months
								Ended
		Year Ended December 31,						March 31,

		2003		2004		2005		2005		2006

								(unaudited)
		(dollars in thousands)
Reconciliation of EBITDA to Net Income:
Net income		$	2,834	$	12,861	$	44,781	$	5,801	$	19,681
	Income taxes		2,772		7,984		26,800		3,490		11,819
	Net interest expense		5,174		9,550		12,660		2,960		2,779
	Depreciation and amortization		18,213		28,676		37,072		8,047		12,837

EBITDA		$	28,993	$	59,071	$	121,313	$	20,298	$	47,116

Operating Data

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


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

	•	our rig utilization rate is calculated using a 55-hour work week per rig;

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

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


										Three Months
	Year Ended									Ended
	December 31,									March 31,

	2003			2004			2005			2005			2006

Well Servicing
Weighted average number of rigs		257			279			305			291			327
Rig hours (000’s)		523.9			618.8			760.7			175.3			209.0
Rig utilization rate		71.4	%		77.8	%		87.1	%		84.3	%		89.4	%
Revenue per rig hour	$	199		$	230		$	292		$	255		$	352
Segment profits per rig hour	$	59		$	72		$	111		$	94		$	152
Segment profits as a percent of revenue		29.6	%		31.2	%		38.1	%		37.1	%		43.4	%
Fluid Services
Weighted average number of fluid service trucks		249			386			455			435			529
Revenue per fluid service truck (000’s)	$	212		$	256		$	291		$	67		$	82
Segment profits per fluid service truck (000’s)	$	74		$	87		$	109		$	24		$	32
Segment profits as a percent of revenue		34.8	%		34.0	%		37.6	%		34.3	%		39.0	%
Drilling and Completion Services
Segment profits as a percent of revenue		36.8	%		40.4	%		48.4	%		45.6	%		49.5	%
Well Site Construction Services
Segment profits as a percent of revenue		28.3	%		23.1	%		29.9	%		20.6	%		25.5	%

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

RISK FACTORS

You should carefully consider the risks described below, as well as the other information included in this prospectus, before making an investment decision to invest in our common stock. If any of these risks were to occur, our business, results of operations or financial condition could be materially and adversely affected. In that case, the trading price of our common stock could decline, and you could lose all or part of your investment.

Risks Related to Our Business

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

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

Prices for oil and gas historically have been extremely volatile and are expected to continue to be volatile. For example, although oil and natural gas prices have recently hit record prices exceeding $70 per barrel and $14.00 per mcf, respectively, oil and natural gas prices fell below $11 per barrel and $2 per mcf, respectively, in early 1999. The Cushing WTI Spot Oil Price averaged $31.08, $41.51, $56.64 and $63.27 per barrel in 2003, 2004, 2005, and the first three months of 2006, respectively, and the average wellhead price for natural gas, as recorded by the Energy Information Agency, was $4.98, $5.49, $7.51 and $7.49 per mcf for 2003, 2004, 2005, and the first three months of 2006, respectively. Commodity prices have increased significantly in recent years, and these prices may not remain at current levels.

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

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

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

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

Our business strategy includes growth through the acquisitions of other businesses. We may not be able to continue to identify attractive acquisition opportunities or successfully acquire

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

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

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

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

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

We have had only limited operating experience with the improvements we have made to date. We may not be able to implement and maintain adequate controls over our financial processes and reporting in the future, which may require us to restate our financial statements in the future. In addition, we may discover additional past, ongoing or future weaknesses or significant deficiencies in our financial reporting system in the future. Any failure to implement required new or improved controls, or difficulties encountered in their implementation, could cause us to fail to meet our reporting obligations or result in material misstatements in our financial statements. Any such failure also could adversely affect the results of the periodic management evaluations and annual auditor attestation reports regarding the effectiveness of our “internal control over financial reporting” that will be required when the SEC’s rules under

Section 404 of the Sarbanes-Oxley Act of 2002 become applicable to us beginning with our Annual Report on Form 10-K for the year ending December 31, 2006 to be filed in the first quarter of 2007. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could result in a lower trading price of our common stock.

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

We anticipate that we will continue to make substantial capital investments to purchase additional equipment to expand our services, refurbish our well servicing rigs and replace existing equipment. For the year ended December 31, 2005, we invested approximately $83.1 million in cash for capital investments, excluding acquisitions. During the first quarter of 2006, we made capital expenditures of approximately $30.0 million, and we expect to spend a total of approximately $93 million in cash capital expenditures during fiscal year 2006, excluding acquisitions. Historically, we have financed these investments through internally generated funds, debt and equity offerings, our capital lease program and our secured credit facilities. These significant capital investments require cash that we could otherwise apply to other business needs. However, if we do not incur these expenditures while our competitors make substantial fleet investments, our market share may decline and our business may be adversely affected. In addition, if we are unable to generate sufficient cash internally or obtain alternative sources of capital to fund our proposed capital expenditures, acquisitions, take advantage of business opportunities or respond to competitive pressures, it could materially adversely affect our results of operations, financial condition and growth. If we raise additional funds by issuing equity securities, dilution to existing stockholders may result.

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

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

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

Our customers consist primarily of major and independent oil and gas companies. During 2005 and the first three months of 2006, our top five customers accounted for 16% and 14%, respectively, of our revenues. The loss of any one of our largest customers or a sustained decrease in demand by any of such customers could result in a substantial loss of revenues and could have a material adverse effect on our results of operations.

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

We currently purchase our well servicing rigs from a single supplier as part of a 102-rig commitment for rigs to be delivered through the end of December 2007, of which 45 rigs have been delivered as of March 31, 2006. There is also a limited number of suppliers that manufacture this type of equipment. Although pricing is generally fixed for this newbuild contract

and program, future price increases could affect our ability to continue to increase the number of newbuild rigs in our fleet at economic levels. In addition, the failure of our current supplier to timely deliver the newbuild rigs could adversely affect our budgeted or projected financial and operational data.

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

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

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

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

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

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

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


	•	personal injury or loss of life;

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

	•	suspension of operations.

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

We maintain insurance coverage that we believe to be customary in the industry against these hazards. However, we do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. We are also self-insured up to

retention limits with regard to workers’ compensation and medical and dental coverage of our employees and, with certain exceptions, we generally maintain no physical property damage coverage on our workover rig fleet. We maintain accruals in our consolidated balance sheets related to self-insurance retentions by using third-party data and historical claims history. The occurrence of an event not fully insured against, or the failure of an insurer to meet its insurance obligations, could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of these risks, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitive. It is likely that, in our insurance renewals, our premiums and deductibles will be higher, and certain insurance coverage either will be unavailable or considerably more expensive than it has been in the recent past. In addition, our insurance is subject to coverage limits and some policies exclude coverage for damages resulting from environmental contamination.

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

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

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

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

As of May 31, 2006, our total debt was $249.6 million, including $225.0 million of Senior Notes due 2016 and capital lease obligations in the aggregate amount of $24.6 million. Our Senior Notes due 2016 bear interest at 7.125%, payable semi-annually in arrears on April 15 and October 15 of each year, starting October 15, 2006. In addition, as of May 31, 2006, we had $9.6 million of letters of credit outstanding and availability for up to $140.4 million of additional borrowings under our 2005 Credit Facility and the potential to expand term or revolving borrowings under our 2005 Credit Facility by up to an additional $75 million.

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


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

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

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

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

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

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

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


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

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


	•	limitations on the incurrence of additional indebtedness;

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

	•	limitation on dividends and distributions.

In addition, our 2005 Credit Facility requires us to maintain certain financial ratios and to satisfy certain financial conditions and covenants, several of which become more restrictive over time and may require us to reduce our debt or take some other action in order to comply with them. The failure to comply with any of these financial conditions, financial ratios or covenants would cause a default under our 2005 Credit Facility. A default, if not waived, could result in acceleration of the outstanding indebtedness under our 2005 Credit Facility, in which case the debt would become immediately due and payable. In addition, a default or acceleration of indebtedness under our 2005 Credit Facility could result in a default or acceleration of our Senior Notes or other indebtedness with cross-default or cross-acceleration provisions. If this occurs, we may not be able to pay our debt or borrow sufficient funds to refinance it. Even if new financing is available, it may not be available on terms that are acceptable to us. These restrictions could also limit our ability to obtain future financings, make needed capital

expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We also may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under our 2005 Credit Facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facilities — 2005 Credit Facility” for a discussion of our 2005 Credit Facility.


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

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

Risks Related to our Relationship with DLJ Merchant Banking


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

As of May 18, 2006, DLJ Merchant Banking Partners III, L.P. and affiliated funds (“DLJ Merchant Banking”), which are managed by affiliates of Credit Suisse, a Swiss Bank, and Credit Suisse Securities (USA) LLC, beneficially owned approximately 47.4% of our outstanding common stock. After giving effect to the shares to be sold in this offering, DLJ Merchant Banking will beneficially own approximately 26.9% of our outstanding common stock (or approximately 23.8% if the underwriters’ over-allotment option is exercised in full), although DLJ Merchant Banking will own only approximately 17.5% of our outstanding shares of common stock (or approximately 14.0% if the underwriters’ over-allotment option is exercised in full) due to their ownership of warrants that would not entitle DLJ Merchant Banking to vote unless the warrants were exercised for shares. Nonetheless, DLJ Merchant Banking is in a position to have a substantial influence on the outcome of matters requiring a stockholder vote, including the election of directors, adoption of amendments to our certificate of incorporation or bylaws or approval of transactions involving a change of control. The interests of DLJ Merchant Banking may differ from those of our other stockholders, and DLJ Merchant Banking may vote its common stock in a manner that may not be in the best interest of the other stockholders.

Risks Related to this Distribution


	Certain stockholders’ shares are restricted from immediate resale but may be sold into the market in the near future. This could cause the market price of our common stock to drop significantly.

As of July 24, 2006, we had outstanding 33,827,105 shares of common stock. In addition to shares issuable upon the exercise of options issued under our 2003 Incentive Plan, there are 4,350,000 shares that may be issued upon the exercise of warrants held by DLJ Merchant Banking. Of these outstanding shares, after this distribution, 17,708,335 shares will be freely tradable without restriction under the Securities Act except for any shares purchased by one of our “affiliates” as defined in Rule 144 under the Securities Act.

After this distribution, the holders of 13,709,424 shares (not including shares issuable upon the exercise of warrants held by DLJ Merchant Banking) will have rights, subject to some limited conditions, to demand that we include their shares in registration statements that we file on their

behalf, on our behalf or on behalf of other stockholders. By exercising their registration rights and selling a large number of shares, these holders could cause the price of our common stock to decline. Furthermore, if we file a registration statement to offer additional shares of our common stock and have to include shares held by those holders, it could impair our ability to raise needed capital by depressing the price at which we could sell our common stock.


	Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:


	•	a classified board of directors, so that only approximately one-third of our directors are elected each year;

	•	limitations on the removal of directors;

	•	the prohibition of stockholder action by written consent; and

	•	limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.

Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors.


	*Because we have no plans to pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us.*

We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that the board of directors deems relevant. The terms of our 2005 Credit Facility and the indenture governing our Senior Notes may restrict the payment of dividends without the prior written consent of the lenders. Investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our common stock.


	*If our stock price declines after this distribution, you could lose a significant part of your investment.*

The market price of our common stock could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:


	•	changes in securities analysts’ recommendations and their estimates of our financial performance;


	•	the public’s reaction to our press releases, announcements and our filings with the Securities and Exchange Commission;

	•	fluctuations in broader stock market prices and volumes, particularly among securities of oil and gas service companies;

	•	changes in market valuations of similar companies;

	•	additions or departures of key personnel;

	•	commencement of or involvement in litigation;

	•	announcements by us or our competitors of strategic alliances, significant contracts, new technologies, acquisitions, commercial relationships, joint ventures or capital commitments;

	•	variations in our quarterly results of operations or cash flows or those of other oil and gas service companies;

	•	changes in our pricing policies or pricing policies of our competitors;

	•	future issuances and sales of our common stock; and

	•	changes in general conditions in the U.S. economy, financial markets or the oil and gas industry.

In recent years, the stock market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. These market fluctuations may also result in a lower price of our common stock.

FORWARD-LOOKING STATEMENTS AND INDUSTRY DATA

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

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

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

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


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

	•	the effects of future acquisitions on our business;

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

	•	competition within our industry;

	•	general economic and market conditions;

	•	our access to current or future financing arrangements;

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

	•	environmental and other governmental regulations.

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

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

PLAN OF DISTRIBUTION

The shares of our common stock are being registered to permit a one time distribution of controlled securities to the partners of Southwest Partners II, L.P. and Southwest Partners III, L.P. and to the members of Fortress Holdings, LLC. Neither we, nor the distributing stockholders will receive any proceeds from this transaction.

The distributing stockholders have agreed, among other things, to bear all expenses payable in connection with the registration and distribution of the shares of common stock covered by this prospectus. We estimate that the expenses for which we will be responsible in connection with filing this registration statement and distribution of prospectuses will be approximately $275,000.

The shares of common stock to be distributed pursuant to this prospectus are listed on the New York Stock Exchange under the trading symbol “BAS.”

If dealers are utilized in the sale of shares of common stock, the partners or members will sell such shares of common stock to the dealers as principals. The dealers may then resell such shares of common stock to the public at varying prices to be determined by such dealers at the time of resale. The names of the dealers and the terms of the transaction will be set forth in a prospectus supplement, if required.

The partners or members may also sell shares of common stock through agents designated by them from time to time.

The partners or members may sell any of the shares of common stock directly to purchasers. In this case, the partners or members may not engage underwriters or agents in the offer and sale of these shares of common stock.

The partners or members may indemnify underwriters, dealers or agents who participate in the distribution of securities against certain liabilities, including liabilities under the Securities Act and agree to contribute to payments which these underwriters, dealers or agents may be required to make.

The shares of common stock may be sold in one or more transactions at fixed prices, at prevailing market prices at the time of sale, at varying prices determined at the time of sale, or at negotiated prices. Sales may be effected in transactions, which may involve block transactions or crosses:


	•	on any national securities exchange or quotation service on which the shares of common stock may be listed or quoted at the time of sale;

	•	in the over-the-counter market;

	•	in transactions otherwise than on exchanges or quotation services or in the over-the-counter market;

	•	through the exercise of purchased or written options; or

	•	through any other method permitted under applicable law.

In connection with sales of the shares of common stock or otherwise, the partners or members may enter into hedging transactions with broker-dealers, which may in turn engage in short sales of the shares of common stock in the course of hedging the positions they assume. The partners or members may also sell short the shares of common stock and deliver the shares of common stock to close out short positions, or loan or pledge the shares of common stock to broker-dealers that in turn may sell the shares of common stock.

In order to comply with the securities laws of some states, if applicable, the shares of common stock may be sold in these jurisdictions only through registered or licensed brokers or dealers. In addition, in some states the shares of common stock may not be sold unless they have been registered or qualified for sale or an exemption from registration or qualification requirements is available and is complied with.

The partners or members and any underwriters, broker-dealers or agents that participate in the sale of the shares of common stock may be “underwriters” within the meaning of Section 2(11) of the Securities Act. Any discounts, commissions, concessions or profit they earn on any resale of the shares of common stock may be underwriting discounts and commissions under the Securities Act. Any partner or member who is an “underwriter” within the meaning of Section 2(11) of the Securities Act will be subject to the prospectus delivery requirements of the Securities Act. The partners or members have acknowledged that they understand their obligations to comply with the provisions of the Exchange Act and the rules thereunder relating to stock manipulation, particularly Regulation M.

USE OF PROCEEDS

We will not receive any net proceeds in connection with the distribution of shares of common stock by the distributing stockholders. However, the distributing stockholders have agreed to pay our expenses incurred in connection with the registration of the distribution. See “Plan of Distribution.”

PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY

Our common stock has traded on the New York Stock Exchange under the symbol “BAS” since December 9, 2005. As of August 2, 2006, there were 39 stockholders of record. The following table sets forth, for the periods indicated, the range of high and low sales prices for our common stock as reported by the New York Stock Exchange:


	Price

	High		Low

2005
Fourth Quarter(1)	$	22.60	$	19.10
2006
First Quarter	$	31.15	$	19.91
Second Quarter	$	38.30	$	24.32
Third Quarter(2)	$	31.37	$	23.60


(1)	Reflects trading activity from December 9, 2005 through December 31, 2005.


(2)	Reflects trading activity through August 2, 2006.

On August 2, 2006, the last reported sale price of our common stock was $27.62 per share.

We have not declared or paid any cash dividends on our common stock, and we do not currently anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any future determination relating to our dividend policy will be at the discretion of our board of directors and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant by our board. We are also currently restricted in our ability to pay dividends under our 2005 Credit Facility and may be limited in our ability to pay dividends under the indenture governing our Senior Notes.

CAPITALIZATION

The following table sets forth our capitalization at March 31, 2006. The information was derived from and is qualified by reference to our financial statements included elsewhere in this prospectus. You should read this information in conjunction with “Selected Historical Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our combined financial statements and the related notes thereto included elsewhere in this prospectus.


				March 31,
				2006

				(in thousands)
Cash and cash equivalents				$	19,953

Total long-term debt, including current portion:
	Notes payable:
		Revolving credit facility		$	96,000
		Term B Loan			89,750
		Other debt and obligations under capital leases			24,297

			Total		210,047

Stockholders’ equity:
	Common stock, $.01 par value, 80,000,000 shares authorized; 33,931,935 shares issued and 33,787,305 shares outstanding				339
	Additional paid-in capital				235,264
	Deferred compensation				—
	Retained earnings				46,174
	Treasury stock, 144,630 shares at cost				(3,618	)
	Accumulated other comprehensive income				82

		Total stockholders’ equity			278,241

		Total capitalization		$	488,288

The foregoing capitalization does not reflect our issuance in April 2006 of $225 million of Senior Notes due 2016, the proceeds of which were used to retire the outstanding Term B Loan balance and to pay down the outstanding balance under our revolving credit facility. As of May 31, 2006, we had no amounts outstanding under our revolving credit facility.

SELECTED HISTORICAL FINANCIAL DATA

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


																			Three Months Ended
				Year Ended December 31,															March 31,

				2001			2002			2003			2004			2005			2005			2006

																			(unaudited)
				(dollars in thousands, except per share data)
Statement of Operations Data:
Revenues:
	Well servicing			$	62,943		$	73,848		$	104,097		$	142,551		$	221,993		$	44,798		$	73,465
	Fluid services				36,766			34,170			52,810			98,683			132,280			29,303			43,121
	Drilling and completion services				—			733			14,808			29,341			59,832			10,764			27,455
	Well site construction services				—			—			9,184			40,927			45,647			8,948			10,265

		Total revenues			99,709			108,751			180,899			311,502			459,752			93,813			154,306

Expenses:
	Well servicing				40,906			55,643			73,244			98,058			137,392			28,191			41,610
	Fluid services				21,363			22,705			34,420			65,167			82,551			19,238			26,305
	Drilling and completion services				—			512			9,363			17,481			30,900			5,860			13,854
	Well site construction services				—			—			6,586			31,454			32,000			7,108			7,643
	General and administrative(1)				10,813			13,019			22,722			37,186			55,411			13,091			18,005
	Depreciation and amortization				9,599			13,414			18,213			28,676			37,072			8,047			12,837
	Loss (gain) on disposal of assets				(10	)		351			391			2,616			(222	)		102			(200	)

		Total expenses			82,671			105,644			164,939			280,638			375,104			81,637			120,054

			Operating income		17,038			3,107			15,960			30,864			84,648			12,176			34,252
Other income (expense):
Net interest expense					(3,303	)		(4,750	)		(5,174	)		(9,550	)		(12,660	)		(2,960	)		(2,779	)
Gain (loss) on early extinguishment of debt					(1,462	)		—			(5,197	)		—			(627	)		—			—
Other income (expense)					16			31			146			(398	)		220			75			27

Income (loss) from continuing operations before income taxes					12,289			(1,612	)		5,735			20,916			71,581			9,291			31,500
Income tax (expense) benefit					(4,688	)		382			(2,772	)		(7,984	)		(26,800	)		(3,490	)		(11,819	)

Income (loss) from continuing operations					7,601			(1,230	)		2,963			12,932			44,781			5,801			19,681
Income (loss) from discontinued operations, net of tax					—			—			22			(71	)		—			—			—
Cumulative effect of accounting change, net of tax					—			—			(151	)		—			—			—			—

Net income (loss)					7,601			(1,230	)		2,834			12,861			44,781			5,801			19,681
Preferred stock dividend					—			(1,075	)		(1,525	)		—			—			—			—
Accretion of preferred stock discount					—			(374	)		(3,424	)		—			—			—			—

Net income (loss) available to common stockholders				$	7,601		$	(2,679	)	$	(2,115	)	$	12,861		$	44,781		$	5,801		$	19,681


																	Three Months Ended
		Year Ended December 31,															March 31,

		2001			2002			2003			2004			2005			2005			2006

																	(unaudited)
		(dollars in thousands, except per share data)
Basic earnings (loss) per share of common stock(2):
	Continuing operations less preferred stock dividend and accretion	$	0.50		$	(0.13	)	$	(0.09	)	$	0.46		$	1.57		$	0.21		$	0.59
	Discontinued operations		—			—			—			—			—			—			—
	Cumulative effect of accounting change		—			—			—			—			—			—			—

	Net income (loss) available to common stockholders	$	0.50		$	(0.13	)	$	(0.09	)	$	0.46		$	1.57		$	0.21		$	0.59

Diluted earnings (loss) per share of common stock(2):
	Continuing operations less preferred stock dividend and accretion	$	0.50		$	(0.13	)	$	(0.09	)	$	0.42		$	1.35		$	0.18		$	0.53
	Discontinued operations		—			—			—			—			—			—			—
	Cumulative effect of accounting change		—			—			—			—			—			—			—

	Net income (loss) available to common stockholders	$	0.50		$	(0.13	)	$	(0.09	)	$	0.42		$	1.35		$	0.18		$	0.53

Statement of Cash Flow:
Cash flows from operating activities		$	14,060		$	17,012		$	29,815		$	46,539		$	99,189		$	16,734		$	25,915
Cash flows from investing activities			(60,305	)		(45,303	)		(84,903	)		(73,587	)		(107,679	)		(19,946	)		(111,584	)
Cash flows from financing activities			50,770			21,572			79,859			21,498			21,188			(2,817	)		72,777
Capital expenditures:
	Acquisitions, net of cash acquired		44,928			31,075			61,885			19,284			25,378			3,909			87,520
	Property and equipment		15,208			14,674			23,501			55,674			83,095			16,083			24,812
Other Financial Data:
EBITDA(3)		$	25,191		$	16,552		$	28,993		$	59,071		$	121,313		$	20,298		$	47,116


	As of December 31,										As of
											March 31,
	2001		2002		2003		2004		2005		2006

											(unaudited)
	(dollars in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	7,645	$	926	$	25,697	$	20,147	$	32,845	$	19,953
Property and equipment, net		78,602		108,487		188,243		233,451		309,075		399,865
Total assets		126,207		156,502		302,653		367,601		496,957		616,787
Long-term debt, including current portion		45,258		39,706		148,509		182,476		126,887		210,047
Mandatorily redeemable cumulative preferred stock		—		12,093		—		—		—		—
Stockholders’ equity		58,938		72,558		107,295		121,786		258,575		278,241


(1)	Includes approximately $994,000, $1,587,000 and $2,890,000 of non-cash stock compensation expense for the years ended December 31, 2003, 2004 and 2005, respectively, and $591,000 and $758,000 for the three months ended March 31, 2005 and 2006, respectively.

(2)	Reflects a 5-for-1 stock split effected as a stock dividend in September 2005.

(3)	EBITDA means earnings before interest, taxes, depreciation and amortization. EBITDA is used as a supplemental financial measure by our management and directors and by external users of our financial statements, such as investors, to assess:


•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

•	the ability of our assets to generate cash sufficient to pay interest on our indebtedness; and


•	our operating performance and return on invested capital as compared to those of other companies in the well services industry, without regard to financing methods and capital structure.


•	EBITDA does not reflect our current or future requirements for capital expenditures or capital commitments;

•	EBITDA does not reflect changes in, or cash requirements necessary to service interest or principal payments on, our debt;

•	EBITDA does not reflect income taxes;

•	although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA does not reflect any cash requirements for such replacements; and

•	other companies in our industry may calculate EBITDA differently than we do, limiting its usefulness as a comparative measure.


	The following table presents a reconciliation of EBITDA to net income (loss), which is the most directly comparable GAAP financial performance measure, for each of the periods indicated:


													Three Months
													Ended
		Year Ended December 31,											March 31,

		2001		2002			2003		2004		2005		2005		2006

													(unaudited)
		(dollars in thousands)
Reconciliation of EBITDA to Net Income (Loss):
Net income (loss)		$	7,601	$	(1,230	)	$	2,834	$	12,861	$	44,781	$	5,801	$	19,681
	Income tax expense (benefit)		4,688		(382	)		2,772		7,984		26,800		3,490		11,819
	Net interest expense		3,303		4,750			5,174		9,550		12,660		2,960		2,779
	Depreciation and amortization		9,599		13,414			18,213		28,676		37,072		8,047		12,837

EBITDA		$	25,191	$	16,552		$	28,993	$	59,071	$	121,313	$	20,298	$	47,116

MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Overview

We provide a wide range of well site services to oil and gas drilling and producing companies, including well servicing, fluid services, drilling and completion services and well site construction services. Our results of operations since the beginning of 2002 reflect the impact of our acquisition strategy as a leading consolidator in the domestic land-based well services industry during this period. Our acquisitions have increased our breadth of service offerings at the well site and expanded our market presence. In implementing this strategy, we have purchased businesses and assets in 40 separate acquisitions from January 1, 2001 to March 31, 2006. Our weighted average number of well servicing rigs has increased from 126 in 2001 to 327 in the first quarter of 2006, and our weighted average number of fluid service trucks has increased from 156 to 529 in the same period. In 2003, primarily through acquisitions, we significantly increased our drilling and completion (principally pressure pumping) services and entered the well site construction services segment. These acquisitions make changes in revenues, expenses and income not directly comparable.

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


														Three Months Ended
		Year Ended December 31,												March 31,

		2003				2004				2005				2005				2006

Revenues:
Well servicing		$	104.1	58	%	$	142.6	46	%	$	222.0	48	%	$	44.8	48	%	$	73.5	47	%
Fluid services			52.8	29	%		98.7	32	%		132.3	29	%		29.3	31	%		43.1	28	%
Drilling and completion services			14.8	8	%		29.3	9	%		59.8	13	%		10.8	11	%		27.4	18	%
Well site construction services			9.2	5	%		40.9	13	%		45.7	10	%		8.9	10	%		10.3	7	%

	Total revenues	$	180.9	100	%	$	311.5	100	%	$	459.8	100	%	$	93.8	100	%	$	154.3	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. In addition, the discovery rate of new oil and gas reserves in our market areas also may have an impact on our business, even in an environment of stronger oil and gas prices. For a more comprehensive discussion of our industry trends, see “Business — General Industry Overview.”

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

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


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

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

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

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

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

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

Recent Strategic Acquisitions and Expansions

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

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

Selected 2003 Acquisitions

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

New Force Energy Services, Inc.

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

FESCO Holdings, Inc./ First Energy Services Company

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

PWI Inc.

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

Pennant Services Company

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

Selected 2004 Acquisitions

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

Energy Air Drilling

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

AWS Wireline Services

On November 1, 2004, we completed the acquisition of substantially all of the operating assets of AWS Wireline Services, a cased-hole wireline company based in Albany, Texas. This acquisition of six wireline units was our initial entry into the wireline business. This service is complementary to our existing pressure pumping service organization infrastructure in this same market area. This transaction was structured as an asset purchase for a total purchase price of approximately $4.3 million in cash.

Selected 2005 Acquisitions

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

MD Well Service, Inc.


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

Oilwell Fracturing Services, Inc.

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

Selected 2006 Acquisitions

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

LeBus Oil Field Service Co.


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

G&L Tool, Ltd.

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

Segment Overview

Well Servicing


	In 2005, our well servicing segment represented 48% of our revenues and, during the first three months of 2006, 47% of our revenues. Revenue in our well servicing segment is derived

from maintenance, workover, completion and plugging and abandonment services. We provide maintenance related services as part of the normal, periodic upkeep of producing oil and gas wells. Maintenance-related services represent a relatively consistent component of our business. Workover and completion services generate more revenue per hour than maintenance work due to the use of auxiliary equipment, but demand for workover and completion services fluctuates more with the overall activity level in the industry.

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

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


	Weighted								Segment
	Average				Rig		Revenue		Profits
	Number		Rig		Utilization		per		per		Segment
	of Rigs		Hours		Rate		Rig Hour		Rig Hour		Profits %

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

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

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

We have been able to increase our revenue per rig hour from $188 in the first quarter of 2003 to $352 in the first quarter of 2006 mainly as a result of this higher utilization, which has contributed to our improved segment profits.

Fluid Services

In 2005, our fluid services segment represented 29% of our revenues and, during the first three months of 2006, 28% of our revenues. Revenues in our fluid services segment are earned from the sale, transportation, storage and disposal of fluids used in the drilling, production and maintenance of oil and gas wells. The fluid services segment has a base level of business consisting of transporting and disposing of salt water produced as a by-product of the production of oil and gas. These services are necessary for our customers and generally have a stable demand but typically produce lower relative segment profits than other parts of our fluid services segment. Fluid services for completion and workover projects typically require fresh or brine water for making drilling mud, circulating fluids or frac fluids used during a job, and all of these fluids require storage tanks and hauling and disposal. Because we can provide a full complement of fluid sales, trucking, storage and disposal required on most drilling and workover projects, the add-on services associated with drilling and workover activity enable us to generate higher segment profits contributions. The higher segment profits are due to the relatively small incremental labor costs associated with providing these services in addition to our base fluid services segment. We typically price fluid services by the job, by the hour or by the quantities sold, disposed of or hauled.

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


	Weighted
	Average				Segment
	Number of		Revenue per		Profits per
	Fluid Service		Fluid Service		Fluid Service		Segment
	Trucks		Truck		Truck		Profits %

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

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

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

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

The majority of the increase in revenue per fluid services truck from $51,000 in the first quarter of 2003 to $82,000 in the first quarter of 2006 is due to the revenues derived from the expansion of our frac tank fleet and disposal facilities as well as increases in prices charged for our services. Our segment profits per fluid services truck have increased because of these factors and increased utilization of our equipment.

Drilling and Completion Services

In 2005, our drilling and completion services segment represented 13% of our revenues and, during the first three months of 2006, 18% of our revenue. Revenues from our drilling and completion services segment are generally derived from a variety of services designed to stimulate oil and gas production or place cement slurry within the wellbores. Our drilling and completion services segment includes pressure pumping, cased-hole wireline services, underbalanced drilling and fishing and rental tool operations.

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

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

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

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

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


			Segment
	Revenues		Profits %

2003:
First Quarter	$	2,642		45.3%
Second Quarter	$	3,454		32.7%
Third Quarter	$	4,183		38.2%
Fourth Quarter	$	4,529		33.6%
Full Year	$	14,808		36.8%
2004:
First Quarter	$	4,865		35.5%
Second Quarter	$	7,251		46.0%
Third Quarter	$	8,463		41.0%
Fourth Quarter	$	8,762		38.0%
Full Year	$	29,341		40.4%
2005:
First Quarter	$	10,764		45.6%
Second Quarter	$	13,512		49.1%
Third Quarter	$	15,883		48.2%
Fourth Quarter	$	19,673		49.5%
Full Year	$	59,832		48.4%
2006:
First Quarter	$	27,455		49.5%

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

Well Site Construction Services

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

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

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


			Segment
	Revenues		Profits %

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

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

Operating Cost Overview

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

Critical Accounting Policies and Estimates

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

Critical Accounting Policies

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

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

Impairments. We review our assets for impairment at a minimum annually, or whenever, in management’s judgment, events or changes in circumstances indicate that the carrying amount of a long-lived asset may not be recovered over its remaining service life. Provisions for asset impairment are charged to income when the sum of the estimated future cash flows, on an undiscounted basis, is less than the assets’ carrying amount. When impairment is indicated, an impairment charge is recorded based on an estimate of future cash flows on a discounted basis.

Self-Insured Risk Accruals. We are self-insured up to retention limits with regard to workers’ compensation and medical and dental coverage of our employees. We generally maintain no physical property damage coverage on our workover rig fleet, with the exception of certain of our 24-hour workover rigs and newly manufactured rigs. We have deductibles per occurrence for workers’ compensation and medical and dental coverage of $150,000 and $125,000, respectively. We have lower deductibles per occurrence for automobile liability and general liability. We maintain accruals in our consolidated balance sheets related to self-insurance retentions by using third party data and historical claims history.

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

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

Critical Accounting Estimates

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

Depreciation and Amortization. In order to depreciate and amortize our property and equipment and our intangible assets with finite lives, we estimate the useful lives and salvage

values of these items. Our estimates may be affected by such factors as changing market conditions, technological advances in industry or changes in regulations governing the industry.

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

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

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

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

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

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

We adopted FAS No. 123R using both the modified prospective method and the prospective method as applicable to the specific awards granted. The modified prospective method was applied to awards granted subsequent to our becoming a public company. Awards granted prior to our becoming public and which were accounted for under APB No. 25 were adopted by using the prospective method. The results of prior periods have not been restated. Compensation expense cost of the unvested portion of awards granted as a private company and outstanding

as of January 1, 2006 will continue to be based upon the intrinsic value method calculated under APB No. 25.

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

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

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


			Weighted		Weighted		Weighted
	Number		Average		Average		Average
	of Options		Exercise		Fair Value		Intrinsic Value
Grants Made	Granted		Price		Per Share		Per Share

January 2005		100,000	$	5.16	$	9.63	$	4.47
March 2005		865,000	$	6.98	$	12.78	$	5.80
May 2005		5,000	$	6.98	$	15.48	$	8.50
December 2005		37,500	$	21.01	$	21.01	$	0.00

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


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

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

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

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

Based on the IPO price of $20.00, the intrinsic value of the options granted in the last twelve months was $12.8 million, all of which related to unvested options. We have recorded

deferred compensation related to these options of $5.2 million, which is being recorded to compensation expense over the service period.

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

Asset Retirement Obligations. SFAS No. 143 requires us to record the fair value of an asset retirement obligation as a liability in the period in which it becomes a legal obligation associated with the retirement of tangible long-lived assets and to capitalize an equal amount as a cost of the asset, depreciating it over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each quarter to reflect the passage of time, changes in the estimated future cash flows underlying the obligation, acquisition or construction of assets, and settlement of obligations.

Results of Operations

The results of operations between periods will not be comparable, primarily due to the significant number of acquisitions made and their relative timing in the year acquired. See note 3 of the notes to our historical consolidated financial statements for more detail.

Three Months Ended March 31, 2006 Compared to Three Months Ended March 31, 2005

Revenues. Revenues increased 64% to $154.3 million in the first three months in 2006 from $93.8 million during the same period in 2005. This increase was primarily due to the internal expansion of our business segments, particularly well servicing and fluid services, as well as in part due to acquisitions. The pricing and utilization of our services, and thus related revenues, improved due to the increase in well maintenance and drilling activity caused by higher oil and gas prices.

Well servicing revenues increased 64% to $73.5 million in the first quarter in 2006 compared to $44.8 million in the first quarter in 2005. This increase was due primarily to the internal growth of this segment as well as an increase in our revenue per rig hour of approximately 38%, from $255 per hour to $352 per hour. Our weighted average number of rigs increased to 327 in the first quarter in 2006 compared to 291 in the same period in 2005, an increase of approximately 12%. In addition, the utilization rate of our rig fleet increased to 89.4% in the first quarter in 2006 compared to 84.3% in the same period in 2005.

Fluid services revenues increased 47% to $43.1 million during the first quarter in 2006 as compared to $29.3 million in the same period in 2005. The increase in revenue was due primarily to our internal growth of this segment. Our weighted average number of fluid service trucks increased to 529 in the first quarter in 2006 compared to 435 in the same period in 2005, an increase of approximately 22%. The increase in weighted average number of fluid service trucks is due to internal expansion as well as the trucks added from the LeBus acquisition. In the first quarter in 2006, our average revenue per fluid service truck was approximately $82,000 as compared to approximately $67,000 in the same period in 2005. The increase in average revenue per fluid service truck reflects the expansion of our frac tank fleet and saltwater disposal operations, and increases in prices charged for our services.

Drilling and completion services revenue increased 155% to $27.5 million during the first quarter in 2006 as compared to $10.8 million in the same period in 2005. The increase in revenue between these periods was primarily the result of internal expansion, the acquisition of Oil Well

Fracturing Services in October 2005, the acquisition of G&L during February 2006 and improved pricing and utilization of our services.

Well site construction services revenue increased 15% to $10.3 million during the first quarter in 2006 as compared to $8.9 million during the same period in 2005.

Direct Operating Expenses. Direct operating expenses, which primarily consist of labor, including workers compensation and health insurance, and maintenance and repair costs, increased 48% to $89.4 million in the first quarter in 2006 from $60.4 million in the same period in 2005 primarily as a result of additional rigs and trucks, as well as higher utilization of our equipment. Operating expenses decreased to 58% of revenue for the first quarter in 2006 from 64% in the same period in 2005, as fixed operating costs such as field supervision, insurance and vehicle expenses were spread over a higher revenue base. We also benefited from higher utilization and increased pricing of our services.

Direct operating expenses for the well servicing segment increased 48% to $41.6 million in the first quarter in 2005 compared to $28.2 million in the same period in 2005 primarily due to the internal growth of this segment. Segment profits for this segment increased to 43.4% of revenues in the first quarter in 2006 compared to 37.1% in the same period in 2005 primarily due to the improved pricing and higher utilization of our equipment.

Direct operating expenses for the fluid services segment increased 37% to $26.3 million in the first quarter in 2006 compared to $19.2 million in the same period in 2005 primarily due to increased activity and expansion of our fluid services fleet. Segment profits for this segment increased to 39.0% of revenues in the first quarter in 2006 compared to 34.3% in the same period in 2005 primarily due to the expansion of our frac tank fleet and saltwater disposal operations, and increases in prices charged for our services.

Direct operating expenses for the drilling and completion services segment increased 136% to $13.9 million in the first quarter in 2006 compared to $5.9 million in the same period in 2005 primarily due to the increased activity and expansion of our services and equipment, including the G&L acquisition. Segment profits for this segment increased to 49.5% of revenues in the first quarter in 2006 compared to 45.6% in the same period in 2005.

Direct operating expenses for the well-site construction services segment increased 8% to $7.6 million in the first quarter in 2006 compared to $7.1 million in the same period in 2005. Segment profits for this segment increased to 25.5% of revenues in the first quarter of 2006 compared to 20.6% in the same period in 2005.

General and Administrative Expenses. General and administrative expenses increased 38% to $18.0 million in the first quarter in 2006 from $13.1 million in the same period in 2005. The increase primarily reflects higher salary and office expenses related to the expansion of our business as well as additional staffing to enhance internal controls as a public company.

Depreciation and Amortization Expenses. Depreciation and amortization expenses were $12.8 million for the first quarter in 2006 and $8.0 million in the same period in 2005, reflecting the increase in the size and investment in our asset base. We invested $87.5 million for acquisitions and an additional $30.0 million for capital expenditures, including capital leases, in the first quarter in 2006.

Interest Expense. Interest expense was $3.1 million in the first quarter in 2006, unchanged from the same period in 2005.

Income Tax Expense (Benefit). Income tax expense was $11.8 million in the first quarter in 2006 compared to $3.5 million in the same period in 2005, reflecting the improvement in our profitability. Our effective tax rate in both periods was approximately 38%.

Net Income. Our net income increased to $19.7 million in the first quarter in 2006 from $5.8 million in the same period in 2005. This improvement was due primarily to the factors described above, including our increased asset base and related revenues, higher utilization rates and increased revenues per rig and fluid service truck, and higher operating margins on our drilling and completion services equipment.

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

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

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

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

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

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

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

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

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

Direct operating expenses for the drilling and completion services segment increased by 77% to $30.9 million in 2005 as compared to $17.5 million in 2004 due primarily to increased

activity and expansion of our services and equipment. Our segment profits increased to 48.4% of revenues in 2005 from 40.4% in 2004.

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

General and Administrative Expenses. General and administrative expenses increased by 49% to $55.4 million in 2005 from $37.2 million in 2004 which included $2.9 million and $1.6 million of stock-based compensation expense in 2005 and 2004, respectively. The increase primarily reflects higher salary and office expenses related to the expansion of our business.

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

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

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

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

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

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

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

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

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

Drilling and completion service revenues were $29.3 million during 2004 as compared to $14.8 million during 2003. Our significant entry into this segment occurred in late January 2003

with the acquisition of New Force and other acquisitions occurring during the fourth quarter of 2003. The increase in revenues between periods is primarily the result of the addition of equipment and an increase in rates due to higher utilization.

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

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

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

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

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

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

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

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

Interest Expense. Interest expense increased 85.6% to $9.7 million in 2004 from $5.2 million in 2003. The increase was due to an increase in long-term debt which was primarily used in connection with our acquisitions, most of which was added in the fourth quarter of 2003, and capital expenditures for property and equipment. In addition, both prime and LIBOR interest rates increased in 2004, and our Term B Loan interest rate is tied directly to these rates. Our 2003 interest expense was favorably impacted by the reduced interest rate we received in our January

2003 refinancing, as well as an additional reduction in interest rates in our October 2003 refinancing. As part of the refinancings in January 2003 and October 2003, we recognized a loss of $5.2 million from the early extinguishment of debt. As part of our 2004 refinancing, we further reduced our base interest rate by 50 basis points. See “— Liquidity and Capital Resources.”

Income Tax Expense. Income taxes increased to an $8.0 million expense in 2004 from a $2.8 million expense in 2003. The change was due to improved profitability offset in part by a decrease in the effective tax rate in 2004. The effective tax rate in 2004 was approximately 38.2% as compared to 48.3% in 2003. The decrease in the effective tax rate in 2004 was due primarily to an adjustment of the federal tax rate from 34% in previous years to 35% in 2003, and the associated effects on our deferred tax liability.

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

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

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

Liquidity and Capital Resources

Currently, our primary capital resources are net cash flows from our operations, utilization of capital leases as allowed under our 2005 Credit Facility and availability under our 2005 Credit Facility, of which approximately $44.4 million was available at March 31, 2006. As of April 30, 2006, we had paid down all amounts under the revolving portion of our 2005 Credit Facility with the proceeds from our offering of Senior Notes and had availability of $140.4 million and $9.6 million of letters of credit outstanding under this facility. As of March 31, 2006, we had cash and cash equivalents of $20.0 million compared to $14.1 million as of March 31, 2005. We have utilized, and expect to utilize in the future, bank and capital lease financing and sales of equity to obtain capital resources. When appropriate, we will consider public or private debt and equity offerings and non-recourse transactions to meet our liquidity needs.

Net Cash Provided By Operating Activities

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

Cash flow from operating activities was $25.9 million during the first quarter of 2006 as compared to $16.7 million during the same period in 2005. The increase in operating cash flows in the first quarter of 2006 over the same period in 2005 was primarily due to expansion of our fleet and improvements in the segment profits and utilization of our equipment.

Capital Expenditures

Capital expenditures are the main component of our investing activities. Cash capital expenditures (including for acquisitions) for the first quarter in 2006 were $112.3 million as compared to $20.0 million for the same period in 2005. In the first quarter of 2006, the majority of our capital expenditures were for business acquisitions, whereas in 2005, the majority of our capital expenditures were for the expansion of our fleet. We also added assets through our capital lease program of approximately $5.2 million in the first quarter in 2006 compared to $1.0 million in the same period in 2005. Cash capital expenditures (including acquisitions) for 2005 were $108.5 million as compared to $75.0 million in 2004, and $85.4 million in 2003. In 2005 and 2004, the majority of our capital expenditures were for the expansion of our fleet. In 2003 the majority of our capital expenditures were for acquisitions. In 2003, we issued 3,650,000 shares of common stock as part of the FESCO acquisition which added a non-cash cost to acquisitions of $18.8 million and is in addition to the $85.4 million spent in 2003. In 2003, we experienced a significant increase in our acquisition activity as compared to the previous periods which allowed us to expand our services and regions where we operate. We also added assets through our capital lease program of approximately $10.3 million, $10.5 million, and $10.8 million in 2005, 2004 and 2003, respectively.

For 2006, we currently have planned approximately $93 million in cash capital expenditures, none of which is planned for acquisitions. We do not budget acquisitions in the normal course of business, but we completed three acquisitions for total consideration paid of $87.5 million, net of cash acquired during the first quarter of 2006 and expect to make additional acquisitions in 2006. The $93 million of capital expenditures planned for property and equipment is primarily for (1) purchase of additional equipment to expand our services, (2) continued refurbishment of our well servicing rigs and (3) replacement of existing equipment. We have taken delivery of 45 newbuild will servicing rigs since October 2004 as part of a 102-rig newbuild commitment. The remainder of these newbuilds is scheduled to be delivered to us prior to the end of December 2007. As of March 31, 2006, we had no executed letters of intent for acquisitions. As of July 11, 2006, we had entered into letters of intent related to the acquisition of three entities totaling approximately $30 million.

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

Capital Resources and Financing

Our current primary capital resources are cash flow from our operations, the ability to enter into capital leases of up to an additional $25.7 million at March 31, 2006, the availability under our credit facility of $44.4 million at March 31, 2006 and a cash balance of $20.0 million at March 31, 2006. As of April 30, 2006, we had paid down all amounts under revolving borrowings under our 2005 Credit Facility with the proceeds from our offering of Senior Notes. During the first quarter in 2006, we financed activities in excess of cash flow from operations primarily through the use of bank debt and capital leases. In 2005, we financed activities in excess of cash flow from operations primarily through the use of bank debt and capital leases. During 2004 and 2003, we utilized bank debt and the issuance of equity for cash as consideration for acquisitions.

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


		Obligations Due in Periods Ended
		December 31,

Contractual Obligations		Total		2006		2007-2008		2009-2010		Thereafter

Long-term debt (excluding capital leases)		$	106,000	$	1,000	$	2,000	$	18,000	$	85,000
Capital leases			20,887		6,646		11,142		3,099		—
Operating leases			4,199		1,198		1,540		998		463
Rig purchase obligations			45,109		22,629		22,480		—		—
Asset retirement obligations			569		—		—		—		569
Other long-term liabilities			1,497		25		1,235		—		237

	Total	$	178,261	$	31,498	$	38,397	$	22,097	$	86,269

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

The table above does not reflect any additional payments that we may be required to make pursuant to contingent earn-out agreements that are associated with certain acquisitions. At March 31, 2006, we had a maximum potential obligation of $21.9 million related to the contingent earn-out agreements. See note 3 of the notes to our audited and unaudited historical consolidated financial statements for additional detail.

The table above also does not reflect $9.6 million of outstanding standby letters of credit issued under our revolving line of credit. At May 31, 2006, of the $150.0 million in financial commitments under the revolving line of credit under our 2005 Credit Facility, there was $140.4 million of available capacity with no outstanding balance and $9.6 million of outstanding standby letters of credit. In the normal course of business, we have performance obligations which are supported by surety bonds and letters of credit. These obligations primarily cover various reclamation and plugging obligations related to our operations, and collateral for future workers compensation and liability retained losses.

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

Senior Notes

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

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

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

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


	•	incur additional indebtedness;

	•	pay dividends or repurchase or redeem capital stock;

	•	make certain investments;

	•	incur liens;

	•	enter into certain types of transactions with affiliates;

	•	limit dividends or other payments by restricted subsidiaries; and

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

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

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

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

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


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

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

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

Credit Facilities

2005 Credit Facility

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

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

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

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

At March 31, 2006, we had outstanding $90.0 million under the Term B Loan and $96.0 million under the Revolver. However, all the outstanding balance of the Term B Loan was retired in April 2006 with proceeds from our offering of Senior Notes.

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


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

	•	50% of the proceeds from any equity offering;

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

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

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

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

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


	•	limitations on the incurrence of additional indebtedness;

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

	•	limitation on dividends and distributions;

	•	limitations on capital expenditures; and

	•	various financial covenants, including:


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

	•	a minimum interest coverage ratio of 3.00 to 1.00.

The 2005 Credit Facility contains customary events of default (which are subject to customary grace periods and materiality standards) including, among others: (1) non-payment of any amounts payable under the 2005 Credit Facility when due; (2) any representation or warrant made in connection with the 2005 Credit Facility being incorrect in any material respect when made or deemed made; (3) default in the observance or performance of any covenant, condition or agreement contained in the 2005 Credit Facility or related loan documents and such default continuing unremedied or not being waived for 30 days; (4) failure to make payments on other indebtedness involving in excess of $1.0 million; (5) voluntary or involuntary bankruptcy, insolvency or reorganization of us or any of our subsidiaries; (6) entry of fines or judgments against us for payment of an amount in excess of $2.5 million; (7) an ERISA event which could reasonably be expected to cause a material adverse effect or the imposition of a lien on any of our assets; (8) any security agreement or document under the 2005 Credit Facility ceasing to create a lien on any assets securing the 2005 Credit Facility; (9) any guarantee ceasing to be in full force and effect; (10) any material provision of the 2005 Credit Facility ceasing to be valid and binding or enforceable; (11) a change of control as defined in the 2005 Credit Agreement; or (12) any determination, ruling, decision, decree or order of any governmental authority that prohibits or restrains us and our subsidiaries from conducting business and that could reasonably be expected to cause a material adverse effect. At March 31, 2006, we were in compliance with our covenants under our 2005 Credit Facility.

2004 Credit Facility

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

2003 Credit Facility

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

was approximately $139 million. We incurred approximately $5.1 million in debt issuance costs in obtaining the 2003 Credit Facility.

2003 Refinancing Facility

In January 2003, we refinanced our then-existing credit facilities by entering into a $62 million credit facility with a capital markets group for a combination of term and revolving loans, and a $22 million revolving line of credit with a bank (collectively, the “2003 Refinancing Facility”). The interest rates on the loans under the 2003 Refinancing Facility were tied to a variable index plus a margin. At the date the 2003 Refinancing Facility was terminated and refinanced by the 2003 Credit Facility, the outstanding principal balance was approximately $54 million. We incurred approximately $2.5 million in debt issuance costs in obtaining the 2003 Refinancing Facility.

Other Debt

We have a variety of other capital leases and notes payable outstanding that are generally customary in our business. None of these debt instruments are material individually or in the aggregate. As of March 31, 2006, we had total capital leases of approximately $24.3 million.

Losses on Extinguishment of Debt

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

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

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

Credit Rating Agencies

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

Preferred Stock

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

Other Matters

Net Operating Losses

We used all of our then-available net operating losses for federal income tax purposes when we completed a recapitalization in December 2000, which included a significant amount of debt forgiveness. In 2002, our profitability suffered and, when combined with a significant level of capital expenditures, we ended 2002 with a net operating loss, or NOL, of $30.4 million. In 2003, we returned to profitability, but we again made significant investments in existing equipment, additional equipment and acquisitions. Due to these events, we again reported a tax loss in 2003 and ended the year with a $50.7 million NOL, including $7.0 million that was included in the purchase of FESCO. As of December 31, 2005, we had approximately $4.9 million of NOL carryforwards related to the pre-acquisition period of FESCO, which is subject to an annual limitation of approximately $900,000. The carryforwards begin to expire in 2017.

Recent Accounting Pronouncements

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

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

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

Impact of Inflation on Operations

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

Quantitative and Qualitative Disclosures about Market Risk

We are exposed to changes in interest rates as a result of our 2005 Credit Facility. We had a total of $106 million of indebtedness outstanding under our 2005 Credit Facility at December 31, 2005. The impact of a 1% increase in interest rates on this amount of debt would result in increased interest expense (excluding effects of our interest rate hedges) of approximately $1.1 million annually, or a decrease in net income of approximately $687,000.

However, as of April 30, 2006, we had retired all amounts outstanding under our Term B Loan and had no amounts outstanding under the Revolver.

We do not hold or issue derivative instruments for trading purposes. We did, however, previously have an interest rate derivative instrument that has been formally designated as a cash flow hedge instrument. This instrument effectively converted the variable interest payments on $65 million of our Term B Loan into fixed interest payments. This hedge was terminated in April 2006 in connection with our repayment of the Term B Loan.

The table below provides scheduled principle payments and fair value information about our market-risk sensitive instruments as of December 31, 2005 (dollars in thousands):


	Expected Year of Maturity

	2006		2007		2008		2009		2010		Thereafter		Total		Fair Value

Debt
Variable rate	$	1,000	$	1,000	$	1,000	$	1,000	$	17,000	$	85,000	$	106,000	$	106,000
Average interest rate(1)


	Average Notional Amounts Outstanding(2)

	2006			2007		2008		2009		2010		Thereafter		Total			Fair Value

Interest Rate Derivatives
Variable to Fixed	$	26,356			—		—		—		—		—	$	26,356		$	422
Average pay rate		3.03	%		—		—		—		—		—		3.03	%		N/A
Average received rate		4.83	%		—		—		—		—		—		4.83	%		N/A


(1)	At our option, borrowings under the Revolver bear interest at either (a) the “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus .5% per annum) plus a margin ranging from 0.50% to 1.25% or (b) the LIBOR rate plus a margin ranging from 1.5% to 2.25%. The margins vary depending on our leverage ratio. At December 31, 2005, our margin on Alternative Base Rates and LIBOR tranches was 0.75% and 1.75%, respectively.

(2)	The notional amounts of interest rate instruments do not represent amounts exchanged by the parties and, thus, are not a measure of our exposure to credit loss. The amounts exchanged are determined by reference to the notional amount and the other terms of the contract. The variable component of the interest rate derivative is based on the LIBOR rate using the forward yield curve as of March 6, 2006.

BUSINESS

General

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


	•	*Well Servicing.* Our well servicing segment (48% of our revenues in 2005 and 47% of our revenues in the first quarter of 2006) currently operates our fleet of over 330 well servicing rigs and related equipment. This business segment encompasses a full range of services performed with a mobile well servicing rig, including the installation and removal of downhole equipment and elimination of obstructions in the well bore to facilitate the flow of oil and gas. These services are performed to establish, maintain and improve production throughout the productive life of an oil and gas well and to plug and abandon a well at the end of its productive life. Our well servicing equipment and capabilities are essential to facilitate most other services performed on a well.

	•	*Fluid Services.* Our fluid services segment (29% of our revenues in 2005 and 28% of our revenues in the first quarter of 2006) currently utilizes our fleet of over 550 fluid services trucks and related assets, including specialized tank trucks, storage tanks, water wells, disposal facilities and related equipment. These assets provide, transport, store and dispose of a variety of fluids. These services are required in most workover, drilling and completion projects and are routinely used in daily producing well operations.

	•	*Drilling and Completion Services.* Our drilling and completion services segment (13% of our revenues in 2005 and 18% of our revenues in the first quarter of 2006) currently operates our fleet of 70 pressure pumping units, 29 air compressor packages specially configured for underbalanced drilling operations and 10 cased-hole wireline units. These services are designed to initiate or stimulate oil and gas production. The largest portion of this business consists of pressure pumping services focused on cementing, acidizing and fracturing services in niche markets. We also entered the fishing and rental tool business through an acquisition in the first quarter of 2006.

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

Our Competitive Strengths

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

Significant Market Position. We maintain a significant market share for our well servicing operations in our core operating areas throughout Texas and a growing market share in the other markets that we serve. Our fleet of over 330 well servicing rigs represents the third-largest fleet in the United States, and our goal is to be one of the top two providers of well site services in each of our core operating areas. Our market position allows us to expand the range of services performed on a well throughout its life, such as completion, maintenance, workover and plugging and abandonment services.

Modern and Active Fleet. We operate a modern and active fleet of well servicing rigs. We believe over 95% of the active U.S. well servicing rig fleet was built prior to 1985. Approximately 98, or 30%, of our rigs at March 31, 2006 were either 2000 model year or newer, or have undergone major refurbishments during the last four years. Since October 2004, we have taken delivery of 45 newbuild well servicing rigs through March 31, 2006 as part of a 102-rig newbuild commitment, driven by our desire to maintain one of the most efficient, reliable and safest fleets in the industry. The remainder of these newbuilds is scheduled to be delivered to us prior to the end of December 2007. In addition to our regular maintenance program, we have an established program to routinely monitor and evaluate the condition of our fleet. We selectively refurbish rigs and other assets to maintain the quality of our service and to provide a safe work environment for our personnel and have made major refurbishments on 46 of our rigs since the beginning of 2001. Approximately 98% of our fleet was active or available for work and the remainder was awaiting refurbishment at March 31, 2006. We believe only approximately 66% of the well servicing rig fleet of our two major competitors are active and available for work. Since 2003, we have obtained annual independent reviews and evaluations of substantially all of our assets, which confirmed the location and condition of these assets.

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

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

Decentralized Management with Strong Corporate Infrastructure. Our corporate group is responsible for maintaining a unified infrastructure to support our diversified operations through standardized financial and accounting, safety, environmental and maintenance processes and controls. Below our corporate level, we operate a decentralized operational organization in which

our seven regional managers are responsible for their regional operations, including asset management, cost control, policy compliance and training and other aspects of quality control. With an average of over 28 years of industry experience, each regional manager has extensive knowledge of the customer base, job requirements and working conditions in each local market. Below our seven regional or product line managers, our 66 area managers are directly responsible for customer relationships, personnel management, accident prevention and equipment maintenance, the key drivers of our operating profitability. This management structure allows us to monitor operating performance on a daily basis, maintain financial, accounting and asset management controls, integrate acquisitions, prepare timely financial reports and manage contractual risk.

Our Business Strategy

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

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

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

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

Pursue Growth Through Selective Capital Deployment. We intend to continue growing our business through selective acquisitions, continuing a newbuild program and/or upgrading our existing assets. Our capital investment decisions are determined by an analysis of the projected return on capital employed of each of those alternatives. Acquisitions are evaluated for “fit” with our area and regional operations management and are thoroughly reviewed by corporate level financial, equipment, safety and environmental specialists to ensure consideration is given to identified risks. We also evaluate the cost to acquire existing assets from a third party, the capital required to build new equipment and the point in the oil and gas commodity price cycle. Based on these factors, we make capital investment decisions that we believe will support our long-term growth strategy, and these decisions may involve a combination of asset acquisitions and the purchase of new equipment. In 2005, we completed eight separate acquisitions for an aggregate purchase price of $25.4 million net of cash acquired, and took delivery of 31 new well servicing rigs. In the first quarter of 2006, we completed three separate acquisitions for an aggregate purchase price of $87.5 million net of cash acquired, and took delivery of 10 new well servicing rigs.

General Industry Overview


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

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

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


	Cushing WTI Spot		Average Wellhead Price
Period	Oil Price ($/bbl)		Natural Gas ($mcf)

1/1/99 — 12/31/99	$	19.34	$	2.19
1/1/00 — 12/31/00		30.38		3.69
1/1/01 — 12/31/01		25.97		4.01
1/1/02 — 12/31/02		26.18		2.95
1/1/03 — 12/31/03		31.08		4.98
1/1/04 — 12/31/04		41.51		5.49
1/1/05 — 12/31/05		56.64		7.51
1/1/06 — 3/31/06		63.27		7.49

Source: U.S. Department of Energy.

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

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

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

Our business is influenced substantially by both operating and capital expenditures by oil and gas companies. Because existing oil and gas wells require ongoing spending to maintain production, expenditures by oil and gas companies for the maintenance of existing wells are relatively stable and predictable compared to exploration and drilling expenditures. In contrast,

capital expenditures by oil and gas companies for drilling are more directly influenced by current and expected oil and gas prices and generally reflect the volatility of commodity prices.

Overview of Our Segments and Services

Well Servicing Segment

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


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

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

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

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 332 well service rigs as of March 31, 2006, including 45 newbuilds since October 2004 and 46 rebuilds since the beginning of 2001. We operate from more than 90 facilities in Texas, Wyoming, Oklahoma, New Mexico, Louisiana, Colorado, Montana, North Dakota, Arkansas and Utah, most of which are used jointly for our business segments. Our rigs are mobile units that generally operate within a radius of approximately 75 to 100 miles from their respective bases. Prior to December 2004, our well servicing segment consisted entirely of land-based equipment. During December 2004, we acquired three inland barges, two of which are equipped with rigs, have been refurbished and were placed into service in the second quarter of 2005. Inland barges are used to service wells in shallow water marine environments, such as coastal marshes and bays.

The following table sets forth the location, characteristics and number of the well servicing rigs that we operated at March 31, 2006. We categorize our rig fleet by the rated capacity of the mast, which indicates the maximum weight that the rig is capable of lifting. This capability is the limiting factor in our ability to provide services. These figures do not include 57 new well

servicing rigs that we have contracted for delivery from April 2006 through December 2007 as part of a 102-rig newbuild commitment:


			Operating Division

			Permian		South		Ark-		Mid-		Northern		Southern
Rig Type		Rated Capacity	Basin		Texas		La-Tex		Continent		Rockies		Rockies		Stacked		Total

Swab		N/A		3		1		8		4		0		0		0		16
Light Duty		<90 tons		6		2		0		24		2		0		2		36
Medium Duty		>90-125 tons		93		34		20		40		16		16		1		220
Heavy Duty		³125 tons		27		3		6		4		6		3		2		51
24-Hour		³125 tons		1		4		0		0		0		0		0		5
Drilling Rigs		³125 tons		0		0		0		0		0		2		0		2
Inland Barge		³125 tons		0		0		2		0		0		0		0		2

	Total	128		130		44		36		72		24		21		5		332

Management currently estimates that there are approximately 3,500 onshore well servicing rigs currently in the U.S., owned by an estimated 125 contractors, and that the actual number that are actively marketed and operable without major capital expenditures may be as much as 20% lower than this estimate. Based on information from U.S. contractors reporting their utilization to Weatherford-AESC, there were 2,508 well servicing rigs working in May 2006. This figure represents a projected utilization rate of 92% for the available fleet that are operable without major capital expenditures.

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

Based on the most recent publicly available information, our two largest competitors own a combined 2,053 rigs of which 1,351 are operated and 702 are stacked. These two competitors’ total rigs represent approximately 59% of the industry’s total fleet. We have the third-largest fleet with over 340 rigs, or over 10% of the overall available U.S. industry’s fleet. Due to the fragmented nature of the market, we believe only one company other than us and our two larger competitors owns more than 50 rigs (with a total of only approximately 135 rigs) and a total of an estimated 120 companies own the approximately 900 estimated remaining well servicing rigs, or approximately 26% of the industry’s total fleet.

Maintenance. Regular maintenance is generally required throughout the life of a well to sustain optimal levels of oil and gas production. We believe regular maintenance comprises the largest portion of our work in this business segment. We provide well service rigs, equipment and crews for these maintenance services. Maintenance services are often performed on a series of wells in proximity to each other. These services consist of routine mechanical repairs necessary to maintain production, such as repairing inoperable pumping equipment in an oil well or replacing defective tubing in a gas well, and removing debris such as sand and paraffin from the well. Other services include pulling the rods, tubing, pumps and other downhole equipment

out of the well bore to identify and repair a production problem. These downhole equipment failures are typically caused by the repetitive pumping action of an oil well. Corrosion, water cut, grade of oil, sand production and other factors can also result in frequent failures of downhole equipment.

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

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

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

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

Plugging and Abandonment. Well servicing rigs are also used in the process of permanently closing oil and gas wells no longer capable of producing in economic quantities. Plugging and abandonment work can be performed with a well servicing rig along with wireline and cementing equipment; however, this service is typically provided by companies that specialize in plugging and abandonment work. Many well operators bid this work on a “turnkey”

basis, requiring the service company to perform the entire job, including the sale or disposal of equipment salvaged from the well as part of the compensation received, and complying with state regulatory requirements. Plugging and abandonment work can provide favorable operating margins and is less sensitive to oil and gas pricing than drilling and workover activity since well operators must plug a well in accordance with state regulations when it is no longer productive. We perform plugging and abandonment work throughout our core areas of operation in conjunction with equipment provided by other service companies.

Fluid Services Segment

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


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

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

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

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

This segment utilizes our fleet of fluid services trucks and related assets, including specialized tank trucks, portable storage tanks, water wells, disposal facilities and related equipment. The following table sets forth the type, number and location of the fluid services equipment that we operated at March 31, 2006:


	Operating Division

	Northern		Permian		Ark-		South		Mid-
	Rockies		Basin		La-Tex		Texas		Continent		Stacked		Total

Fluid Services Trucks		82		126		182		120		38		6		554
Salt Water Disposal Wells		—		12		20		8		7		—		47
Fresh/ Brine Water Stations		—		28		—		3		1		—		32
Fluid Storage Tanks		213		271		681		253		63		—		1,481

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

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

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

logistics — specifically, proximity between areas where salt water is produced and our company owned disposal wells. Ownership of disposal wells eliminates the need to pay third parties a fee for disposal. We operate salt water disposal wells in most of our markets.

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

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

Fluid Services and Support Trucks. We currently own and operate over 550 fluid service tank trucks equipped with a fluid hauling capacity of up to 150 barrels. Each fluid service truck is equipped to pump fluids from or into wells, pits, tanks and other storage facilities. The majority of our fluid service trucks are also used to transport water to fill frac tanks on well locations, including frac tanks provided by us and others, to transport produced salt water to disposal wells, including injection wells owned and operated by us, and to transport drilling and completion fluids to and from well locations. In conjunction with the rental of our frac tanks, we generally use our fluid service trucks to transport water for use in fracturing operations. Following completion of fracturing operations, our fluid service trucks are used to transport the flowback produced as a result of the fracturing operations from the well site to disposal wells. Fluid services trucks are generally provided to oilfield operators within a 50-mile radius of our nearest yard. Our “hot oil” trucks are used to remove paraffin, a by-product of oil production in many fields, from the well bore. If paraffin is left untreated, it can inhibit a well’s production. Our support trucks are used to move our fluid storage tanks and other equipment to and from the job sites of our customers.

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

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

Fluid Storage Tanks. Our fluid storage tanks can store up to 500 barrels of fluid and are used by oilfield operators to store various fluids at the well site, including water, brine, drilling mud and acid for frac jobs, flowback, temporary production and mud storage. We transport the tanks on our trucks to well locations that are usually within a 50-mile radius of our nearest yard. Frac tanks are used during all phases of the life of a producing well. We generally rent fluid services tanks at daily rates for a minimum of three days. A typical fracturing operation can be completed within four days using 10 to 40 frac tanks.

Drilling and Completion Services Segment

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


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

	•	cased-hole wireline services;

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

	•	oilfield services fishing and rental tool business.

This segment currently operates 70 pressure pumping units to conduct a variety of services designed to stimulate oil and gas production or to enable cement slurry to be placed in or circulated within a well. As of March 31, 2006, we also operated 29 air compressor packages, including foam circulation units, for underbalanced drilling and 10 wireline units for cased-hole measurement and pipe recovery services.

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

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

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

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

As a well is drilled, long intervals of rock are left exposed and unprotected. In order to prevent the exposed rock from caving and to prevent fluids from entering or leaving the exposed

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

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

The following table sets forth the type, number and location of the drilling and completion services equipment that we operated at March 31, 2006:


	Operating Division

	Ark-		Mid-		Northern		Southern
	La-Tex		Continent		Rockies		Rockies		Total

Pressure Pumping Units		12		55		3		—		70
Coiled Tubing Units		—		2		1		—		3
Air/ Foam Packages		—		—		—		29		29
Wireline Units		—		10		—		—		10

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

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

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

Underbalanced drilling services, unlike pressure pumping and wireline services, are not utilized universally throughout oil and gas operations. Underbalanced drilling is a technique that

involves maintaining the pressure in a well at or slightly below that of the surrounding formation using air, nitrogen, mist, foam or lightweight drilling fluids instead of conventional drilling fluid. Underbalanced drilling services are utilized in areas where conventional drilling fluids or stimulation techniques will severely damage the producing formation or in areas where drilling performance can be substantially improved with a lightened drilling fluid. In these cases, the drilling fluid is lightened to make the natural pressure of the formation greater than the hydrostatic pressure of the drilling fluid, thereby creating a situation where pressure is forcing fluid out of the formation (i.e., underbalanced) as opposed to into the formation (i.e., over balanced). The most common method of lightening drilling fluid is to mix it with air as the fluid is pumped into the well. By varying the volume of air pumped with the fluid, the net hydrostatic pressure can be adjusted to the desired level. In extreme cases, air alone can be used to circulate rock cuttings from the well.

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

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

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

Well Site Construction Services Segment

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


	•	preparation and maintenance of access roads;

	•	building of drilling locations;

	•	installation of small gathering lines and pipelines; and

	•	maintenance of production facilities.

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

range of services, coupled with our fluid service capabilities in the same markets, differentiates us from our more specialized competitors.

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

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

Properties

Our principal executive offices are currently located at 400 W. Illinois, Suite 800, Midland, Texas 79701. During 2005 we also purchased and are currently renovating a facility in Midland County, Texas to consolidate our corporate office and to expand our refurbishment capacities. We currently conduct our business from 91 area offices, 47 of which we own and 44 of which we lease. Each office typically includes a yard, administrative office and maintenance facility. Of our 91 area offices, 63 are located in Texas, seven are in Oklahoma, five are in Wyoming, four are in New Mexico, four are in Colorado, two are in Louisiana, two are in Montana, two are in North Dakota, one is in Arkansas and one is in Utah.

Customers

We serve numerous major and independent oil and gas companies that are active in our core areas of operations. During 2005 and the first quarter of 2006, we provided services to more than 1,000 customers, with our top five customers comprising only 16% and 14% of our revenues, respectively. The majority of our business is with independent oil and gas companies. While we believe we could redeploy equipment in the current market environment if we lost a single material customer, or a few of them, such loss could have an adverse effect on our business until the equipment is redeployed.

Operating Risks and Insurance

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


	•	personal injury or loss of life;

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

	•	suspension of operations.

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

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

Despite our efforts to maintain high safety standards, we from time to time have suffered accidents in the past and anticipate that we could experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability and our relationships with customers, employees and regulatory agencies. Any significant increase in the frequency or severity of these incidents, or the general level of compensation awards, could adversely affect the cost of, or our

ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations.

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

Competition

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

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

Safety Program

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

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

Environmental Regulation

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

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

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

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

disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination. We believe that we are in substantial compliance with the requirements of CERCLA and RCRA.

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

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

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

We maintain insurance against some risks associated with underground contamination that may occur as a result of well service activities. However, this insurance is limited to activities at the wellsite and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us.

The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.

We are also subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes that regulate the protection of the health and safety of workers. 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 March 31, 2006, we employed approximately 3,700 people, with approximately 85% employed on an hourly basis. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements, and we consider our relations with our employees to be satisfactory.

Litigation

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

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

On December 6, 2004, Karon Smith, et al commenced a civil action against us in the District Court of Hidalgo County, Texas, 206th Judicial District, Karon Smith, et al v. Basic Energy Services GP L.L.C., Cause No. C-42767-04-D. The complaint alleged that (i) one of our fluid services truck drivers disposed of oil-based waste at the plaintiff’s waste disposal facility, which was not equipped to accept oil-based waste, and (ii) the disposal of such oil-based waste resulted in plaintiff’s facility losing contracts to accept waste. On July 25, 2005, the jury in this case returned a verdict in favor of the plaintiff and awarded damages in the amount of $1.2 million. Our insurance company to date has denied coverage of liability in this lawsuit. In March 2006, we reached a settlement of this matter in mediation for $1.0 million, which we had previously recorded in accrued liabilities as of December 31, 2005.

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

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

MANAGEMENT

Directors, Executive Officers and Other Key Employees

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


Name	Age		Position

Steven A. Webster		54	Chairman of the Board
Kenneth V. Huseman		54	President, Chief Executive Officer and Director
Alan Krenek		51	Senior Vice President, Chief Financial Officer, Treasurer and Secretary
Charles W. Swift.		56	Senior Vice President — Rig and Truck Operations
Dub W. Harrison		47	Vice President — Equipment & Safety
Mark D. Rankin		52	Vice President — Risk Management
James E. Tyner		55	Vice President — Human Resources
James S. D’Agostino, Jr.		59	Director
William E. Chiles		57	Director
Robert F. Fulton		54	Director
Sylvester P. Johnson, IV		50	Director
Thomas P. Moore, Jr.		67	Director
H. H. Wommack, III		50	Director

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

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

Kenneth V. Huseman (President — Chief Executive Officer and Director) has 26 years of well servicing experience. He has been our President, Chief Executive Officer and Director since 1999. Prior to joining us, he was Chief Operating Officer at Key Energy Services from 1996 to 1999. He was a Divisional Vice President at WellTech, Inc. from 1993 to 1996. He was a Vice President of Operations at Pool Energy Services Co. from 1982 to 1993, where he managed

operations throughout the United States, including drilling operations in Alaska. Mr. Huseman graduated with a B.B.A. degree in Accounting from Texas Tech University.

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

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

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

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

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

James S. D’Agostino, Jr. (Director) has served as a director since February 2004. Mr. D’Agostino has served as Chairman of the Board, President and Chief Executive Officer of Encore Bank since November 1999, during which time he initiated turnaround efforts and raised over $30 million of new equity to create a unique private banking organization. From 1998 to 1999, Mr. D’Agostino served as Vice Chairman and Group Executive and from 1997 until 1998, he served as President, Member of the Office of Chairman and Director of American General Corporation. Mr. D’Agostino graduated with an economics degree from Villanova University and a J.D. from Seton Hall University School of Law.

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

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

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

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

H. H. Wommack, III (Director) has served as a director since 1992. Mr. Wommack was our founder and our Chairman of the Board from 1992 until January 2001. Mr. Wommack is currently a principal of and Chief Executive Officer of Saber Resources, LLC, a privately held oil and gas company that he founded in May 2004. Mr. Wommack served as Chairman of the Board, President, Chief Executive Officer and a Director of Southwest Royalties Holdings, Inc. from its

formation in July 1997 until April 2005 and of Southwest Royalties, Inc. from its formation in 1983 until its sale in May 2004. Prior to the formation of Southwest Royalties, Mr. Wommack was a self-employed independent oil and gas producer. Mr. Wommack is currently Chairman of the Board of Midland Red Oak Realty, a commercial real estate company involved in investments in the Southwest. Mr. Wommack is also currently the President of Fortress Holdings, LLC and Anchor Resources, LLC. He graduated with a B.A. from the University of North Carolina and a J.D. from the University of Texas School of Law.

Board of Directors

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

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


	•	Class II — Messrs. Chiles and Fulton;

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

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

Committees

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

Audit Committee

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


	•	to appoint, engage and terminate our independent auditors;

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

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

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


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

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

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

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

Nominating and Corporate Governance Committee

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


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

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

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

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

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

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

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

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

Compensation Committee

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


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

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

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


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

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

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

Web Access

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

Compensation Committee Interlocks and Insider Participation

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

Compensation of Executive Officers

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


								Long-Term
		Annual						Compensation
		Compensation(1)
								Restricted		Securities
		Fiscal						Stock		Underlying		All Other
Name and Principal Position		Year		Salary		Bonus		Awards(2)		Options		Compensation(3)

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


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

(2)	Shares of restricted stock were granted to the named executive officers during 2004 as follows: Huseman — 450,000 shares; Carter — 100,000 shares; Swift — 50,000 shares; and Harrison — 50,000 shares. The fair market value as of the date of grant of the shares of restricted stock during February 2004, as determined by our board of directors, was $6.98. These shares are subject to vesting in one-fourth increments on each of February 24, 2005, 2006, 2007 and 2008 for each person other than Mr. Carter, whose shares vested one-half on February 24, 2005 and one-half on February 24, 2006. Cash dividends, if any are paid, would be payable on these shares of restricted stock, but we will retain any stock dividends applicable to these shares until the vesting period is satisfied on the shares on which the stock dividend is issued. For information concerning grants of and the aggregate holdings of restricted stock by the named executive officers, see “Employment Agreements” below. For information regarding repurchases of shares of restricted stock by us from the named executive officers and other officers during 2005 and 2006, see “Certain Relationships and Related Party Transactions” below.

(3)	For 2005, includes: for Mr. Huseman, deferred compensation contributions of $1,600; for Mr. Krenek, moving related allowance of $52,331; for Mr. Carter, deferred compensation contributions of $1,288; for Mr. Swift, vehicle allowance of $9,600 and deferred compensation contributions of $4,800; and for Mr. Harrison, vehicle allowance of $9,600 and deferred compensation contributions of $640. For 2004 includes: for Mr. Huseman, vehicle allowance of $2,308; for each of Mr. Swift and Mr. Harrison, vehicle allowance of $9,600. For 2003 includes:


	for Mr. Huseman, vehicle allowance of $12,000 and life insurance costs of $4,955; for each of Mr. Swift and Mr. Harrison, vehicle allowance of $9,600.

(4)	Mr. Krenek has served as our Chief Financial Officer since January 2005.

(5)	Mr. Carter, our former Executive Vice President and Secretary, retired effective April 30, 2006.

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

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


	Number of Shares
	Underlying Unexercised				Value of Unexercised
	Options at				In-the-Money Options at
	December 31, 2005				December 31, 2005

	Exercisable		Unexercisable		Exercisable		Unexercisable

Kenneth V. Huseman		399,755		166,650	$	6,376,092	$	2,360,068
Alan Krenek		—		125,000		—		1,803,450
James J. Carter		128,720		50,000		2,053,084		708,100
Dub W. Harrison		89,560		41,665		1,428,482		590,057
Charles W. Swift.		89,560		51,665		1,428,482		719,757

Option Grants in Last Fiscal Year

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


	Individual Grants
										Potential Realizable
			% of Total							Value at Assumed
	Number of		Options							Annual Rates of Stock
	Securities		Granted to		Exercise					Price Appreciation for
	Underlying		Employees		or Base					Option Term
	Options		in Fiscal		Price		Expiration
Name	Granted(#)(1)		Year(2)		($/Sh)		Date			5%($)		10%($)

Kenneth V. Huseman		100,000		10.2		6.98		3/1/2015		$	1,383,727	$	2,616,803
Alan Krenek(3)		125,000		12.7		5.52		(4	)		1,398,557		2,635,975
James J. Carter		30,000		3.1		6.98		3/1/2015			415,118		785,041
Charles W. Swift		35,000		3.6		6.98		3/1/2015			484,305		915,881
Dub W. Harrison		25,000		2.5		6.98		3/1/2015			345,932		654,201


(1)	Except as provided in note (3) below, all options reflected in the table were earned in fiscal 2005 and granted on March 2, 2005. No stock appreciation rights (“SARs”) were granted in tandem with the options reflected in this table. Except as provided in note (3) below, these options vest in equal one-fourth increments on each of January 1, 2007, 2008, 2009 and 2010.

(2)	Reflects the percentage of total options granted in fiscal 2005.

(3)	Includes options to purchase 100,000 shares of common stock granted to Mr. Krenek on January 26, 2005 in connection with the commencement of his employment with us. These options vest in equal one-third increments on each of January 26, 2006, 2007 and 2008.


(4)	Options to purchase 100,000 shares of common stock expire on January 25, 2015 and options to purchase 25,000 shares of common stock expire on March 1, 2015.

Compensation of Directors

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

Second Amended and Restated 2003 Incentive Plan

Our 2003 Incentive Plan, which was adopted by our Board of Directors and has been approved by our stockholders as amended, covers stock awards issued under our original 2003 Incentive Plan and predecessor equity plan. This incentive plan permits the granting of any or all of the following types of awards:


	•	stock options;

	•	restricted stock;

	•	performance awards;

	•	phantom shares;

	•	other stock-based awards;

	•	bonus shares; and

	•	cash awards.

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

The number of shares with respect to which awards may be granted under the 2003 Incentive Plan may not exceed 5,000,000 shares, of which awards for 3,680,050 shares have been issued as of March 31, 2006. The incentive plan will be administered by the compensation committee of our board of directors. The compensation committee will select the participants who will receive awards, determine the type and terms of the awards to be granted and interpret and administer the incentive plan. No awards may be granted under the incentive plan after April 12, 2014.

The options granted pursuant to the 2003 Incentive Plan may be either incentive options qualifying for beneficial tax treatment for the recipient as “incentive stock options” under Section 422 of the Code or non-qualified options. No person may be issued incentive stock options that first become exercisable in any calendar year with respect to shares having an aggregate fair market value, at the date of grant, in excess of $100,000. No incentive stock option may be granted to a person if at the time such option is granted the person owns stock

possessing more than 10% of the total combined voting power of all classes of our stock or any of our subsidiaries as defined in Section 424 of the Code, unless at the time incentive stock options are granted the purchase price for the option shares is at least 110% of the fair market value of the option shares on the date of grant and the incentive stock options are not exercisable five years after the date of grant.

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

Tax Treatment for Our 2003 Incentive Plan

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

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

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

disposition of the shares over (b) the option exercise price of such shares, will be ordinary income to the optionee, and we generally will be entitled to a federal income tax deduction in the amount of such income. The balance, if any, of the optionee’s gain upon a disqualifying disposition will qualify as capital gain and will not result in any deduction by us.

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

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

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

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

Employment Agreements

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

Mr. Huseman’s bonus in 2005 was unanimously approved by our Board of Directors, including the independent directors. In 2005 the Board of Directors approved the payment of a

$275,000 bonus to Mr. Huseman, and the Board has approved a salary for Mr. Huseman effective in March 2006 of $400,000.

We have also entered into employment agreements with Dub W. Harrison and Charles W. Swift, as amended in July 2006, for a term through June 2009, and with James E. Tyner through January 2007. Pursuant to the July 2006 amendments, Mr. Harrison is entitled to an annual salary of $150,000 and Mr. Swift is entitled to an annual salary of $200,000. Mr. Tyner is entitled to an annual salary of $110,000 under his employment agreement. Under these agreements, if the officer’s employment is terminated for certain reasons, he would be entitled to a lump sum severance payment equal to six months’ salary, or 18 months’ salary (12 months’ salary in the case of Mr. Tyner) if termination is on or following a change of control of our company. The Board approved a 2006 salary for Mr. Tyner effective in March 2006 of $140,000.

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

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

Indemnification Agreements

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

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

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


	•	us, except for:


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

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

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


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

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

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Transactions with Officers and Directors

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

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

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

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

Summary of Certain Equity Issuances

During the past three years, we have completed the following issuances of equity, including to affiliates and other selling stockholders participating in this offering, outside the issuance of awards pursuant to our 2003 Incentive Plan and the exchange of shares in our holding company reorganization on January 24, 2003 described in this prospectus under “The Company.” We

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

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

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

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

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

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

Relationships with Certain Directors

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

PRINCIPAL STOCKHOLDERS

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


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

	•	each of our named executive officers;

	•	each of our directors; and

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

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


	Shares Beneficially
	Owned

Name of Beneficial Owner	Number		Percent

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


	*	Less than one percent.


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


		186,820 shares); DLJ Merchant Banking III, Inc., as Advisory General Partner on behalf of DLJ Offshore Partners III-1, C.V. and as attorney-in-fact for DLJ Merchant Banking III, L.P., as Associate General Partner of DLJ Offshore Partners III-1, C.V. (147,981 shares and warrants exercisable for 48,285 shares); DLJ Merchant Banking III, Inc., as Advisory General Partner on behalf of DLJ Offshore Partners III-2, C.V. and as attorney-in-fact for DLJ Merchant Banking III, L.P., as Associate General Partner of DLJ Offshore Partners III-2, C.V. (105,421 shares and warrants exercisable for 34,395 shares); DLJMB Partners III GmbH & Co. KG (81,518 shares and warrants exercisable for 26,380 shares); DLJMB Funding III, Inc. (132,220 shares); Millennium Partners II, L.P. (16,211 shares and warrants exercisable for 5,305 shares); MBP III Plan Investors, L.P. (1,465,551 shares and warrants exercisable for 913,500 shares).

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

All of the DLJ Merchant Banking entities can be contacted at Eleven Madison Avenue, New York, New York 10010-3629 except for the three “Offshore Partners” entities, which can be contacted at John B. Gosiraweg, 14, Willemstad, Curacao, Netherlands Antilles.


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

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


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

	(4)	Includes 477,366 shares owned directly by Southwest Partners II, L.P. and 957,070 shares owned directly by Southwest Partners III, L.P. Anchor Resources, LLC, controls the vote of all shares owned by Southwest Partners II, L.P. and Southwest Partners III, L.P. as managing general partner of each of the two partnerships. The number of beneficially owned shares and percentage of class listed above reflect this control. Anchor Resources, LLC owns a 15% managing general partner interest and a 1.7% limited partner interest in


		Southwest Partners II. No other person owns 5% or more of the partnership interests in Southwest Partners II. Anchor Resources, LLC owns a 15% managing general partner interest and a 0.2% limited partner interest in Southwest Partners III. No other person owns 5% or more of the partnership interests in Southwest Partners III. Mr. Wommack, our director, is also a director and President of Anchor Resources, LLC. The members of Anchor Resources, LLC who beneficially own 5% or more of the units of Anchor Resources, LLC are Bosworth & Co., Fortress Holdings, LLC, Harvard & Co., Bear Stearns Securities Corp., and Cudd & Co., who own approximately 25%, 23%, 13%, 11% and 10% of its units, respectively.

	(5)	Includes 307,025 shares of restricted stock, of which 225,000 remain subject to vesting in one-half increments on February 24, 2007 and 2008, and 466,405 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 160,000 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan. Also includes an aggregate of 91,060 shares owned directly by the Kenneth V. Huseman Grantor Retained Annuity Trust and the Jaye M. Huseman Grantor Retained Annuity Trust.

	(6)	Includes 33,335 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 116,665 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.

	(7)	Includes 56,770 shares of restricted stock, which are fully vested. Mr. Carter resigned effective April 30, 2006.

	(8)	Includes 34,259 shares of restricted stock, of which 25,000 remain subject to vesting in one-half increments on February 24, 2007 and 2008, and 91,225 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 40,000 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.

	(9)	Includes 41,282 shares of restricted stock, of which 25,000 remain subject to vesting in one-half increments on February 24, 2007 and 2008, and 102,225 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 50,000 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.


(10)	Includes 62,500 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 35,000 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.

(11)	Includes 31,670 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 45,830 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.

(12)	Includes 35,000 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 47,500 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.

(13)	Does not include 42,500 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.

(14)	Includes 62,500 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 35,000 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan. Also reflects the beneficial ownership of an aggregate of 2,101,641 shares beneficially owned by Fortress Holdings, LLC and Anchor Resources, LLC. H. H. Wommack, III is a significant unitholder of Fortress Holdings, LLC and a director, manager and the President of each of Fortress


	Holdings, LLC and Anchor Resources, LLC with the intercompany relationships discussed in footnotes 3 and 4 above. Mr. Wommack disclaims beneficial ownership of the shares beneficially owned directly by Fortress Holdings, LLC and indirectly by Anchor Resources, LLC other than to the extent of his pecuniary interest in such shares.

(15)	Includes an aggregate of 454,336 restricted shares, of which 275,000 remain subject to vesting, and an aggregate of 1,062,200 shares issuable within 60 days upon the exercise of options granted under our 2003 Incentive Plan. Does not include 754,155 shares underlying options that are not exercisable within 60 days granted under our 2003 Incentive Plan.

DISTRIBUTING STOCKHOLDERS

The following table and related footnotes set forth certain information regarding the stockholders. The number of shares in the column “Number of Shares Offered” represents all of the shares that each distributing stockholder may offer and distribute under this prospectus. To our knowledge, each of the distributing stockholders has sole voting and investment power as to the shares shown, except as disclosed in this prospectus. Beneficial ownership as shown in the table below has been determined in accordance with the applicable rules and regulations promulgated under the Exchange Act. Except as noted in this prospectus, none of the distributing stockholders is a director, officer or employee of ours or an affiliate of such person.


	Beneficial							Beneficial
	Ownership Prior to							Ownership After
	the Distribution							the Distribution
						Number
	Number		Percent			of Shares		Number		Percent
Distributing Stockholders	of Shares		of Class			Distributed		of Shares		of Class

Fortress Holdings, LLC(1)		667,205		2.0	%		667,205		0		0	%
Southwest Partners II, L.P.(1)		477,366			(1)		477,366		0		0
Southwest Partners III, L.P.(1)		957,070			(1)		957,070		0		0


*	Less than one percent.


(1)	See footnotes (3) and (4) under the table for “Principal Stockholders” and related beneficial ownership disclosure in table.

DESCRIPTION OF CAPITAL STOCK

Upon the completion of this offering, our authorized capital stock will consist of:


	•	80,000,000 shares of common stock, $0.01 par value; and

	•	5,000,000 shares of preferred stock, $0.01 par value, none of which are currently designated.

As of August 2, 2006, there were 33,827,015 shares of common stock and no shares of preferred stock outstanding.

The following summarizes the material provisions of our capital stock and important provisions of our certificate of incorporation and bylaws. This summary is qualified by our certificate of incorporation and bylaws, copies of which have been filed as exhibits to the registration statement of which this prospectus is a part and by the provisions of applicable law.

Common Stock

Holders of common stock are entitled to one vote per share on all matters to be voted upon by the stockholders. Because holders of common stock do not have cumulative voting rights, the holders of a majority of the shares of common stock can elect all of the members of the board of directors standing for election. The holders of common stock are entitled to receive dividends as may be declared by the board of directors. Upon our liquidation, dissolution or winding up, and subject to any prior rights of outstanding preferred stock, the holders of our common stock will be entitled to share pro rata in the distribution of all of our assets available for distribution to our stockholders after satisfaction of all of our liabilities and the payment of the liquidation preference of any preferred stock that may be outstanding. There are no redemption or sinking fund provisions applicable to the common stock. All outstanding shares of common stock are fully paid and non-assessable. The holders of our common stock will have no preemptive or other subscription rights to purchase our common stock.

Preferred Stock

Subject to the provisions of the certificate of incorporation and limitations prescribed by law, the board of directors will have the authority to issue up to 5,000,000 shares of preferred stock in one or more series and to fix the rights, preferences, privileges and restrictions of the preferred stock, including dividend rights, dividend rates, conversion rates, voting rights, terms of redemption, redemption prices, liquidation preferences and the number of shares constituting any series or the designation of the series, which may be superior to those of the common stock, without further vote or action by the stockholders. We have no present plans to issue any shares of preferred stock.

One of the effects of undesignated preferred stock may be to enable the board of directors to render more difficult or to discourage an attempt to obtain control of us by means of a tender offer, proxy contest, merger or otherwise, and, as a result, protect the continuity of our management. The issuance of shares of the preferred stock under the board of directors’ authority described above may adversely affect the rights of the holders of common stock. For example, preferred stock issued by us may rank prior to the common stock as to dividend rights, liquidation preference or both, may have full or limited voting rights and may be convertible into shares of common stock. Accordingly, the issuance of shares of preferred stock may discourage bids for the common stock or may otherwise adversely affect the market price of the common stock.

Warrants

There are currently outstanding warrants held by DLJ Merchant Banking to purchase up to 4,350,000 shares of our common stock. These warrants are exercisable at a purchase price of $4.00 per share. Warrants to purchase 600,000 shares expire on February 13, 2007 and warrants to purchase 3,750,000 shares expire on June 30, 2007. These warrants were issued by us in 2002 in connection with the issuance and sale by us of our common stock and preferred stock.

Provisions of Our Certificate of Incorporation and Bylaws


	*Written Consent of Stockholders*

Our certificate of incorporation and bylaws provide that any action required or permitted to be taken by our stockholders must be taken at a duly called meeting of stockholders and not by written consent.


	*Amendment of the Bylaws*

Under Delaware law, the power to adopt, amend or repeal bylaws is conferred upon the stockholders. A corporation may, however, in its certificate of incorporation also confer upon the board of directors the power to adopt, amend or repeal its bylaws. Our charter and bylaws grant our board the power to adopt, amend and repeal our bylaws on the affirmative vote of a majority of the directors then in office. Our stockholders may adopt, amend or repeal our bylaws but only at any regular or special meeting of stockholders by the holders of not less than 66²/3 % of the voting power of all outstanding voting stock.


	*Special Meetings of Stockholders*

Our bylaws preclude the ability of our stockholders to call special meetings of stockholders.


	*Other Limitations on Stockholder Actions*

Advance notice is required for stockholders to nominate directors or to submit proposals for consideration at meetings of stockholders. In addition, the ability of our stockholders to remove directors without cause is precluded.


	*Classified Board*

Only one of three classes of directors is elected each year. See “Management — Board of Directors.”


	*Limitation of Liability of Officers and Directors*

Our certificate of incorporation provides that no director shall be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except for liability as follows:


	•	for any breach of the director’s duty of loyalty to us or our stockholders;

	•	for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of laws;

	•	for unlawful payment of a dividend or unlawful stock purchase or stock redemption; and

	•	for any transaction from which the director derived an improper personal benefit.

The effect of these provisions is to eliminate our rights and our stockholders’ rights, through stockholders’ derivative suits on our behalf, to recover monetary damages against a director for

a breach of fiduciary duty as a director, including breaches resulting from grossly negligent behavior, except in the situations described above.


	*Business Combination Under Delaware Law*

We are subject to the provisions of Section 203 of the Delaware General Corporation Law. In general, Section 203 prohibits a publicly held Delaware corporation from engaging in a “business combination” with an “interested stockholder” for a period of three years after the date of the transaction in which the person became an interested stockholder, unless the business combination is approved in a prescribed manner.

Section 203 defines a “business combination” as a merger, asset sale or other transaction resulting in a financial benefit to the interested stockholders. Section 203 defines an “interested stockholder” as a person who, together with affiliates and associates, owns, or, in some cases, within three years prior, did own, 15% or more of the corporation’s voting stock. Under Section 203, a business combination between us and an interested stockholder is prohibited unless:


	•	our board of directors approved either the business combination or the transaction that resulted in the stockholders becoming an interested stockholder prior to the date the person attained the status;

	•	upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of our voting stock outstanding at the time the transaction commenced, excluding, for purposes of determining the number of shares outstanding, shares owned by persons who are directors and also officers and issued employee stock plans, under which employee participants do not have the right to determine confidentially whether shares held under the plan will be tendered in a tender or exchange offer; or

	•	the business combination is approved by our board of directors on or subsequent to the date the person became an interested stockholder and authorized at an annual or special meeting of the stockholders by the affirmative vote of the holders of at least 66²/3 % of the outstanding voting stock that is not owned by the interested stockholder.

This provision has an anti-takeover effect with respect to transactions not approved in advance by our board of directors, including discouraging takeover attempts that might result in a premium over the market price for the shares of our common stock. With approval of our stockholders, we could amend our certificate of incorporation in the future to elect not to be governed by the anti-takeover law. This election would be effective 12 months after the adoption of the amendment and would not apply to any business combination between us and any person who became an interested stockholder on or before the adoption of the amendment.

Registration Rights

Under the terms of our Second Amended and Restated Stockholders’ Agreement dated as of April 2, 2004, DLJ Merchant Banking has demand rights to require us to register shares of our common stock. These stockholders may require us to register shares of common stock on up to three occasions after the completion of an initial public offering, provided that the proposed offering proceeds for the offering equal or exceed $10 million (or $5 million if we are able to register on Form S-3). Under this agreement, Fortress Holdings, LLC, Southwest Partners II, L.P. and Southwest Partners III, L.P., which we call the “Southwest Parties,” also currently have demand rights to require us to register shares of our common stock. The Southwest Parties may make one request to us to register shares of our common stock, provided that the proceeds from the sale of such shares pursuant to such registration are expected to be at least $10 million (or $5 million if we are able to register such shares on Form S-3) and, at the time of such

demand, DLJ Merchant Banking beneficially owns less than 25% of their percentage ownership of our common stock immediately following the closing of the Securities Purchase Agreement dated as of December 21, 2000, by and among DLJ Merchant Banking and us. In addition, all stockholders who continue to own “Registrable Shares” under the stockholders’ agreement may generally require us to include shares of common stock in a registration statement filed by us other than on Forms S-4 or S-8 or any successor forms. The rights granted under this agreement terminate whenever the shares covered by this agreement may be sold under Rule 144(k) or when these shares have been disposed of in connection with a registration statement or under Rule 144. The rights granted under this agreement have terminated with respect to certain parties thereto who are no longer our affiliates and have held shares for over two years. Since we are registering all of the shares of the Southwest Parties under this prospectus, their demand registration rights under the agreement shall terminate.

Transfer Agent and Registrar

The transfer agent and registrar for the common stock is American Stock Transfer & Trust Company.

Listing

Our shares of common stock are listed on the NYSE under the symbol “BAS.”

SHARES ELIGIBLE FOR FUTURE SALE

As of August 2, 2006, there were 33,827,105 shares of common stock outstanding. In addition to shares issuable upon the exercise of options issued under our 2003 Incentive Plan, there are 4,350,000 shares that may be issued upon the exercise of warrants held by DLJ Merchant Banking. Of these outstanding shares, after this distribution, 17,708,335 shares will be freely tradable without restriction under the Securities Act except for any shares purchased by one of our “affiliates” as defined in Rule 144 under the Securities Act. After this distribution, a total of 16,118,770 shares will be “restricted securities” within the meaning of Rule 144 under the Securities Act.

The restricted securities generally may not be sold unless they are registered under the Securities Act or are sold under an exemption from registration, such as the exemption provided by Rule 144 under the Securities Act. After this distribution, the holders of 13,709,424 shares (not including shares issuable upon the exercise of warrants held by DLJ Merchant Banking) will have rights, subject to some limited conditions, to demand that we include their shares in registration statements that we file on their behalf, on our behalf or on behalf of other stockholders. By exercising their registration rights and selling a large number of shares, these holders could cause the price of our common stock to decline. Furthermore, if we file a registration statement to offer additional shares of our common stock and have to include shares held by those holders, it could impair our ability to raise needed capital by depressing the price at which we could sell our common stock.

As restrictions on resale end, the market price of our common stock could drop significantly if the holders of these restricted shares sell them, or are perceived by the market as intending to sell them.

We have filed a registration statement with the SEC on Form S-8 providing for the registration of 5,000,000 shares of our common stock issued or reserved for issuance under our stock option plans. Subject to the exercise of unexercised options or the expiration or waiver of vesting conditions for restricted stock and the expiration of lock-ups we and our stockholders have entered into, shares registered under this registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

Rule 144

In general, under Rule 144 as currently in effect, any person (or persons whose shares are aggregated), including an affiliate, who has beneficially owned shares for a period of at least one year is entitled to sell, within any three-month period, a number of shares that does not exceed the greater of:


	•	1% of the then outstanding shares of common stock; and

	•	the average weekly trading volume in the common stock on the NYSE during the four calendar weeks immediately preceding the date on which the notice of the sale on Form 144 is filed with the Securities Exchange Commission.

Sales under Rule 144 are also subject to other provisions relating to notice and manner of sale and the availability of current public information about us.

Rule 144(k)

Under Rule 144(k), a person who is not deemed to have been one of our affiliates at any time during the 90 days preceding a sale, and who has beneficially owned the shares proposed to be sold for at least two years, including the holding period of any prior owner other than an “affiliate,” is entitled to sell the shares without complying with the manner of sale, public information, volume limitation or notice provision of Rule 144.

LEGAL MATTERS

The validity of the shares of common stock distributed by the distributing holders under this prospectus will be passed upon for us by Andrews Kurth LLP, Houston, Texas.

EXPERTS

The consolidated financial statements of Basic Energy Services, Inc. and subsidiaries as of December 31, 2004 and 2005, and for each of the years in the three-year period ended December 31, 2005, have been included in this prospectus and in the registration statement in reliance upon the report of KPMG LLP, an independent registered public accounting firm, appearing elsewhere in this prospectus, and upon the authority of said firm as experts in accounting and auditing. The audit report covering the December 31, 2005 consolidated financial statements refers to a change in the method of accounting for asset retirement obligations as of January 1, 2003.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 regarding the common stock offered by this prospectus. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common stock offered in this prospectus, 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 at http://www.sec.gov. Please call the SEC at 1-800-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, and the underwriters 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, and the underwriters 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 at http://www.basicenergyservices.com, and we make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus. You may also request a copy of these filings at no cost, by writing or telephoning us at the following address: Basic Energy Services, Inc., Attention: Chief Financial Officer, 400 W. Illinois, Suite 800, Midland, Texas 79701, (432) 620-5500.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


		Page

Audited Consolidated Financial Statements

	Report of Independent Registered Public Accounting Firm		F1-1

	Consolidated Balance Sheets as of December 31, 2005 and 2004		F1-2

	Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2005, 2004 and 2003		F1-3

	Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2005, 2004 and 2003		F1-4

	Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003		F1-5

	Notes to Consolidated Financial Statements		F1-6

	Financial Statement Schedule II — Valuation and Qualifying Accounts		F1-37

Unaudited Consolidated Financial Statements

	Consolidated Balance Sheet as of March 31, 2006		F2-1

	Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2006 and 2005		F2-2

	Consolidated Statements of Stockholders’ Equity for the three months ended March 31, 2006		F2-3

	Consolidated Statements of Cash Flows for the three months ended March 31, 2006 and 2005		F2-4

	Notes to Consolidated Financial Statements		F2-5

F-1

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Basic Energy Services, Inc.:

We have audited the accompanying consolidated balance sheets of Basic Energy Services, Inc. and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2005. In connection with our audits of the consolidated financial statements, we also have audited the accompanying financial statement schedule. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedules based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Basic Energy Services, Inc. and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 2 of the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations”.


	KPMG LLP

Dallas, Texas

March 20, 2006

F1-1

Basic Energy Services, Inc.

Consolidated Balance Sheets


			December 31,

			2005			2004

			(In thousands,
			except share data)
ASSETS
Current assets:
	Cash and cash equivalents		$	32,845		$	20,147
	Trade accounts receivable, net of allowance of $2,775 and $3,108, respectively			86,932			56,651
	Accounts receivable — related parties			65			103
	Inventories			1,648			1,176
	Prepaid expenses			3,112			1,798
	Other current assets			2,060			2,454
	Deferred tax assets			6,020			4,899

		Total current assets		132,682			87,228

	Property and equipment, net			309,075			233,451
	Deferred debt costs, net of amortization			4,833			4,709
	Goodwill			48,227			39,853
	Other assets			2,140			2,360

			$	496,957		$	367,601

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable		$	13,759		$	11,388
	Accrued expenses			33,548			20,486
	Income taxes payable			7,210			—
	Current portion of long-term debt			7,646			11,561
	Other current liabilities			1,124			545

		Total current liabilities		63,287			43,980

Long-term debt				119,241			170,915
Deferred income				17			44
Deferred tax liabilities				53,770			30,247
Other long-term liabilities				2,067			629
Commitments and contingencies
Stockholders’ equity:
	Common stock; $.01 par value; 80,000,000 shares authorized; 33,931,935 shares issued, 33,785,359 shares outstanding at December 31, 2005 and 28,931,935 shares issued and outstanding at December 31, 2004, respectively			339			58
Additional paid-in capital				239,218			142,802
Deferred compensation				(7,341	)		(4,990	)
Retained earnings (deficit)				28,654			(16,127	)
Treasury stock, 146,576 shares at December 31, 2005, at cost				(2,531	)		—
Accumulated other comprehensive income				236			43

	Total stockholders’ equity			258,575			121,786

			$	496,957		$	367,601

See accompanying notes to consolidated financial statements.

F1-2

Basic Energy Services, Inc.

Consolidated Statements of Operations and Comprehensive Income


				Years Ended December 31

				2005			2004			2003

				(Dollars in thousands, except
				per share amounts)
Revenues:
	Well servicing			$	221,993		$	142,551		$	104,097
	Fluid services				132,280			98,683			52,810
	Drilling and completion services				59,832			29,341			14,808
	Well site construction services				45,647			40,927			9,184

		Total revenues			459,752			311,502			180,899

Expenses:
	Well servicing				137,392			98,058			73,244
	Fluid services				82,551			65,167			34,420
	Drilling and completion services				30,900			17,481			9,363
	Well site construction services				32,000			31,454			6,586
	General and administrative, including stock-based compensation of $2,890, $1,587, and $994 in 2005, 2004 and 2003, respectively				55,411			37,186			22,722
	Depreciation and amortization				37,072			28,676			18,213
	(Gain) loss on disposal of assets				(222	)		2,616			391

		Total expenses			375,104			280,638			164,939

			Operating income		84,648			30,864			15,960
Other income (expense):
	Interest expense				(13,065	)		(9,714	)		(5,234	)
	Interest income				405			164			60
	Loss on early extinguishment of debt				(627	)		—			(5,197	)
	Other income (expense)				220			(398	)		146

Income from continuing operations before income taxes					71,581			20,916			5,735
Income tax expense					(26,800	)		(7,984	)		(2,772	)

Income from continuing operations					44,781			12,932			2,963
Discontinued operations, net of tax					—			(71	)		22
Cumulative effect of accounting change, net of tax					—			—			(151	)

Net income					44,781			12,861			2,834

Preferred stock dividend					—			—			(1,525	)
Accretion of preferred stock discount					—			—			(3,424	)

Net income (loss) available to common stockholders				$	44,781		$	12,861		$	(2,115	)

Basic earnings per share of common stock:
	Continuing operations			$	1.57		$	0.46		$	(0.09	)
	Discontinued operations				—			—			—

	Net income (loss) available to common stockholders			$	1.57		$	0.46		$	(0.09	)

Diluted earnings per share of common stock:
	Continuing operations			$	1.35		$	0.42		$	(0.09	)
	Discontinued operations				—			—			—

	Net income (loss) available to common stockholders			$	1.35		$	0.42		$	(0.09	)

Comprehensive Income:
Net income				$	44,781		$	12,861		$	2,834
Unrealized gains on hedging activities					193			43			—

Comprehensive Income:				$	44,974		$	12,904		$	2,834

See accompanying notes to consolidated financial statements.

F1-3

Basic Energy Services, Inc.

Consolidated Statements of Stockholders’ Equity


																	Accumulated
	Common Stock				Additional									Retained			Other		Total
					Paid-in			Deferred			Treasury			Earnings			Comprehensive		Stockholders’
	Shares		Amount		Capital			Compensation			Stock			(Deficit)			Income		Equity

	(In thousands, except share data)
Balance — December 31, 2002		20,368,610	$	41	$	97,294		$	—		$	—		$	(24,777	)	$	—	$	72,558
Exercise of EBITDA contingent warrants		771,740		2		—			—			—			—			—		2
EBITDA contingent warrants		—		—		3,571			—			—			(2,660	)		—		911
FESCO Holdings, Inc. acquisition		3,650,000		7		18,820			—			—			—			—		18,827
Stock-based compensation awards		—		—		380			(380	)		—			—			—		—
Amortization of deferred compensation		—		—		—			83			—			—			—		83
Preferred stock conversion to common stock		3,304,085		6		16,459			—			—			564			—		17,029
Accretion of preferred stock discount		—		—		—			—			—			(3,424	)		—		(3,424	)
Preferred stock dividends		—		—		—			—			—			(1,525	)		—		(1,525	)
Net income		—		—		—			—			—			2,834			—		2,834

Balance — December 31, 2003		28,094,435		56		136,524			(297	)		—			(28,988	)		—		107,295
Issuance of restricted stock and stock options		837,500		2		6,278			(6,280	)		—			—			—		—
Amortization of deferred compensation		—		—		—			1,587			—			—			—		1,587
Unrealized gain on interest rate swap agreement		—		—		—			—			—			—			43		43
Net income		—		—		—			—			—			12,861			—		12,861

Balance — December 31, 2004		28,931,935		58		142,802			(4,990	)		—			(16,127	)		43		121,786
Stock-based compensation awards		—		—		5,241			(5,241	)		—			—			—		—
Amortization of deferred compensation		—		—		—			2,890			—			—			—		2,890
Unrealized gain on interest rate swap agreement		—		—		—			—			—			—			193		193
Forfeited 11,250 shares at cost of $0		—		—		—			—			—			—			—		—
Effect of stock split		—		231		(231	)		—			—			—			—		—
Proceeds from common stock issuance, net of $2,044 of offering costs		5,000,000		50		91,406			—			—			—			—		91,456
Purchase of 135,326 of treasury stock		—		—		—			—			(2,531	)		—			—		(2,531	)
Net income		—		—		—			—			—			44,781			—		44,781

Balance — December 31, 2005		33,931,935	$	339	$	239,218		$	(7,341	)	$	(2,531	)	$	28,654		$	236	$	258,575

See accompanying notes to consolidated financial statements.

F1-4

Basic Energy Services, Inc.

Consolidated Statements of Cash Flows


					Years Ended December 31,

					2005			2004			2003

					(In thousands)
Cash flows from operating activities:
	Net income				$	44,781		$	12,861		$	2,834
		Adjustments to reconcile net income to net cash provided by operating activities:
			Depreciation and amortization			37,072			28,676			18,213
			Accretion on asset retirement obligation			42			33			28
			Change in allowance for doubtful accounts			(333	)		1,150			1,279
			Non-cash interest expense			1,062			970			694
			Non-cash compensation			2,890			1,587			994
			Loss on early extinguishment of debt			627			—			3,588
			(Gain) loss on disposal of assets			(222	)		2,616			391
			Deferred income taxes			18,301			7,984			2,840
			Other non-cash items			—			—			(11	)
			Non-cash effect of discontinued operations			—			—			13
			Cumulative effect of accounting change			—			—			151
	Changes in operating assets and liabilities, net of acquisitions:
			Accounts receivable			(27,577	)		(13,841	)		(12,120	)
			Inventories			(262	)		394			125
			Prepaid expenses and other current assets			304			446			(1,243	)
			Other assets			(49	)		(569	)		1,261
			Accounts payable			2,174			3,416			2,863
			Income tax payable			7,013			—			—
			Deferred income and other liabilities			374			127			(11	)
			Accrued expenses			12,992			689			7,926

				Net cash provided by operating activities		99,189			46,539			29,815

	Cash flows from investing activities:
			Purchase of property and equipment			(83,095	)		(55,674	)		(23,501	)
			Proceeds from sale of assets			2,436			2,484			660
			Payments for other long-term assets			(1,642	)		(1,113	)		(177	)
			Payments for businesses, net of cash acquired			(25,378	)		(19,284	)		(61,885	)

				Net cash used in investing activities		(107,679	)		(73,587	)		(84,903	)

	Cash flows from financing activities:
			Proceeds from debt			16,000			43,500			203,012
			Payments of debt			(81,924	)		(21,236	)		(115,603	)
			Proceeds from common stock, net of $2,044 of offering costs			91,456			—			—
			Purchase of treasury stock			(2,531	)		—			—
			Collections of notes receivable			—			—			9
			Proceeds from exercise of EBITDA contingent warrants			—			—			2
			Deferred loan costs and other financing activities			(1,813	)		(766	)		(7,561	)

				Net cash provided by financing activities		21,188			21,498			79,859

				Net increase (decrease) in cash and equivalents		12,698			(5,550	)		24,771
	Cash and cash equivalents — beginning of year					20,147			25,697			926

	Cash and cash equivalents — end of year				$	32,845		$	20,147		$	25,697

See accompanying notes to consolidated financial statements.

F1-5

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements

December 31, 2005, 2004, and 2003


1.	Nature of Operations and Basis of Presentation

Organization and Restructuring

Basic Energy Services, Inc. (predecessor entity), a Delaware corporation (“Historical Basic”) commenced operations in 1992. Effective January 24, 2003, Historical Basic changed its corporate structure to a holding company format. The purpose of this corporate restructuring was to provide greater operational, administrative and financial flexibility to Historical Basic, as well as improved economics. In connection with this restructuring, Historical Basic merged with a newly formed subsidiary of BES Holding Co. (“New Basic”), a Delaware corporation incorporated on January 7, 2003 as a wholly-owned subsidiary of New Basic. The merger was structured as a tax-free reorganization to Historical Basic stockholders. As a result of the merger, each share of outstanding common stock of Historical Basic was exchanged for one share of common stock of New Basic, and each share of outstanding Series A 10% Cumulative Preferred Stock of Historical Basic was exchanged for one share of Series A 10% Cumulative Preferred Stock of New Basic, and with respect to any accrued and unpaid dividends, shares of additional preferred stock with a liquidation preference equal to such accrued and unpaid dividends. Historical Basic survived the merger and was subsequently converted to a Delaware limited partnership now known as Basic Energy Services, L.P., which is currently an indirect wholly-owned subsidiary of New Basic. On April 2, 2004, BES Holding Co. changed its name to Basic Energy Services, Inc. Historical Basic prior to January 24, 2003 and New Basic thereafter are referred to in these Notes to Consolidated Financial Statements as “Basic.”

Basis of Presentation


	The historical consolidated financial statements presented herein of Basic prior to its formation are the historical results of Historical Basic since the ownership of Basic and Historical Basic at the merger date were identical. The financial results of New Basic and Historical Basic are combined to present the consolidated financial statements of Basic.

Nature of Operations

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


2.	Summary of Significant Accounting Policies

Principles of Consolidation


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

Estimates and Uncertainties


	Preparation of the accompanying consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amount of assets and liabilities and

F1-6

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


	disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Areas where critical accounting estimates are made by management include:


	•	Depreciation and amortization of property and equipment and intangible assets

	•	Impairment of property and equipment and goodwill

	•	Allowance for doubtful accounts

	•	Litigation and self-insured risk reserves

	•	Fair value of assets acquired and liabilities assumed

	•	Stock-based compensation

	•	Income taxes

	•	Asset retirement obligation

Revenue Recognition

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

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

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

Well Site Construction Services — Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Basic prices well site construction services by the hour, day, or project depending on the type of service performed.

Cash and Cash Equivalents


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

F1-7

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Fair Value of Financial Instruments


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

Inventories


	Inventories, consisting mainly of rig components, repair parts, drilling and completion materials and gravel, are held for use in the operations of Basic and are stated at the lower of cost or market, with cost being determined on the first-in, first-out (“FIFO”) method.

Property and Equipment

Property and equipment are stated at cost, or at estimated fair value at acquisition date if acquired in a business combination. Expenditures for repairs and maintenance are charged to expense as incurred and additions and improvements that significantly extend the lives of the assets are capitalized. Upon sale or other retirement of depreciable property, the cost and accumulated depreciation and amortization are removed from the related accounts and any gain or loss is reflected in operations. All property and equipment are depreciated or amortized (to the extent of estimated salvage values) on the straight-line method and the estimated useful lives of the assets are as follows:


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

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

Impairments

F1-8

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

lowest identifiable level. If the carrying amount of such assets exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of such assets exceeds the fair value of the assets. Assets to be disposed of would be separately presented in the consolidated balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated. The assets and liabilities, if material, of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the consolidated balance sheet.

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

Basic had no impairment expense in 2005, 2004 or 2003.

Deferred Debt Costs


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

Deferred debt costs of approximately $7.0 million at December 31, 2005 and $5.8 million at December 31, 2004, respectively, represent debt issuance costs and are recorded net of accumulated amortization of $2.2 million, and $1.1 million at December 31, 2005 and December 31, 2004, respectively. Amortization of deferred debt costs totaled approximately $1,062,000, $907,000 and $694,000 for the years ended December 31, 2005, 2004 and 2003, respectively.

In 2005, Basic recognized a loss on early extinguishment of debt related to deferred debt costs. (See note 5)

Goodwill

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

Intangible assets subject to amortization under SFAS No. 142 consist of non-compete agreements. Amortization expense for the non-compete agreements is calculated using the straight-line method over the period of the agreement, ranging from three to five years. The

F1-9

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

weighted average amortization period for non-compete agreements acquired during 2005 and 2004 is 60 months.

The gross carrying amount of non-compete agreements subject to amortization totaled approximately $2.7 million and $3.7 million at December 31, 2005 and 2004, respectively. Accumulated amortization related to these intangible assets totaled approximately $1.6 and $2.4 million at December 31, 2005 and 2004, respectively. Amortization expense for the years ended December 31, 2005, 2004 and 2003 was approximately $519,000, $457,000, and $364,000, respectively. Amortization expense for the next five succeeding years is estimated to be approximately $461,000, $325,000, $223,000, $122,000, and $22,000 in 2006, 2007, 2008, 2009, and 2010 respectively.

Basic has identified its reporting units to be well servicing, fluid services, drilling and completion services and well site construction services. The goodwill allocated to such reporting units as of December 31, 2005 is $9.9 million, $20.6 million, $14.0 million and $3.7 million, respectively. The change in the carrying amount of goodwill for the year ended December 31, 2005 of $8.4 million relates to goodwill from acquisitions and payments pursuant to contingent earn-out agreements, with approximately $1.1 million, $2.2 million and $5.1 million of goodwill additions relating to the well servicing, fluid services and drilling and completion units, respectively.

Stock-Based Compensation


	Basic accounts for stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB No. 25”). Accordingly, Basic has adopted the disclosure provisions of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”).

F1-10

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”) sets forth alternative accounting and disclosure requirements for stock-based compensation arrangements. Companies may continue to follow the provisions of APB No. 25 to measure and recognize employee stock-based compensation; however, SFAS No. 123 requires disclosure of pro forma net income and earnings per share that would have been reported under the fair value based recognition provisions of SFAS No. 123. The following table illustrates the effect on net income if Basic had applied the fair value recognition provisions of SFAS No. 123 to stock-based employee compensation.


		Years Ended December 31,

		2005			2004			2003

Net income (loss) available to common stockholders — as reported		$	44,781		$	12,861		$	(2,115	)
Add: Stock-based employee compensation expense included in statement of operations, net of tax			1,806			986			523
Deduct: Stock-based employee compensation expense determined under fair-value based method for all awards, net of tax			(2,231	)		(1,283	)		(779	)

Net income available to common stockholders — pro forma basis		$	44,356		$	12,564		$	(2,371	)

Basic earnings per share of common stock:
	As reported	$	1.57		$	0.46		$	(0.09	)
	Pro forma	$	1.55		$	0.45		$	(0.11	)
Diluted earnings per share of common stock:
	As reported	$	1.35		$	0.42		$	(0.09	)
	Pro forma	$	1.34		$	0.41		$	(0.11	)

Under SFAS No. 123, the fair value of each stock option grant is estimated on the date of grant using the Black-Scholes-Merton option pricing model with the following weighted average assumptions used for grants during the years ended December 31, 2005, 2004, and 2003:


	2005			2004			2003

Risk-free interest rate		4.5	%		4.4	%		2.9	%
Expected life		9.9			10.0			10.0
Expected volatility		0.5	%		0.0	%		0.0	%
Expected dividend yield		—			—			—

Income Taxes

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

F1-11

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Concentrations of Credit Risk

Financial instruments, which potentially subject Basic to concentration of credit risk, consist primarily of temporary cash investments and trade receivables. Basic restricts investment of temporary cash investments to financial institutions with high credit standing. Basic’s customer base consists primarily of multi-national and independent oil and natural gas producers. It performs ongoing credit evaluations of its customers but generally does not require collateral on its trade receivables. Credit risk is considered by management to be limited due to the large number of customers comprising its customer base. Basic maintains an allowance for potential credit losses on its trade receivables, and such losses have been within management’s expectations.

Basic did not have any one customer which represented 10% or more of consolidated revenue for 2005, 2004, or 2003.


	*Derivative Instruments and Hedging Activities*

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), which establishes standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires that an entity recognize all derivative as either assets or liabilities on the balance sheet and measure those instruments at fair value. It establishes conditions under which a derivative may be designated as a hedge, and establishes standards for reporting changes in the fair value of a derivative. Basic adopted SFAS No. 133, as amended by SFAS No. 138, on January 1, 2001. Basic adopted the additional amendments pursuant to SFAS No. 149 for contracts entered or modified after June 30, 2003, if any. At inception, Basic formally documents the relationship between the hedging instrument and the underlying hedged item as well as risk management objective and strategy. Basic assesses, both at inception and on an ongoing basis, whether the derivative used in hedging transition is highly effective in offsetting changes in the fair value of cash flows of the respective hedged item.

Basic had no derivative contacts in 2003. In May 2004, Basic implemented a cash flow hedge to protect itself from fluctuation in cash flows associated with its credit facility. Changes in fair value of the hedging derivative are initially recorded in other comprehensive income, then recognized in income in the same period(s) in which the hedged transaction affects income. Ineffective portions of a cash flow hedging derivative’s change in fair value are recognized currently in earnings. Basic had no ineffectiveness related to its cash flow hedge in 2005 or 2004.

Asset Retirement Obligations

As of January 1, 2003, Basic adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligation” (“SFAS No. 143”). SFAS No. 143 requires Basic to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets and capitalize on equal amount as a cost of the asset depreciating it over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each quarter to reflect the passage of time, changes in the estimated future cash flows underlying the obligation, acquisition or construction of assets, and settlements of obligations. On January 1, 2003, Basic recorded additional costs, net of accumulated depreciation of approximately $102,000, an asset retirement obligation of approximately $340,000, and an after-tax charge of approximately $151,000 for the cumulative effect on prior year’s depreciation of the

F1-12

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


	additional costs and the accretion expense on the liability related to the expected abandonment costs.

Basic owns and operates salt water disposal sites, brine water wells, gravel pits and land farm sites, each of which is subject to rules and regulations regarding usage and eventual closure. The following table reflects the changes in the liability during years ended December 31, 2005 and 2004 (in thousands):


Balance, December 31, 2003	$	415
Additional asset retirement obligations recognized through acquisitions		36
Accretion expense		33
Settlements		(11	)

Balance, December 31, 2004	$	473
Additional asset retirement obligations recognized through acquisitions		74
Accretion expense		42
Settlements		(20	)

Balance, December 31, 2005	$	569

The pro forma net income (loss) and related per share amounts assuming SFAS no. 143 had been applied in 2003 are as follows (in thousands, except per share data):


		2003

Pro forma net income (loss) available to common shareholders(a)		$	(1,964	)
Pro forma earnings per share of common stock Basic
	Basic	$	(0.09	)
	Diluted	$	(0.09	)


(a)		The net income available to common stockholders in 2003 has been adjusted to remove the $151,000 cumulative effect of accounting change attributable to SFAS No. 143.

Environmental

Basic is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require Basic to remove or mitigate the adverse environmental effects of disposal or release of petroleum, chemical and other substances at various sites. Environmental expenditures are expensed or capitalized depending on the future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated.

Litigation and Self-Insured Risk Reserves

Basic estimates its reserves related to litigation and self-insured risks based on the facts and circumstances specific to the litigation and self-insured claims and its past experience with similar claims in accordance with statement of financial accounting standard No. 5, “Accounting for Contingencies”. Basic maintains accruals in the consolidated balance sheets to cover self-insurance retentions (See note 7).

F1-13

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Comprehensive Income

Basic follows the provisions of Statement of Financial Accounting Standards No. 130, “Reporting of Comprehensive Income” (“SFAS No. 130”). SFAS No. 130 establishes standards for reporting and presentation of comprehensive income and its components. SFAS No. 130 requires all items that are required to be recognized under accounting standards as components of comprehensive income to be reported in a financial statement that is displayed with the same prominence as other financial statements. In accordance with the provisions of SFAS No. 130, gains and losses on cash flow hedging derivatives, to the extent effective, are included in other comprehensive income (loss).

Reclassifications


	Certain reclassifications of prior year financial statement amounts have been made to conform to current year presentations.

Recent Accounting Pronouncements

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

Compensation cost for the unvested portion of awards that are outstanding as of January 1, 2006 will be recognized ratably over the remaining vesting period. The compensation cost for the unvested portion of awards will be based on the fair value at date of grant as calculated for Basic’s pro forma disclosure under SFAS No. 123. However, Basic will continue to account for any portion of awards outstanding on January 1, 2006 that were initially measured using the minimum value method under the intrinsic value method in accordance with APB No. 25. Basic will recognize compensation expense for awards under its Second Amended and Restated 2003 Incentive Plan (the “Incentive Plan”) beginning in January 1, 2006.

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

F1-14

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


3.	Acquisitions

In 2005, 2004 and 2003, Basic acquired either substantially all of the assets or all of the outstanding capital stock of each of the following businesses, each of which were accounted for using the purchase method of accounting (in thousands):


			Total Cash Paid
			(net of cash
	Closing Date		acquired)

New Force Energy Services		January 27, 2003	$	7,665
S & S Bulk Cement		April 17, 2003		195
Briscoe Oil Tools		June 13, 2003		260
FESCO Holdings, Inc.(a)		October 3, 2003		19,093
PWI, Inc.		October 3, 2003		25,104
Pennant Service Company		October 3, 2003		7,387
Graham Acidizing		December 1, 2003		2,181

Total 2003			$	61,885

Action Trucking — Curtis Smith, Inc.		April 27, 2004	$	821
Rolling Plains		May 30, 2004		3,022
Perry’s Pump Service		May 30, 2004		1,379
Lone Tree Construction		June 23, 2004		211
Hayes Services		July 1, 2004		1,595
Western Oil Well		July 30, 2004		854
Summit Energy		August 19, 2004		647
Energy Air Drilling		August 30, 2004		6,500
AWS Wireline		November 1, 2004		4,255

Total 2004			$	19,284

R & R Hot Oil Service		January 5, 2005		1,702
Premier Vacuum Service, Inc.		January 28, 2005		1,009
Spencer’s Coating Specialist		February 9, 2005		619
Mark’s Well Service		February 25, 2005		579
Max-Line, Inc.		April 28, 2005		1,498
MD Well Service, Inc.		May 17, 2005		4,478
179 Disposal, Inc.		August 4, 2005		1,729
Oilwell Fracturing Services, Inc.		October 11, 2005		13,764

Total 2005			$	25,378


(a)		This acquisition was funded through the issuance of Basic’s common stock. The total cash paid represents the retirement of debt at closing and transaction costs incurred net of the cash acquired.

The operations of each of the acquisitions listed above are included in Basic’s statement of operations as of each respective closing date. The acquisitions of New Force Energy Services (“New Force”), FESCO Holding, Inc. (“FESCO”) and PWI, Inc. and certain other affiliated entities (“PWI”) in 2003 are deemed significant and discussed below in further detail.

F1-15

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

New Force Energy Services

On January 27, 2003, Basic acquired substantially all of the assets of New Force for $7.7 million plus a $2.7 million contingent earn-out payment. The contingent earn-out payment will be paid upon the New Force assets meeting certain financial objectives in the future. The preliminary cash cost of the New Force acquisition was $7.7 million (including other direct acquisition costs) which was allocated $6.3 million to property and equipment, $1.3 million to goodwill, $105,000 to inventory and $10,000 to non-compete agreements.

FESCO Holdings, Inc.

On October 3, 2003, Basic acquired all the capital stock of FESCO. As consideration for the acquisition of FESCO, Basic issued 3,650,000 shares of its common stock, based on an estimated fair value of the stock of $5.16 per share (a total fair value of approximately $18.8 million), and paid approximately $19.1 million in net cash at the closing, representing the retirement of debt of FESCO at closing and the payment of transaction costs incurred, net of the cash held by FESCO. In addition to assuming the working capital of FESCO, Basic incurred other direct acquisition costs and assumed certain other liabilities of FESCO, resulting in Basic recording an aggregate purchase price of approximately $37.9 million. The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):


Current assets, excluding cash		$	12,855
Property and equipment			32,344
Other assets			38

	Total assets acquired		45,237

Current liabilities			5,592
Deferred tax liability			1,725

	Total liabilities assumed		7,317

Net assets acquired		$	37,920

PWI, Inc.

On October 3, 2003, Basic acquired substantially all the assets of PWI for $25.1 million plus a $2.5 million contingent earn-out payment. The contingent earn-out agreement was terminated by the parties entering into an agreement to pay $75,000 per year for four years beginning in October 2005. The cash cost of the PWI acquisition was $25.1 million (including other direct acquisition costs) which was allocated $16.4 million to property and equipment, $8.6 million to goodwill, $250,000 to non-compete agreements and $200,000 to liabilities assumed.

Contingent Earn-out Arrangements and Final Purchase Price Allocations

Contingent earn-out arrangements are generally arrangements entered in certain acquisitions to encourage the owner/manager to continue operating and building the business after the purchase transaction. The contingent earn-out arrangements of the related acquisitions are generally linked to certain financial measures and performance of the assets acquired in the various acquisitions. All amounts paid or reasonably accrued for related to the contingent earn-out payments are reflected as increases to the goodwill associated with the acquisition.

F1-16

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

The following presents a summary of acquisitions that have a contingent earn-out arrangement in effect as of December 31, 2005 (in thousands):

Termination

Maximum

Date of

Exposure of

Contingent

Amount Paid or

Earn-out

Accrued Through

Acquisition

Arrangement

December 31, 2005

Advantage Services, Inc.

October 9, 2005

250

219

New Force Energy Services

January 27, 2008

2,700

1,639

S&S Bulk Cement

April 20, 2008

115

Briscoe Oil Tools

June 12, 2008

125

Rolling Plains

April 30, 2009

588

Premier Vacuum Services, Inc.

February 1, 2010

900

226

4,090

2,869


*	Basic will pay to the sellers an amount for each of the five consecutive 12 month periods beginning on May 1, 2004 equal to 50% of the amount by which annual EBITDA exceeds an annual targeted EBITDA. There is no guarantee or assurance that the targeted EBITDA will be reached

The following unaudited pro forma results of operations have been prepared as though the New Force, FESCO and PWI acquisitions had been completed on January 1, 2003. Pro forma amounts are based on the final purchase price allocations of the significant acquisitions and are not necessarily indicative of the results that may be reported in the future (in thousands, except per share data).


	Year Ended
	December 31, 2003

	(Unaudited)
Revenues	$	228,059
Income (loss) from continuing operations less preferred stock dividends and accretion	$	(1,182	)
Earnings per common share — basic	$	(0.05	)
Earnings per common share — diluted	$	(0.05	)

Basic does not believe the pro-forma effect of the remainder of the acquisitions completed in 2003, 2004, or 2005 is material, either individually or when aggregated, to the reported results of operations.

F1-17

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


4.	Property and Equipment

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


	December 31,		December 31,
	2005		2004

Land	$	1,902	$	1,573
Buildings and improvements		8,634		6,615
Well service units and equipment		199,070		138,957
Fluid services equipment		59,104		53,111
Brine and fresh water stations		7,746		7,722
Frac/test tanks		31,475		19,707
Pressure pumping equipment		31,101		14,971
Construction equipment		24,224		21,964
Disposal facilities		16,828		14,079
Vehicles		23,329		18,881
Rental equipment		6,519		4,885
Aircraft		3,236		3,335
Other		8,602		7,780

		421,770		313,580
Less accumulated depreciation and amortization		112,695		80,129

Property and equipment, net	$	309,075	$	233,451

Basic is obligated under various capital leases for certain vehicles and equipment that expire at various dates during the next five years. The gross amount of property and equipment and related accumulated amortization recorded under capital leases and included above consists of the following (in thousands):


	December 31,		December 31,
	2005		2004

Light vehicles	$	17,912	$	12,993
Fluid services equipment		14,011		10,558
Construction equipment		1,300		840

		33,223		24,391
Less accumulated amortization		8,474		7,201

	$	24,749	$	17,190

Amortization of assets held under capital leases of approximately $1.8 million, $1.8 million, and $2.5 million for the years ended December 31, 2005, 2004, and 2003, respectively, is included in depreciation and amortization expense in the consolidated statements of operations.

F1-18

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


5.	Long-Term Debt

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


		December 31,		December 31,
		2005		2004

Credit Facilities:
	Term B Loan	$	90,000	$	166,500
	Revolver		16,000		—
Capital leases and other notes			20,887		15,976

			126,887		182,476
Less current portion			7,646		11,561

		$	119,241	$	170,915

2005 Credit Facility

On December 15, 2005, Basic entered into a $240 million Third Amended and Restated Credit Agreement with a syndicate of lenders (“2005 Credit Facility”) which refinanced all of its then existing credit facilities. The 2005 Credit Facility provides for a $90 million Term B Loan (“2005 Term B Loan”) and a $150 million revolving line of credit (“Revolver”). The commitment under the Revolver allows for (a) the borrowing of funds (b) issuance of up to $20 million of letters of credit and (c) $2.5 million of swing-line loans (next day borrowing). The amounts outstanding under the 2005 Term B Loan require quarterly amortization at various amounts during each quarter with all amounts outstanding on December 15, 2011 being due and payable in full. All the outstanding amounts under the Revolver are due and payable on December 15, 2010. The 2005 Credit Facility is secured by substantially all of Basic’s tangible and intangible assets. Basic incurred approximately $1.8 million in debt issuance costs in obtaining the 2005 Credit Facility.

At Basic’s option, borrowings under the 2005 Term B Loan bear interest at either the (a) “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus .5% per annum) plus 1% or (b) the LIBOR rate plus 2.0%. At December 31, 2005, Basic’s weighted average interest rate on its Term B Loan was 6.4%.

At Basic’s option, borrowings under the 2005 Revolver bear interest at either the (a) “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus .5% per annum) plus a margin ranging from .50% to 1.25% or (b) the LIBOR rate plus a margin ranging from 1.5% to 2.25%. The margins vary depending on Basic’s leverage ratio. At December 31, 2005, Basic’s margin on Alternative Base Rates and LIBOR tranches was .75% and 1.75%, respectively. Fees on the letters of credit are due quarterly on the outstanding amount of the letters of credit at a rate ranging from 1.5% to 2.25% for participation fees and .125% for fronting fees. A commitment fee is due quarterly on the available borrowings under the Revolver at rates ranging from .375% to .5%.

At December 31, 2005 Basic, under its Revolver, had outstanding $16 million of borrowings and $9.6 million of letters of credit and no amounts outstanding in swing-line loans. At December 31, 2005 Basic had availability under its Revolver of $124.4 million.

F1-19

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

any equity offering. The 2005 Credit Facility required Basic to enter into an interest rate hedge, acceptable to the lenders, through May 28, 2006 on at least $65 million of Basic’s then outstanding indebtedness. Paydowns on the 2005 Term B Loan may not be reborrowed.

The 2005 Credit Facility contains various restrictive covenants and compliance requirements, which include (a) limiting of the incurrence of additional indebtedness, (b) restrictions on mergers, sales or transfers of assets without the lenders’ consent, (c) limitation on dividends and distributions and (d) various financial covenants, including (1) a maximum leverage ratio of 3.5 to 1.0 reducing over time to 3.25 to 1.0, (2) a minimum interest coverage ratio of 3.0 to 1.0 and (e) limitations on capital expenditures in any period of four consecutive quarters in excess of 20% of Consolidated Net Worth unless certain criteria are met. At December 31, 2005 and December 31, 2004, Basic was in compliance with its covenants.

2004 Credit Facility

On December 21, 2004, Basic entered into a $220 million Second Amended and Restated Credit Agreement with a syndicate of lenders (“2004 Credit Facility”) which refinanced all of its then existing credit facilities. The 2004 Credit Facility provided for a $170 million Term B Loan (“2004 Term B Loan”) and a $50 million revolving line of credit (“2004 Revolver”). The commitment under the 2004 Revolver allowed for (a) the borrowing of funds (b) issuance of up to $20 million of letters of credit and (c) $2.5 million of swing-line loans (next day borrowing). The amounts outstanding under the 2004 Term B Loan required quarterly amortization at various amounts during each quarter with all amounts outstanding on October 3, 2009 being due and payable in full. All the outstanding amounts under the 2004 Revolver were due and payable on October 3, 2008. The 2004 Credit Facility was secured by substantially all of Basic’s tangible and intangible assets. Basic incurred approximately $766,000 in debt issuance costs in obtaining the 2004 Credit Facility.

At Basic’s option, borrowings under the 2004 Term B Loan bore interest at either (a) the “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus .5% per annum) plus 2% or (b) LIBOR plus 3%. At December 31, 2004, Basic’s weighted average interest rate on its 2004 Term B Loan was 5.5%.

At Basic’s option, borrowings under the 2004 Revolver bore interest at either the (a) the “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus .5% per annum) plus a margin ranging from 1.5% to 2.0% or (b) the LIBOR rate plus a margin ranging from 2.5% to 3.0%. The margins varied depending on Basic’s leverage ratio. At December 31, 2004, Basic’s margin on Alternative Base Rates and LIBOR tranches was 2.0% and 3.0%, respectively. Fees on the letters of credit were due quarterly on the outstanding amount of the letters of credit at a rate ranging from 2.5% to 3.0% for participation fees and .125% for fronting fees. A commitment fee was due quarterly on the available borrowings under the 2004 Revolver at rates ranging from .375% to .5%.

At December 31, 2004, Basic, under its 2004 Revolver, had outstanding $8.3 million of letters of credit and no amounts outstanding in swing-line loans. At December 31, 2004, Basic had availability under its 2004 Revolver of $41.7 million.

2003 Credit Facility


	On October 3, 2003, Basic entered into a $170 million credit facility with a syndicate of lenders (“2003 Credit Facility”) which refinanced all of its then existing credit facilities. The 2003 Credit Facility provided for a $140 million Term B Loan (“2003 Term B Loan”) and a $30 million

F1-20

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

revolving line of credit (“2003 Revolver”). The commitment under the 2003 Revolver allowed for (a) the borrowing of funds (b) issuance of up to $10 million of letters of credits and (c) $2.5 million of swing-line loans (next day borrowing). The amounts outstanding under the 2003 Term B Loan required quarterly amortization at various amounts during each quarter with all amounts outstanding on October 3, 2009 being due and payable in full. All the outstanding amounts under the 2003 Revolver were due and payable on October 3, 2008. The 2003 Credit Facility was secured by substantially all of Basic’s tangible and intangible assets. Basic incurred approximately $5.1 million in debt issuance costs in obtaining the 2003 Credit Facility.

At Basic’s option, borrowings under the 2003 Term B Loan bore interest at either (a) the “Alternative Base Rate” (i.e. the higher of the bank’s prime rate of the federal funds rate plus .5% per annum) plus 2.5% or (b) the LIBOR rate plus 3.5%. At December 31, 2003, Basic’s weighted average interest rate on its 2003 Term B Loan was 4.67%.

At Basic’s option, borrowings under the 2003 Revolver bore interest at either the (a) the “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus .5% per annum) plus a margin ranging from 1.5% to 2.0% or (b) the Libor rate plus a margin ranging from 2.5% to 3.0%. The margins varied depending on Basic’s leverage ration. At December 31, 2003, Basic’s margin on Alternative Base Rates and LIBOR tranches was 2.0% and 3.0%, respectively. Fees on the letters of credit were due quarterly on the outstanding amount of the letters of credit at a rate ranging from 2.5% to 3.0% for participations fees and .125% for fronting fees. A commitment fee was due quarterly on the available borrowings under the 2003 Revolver at rates ranging from .5% to .375%.

At December 31, 2003, Basic, under its 2003 Revolver, had $5.3 million of outstanding letters of credit and no amounts outstanding in swing-line loans. At December 31, 2003, Basic had availability under its 2003 Revolver of $24.7 million.

Other Debt


	Basic has a variety of other capital leases and notes payable outstanding that are generally customary in its business. None of these debt instruments are material individually or in the aggregate.

As of December 31, 2005, the aggregate maturities of debt, including capital leases, for the next five years and thereafter are as follows (in thousands):


	Debt		Capital Leases

2006	$	1,000	$	6,646
2007		1,000		6,024
2008		1,000		5,118
2009		1,000		2,713
2010		17,000		386
Thereafter		85,000		—

	$	106,000	$	20,887

F1-21

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

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


	Year Ended December 31,

	2005		2004		2003

Cash payments for interest	$	11,421	$	8,159	$	3,934
Commitment and other fees paid		185		25		109
Amortization of debt issuance costs		1,062		970		694
Other		397		560		497

	$	13,065	$	9,714	$	5,234

Losses on Extinguishment of Debt


	In 2005, Basic recognized a loss on the early extinguishment of debt. Basic wrote-off unamortized debt issuance costs of approximately $627,000.

In 2003, Basic recognized a loss on the early extinguishment of debt. Basic paid termination fees of approximately $1.7 million and wrote-off unamortized debt issuance costs of approximately $3.5 million which resulted in a loss of approximately $5.2 million.

In 2003, Basic adopted Statement of Financial Accounting Standards No. 145 “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections” (“SFAS No. 145”). The provisions of SFAS No. 145, which are currently applicable to Basic, rescind Statement No. 4, which required all gains and losses from extinguishment of debt to be aggregated and classified as an extraordinary item, and instead require that such gains and losses be reported as ordinary income or loss. Basic now records gains and losses from the extinguishment of debt as ordinary income or loss.


6.	Income Taxes

Income tax provision (benefit) was allocated as follows (in thousands):


	Years Ended December 31,

	2005		2004			2003

Income from continuing operations	$	26,800	$	7,984		$	2,772
Discontinued operations		—		(38	)		13
Cumulative effect of accounting change		—		—			(88	)

	$	26,800	$	7,946		$	2,697

Income tax expense (benefit) attributable to income (loss) from continuing operations consists of the following (in thousands):


	Years Ended December 31,

	2005		2004		2003

Current	$	8,499	$	—	$	(68	)
Deferred		18,301		7,984		2,840

	$	26,800	$	7,984	$	2,772

F1-22

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Basic paid federal income taxes of $1,325,000 during 2005. No federal income taxes were paid or received in 2004. In 2003 Basic received an income tax refund, net, of approximately $1.5 million.

Reconciliation between the amount determined by applying the federal statutory rate of 35% to the income (loss) from continuing operations with the provision (benefit) for income taxes is as follows (in thousands):


	Years Ended December 31,

	2005		2004			2003

Statutory federal income tax	$	25,053	$	7,321		$	2,007
Meals and entertainment		324		265			166
State taxes, net of federal benefit		1,415		421			138
Change in tax rates		—		—			542
Changes in estimates and other		8		(23	)		(81	)

	$	26,800	$	7,984		$	2,772

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are as follows (in thousands):


			December 31,

			2005			2004

Current deferred taxes:
	Receivables allowance		$	1,025		$	1,148
	Interest rate derivative			(186	)		—
	EBITDA contingent warrants			—			337
	Accrued liabilities			5,181			3,414

		Net current deferred tax asset	$	6,020		$	4,899

Noncurrent deferred taxes:
	Operating loss and tax credit carryforwards		$	1,856		$	20,782
	Property and equipment			(55,768	)		(51,194	)
	Goodwill and intangibles			(1,208	)		(602	)
	Deferred Compensation			1,140			617
	Asset retirement obligation			210			175
	Other			—			(25	)

		Net noncurrent deferred tax liability	$	(53,770	)	$	(30,247	)

Basic provides a valuation allowance when it is more likely than not that some portion of the deferred tax assets will not be realized. There was no valuation allowance necessary as of December 31, 2005 or 2004.

As of December 31, 2005, Basic had approximately $4.9 million of net operating loss carryforwards (“NOL”) for U.S. federal income tax purposes related to the preacquisition period of FESCO, which are subject to an annual limitation of approximately $900,000. The carryforwards begin to expire in 2017.

F1-23

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


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.

On September 3, 2004, a group of plaintiffs commenced a civil action against Basic in the District Court of Panola County, Texas, 123rd Judicial District. The complaint alleges that Basic’s operation of a saltwater disposal well has contaminated both the groundwater and the soil in the surrounding area. The relief requested in the complaint is monetary damages, injunctive relief, environmental remediation and a court order requiring Basic to provide drinking water to the community. In response to the complaint, Basic has retained counsel and filed a general denial. Basic is in the beginning stages of discovery and settlement negotiations are underway. Should negotiations fail, Basic intends to defend itself vigorously in this action.

On October 18, 2005, a group of plaintiffs commenced a civil action against Basic in the 123rd Judicial District Court of Panola County, Texas. The factual basis for this complaint and relief claims that Basic’s operation of a saltwater disposal well has contaminated both the groundwater and the soil in the surrounding area. In addition, this complaint alleges a wrongful death and personal injuries to unspecified persons. In response to this complaint, Basic has retained counsel and intends to defend itself vigorously in this action.

On July 25, 2005, a jury returned a verdict in favor of a salt water disposal operator who had filed suit against Basic. The jury awarded the plaintiff $1.2 million in damages. Basic’s insurance company denied coverage of liability. Basic believes that it has reached a settlement of this matter in connection with a mediation in March 2006 for $1.0 million. As of December 31, 2005, Basic accrued a $1.0 million loss for this contingency.

F1-24

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

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, 2005, the future minimum lease payments under non-cancelable operating leases are as follows (in thousands):


Year Ended December 31,

2006	$	1,198
2007		816
2008		724
2009		570
2010		428
Thereafter		463

Rent expense approximated $7.0 million, $5.6 million, and $3.0 million for 2005, 2004, and 2003, respectively.

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

Employment Agreements

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

Basic has entered into employment agreements with various other executive officers of Basic that range in term up through 2007. Under these agreements, if the officer’s employment is terminated for certain reasons, he would be entitled to a lump sum severance payment equal to six months annual salary, or 12 to 36 months’ annual salary if termination is on or following a change of control of Basic.

Self-Insured Risk Accruals

Basic is self-insured up to retention limits as it relates to workers’ compensation and medical and dental coverage of its employees. Basic, generally, maintains no physical property damage coverage on its workover rig fleet, with the exception of certain of its 24-hour workover rigs and newly manufactured rigs. Basic has deductibles per occurrence for workers’ compensation and medical and dental coverage of $150,000 and $125,000, respectively. Basic has lower deductibles per occurrence for automobile liability and general liability. Basic maintains

F1-25

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


	accruals in the accompanying consolidated balance sheets related to self-insurance retentions by using third-party data and historical claims history.

At December 31, 2005 and December 31, 2004, self-insured risk accruals, net of related recoveries/receivables totaled approximately $9.5 million and $6.6 million, respectively.


8.	Mandatorily Redeemable Preferred Stock and Stockholders’ Equity

Common Stock

In February 2002, a group of related investors purchased a total of 3,000,000 shares of Basic’s common stock at a purchase price of $4 per share, for a total purchase price of $12 million. As part of the purchase, 600,000 common stock warrants were issued in connection with this transaction, the fair value of which was approximately $1.2 million (calculated using an option valuation model). The warrants allow the holder to purchase 600,000 shares of Basic’s common stock at $4 per share. The warrants are exercisable in whole or in part after June 30, 2002 and prior to February 13, 2007.

In May 2003, the holders of the exercisable EBITDA Contingent Warrants purchased 771,740 shares of Basic’s common stock as a price of $.01 per share. See note 11. In October, 2003 Basic issued 3,650,000 shares of its common stock to acquire all the capital sock of FESCO. See note 3.

In February 2004, Basic granted certain officers and directors 837,500 restricted shares of common stock. The shares vest 25% per year for four years from the award date and are subject to other vesting and forfeiture provisions. The estimated fair value of the restricted shares was $5.8 million at the date of the grant and was recorded as deferred compensation, a component of stockholders’ equity. This amount is being charged to expense over the respective vesting period and totaled approximately $1.6 million and $1.3 million for the years ended December 31, 2005 and 2004, respectively.

On August 3, 2005, the board of directors of Basic approved a resolution to effect a 5-for-1 stock split of the Company’s common stock in the form of a stock dividend resulting in 28,931,935 shares of common stock outstanding, and to amend the Company’s certificate of incorporation to increase the authorized common stock to 80,000,000 shares. The earnings per share information and all common stock information have been retroactively restated for all periods presented to reflect this stock split. On September 22, 2005 the pricing committee set the record date and distribution date for the stock dividend, and the stock dividend was paid on September 26, 2005 to holders of record on September 23, 2005. The Company retained the current par value of $.01 per share for all common shares.

In December 2005, Basic issued 5,000,000 shares of common stock during the Company’s Initial Public Offering to a group of investors for $100 million or $20 per share. After deducting fees, this resulted in net proceeds to Basic totaling approximately $91.5 million.

Preferred Stock


	In June 2002, Basic issued 150,000 shares of mandatorily redeemable Series A 10% Cumulative Preferred Stock (“Series A Preferred Stock”) to a group of investors for $15 million or $100 per share. After deducting fees, this resulted in net proceeds to Basic totaling approximately $14.9 million.

Dividends on each share of Series A Preferred Stock accrued on a daily basis at the rate of 10% per annum of the sum of the Liquidation Value ($100) thereof plus all accrued and unpaid

F1-26

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

dividends thereon from and including the date of issuance of such share. All dividends which had accrued on the Series A Preferred Stock were payable on March 31, June 30, September 30 and December 31 of each year, beginning September 30, 2002. all dividends which had accrued on Series A shares outstanding remained as accumulated dividends until paid to the holders thereof.

Basic could redeem all or any portion of the Series A Preferred Stock by paying a price per share equal to the Liquidation Value ($100) plus all accrued and unpaid dividends plus a premium equal to 1% of the sum of the Liquidation Value plus all accrued and unpaid dividends on or prior to March 31, 2008. Basic was required to redeem all Series A Preferred Stock on March 31, 2008 (including accrued and unpaid dividends).

The difference between the $15 million face value of the Series A Preferred Stock and ultimate redemption value of approximately $26,975,000 (assuming Basic paid no dividends in cash prior to redemption) was being accreted to the face value of the Series A Preferred Stock from the date of issuance to the mandatory redemption date of March 31, 2008 utilizing the effective interest method.

In connection with the Series A Preferred Stock financing transaction, Basic granted 3,750,000 common stock warrants to acquire a total of 3,750,000 shares of common stock at a price of $4 per share, exercisable in whole or in part from June 30, 2002 through June 30, 2007 to the holders of Series A Preferred Stock, the relative fair value of which (the initial fair value was approximately $5.9 million, calculated using an option valuation model, and the relative fair value was approximately $4.4 million) was recorded as a discount on the Series A Preferred and included in additional pain-in capital. The Series A Preferred Stock discount, consisting of the warrant fair value of $4.3 million and $58,000 of offering expenses, was being accreted to the Series A Preferred Stock face value from the date of issuance to the mandatory redemption date of March 31, 2008 utilizing the effective interest method.

In January 2003, Basic issued an additional 9,020 shares of Series A Preferred Stock in lieu of cash of approximately $902,000 for accrued dividends on the Series A Preferred Stock.

On October 3, 2003, all the Series A Preferred Stock, plus accrued dividends, was converted into 3,304,085 shares of Basic’s common stock, at which time the estimated fair value of Basic’s common stock was $5.16 per share, pursuant to a share exchange agreement dated September 22, 2003. This conversion did not include the 3,750,000 common stock warrants which remain outstanding at December 31, 2005. The excess of the consideration received by the preferred shareholders over the book value of the preferred stock at the conversion date has been treated as a reduction in net income available to common stockholders.


9.	Stockholders’ Agreement

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

The Stockholders’ Agreement imposes transfer restrictions on the stockholders prior to December 21, 2007 (or earlier upon either (i) DLJ Merchant Banking and its affiliates ceasing to own at least 25% of its percentage based on their initial equity positions, or (ii) the end of a contractual lock-up period imposed by underwriters after in initial public offering). During this period, stockholders are generally prohibited from transferring shares to persons other than permitted assignees. The Stockholders’ Agreement provides for participation rights of the other stockholders to require affiliates of DLJ Merchant Banking to offer to include a specified percentage of their shares whenever affiliates of DLJ Merchant Banking sell their shares for

F1-27

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

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

The Stockholders’ Agreement also provided for demand registration rights after an initial public offering, and piggyback registration rights both in and after an initial public offering of Basic’s common stock.


10.	Incentive Plan

In May 2003, Basic’s board of directors and stockholders approved the Basic 2003 Incentive Plan (the “Plan”) (as amended effective April 22, 2005) which provides for granting of incentive awards in the form of stock options, restricted stock, performance awards, bonus shares, phantom shares, cash awards and other stock-based awards to officers, employees, directors and consultants of Basic. The Plan assumed awards of the plans of Basic’s successors that were awarded and remained outstanding prior to adoption of the Plan. The Plan provides for the issuance of 5,000,000 shares. The Plan is administered by the Plan committee, and in the absence of a Plan committee, by the Board of Directors, which determines the awards, and the associated terms of the awards and interprets its provisions and adopts policies for implementing the Plan. The number of shares authorized under the Plan and the number of shares subject to an award under the Plan will be adjusted for stock splits, stock dividends, recapitalizations, mergers and other changes affecting the capital stock of Basic.

On January 26, 2005, March 2, 2005, May 16, 2005, and on December 16, 2005 the board of directors granted various employees options to purchase 100,000, 865,000, 5,000 and 37,500 shares, respectively, of common stock of Basic at exercise prices of $5.16, $6.98, $6.98, and $21.01 per share, respectively. Of the 1,007,500 options granted in 2005, 970,000 options vest over a five-year period and expire 10 years from the date they are granted. The remaining 37,500 options vest over a three-year period and expire 10 years from the date they are granted. In connection with the stock option grants, Basic recorded deferred compensation of approximately $5.2 million which is being amortized over the related vesting period.

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

F1-28

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

The following table reflects the summary of the stock options outstanding for the years ended December 31, 2005, 2004, and 2003 and the changes during the years then ended:


			2005					2004					2003

						Weighted					Weighted					Weighted
			Number of			Average		Number of			Average		Number of			Average
			Options			Price		Options			Price		Options			Price

Non-statutory stock options:
	Outstanding, beginning of year			1,463,300		$	4.17		1,290,800		$	4.03		700,800		$	4.00
		Options granted		1,007,500		$	7.32		197,500		$	5.16		642,500		$	4.06
		Options forfeited		(25,000	)	$	6.98		(25,000	)	$	5.16		(52,500	)	$	4.00
		Options exercised		—		$	—		—		$	—		—		$	—

	Outstanding, end of year			2,445,800		$	5.44		1,463,300		$	4.17		1,290,800		$	4.03

	Exercisable, end of year			1,126,665					872,440					421,675

Weighted average fair value of options granted during the year			$	8.00				$	3.14				$	1.61

The following table summarizes information about Basic’s stock options outstanding and options exercisable at December 31, 2005:


	Options Outstanding						Options Exercisable

	Number of Options		Weighted Average		Weighted		Number of Options		Weighted
Range of	Outstanding at		Remaining		Average		Outstanding at		Average
Exercise Prices	December 31, 2005		Contractual Life		Exercise Price		December 31, 2005		Exercise Price

$ 4.00		1,253,300		6.43 years	$	4.00		1,074,166	$	4.00
$ 5.16		310,000		8.48 years	$	5.16		52,499	$	5.16
$ 6.98		845,000		9.17 years	$	6.98		—	$	—
$21.01		37,500		9.96 years	$	21.01		—	$	—

		2,445,800						1,126,665


11.	EBITDA Contingent Warrants

On December 21, 2000, Basic issued EBITDA Contingent Warrants to purchase up to an aggregate of (a) 1,149,705 shares, at $.01 per share, of its common stock as a dividend to stockholders of record on December 18, 2000 and (b) 287,425 shares, at $0.01 per share, as part of an authorized issuance to certain members of management of Basic. The determination of the ultimate number of EBITDA Contingent Warrants that may be exercised was dependent of Basic achieving certain levels of financial performance in 2001 and 2002. The warrants became exercisable no later than March 31, 2003 based on the actual financial performance for 2001 and 2002 and expired on May 1, 2003.

On August 23, 2001, Basic issued additional EBITDA Contingent Warrants to purchase up to an aggregate of 106,310 shares, at $0.01 per share, of Basic’s common stock as part of an authorized issuance to certain members of its management. The determination of the ultimate number of EBITDA Contingent Warrants that may be exercised was dependent on Basic’s achieving certain levels of financial performance in 2001 and 2002. The warrants became exercisable, and were not subject to forfeiture for termination, no later than March 31, 2003 based on actual financial performance for 2001 and 2002 and expired on May 1, 2003.

F1-29

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

In 2003, it was determined that Basic did not meet the financial performance objectives as set forth in the EBITDA Contingent Warrant grants. However, the board of directors evaluated other subjective matters regarding these grants and authorized the award of 574,860 warrants to the stockholders and 196,880 warrants to certain members of management even though the performance criteria was not met. As a result, Basic recognized the compensation expense of $911,000 related to the portion of the warrants issued to management in 2003. In 2003, all holders of the warrants exercised all of their rights and acquired common stock of Basic. The value of the warrants associated with the common stock dividend was recorded in 2003 when the number of warrants to be issued was known.


12.	Related Party Transactions

Basic provided services and products for workover, maintenance and plugging of existing oil and gas wells to Southwest Royalties, Inc., an affiliate of a director and other significant stockholders of Basic, for approximately $0, $140,000, and $1.3 million in 2005, 2004, and 2003, respectively. Basic had no receivables from this related party as of December 31, 2005 or 2004. Basic had receivables from employees totaling $65,000 and $64,900 as of December 31, 2005 and 2004 respectively.


13.	Profit Sharing Plan

Basic has a 401(k) profit sharing plan that covers substantially all employees with more than 90 days of service. Employees may contribute up to their base salary not to exceed the annual Federal maximum allowed for such plans. Basic makes a matching contribution proportional to each employee’s contribution. Employee contributions are fully vested at all times. Employer matching contributions vest incrementally, with full vesting occurring after five years of service. Employer contributions to the 401(k) plan approximated $468,000, $363,000 and $180,000 in 2005, 2004, and 2003, respectively.


14.	Deferred Compensation Plan

In April 2005, Basic established a deferred compensation plan for certain employees. Participants may defer up to 50% of their salary and 100% of any cash bonuses. Basic makes matching contributions of 20% of the participants’ deferrals. Employer matching contributions and earnings thereon are subject to a five-year vesting schedule with full vesting occurring after five years of service. Employer contributions to the deferred compensation plan approximated $56,000, $0, and $0 in 2005, 2004, and 2003, respectively.

F1-30

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


15.	Earnings Per Share

Basic presents earnings per share information in accordance with the provisions of Statement of Financial Accounting Standards No. 128, “Earnings per Share” (“SFAS No. 128”). Under SFAS No. 128, basic earnings per common share are determined by dividing net earnings applicable to common stock by the weighted average number of common shares actually outstanding during the year. Diluted earnings per common share is based on the increased number of shares that would be outstanding assuming conversion of dilutive outstanding securities using the ’as if converted” method. The following table sets forth the computation of basic and diluted earnings per share. (in thousands, except share data):


		Years Ended December 31,

		2005		2004			2003

Numerator (both basic and diluted):
	Income from continuing operations	$	44,781	$	12,932		$	(1,986	)
	Discontinued operations, net of tax		—		(71	)		22
	Cumulative effect of accounting change		—		—			(151	)

	Net income available to common stockholders	$	44,781	$	12,861		$	(2,115	)

Denominator:
	Weighted average common stock outstanding		28,381,853		28,094,435			22,575,940
	Vested restricted stock		199,058		—			—

	Denominator for basic earnings per share		28,580,911		28,094,435			22,575,940
	Stock options		789,991		389,975			—
	Unvested restricted stock		638,442		837,500			—
	Common stock warrants		3,159,035		1,333,310			—

	Denominator for diluted earnings per share		33,168,379		30,655,220			22,575,940

Basic earnings per common share:
	Income from continuing operations less preferred stock dividends and accretion	$	1.57	$	0.46		$	(0.09	)
	Discontinued operations, net of tax		—		—			—

	Net income (loss) available to common stockholders	$	1.57	$	0.46		$	(0.09	)

Diluted earnings per common share:
	Income from continuing operations less preferred stock dividends and accretion	$	1.35	$	0.42		$	(0.09	)
	Discontinued operations, net of tax		—		—			—

	Net income (loss) available to common stockholders	$	1.35	$	0.42		$	(0.09	)

The diluted earnings per share calculation for 2003 excludes the effects of all stock options and common stock warrants as the effects would be anti-dilutive as a result of the net loss.


16.	Assets Held for Sale and Discontinued Operations

In August, 2003 Basic’s management and board of directors made the decision to dispose of its fluid services operations in Alaska it acquired in the FESCO acquisition prior to closing of the acquisition. After this disposal Basic no longer had any operations in Alaska.

F1-31

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

The following are the results of operations, since their acquisition in October 2003, from the discontinued operations (in thousands):


		Years Ended
		December 31,

		2004			2003

Revenues		$	1,705		$	550
Operating costs			(1,814	)		(515	)
Income taxes — deferred			38			(13	)

	Loss from discontinued operations, net of tax	$	(71	)	$	22


17.	Business Segment Information

Basic’s reportable business segments are well servicing, fluid services, drilling and completion services and well site construction services. The following is a description of the segments:

Well Servicing: This business segment encompasses a full range of services performed with a mobile well servicing rig, including the installation and removal of downhole equipment and elimination of obstructions in the well bore to facilitate the flow of oil and gas. These services are performed to establish, maintain and improve production throughout the productive life of an oil and gas well and to plug and abandon a well at the end of its productive life. Basic well servicing equipment and capabilities are essential to facilitate most other services performed on a well.

Fluid Services: This segment utilizes a fleet of trucks and related assets, including specialized tank trucks, storage tanks, water wells, disposal facilities and related equipment. Basic employs these assets to provide, transport, store and dispose of a variety of fluids. These services are required in most workover, drilling and completion projects as well as part of daily producing well operations.

Drilling and completion Services: This segment focuses on a variety of services designed to stimulate oil and gas production or to enable cement slurry to be placed in or circulated within a well. These services are carried out in niche markets for jobs requiring a single truck and lower horsepower.

Well Site Construction Services: This segment utilizes a fleet of power units, dozers, trenchers, motor graders, backhoes and other heavy equipment. Basic employs these assets to provide services for the construction and maintenance of oil and gas production infrastructure, such as preparing and maintaining access roads and well locations, installation of small diameter gathering lines and pipelines and construction of temporary foundations to support drilling rigs.

F1-32

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Basic’s management evaluates the performance of its operating segments based on operating revenues and segment profits. Corporate expenses include general corporate expenses associated with managing all reportable operating segments. Corporate assets consist principally of working capital and debt financing costs. The following table sets forth certain financial information with respect to Basic’s reportable segments (in thousands):


							Drilling and			Well Site
	Well			Fluid			Completion			Construction			Corporate
	Servicing			Services			Services			Services			and Other		Total

*Year ended December 31, 2005*
Operating revenues	$	221,993		$	132,280		$	59,832		$	45,647		$	—	$	459,752
Direct operating costs		(137,392	)		(82,551	)		(30,900	)		(32,000	)		—		(282,843	)

Segment profits	$	84,601		$	49,729		$	28,932		$	13,647		$	—	$	176,909

Depreciation and amortization	$	18,671		$	9,415		$	3,644		$	2,808		$	2,534	$	37,072
Capital expenditures, (excluding acquisitions)	$	42,838		$	21,602		$	8,361		$	6,443		$	3,851	$	83,095
Identifiable assets	$	169,487		$	100,959		$	45,850		$	28,376		$	152,621	$	497,293
*Year ended December 31, 2004*
Operating revenues	$	142,551		$	98,683		$	29,341		$	40,927		$	—	$	311,502
Direct operating costs		(98,058	)		(65,167	)		(17,481	)		(31,454	)		—		(212,160	)

Segment profits	$	44,493		$	33,516		$	11,860		$	9,473		$	—	$	99,342

Depreciation and amortization	$	14,125		$	8,316		$	2,402		$	1,857		$	1,976	$	28,676
Capital expenditures, (excluding acquisitions)	$	27,918		$	16,436		$	3,670		$	4,748		$	2,902	$	55,674
Identifiable assets	$	126,208		$	87,349		$	24,246		$	24,064		$	105,993	$	367,860
*Year ended December 31, 2003*
Operating revenues	$	104,097		$	52,810		$	14,808		$	9,184		$	—	$	180,899
Direct operating costs		(73,244	)		(34,420	)		(9,363	)		(6,586	)		—		(123,613	)

Segment profits	$	30,853		$	18,390		$	5,445		$	2,598		$	—	$	57,286

Depreciation and amortization	$	9,100		$	5,201		$	2,575		$	850		$	487	$	18,213
Capital expenditures, (excluding acquisitions)	$	13,217		$	6,298		$	676		$	2,412		$	898	$	23,501
Identifiable assets	$	102,948		$	73,841		$	10,387		$	31,322		$	84,155	$	302,653

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


	Year Ended December 31,

	2005			2004			2003

Segment profits	$	176,909		$	99,342		$	57,286
General and administrative expenses		(55,411	)		(37,186	)		(22,722	)
Depreciation and amortization		(37,072	)		(28,676	)		(18,213	)
Gain (loss) on disposal of assets		222			(2,616	)		(391	)

Operating income	$	84,648		$	30,864		$	15,960

F1-33

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


18.	Accrued Expenses

The accrued expenses are as follows (in thousands):


	December 31,

	2005		2004

Compensation related	$	10,576	$	6,764
Workers’ compensation self-insured risk reserve		7,461		5,469
Health self-insured risk reserve		2,200		1,490
Accrual for receipts		1,841		903
Authority for expenditure accrual		3,052		879
Ad valorem taxes		935		845
Sales tax		2,407		692
Insurance obligations		673		586
Purchase order accrual		96		409
Professional fee accrual		1,079		392
Diesel tax accrual		385		336
Acquired contingent earnout obligation		—		273
Retainers		1,042		250
Fuel accrual		368		317
Accrued interest		391		232
Contingent liability		1,000		—
Other		42		649

	$	33,548	$	20,486


19.	Supplemental Schedule of Non-Cash Investing and Financing Activities


	Year Ended December 31,

	2005		2004		2003

	(In thousands)
Capital leases issued for equipment	$	10,334	$	10,472	$	10,782
Preferred stock dividend	$	—	$	—	$	1,525
Preferred stock issued to pay accrued dividends	$	—	$	—	$	902
Accretion of preferred stock discount	$	—	$	—	$	3,424
Common stock issued for FESCO acquisition	$	—	$	—	$	18,827
Common stock issued for preferred stock	$	—	$	—	$	17,029
Vehicle rebate accrual	$	—	$	709	$	—
Asset retirement obligation additions	$	74	$	21	$	—

F1-34

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


20.	Quarterly Financial Data (Unaudited)

The following table summarizes results for each of the four quarters in the years ended December 31, 2005 and 2004:


			First		Second		Third		Fourth
			Quarter		Quarter		Quarter		Quarter		Year

Year ended December 31, 2005:
		Total revenues	$	93,813	$	109,818	$	120,771	$	135,350	$	459,752
		Segment profits	$	33,416	$	42,238	$	45,791	$	55,464	$	176,909
		Income from continuing operations	$	5,801	$	10,747	$	12,335	$	15,898	$	44,781
		Net income available to common stockholders	$	5,801	$	10,747	$	12,335	$	15,898	$	44,781
	Basic earnings per share of common stock(a):
		Continuing operations	$	0.21	$	0.38	$	0.44	$	0.54	$	1.57
		Net income available to common stockholders	$	0.21	$	0.38	$	0.44	$	0.54	$	1.57
	Diluted earnings per share of common stock(a):
		Continuing operations	$	0.18	$	0.33	$	0.38	$	0.46	$	1.35
		Net income available to common stockholders	$	0.18	$	0.33	$	0.38	$	0.46	$	1.35
	Weighted average common shares outstanding:
		Basic		28,186		28,328		28,318		29,481		28,581
		Diluted		32,157		32,783		32,802		34,436		33,168
Year ended December 31, 2004:
		Total revenues	$	67,603	$	74,262	$	83,714	$	85,923	$	311,502
		Segment profits	$	21,548	$	23,717	$	26,605	$	27,472	$	99,342
		Income from continuing operations	$	2,633	$	3,369	$	3,800	$	3,130	$	12,932
		Net income available to common stockholders	$	2,685	$	3,405	$	3,641	$	3,130	$	12,861
	Basic earnings per share of common stock(a):
		Continuing operations	$	0.09	$	0.12	$	0.14	$	0.11	$	0.46
		Net income available to common stockholders	$	0.10	$	0.12	$	0.13	$	0.11	$	0.46
	Diluted earnings per share of common stock(a):
		Continuing operations	$	0.09	$	0.11	$	0.12	$	0.10	$	0.42
		Net income (loss) available to common stockholders	$	0.09	$	0.11	$	0.12	$	0.10	$	0.42
	Weighted average common shares outstanding:
		Basic		28,094		28,094		28,094		28,094		28,094
		Diluted		30,391		31,270		31,493		31,789		30,655


(a)		The sum of individual quarterly net income per share may not agree to the total for the year to due each period’s computation based on the weighted average number of common shares outstanding during each period.

F1-35

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


21.	Subsequent Events


*(a)*	*Acquisitions*

On January 31, 2006, Basic acquired all of the outstanding capital stock of LeBus Oil Field Service Co. for an acquisition price of $26 million, subject to adjustments. The acquisition will operate in Basic’s fluid services line of business in the Ark-La-Tex division.

On February 28, 2006, Basic acquired substantially all of the operating assets of G&L Tool, Ltd. for total consideration of $58 million cash. This acquisition will operate in Basic’s drilling and completion line of business. The purchase agreement also contained an earn-out agreement based on annual EBITDA targets.

F1-36

BASIC ENERGY SERVICES, INC.

December 31, 2005, 2004, and 2003

Schedule II — Valuation and Qualifying Accounts


			Additions

	Balance at		Charged to		Charged to					Balance at
	Beginning of		Costs and		Other		Deductions			End of
	Period		Expenses(a)		Accounts(b)		(c)			Period
Description
	(In thousands)
Year Ended December 31, 2005
Allowance for Bad Debt	$	3,108	$	1,651	$	—	$	(1,984	)	$	2,775
Year Ended December 31, 2004
Allowance for Bad Debt	$	1,958	$	1,200	$	—	$	(50	)	$	3,108
Year Ended December 31, 2003
Allowance for Bad Debt	$	501	$	1,279	$	375	$	(197	)	$	1,958


(a)		Charges relate to provisions for doubtful accounts

(b)		Reflects the impact of acquisitions

(c)		Deductions relate to the write-off of accounts receivable deemed uncollectible

F1-37

Basic Energy Services, Inc.

Consolidated Balance Sheet

(In thousands, except share data)


			March 31,
			2006

			(Unaudited)
ASSETS
Current assets:
	Cash and cash equivalents		$	19,953
	Trade accounts receivable, net of allowance of $2,984			101,241
	Accounts receivable — related parties			92
	Inventories			1,851
	Prepaid expenses			3,790
	Other current assets			2,744
	Deferred tax assets			6,700

		Total current assets		136,371

Property and equipment, net				399,865
Deferred debt costs, net of amortization				4,583
Goodwill				73,201
Other assets				2,767

			$	616,787

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable		$	11,376
	Accrued expenses			39,711
	Income taxes payable			13,124
	Current portion of long-term debt			8,559
	Other current liabilities			1,328

		Total current liabilities		74,098

Long-term debt				201,488
Deferred income				11
Deferred tax liabilities				59,956
Other long-term liabilities				2,993
Commitments and contingencies
Stockholders’ equity:
	Common stock; $.01 par value; 80,000,000 shares authorized; 33,931,935 shares issued; 33,787,305 shares outstanding			339
	Additional paid-in capital			235,264
	Deferred compensation			—
	Retained earnings			46,174
	Treasury stock, 144,630 shares, at cost			(3,618	)
	Accumulated other comprehensive income			82

		Total stockholders’ equity		278,241

			$	616,787

See accompanying notes to consolidated financial statements.

F2-1

Basic Energy Services, Inc.

Consolidated Statements of Operations and Comprehensive Income

(Dollars in thousands, except per share amounts)


				Three Months
				Ended March 31,

				2006			2005

				(Unaudited)
Revenues:
	Well servicing			$	73,465		$	44,798
	Fluid services				43,121			29,303
	Drilling and completion services				27,455			10,764
	Well site construction services				10,265			8,948

		Total revenues			154,306			93,813

Expenses:
	Well servicing				41,610			28,191
	Fluid services				26,305			19,238
	Drilling and completion services				13,854			5,860
	Well site construction services				7,643			7,108
	General and administrative, including stock-based compensation of $758 and $591 in 2006 and 2005, respectively				18,005			13,091
	Depreciation and amortization				12,837			8,047
	(Gain) loss on disposal of assets				(200	)		102

		Total expenses			120,054			81,637

			Operating income		34,252			12,176
Other income (expense):
	Interest expense				(3,138	)		(3,061	)
	Interest income				359			101
	Other income				27			75

Income from continuing operations before income taxes					31,500			9,291
Income tax expense					(11,819	)		(3,490	)

Net income				$	19,681		$	5,801

Earnings per share of common stock:
	Basic			$	0.59		$	0.21

	Diluted			$	0.53		$	0.18

Comprehensive Income:
Net income				$	19,681		$	5,801
	Unrealized gains (loss) on hedging activities				(154	)		314

Comprehensive Income				$	19,527		$	6,115

See accompanying notes to consolidated financial statements.

F2-2

Basic Energy Services, Inc.

Consolidated Statements of Stockholders’ Equity

(In thousands, except share data)


																	Accumulated
	Common Stock				Additional												Other			Total
					Paid-In			Deferred			Treasury			Retained			Comprehensive			Stockholders’
	Shares		Amount		Capital			Compensation			Stock			Earnings			Income			Equity

	(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 new accounting standard		—		—		(7,341	)		7,341			—			—			—			—
Amortization of deferred compensation		—		—		758			—			—			—			—			758
Unrealized loss on interest rate swap agreement		—		—		—			—			—			—			(154	)		(154	)
Offering costs		—		—		(161	)		—			—			—			—			(161	)
Purchase of treasury stock		—		—		—			—			(3,248	)		—			—			(3,248	)
Exercise of stock options		—		—		2,790			—			2,161			(2,161	)		—			2,790
Net income		—		—		—			—			—			19,681			—			19,681

Balance — March 31, 2006 (Unaudited)		33,931,935	$	339	$	235,264		$	—		$	(3,618	)	$	46,174		$	82		$	278,241

See accompanying notes to consolidated financial statements.

F2-3

Basic Energy Services, Inc.

Consolidated Statements of Cash Flows

(In thousands)


					Three Months Ended
					March 31,

					2006			2005

					(Unaudited)
Cash flows from operating activities:
	Net income				$	19,681		$	5,801
		Adjustments to reconcile net income to net cash provided by operating activities:
			Depreciation and amortization			12,837			8,047
			Accretion on asset retirement obligation			19			9
			Change in allowance for doubtful accounts			209			450
			Non-cash interest expense			310			263
			Non-cash compensation			758			591
			(Gain) loss on disposal of assets			(200	)		102
			Deferred income taxes			(2,873	)		3,490
		Changes in operating assets and liabilities, net of acquisitions:
			Accounts receivable			(10,708	)		(2,763	)
			Inventories			(18	)		(171	)
			Prepaid expenses and other current assets			(1,442	)		(317	)
			Other assets			(319	)		(53	)
			Accounts payable			(3,169	)		(1,344	)
			Excess tax benefits from exercise of employee stock options			(2,790	)		—
			Income tax payable			7,449			—
			Deferred income and other liabilities			342			(122	)
			Accrued expenses			5,829			2,751

				Net cash provided by operating activities		25,915			16,734

		Cash flows from investing activities:
			Purchase of property and equipment			(24,812	)		(16,083	)
			Proceeds from sale of assets			1,141			95
			Payments for other long-term assets			(393	)		(49	)
			Payments for businesses, net of cash acquired			(87,520	)		(3,909	)

				Net cash used in investing activities		(111,584	)		(19,946	)

		Cash flows from financing activities:
			Proceeds from debt			80,000			129
			Payments of debt			(6,544	)		(2,938	)
			Offering costs related to initial public offering			(161	)		—
			Purchase of treasury stock			(1,258	)		—
			Excess tax benefits from exercise of employee stock options			2,790			—
			Exercise of employee stock options			(1,990	)		—
			Deferred loan costs and other financing activities			(60	)		(8	)

				Net cash provided by (used in) financing activities		72,777			(2,817	)

				Net increase (decrease) in cash and equivalents		(12,892	)		(6,029	)
		Cash and cash equivalents — beginning of period				32,845			20,147

		Cash and cash equivalents — end of period			$	19,953		$	14,118

See accompanying notes to consolidated financial statements.

F2-4

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements

March 31, 2006


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


2.	Summary of Significant Accounting Policies

Principles of Consolidation


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

Revenue Recognition

Well Site Construction Services — Basic recognizes revenue when services are performed, collection of the relevant receivables is probable, persuasive evidence of an arrangement exists

F2-5

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

and the price is fixed or determinable. Basic prices well site construction services by the hour, day, or project depending on the type of service performed.

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.

Basic had no impairment expense in the three months ended March 31, 2006 and 2005, respectively.

Deferred Debt Costs

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

Deferred debt costs of approximately $7.1 million at March 31, 2006 and $7.0 million at December 31, 2005, respectively, represent debt issuance costs and are recorded net of accumulated amortization of $2.5 million, and $2.2 million at March 31, 2006 and December 31, 2005, respectively. Amortization of deferred debt costs totaled approximately $311,000 and $263,000 for the three months ended March 31, 2006 and 2005, respectively.

Goodwill

F2-6

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

then the fair value of the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination. The amount of impairment for goodwill is measured as the excess of its carrying value over its fair value. Basic completed its assessment of goodwill impairment as of the date of adoption and completed a subsequent annual impairment assessment as of December 31 each year thereafter. The assessments did not result in any indications of goodwill impairment.

Basic has identified its reporting units to be well servicing, fluid services, drilling and completion services and well site construction services. The goodwill allocated to such reporting units as of March 31, 2006 is $9.9 million, $30.7 million, $28.9 million and $3.7 million, respectively. The change in the carrying amount of goodwill for the three months ended March 31, 2006 of $25.0 million relates to goodwill from acquisitions and payments pursuant to contingent earn-out agreements, with approximately $10.1 million and $14.9 million of goodwill additions relating to the fluid services and drilling and completion units, respectively.

Stock-Based Compensation

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

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

Under SFAS No. 123R, entities using the minimum value method and the prospective application are not permitted to provide the pro forma disclosures (as was required under Statement of Financial Accounting Standard No. 123,“Accounting for Stock-Based Compensation” (“SFAS No. 123”)) subsequent to adoption of SFAS 123R since they do not have the fair value information required by SFAS No. 123R. Therefore, in accordance with 123R, Basic will no longer include pro forma disclosures that were required by SFAS 123.

Asset Retirement Obligations

Basic owns and operates salt water disposal sites, brine water wells, gravel pits and land farm sites, each of which is subject to rules and regulations regarding usage and eventual

F2-7

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

closure. The following table reflects the changes in the liability during the three months ended March 31, 2006 (in thousands):


Balance, December 31, 2005	$	569
Additional asset retirement obligations recognized through acquisitions		118
Accretion Expense		19
Increase in asset retirement obligations due to change in estimate		295

Balance, March 31, 2006 (unaudited)	$	1,001

Environmental

Litigation and Self-Insured Risk Reserves

Basic estimates its reserves related to litigation and self-insured risks based on the facts and circumstances specific to the litigation and self-insured claims and its past experience with similar claims in accordance with Statement of Financial Accounting Standard No. 5 “Accounting for Contingencies”. Basic maintains accruals in the consolidated balance sheets to cover self-insurance retentions (See note 6).

Recent Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board issued SFAS No. 123R. As discussed under this Note 2, “Stock-Based Compensation,” Basic adopted the provisions of SFAS No. 123R on January 1, 2006.

F2-8

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


3.	Acquisitions

In 2006 and 2005, Basic acquired either substantially all of the assets or all of the outstanding capital stock of each of the following businesses, each of which were accounted for using the purchase method of accounting (in thousands):


			Total Cash Paid
			(net of cash
	Closing Date		acquired)

R & R Hot Oil Service		January 5, 2005	$	1,702
Premier Vacuum Service, Inc.		January 28, 2005		1,009
Spencer’s Coating Specialist		February 9, 2005		619
Mark’s Well Service		February 25, 2005		579
Max-Line, Inc.		April 28, 2005		1,498
MD Well Service, Inc.		May 17, 2005		4,478
179 Disposal, Inc.		August 4, 2005		1,729
Oilwell Fracturing Services, Inc.		October 11, 2005		13,764

Total 2005			$	25,378

LeBus Oil Field Services Co.		January 31, 2006	$	24,508
G&L Tool, Ltd.		February 28, 2006		58,000
Arkla Cementing, Inc.		March 27, 2006		5,012

Total 2006			$	87,520

Contingent Earn-out Arrangements and Final Purchase Price Allocations

On February 28, 2006, Basic acquired substantially all of the assets of G&L Tool for $58.0 million plus a contingent earn-out payment not to exceed $21.0 million. The contingent earn out payment will be equal to fifty percent of the amount by which the annual EBITDA earned by Basic exceeds an annual targeted EBITDA. There is no guarantee or assurance that the targeted EBITDA will be reached. This acquisition provided a platform to expand into the fishing and rental tool market operations. The cost of the G&L acquisition was allocated $43.3 million to property and equipment, $14.6 million to goodwill, and $51,000 to non-compete agreements. The allocations of the purchase price are based upon preliminary estimates and assumptions. Accordingly, the allocations are subject to revision when the Company receives final information, including appraisals and other analyses. Revisions to the fair values, which may be significant, will be recorded by the Company as further adjustments to the purchase price allocations.

F2-9

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

The following unaudited pro-forma results of operations have been prepared as though the G&L Tool acquisition had been completed on January 1, 2005. Pro forma amounts are based on the preliminary purchase price allocations of the significant acquisitions and are not necessarily indicative of the results that may be reported in the future (in thousands, except per share data).


	Three Months
	Ended March 31,

	2006		2005

	(Unaudited)
Revenues	$	163,799	$	101,482
Net income	$	22,145	$	7,296
Earnings per common share — basic	$	0.67	$	0.26
Earnings per common share — diluted	$	0.60	$	0.23

Basic does not believe the pro-forma effect of the remainder of the acquisitions completed in 2005 or 2006 is material, either individually or when aggregated, to the reported results of operations.


4.	Property and Equipment

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


	March 31,		December 31,
	2006		2005

	(Unaudited)
Land	$	2,108	$	1,902
Buildings and improvements		10,418		8,634
Well service units and equipment		217,086		199,070
Fluid services equipment		72,797		59,104
Brine and fresh water stations		7,773		7,746
Frac/test tanks		43,425		31,475
Pressure pumping equipment		38,479		31,101
Construction equipment		25,013		24,224
Disposal facilities		21,685		16,828
Vehicles		25,382		23,329
Rental equipment		47,906		6,519
Aircraft		3,236		3,236
Other		8,473		8,602

		523,781		421,770
Less accumulated depreciation and amortization		123,916		112,695

Property and equipment, net	$	399,865	$	309,075

F2-10

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


	March 31,		December 31,
	2006		2005

	(Unaudited)
Light vehicles	$	19,564	$	17,912
Fluid services equipment		14,662		14,011
Construction equipment		3,156		1,300

		37,382		33,223
Less accumulated amortization		9,535		8,474

	$	27,847	$	24,749

Amortization of assets held under capital leases of approximately $1,060,000 and $253,000 for the three months ended March 31, 2006 and 2005, respectively, is included in depreciation and amortization expense in the consolidated statements of operations.


5.	Long-Term Debt

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


		March 31,		December 31,
		2006		2005

		(Unaudited)
Credit Facilities:
	Term B Loan	$	89,750	$	90,000
	Revolver		96,000		16,000
Capital leases and other notes			24,297		20,887

			210,047		126,887
Less current portion			8,559		7,646

		$	201,488	$	119,241

2005 Credit Facility

On December 15, 2005, Basic entered into a $240 million Third Amended and Restated Credit Agreement with a syndicate of lenders (“2005 Credit Facility”), which refinanced all of its then existing credit facilities. The 2005 Credit Facility, as amended effective March 28, 2006, provides for a $90 million Term B Loan (“2005 Term B Loan”) and a $150 million revolving line of credit (“Revolver”). The commitment under the Revolver allows for (a) the borrowing of funds (b) issuance of up to $30 million of letters of credit and (c) $2.5 million of swing-line loans (next day borrowing). The amounts outstanding under the 2005 Term B Loan require quarterly amortization at various amounts during each quarter with all amounts outstanding on December 15, 2011 being due and payable in full. All the outstanding amounts under the Revolver are due and payable on December 15, 2010. The 2005 Credit Facility is secured by substantially all of Basic’s tangible and intangible assets. Basic incurred approximately $1.8 million in debt issuance costs in obtaining the 2005 Credit Facility.

F2-11

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

At Basic’s option, borrowings under the 2005 Term B Loan bear interest at either the (a) “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus .5% per annum) plus 1% or (b) the LIBOR rate plus 2.0%. At March 31, 2006 and December 31, 2005, Basic’s weighted average interest rate on its Term B Loan was 7.1% and 6.4%.

At Basic’s option, borrowings under the 2005 Revolver bear interest at either the (a) “Alternative Base Rate” (i.e. the higher of the bank’s prime rate or the federal funds rate plus .5% per annum) plus a margin ranging from .50% to 1.25% or (b) the LIBOR rate plus a margin ranging from 1.5% to 2.25%. The margins vary depending on Basic’s leverage ratio. At March 31, 2006, Basic’s margin on Alternative Base Rates and LIBOR tranches was .75% and 1.75%, respectively. Fees on the letters of credit are due quarterly on the outstanding amount of the letters of credit at a rate ranging from 1.5% to 2.25% for participation fees and .125% for fronting fees. A commitment fee is due quarterly on the available borrowings under the Revolver at rates ranging from .375% to .5%.

At March 31, 2006 Basic, under its Revolver, had outstanding $96 million of borrowings and $9.6 million of letters of credit and no amounts outstanding in swing-line loans. At March 31, 2006 and December 31, 2005 Basic had availability under its Revolver of $44.4 million and $124.4 million, respectively.

Pursuant to the 2005 Credit Facility, Basic must apply proceeds to reduce principal outstanding under the 2005 Term B Revolver from (a) individual assets sales greater than $2 million or $7.5 million in the aggregate on an annual basis, and (b) 50% of the proceeds from any equity offering. The 2005 Credit Facility required Basic to enter into an interest rate hedge, through May 28, 2006 on at least $65 million of Basic’s then outstanding indebtedness. The March 28, 2006 amendment deletes this requirement upon payoff of the Term B Loans. Paydowns on the 2005 Term B Loan may not be reborrowed.

The 2005 Credit Facility contains various restrictive covenants and compliance requirements, which include (a) limiting of the incurrence of additional indebtedness, (b) restrictions on mergers, sales or transfers of assets without the lenders’ consent, (c) limitation on dividends and distributions and (d) various financial covenants, including (1) a maximum leverage ratio of 3.5 to 1.0 reducing over time to 3.25 to 1.0, (2) a minimum interest coverage ratio of 3.0 to 1.0 and (e) limitations on capital expenditures in any period of four consecutive quarters in excess of 20% of Consolidated Net Worth unless certain criteria are met. At March 31, 2006 and December 31, 2005, Basic was in compliance with its covenants.

F2-12

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Other Debt


	Basic has a variety of other capital leases and notes payable outstanding that are generally customary in its business. None of these debt instruments are material individually or in the aggregate. Basic’s interest expense consisted of the following (in thousands):


	Three Months
	Ended March 31,

	2006		2005

	(Unaudited)
Cash payments for interest	$	1,942	$	2,723
Commitment and other fees paid		148		—
Amortization of debt issuance costs		311		263
Other		737		75

	$	3,138	$	3,061


6.	Commitments and Contingencies

Environmental

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 its 24-hour workover rigs and newly manufactured rigs. Basic has deductibles per occurrence for workers’

F2-13

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


	compensation and medical and dental coverage of $150,000 and $125,000, respectively. Basic has lower deductibles per occurrence for automobile liability and general liability. Basic maintains accruals in the accompanying consolidated balance sheets related to self-insurance retentions by using third-party data and historical claims history.

At March 31, 2006 and December 31, 2005, self-insured risk accruals, net of related recoveries/receivables totaled approximately $11.4 million and $9.5 million, respectively.


7.	Stockholders’ Equity

Common Stock

In February 2004, Basic granted certain officers and directors 837,500 restricted shares of common stock. The shares vest 25% per year for four years from the award date and are subject to other vesting and forfeiture provisions. The estimated fair value of the restricted shares was $5.8 million at the date of the grant and was recorded as deferred compensation, a component of stockholders’ equity. This amount is being charged to expense over the respective vesting period and totaled approximately $379,000 and $409,000 for the three months ended March 31, 2006 and 2005, respectively.

In March 2006, Basic issued 148,720 shares of common stock from treasury stock for the exercise of stock options.


8.	Incentive Plan

In May 2003, Basic’s board of directors and stockholders approved the Basic 2003 Incentive Plan (as amended effective April 22, 2005), (the “Plan”) which provides for granting of incentive awards in the form of stock options, restricted stock, performance awards, bonus shares, phantom shares, cash awards and other stock-based awards to officers, employees, directors and consultants of Basic. The Plan assumed awards of the plans of Basic’s successors that were awarded and remained outstanding prior to adoption of the Plan. The Plan provides for the issuance of 5,000,000 shares. The Plan is administered by the Plan committee, and in the absence of a Plan committee, by the Board of Directors, which determines the awards, and the associated terms of the awards and interprets its provisions and adopts policies for implementing the Plan. The number of shares authorized under the Plan and the number of shares subject to an award under the Plan will be adjusted for stock splits, stock dividends, recapitalizations, mergers and other changes affecting the capital stock of Basic.

On March 15, 2006, the board of directors granted various employees options to purchase 418,000 shares, respectively, of common stock of Basic at exercise prices of $26.84 per share, respectively. All of the 418,000 options granted in 2006 vest over a five-year

F2-14

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

period and expire 10 years from the date they were granted. Option awards are generally granted with an exercise price equal to the market price of the Company’s stock at the date of grant.

The fair value of each option award is estimated on the date of grant using the Black-Scholes-Merton option-pricing model that uses the subjective assumptions noted in the following table. Since the Company has only been public since December 2005, expected volatilities are based upon a peer group. When the Company has sufficient historical data to calculate expected volatility, the Company will use its’ own historical data to calculate expected volatility. The expected term of options granted represents the period of time that options granted are expected to be outstanding. The risk-free rate for periods within the contractual life of the options is based on the U.S. Treasury yield curve in effect at the time of grant. The estimates involve inherent uncertainties and the application of management judgment. In addition, we are required to estimate the expected forfeiture rate and only recognize expense for those options expected to vest. Compensation expense related to share-based arrangements was approximately $758,000 and $591,000 during the three months ended March 31, 2006 and 2005, respectively.

The fair value of each option award accounted for under FAS 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:


	Three Months
	Ended March 31,
	2006

Risk-free interest rate		4.7	%
Expected term		6.65
Expected volatility		47.0	%
Expected dividend yield		—

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

The following table reflects the summary of stock options outstanding for the three months ended March 31, 2006 and the changes during the three months then ended:


					Weighted		Aggregate
		Number of			Average		Intrinsic
		Options			Exercise		Value
		Granted			Price		(000’s)

Non-statutory stock options:
	Outstanding beginning of period		2,445,800		$	5.44		—
	Options granted		418,000		$	26.84		—
	Options forfeited		(10,000	)	$	6.98		—
	Options exercised		(148,720	)	$	4.00		—

	Outstanding, end of period		2,705,080		$	8.82	$	52,866

	Exercisable, end of period		1,277,913		$	4.16	$	32,769

	Expected to vest, end of period		1,391,469		$	12.64	$	23,883

F2-15

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

The following table summarizes information about Basic’s stock options outstanding and options exercisable at March 31, 2006:


	Options Outstanding						Options Exercisable

	Number of						Number of
	Options		Weighted		Weighted		Options		Weighted		Weighted
	Outstanding at		Average		Average		Outstanding at		Average		Average
Range of	March 31,		Remaining		Exercise		March 31,		Remaining		Exercise
Exercise Prices	2006		Contractual Life		Price		2006		Contractual Life		Price

$ 4.00		1,104,580		6.20	$	4.00		1,104,580		6.20	$	4.00
$ 5.16		310,000		8.23	$	5.16		173,333		8.12	$	5.16
$ 6.98		835,000		8.92	$	6.98		—		—	$	—
$21.01		37,500		9.71	$	21.01		—		—	$	—
$26.84		418,000		9.96	$	26.84		—		—	$	—

		2,705,080						1,277,913

The weighted-average grant date fair value of share options granted during the three months ended March 31, 2006 and 2005 was $14.47 and $8.10, respectively. The total intrinsic value of share options exercised during the three months ended March 31, 2006 and 2005 was approximately $3.4 million and $0, respectively.

A summary of the status of the Company’s non-vested share grants at March 31, 2006 and changes during the three months ended March 31, 2006 is presented in the following table:


				Weighted Average
	Number of			Grant Date Fair
Nonvested Shares	Shares			Value Per Share

Nonvested at beginning of period		591,875		$	6.98
Granted during period		—			—
Vested during period		(230,625	)		6.98
Forfeited during period		—			—

Nonvested at end of period		361,250		$	6.98

As of March 31, 2006, there was $12.2 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 3.78 years. The total fair value of shares vested during the three months ended March 31, 2006 and 2005 was approximately $15.4 million and $6.2 million, respectively.

Cash received from share option exercises under the incentive plan was $0 for the three months ended March 31, 2006 and 2005, respectively. The actual tax benefit realized for the tax deductions from option exercise is $2.8 million and $0, respectively, for the three months ended March 31, 2006 and 2005.


9.	Related Party Transactions

Basic had receivables from employees of approximately $92,000 and $65,000 as of March 31, 2006 and December 31, 2005, respectively.

F2-16

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


10.	Earnings Per Share


		Three Months Ended
		March 31,

		2006		2005

		(Unaudited)
Numerator (both basic and diluted):
	Net income	$	19,681	$	5,801
Denominator:
	Denominator for basic earnings per share		33,261,539		28,186,147
	Stock options		1,093,089		571,182
	Unvested restricted stock		256,238		603,125
	Common stock warrants		2,291,362		2,796,706

	Denominator for diluted earnings per share		36,902,228		32,157,160

	Basic earnings per common share	$	.59	$	.21

	Diluted earnings per common share	$	.53	$	.18


11.	Business Segment Information

Basic’s reportable business segments are well servicing, fluid services, drilling and completion services and well site construction services. The following is a description of the segments:

Drilling and Completion Services: This segment focuses on a variety of services designed to stimulate oil and gas production or to enable cement slurry to be placed in or circulated within a well. These services are carried out in niche markets for jobs requiring a single truck and lower horsepower.

F2-17

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


								Drilling and			Well Site
		Well			Fluid			Completion			Construction			Corporate
		Servicing			Services			Services			Services			and Other		Total

*Three Months Ended March 31, 2006*
	(Unaudited)
Operating revenues		$	73,465		$	43,121		$	27,455		$	10,265		$	—	$	154,306
Direct operating costs			(41,610	)		(26,305	)		(13,854	)		(7,643	)		—		(89,412	)

Segment profits		$	31,855		$	16,816		$	13,601		$	2,622		$	—	$	64,894

Depreciation and amortization		$	5,694		$	3,520		$	2,321		$	830		$	472	$	12,837
Capital expenditures, (excluding acquisitions)		$	11,005		$	6,804		$	4,485		$	1,604		$	914	$	24,812
Identifiable assets		$	185,390		$	138,969		$	106,264		$	29,747		$	156,417	$	616,787
*Three Months Ended March 31, 2005*
	(Unaudited)
Operating revenues		$	44,798		$	29,303		$	10,764		$	8,948		$	—	$	93,813
Direct operating costs			(28,191	)		(19,238	)		(5,860	)		(7,108	)		—		(60,397	)

Segment profits		$	16,607		$	10,065		$	4,904		$	1,840		$	—	$	33,416

Depreciation and amortization		$	4,094		$	2,332		$	531		$	653		$	437	$	8,047
Capital expenditures, (excluding acquisitions)		$	8,182		$	4,660		$	1,061		$	1,306		$	874	$	16,083
Identifiable assets		$	134,569		$	90,003		$	25,400		$	24,213		$	104,283	$	378,468

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 March 31,

	2006			2005

Segment profits	$	64,894		$	33,416
General and administrative expenses		(18,005	)		(13,091	)
Depreciation and amortization		(12,837	)		(8,047	)
Gain (loss) on disposal of assets		200			(102	)

Operating income	$	34,252		$	12,176

F2-18

BASIC ENERGY SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


12.	Supplemental Schedule of Cash Flow Information:

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


	Three Months
	Ended March 31,

	2006		2005

	(In thousands)
Capital leases issued for equipment	$	5,203	$	1,032
Asset retirement obligation additions	$	413	$	—

Basic paid income taxes of approximately $6.9 million and $0 during the three months ended March 31, 2006 and 2005, respectively.


13.	Subsequent Events


*(a)*	*Debt Offering*


	In April 2006, the Company completed a private offering for $225,000,000 aggregate principal amount of 7.125% Senior Notes due April 15, 2016. The net proceeds from the offering were used to retire the outstanding Term B Loan balance and to repay current borrowings under the revolving credit facility. Any remaining proceeds will be used for general corporate purposes.

In connection with the retirement of the Term B Loan on April 13, 2006, we will expense remaining unamortized deferred debt issuance costs which amounted to approximately $2.7 million, net.

F2-19

APPENDIX A

GLOSSARY OF TERMS

Acidizing: The process of pumping solvent into the well as a means of dissolving unwanted material.

Brine water: Water that is heavily saturated with salt used in various well completion and workover activities.

Cased-hole: A wellbore lined with a string of casing or liner (generally metal casing placed and cemented) to protect the open hole from fluids, pressures, wellbore stability problems or a combination of these. Although the term can apply to any hole section, it is often used to describe techniques and practices applied after a casing or liner has been set across the reservoir zone, such as cased-hole logging or cased-hole testing.

Casing: Steel pipe placed in an oil or gas well as drilling progresses to prevent the wall of the hole from caving in, to prevent seepage of fluids, and to provide a means of extracting petroleum if the well is productive.

Drilling mud: The fluid pumped down the drilling string and up the well bore to bring debris from the drilling and workover operators to the surface. Drilling muds also cool and lubricate the bit, protect against blowouts by holding back underground pressures and, in new well drilling, deposit a mud cake on the wall of the borehole to minimize loss of fluid to the formation.

Electric wireline: Wireline that contains an electrical conduit, thereby enabling the use of downhole electrical sensors to measure pressures and temperatures.

Fishing: The process of recovering lost or stuck equipment in the wellbore.

Frac job or fracturing operations: A procedure to stimulate production of oil or gas from a well by pumping fluids from the surface under high pressure into the wellbore to induce fractures in the formation.

Frac tank: A steel tank used to store fluids at the well location to facilitate completion and workover operations. The largest demand is related to the storage of fluid used in fracturing operations.

Hot oil truck: A truck mounted pump, tank and heating element used to melt paraffin accumulated in the well bore by pumping heated oil or water through the well.

Newbuild: A newly built rig, as compared to a refurbished rig that may contain substantially all new components or new derrick but utilizes an older frame.

Plugging and abandonment activities: Activities to remove production equipment and seal off a well at the end of a well’s economic life.

Slickline. A form of wireline that lacks an electrical conduit and is used only to perform mechanical tasks such as setting or retrieving various tools.

Stimulation: The general process of improving well productivity through fracturing or acidizing operations.

Swab rig: Truck mounted equipment consisting of a hoist and mast used to remove, or “swab,” wellbore fluids by alternatively lowering and raising tools in a well’s tubing or casing.

Underbalanced drilling: A technique that involves maintaining the pressure in a well at or slightly below that of the surrounding formation using air, nitrogen, mist, foam or lightweight drilling fluids instead of conventional drilling fluid.

Water cut: The volume of water produced by a well as a percentage of all fluids produced.

A-1

Wellbore: The drilled hole of a well, which may include open hole or uncased portions, and which may also refer to the rock face that bounds the inside diameter of the wall of the drilled hole.

Well completion: The activities and procedures necessary to prepare a well for the production of oil and gas after the well has been drilled to its targeted depth. Well completions establish a flow path for hydrocarbons between the reservoir and the surface.

Well servicing: The maintenance work performed on an oil or gas well to improve or maintain the production from a formation already producing. It usually involves repairs to the downhole pump, rods, tubing, and so forth or removal of sand, paraffin or other debris which is preventing or restricting production of oil or gas.

Well workover: Refers to a broad category of procedures preformed on an existing well to correct a major downhole problem, such as collapsed casing, or to establish production from a formation not previously produced, including deepening the well from its originally completed depth.

Wireline: A general term used to describe well-intervention operations conducted using single-strand or multistrand wire or cable for intervention in oil or gas wells. Although applied inconsistently, the term is used commonly in association with electric logging and cables incorporating electrical conductors See “slickline” and “electric wireline” for specific types of wireline services.

A-2

No dealer, salesperson or other person is authorized to give any information or to represent anything not contained in this prospectus. You must not rely on any unauthorized information or representations. This prospectus is an offer to sell only the shares of common stock offered hereby, but only under circumstances and in jurisdictions where it is lawful to do so. The information contained in this prospectus is current only as of its date.

2,101,641 Shares

Basic Energy Services, Inc.

Common Stock

PROSPECTUS

, 2006

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS


ITEM 13.	*Other Expenses of Issuance and Distribution*

Set forth below are the expenses expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee and the NASD filing fee, the amounts set forth below are estimates:


Securities and Exchange Commission registration fee		$	5,420
NASD filing fee			0
Printing and engraving expenses			100,000
Legal fees and expenses			75,000
Accounting fees and expenses			75,000
Transfer agent and registrar fees			5,000
Miscellaneous			13,916

	TOTAL	$	275,000


ITEM 14.	*Indemnification of Directors and Officers*

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

II-1

not in good faith or which involve intentional misconduct or knowing violation of II-1 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.

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.


ITEM 15.	*Recent Sales of Unregistered Securities*

During the past three years, we have issued unregistered securities to a limited number of persons, as described below. None of these transactions involved any underwriters or public offerings, and we believe that each of these transactions was exempt from registration requirements pursuant to Section 3(a)(9) or Section 4(2) of the Securities Act of 1933, as amended, Regulation D promulgated thereunder or Rule 701 of the Securities Act of 1933. The recipients of these securities represented their intention to acquire the securities for investment only and not with a view to or for sale in connection with any distribution thereof, and appropriate legends were affixed to the share certificates and instruments issued in these transactions. No remuneration or commission was paid or given directly or indirectly. The following information gives effect to a 5-for-1 stock split effected prior to the completion of our initial public offering:

On October 1, 2003, we granted options to purchase an aggregate of 37,500 shares of common stock under our 2003 Incentive Plan to a new director at an exercise price of $5.1584 per share. We received no payments from the optionee upon issuance of the options.

II-2

On October 3, 2003, we issued an aggregate of 3,650,000 shares of common stock, including 912,500 shares of common stock issued into escrow, to former stockholders of FESCO Holdings, Inc. as consideration for all of the outstanding shares of FESCO Holdings, Inc. The implied value per share in connection with the share exchange was $5.1584 per share.

On October 3, 2003, we issued an aggregate of 3,304,085 shares of common stock in exchange for all of the outstanding shares of our Series A 10% Cumulative Preferred Stock and accrued dividends. The implied value per share in connection with the share exchange was $5.1584 per share.

On February 23, 2004, our board of directors approved the issuance of 837,500 shares of restricted stock to our officers under our 2003 Incentive Plan. These shares, as issued effective April 22, 2004 after stockholder approval of our Amended and Restated 2003 Incentive Plan, are subject to vesting in one-fourth increments for all officers other than Mr. Carter on February 24, 2005, 2006, 2007 and 2008, and with respect to shares owned by Mr. Carter, vesting one-half on February 24, 2005 and 2006. All of these shares are also subject to repurchase at the lower of their book value or their fair market value in accordance with our Second Amended and Restated Stockholders Agreement. We received no payments from the recipients upon the issuance of these shares.

On March 1, 2004, we granted options to purchase an aggregate of 37,500 shares of common stock under our 2003 Incentive Plan to a new director at an exercise price of $5.1584 per share. We received no payments from the optionee upon issuance of the options.

On March 23, 2004, we granted options to purchase an aggregate of 50,000 shares of common stock under our Amended and Restated 2003 Incentive Plan to employees at an exercise price of $5.1584. We received no payments from optionees upon issuance of the options.

On January 26, 2005, we granted options to purchase an aggregate of 100,000 shares of common stock under our Amended and Restated 2003 Incentive Plan to a new executive officer at an exercise price of $5.1584. We received no payment from the optionee upon the issuance of the options.

On March 2, 2005, we granted options to purchase an aggregate of 865,000 shares of common stock under our Amended and Restated 2003 Incentive Plan to employees at an exercise price of $6.98.

On April 7, 2006, we issued $225 million of 7.125% senior notes due 2016 in a private placement under Rule 4(2) of the Securities Act of 1933, as amended. The initial purchasers in the transaction were UBS Securities LLC, Banc of America Securities LLC, Lehman Brothers Inc., Credit Suisse Securities (USA) LLC and Goldman, Sachs & Co. The notes were offered and sold by the initial purchasers only to qualified institutional investors in accordance with Rule 144A under the Securities Act and to persons outside the United States in compliance with Regulation S of the Securities Act. The gross proceeds to Basic were approximately $225 million and the net proceeds to Basic (after deducting the initial purchasers’ discounts and commissions and Basic’s estimated expenses) were approximately $220.5 million.


ITEM 16.	*Exhibits and Financial Statement Schedules*

a. Exhibits:


	3	.1		—		Amended and Restated Certificate of Incorporation of the Basic Energy Services, Inc. (the “Company”), dated September 22, 2005. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)

II-3


3	.2	—	Amended and Restated Bylaws of the Company, dated December 14, 2005. (Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on December 14, 2005)
4	.1	—	Specimen Stock Certificate representing common stock of the Company. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on November 4, 2005)
4	.2	—	Indenture dated April 12, 2006, among Basic Energy Services, Inc., the guarantors party thereto, and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on April 13, 2006)
4	.3	—	Form of 7.125% Senior Note due 2016. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on April 13, 2006)
4	.4	—	First Supplemental Indenture dated as of July 14, 2006, among Basic Energy Services, Inc., the guarantors party thereto, and the Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on July 20, 2006)
5	.1*	—	Opinion of Andrews Kurth LLP
10	.1	—	Asset Purchase Agreement dated as of February 21, 2006 among Basic Energy Services, LP, Basic Energy Services GP, LLC, G&L Tool, Ltd., DLH Management, LLC and LJH, Ltd. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on March 2, 2006)
10	.2	—	Contingent Earn Out Agreement dated as of February 28, 2006 among Basic Energy Services, LP and G&L Tool, Ltd. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on March 2, 2006)
10	.3	—	Third Amended and Restated Credit Agreement dated as of October 3, 2003, amended and restated as of December 15, 2005, among the Company, the subsidiary guarantors party thereto, Bank of America, N.A., as syndication agent, Hibernia National Bank, as co-documentation agent, BNP Paribas, as co-documentation agent, UBS AG, Stamford Branch, as issuing bank, administrative agent and collateral agent, and the lenders party thereto. (Incorporated by reference to Exhibit 10.10 to the Company’s Annual Report on Form 10-K filed on March 23, 2006)
10	.4	—	Amendment No. 1 to Third Amended and Restated Credit Agreement, dated March 28, 2006, by and among the Company, the subsidiary guarantors party thereto, and UBS Loan Finance LLC, Bank of America, N.A., Hibernia National Bank, BNP Paribas, UBS AG, Stamford Branch, as administrative agent, and the lenders party thereto. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on April, 3, 2006)
10	.5	—	Purchase Agreement dated April 7, 2006, among the Company, the guarantors party thereto and the initial purchasers party thereto. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on April 13, 2006)
10	.6	—	Registration Rights Agreement dated April 12, 2006, among the Company, the guarantors party thereto and the initial purchasers party thereto. (Incorporated by reference to Exhibit 10.2 on the Company’s Current Report on Form 8-K filed on April 13, 2006)
10	.7	—	Summary of 2006 salaries and other compensation for named executive officers and certain employees (Incorporated by reference to Item 1.01 of the Company’s Form 8-K filed on March 8, 2006).

II-4


10	.8	—	Form of Indemnification Agreement (Incorporated by reference to Exhibit 10.1 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517) filed on September 28, 2005)
10	.9	—	Employment Agreement dated as of March 1, 2004 with Kenneth V. Huseman (Incorporated by reference to Exhibit 10.2 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on August 12, 2005)
10	.10	—	Employment Agreement dated as of May 1, 2003 with Dub W. Harrison (Incorporated by reference to Exhibit 10.3 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed August 12, 2005)
10	.11	—	Employment Agreement dated as of May 1, 2003 with Charles W. Swift (Incorporated by reference to Exhibit 10.4 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed August 12, 2005)
10	.12	—	Employment Agreement dated as of January 26, 2005 with Alan Krenek (Incorporated by reference to Exhibit 10.6 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed August 12, 2005)
10	.13	—	Second Amended and Restated Stockholders’ Agreement dated as of April 2, 2004 by and among Basic Energy Services, Inc. and the stockholders listed therein (Incorporated by reference to Exhibit 10.7 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed August 12, 2005)
10	.14	—	Second Amended and Restated 2003 Incentive Plan (Incorporated by reference to Exhibit 10.11 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed August 12, 2005)
10	.15	—	Form of Non-Qualified Option Grant Agreement (Executive Officer — Pre-March 1, 2005). (Incorporated by reference to Exhibit 10.12 of the Company’s Annual Report on Form 10-K filed on March 23, 2006)
10	.16	—	Form of Non-Qualified Option Grant Agreement (Executive Officer — Post-March 1, 2005). (Incorporated by reference to Exhibit 10.13 of the Company’s Annual Report on Form 10-K filed on March 23, 2006)
10	.17	—	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 Annual Report on Form 10-K filed on March 23, 2006)
10	.18	—	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 Annual Report on Form 10-K filed on March 23, 2006)
10	.19	—	Form of Restricted Stock Grant Agreement. (Incorporated by reference to Exhibit 10.16 of the Company’s Annual Report on Form 10-K filed on March 23, 2006)
10	.20	—	Form of Non-Qualified Stock Option Agreement (Director form effective March 2006) (Incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006)
10	.21	—	Form of Non-Qualified Stock Option Agreement (Employee form effective March 2006) (Incorporated by reference to Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006)
10	.22	—	Workover Unit Package Contract and Acceptance Agreement, dated as of May 17, 2005, by and between Basic Energy Services, Inc. and Taylor Rigs, LLC (Incorporated by reference to Exhibit 10.17 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed November 4, 2005)
10	.23*	—	Fee Reimbursement Agreement, dated as of July 24, 2006, by and among the Company, Southwest Partners II, L.P., Southwest Partners III, L.P. and Fortress Holdings, LLC

II-5


21	.1	—	Subsidiaries of Basic Energy Services (Incorporated by reference to Exhibit 21.1 to the Company’s Annual Report on Form 10-K filed on March 23, 2006)
23	.1**	—	Consent of KPMG LLP
23	.3	—	Consent of Andrews Kurth LLP (Contained in Exhibit 5.1)
24	.1*	—	Power of Attorney


*	Previously filed


**	Filed herewith

b. Financial Statement Schedules

With the exception of Schedule II — Valuation and Qualifying Accounts, all other consolidated financial statement schedules have been omitted because they are not required, are not applicable, or the required information has been included elsewhere in this Form S-1.


ITEM 17.	*Undertakings*

The undersigned Registrant hereby undertakes:


	(a) 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 provisions described in Item 14, 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) For purpose of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in the form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.

	(c) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus 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.

II-6

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, in the State of Texas, on August 3, 2006.


	BASIC ENERGY SERVICES, INC.


	By:	*


	Name: Kenneth V. Huseman


	Title:	President, Chief Executive Officer and Director

Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed below by the following persons in the capacities and on the dates indicated below.


Signature		Date


* Kenneth V. Huseman	President, Chief Executive Officer and Director (Principal Executive Officer)	August 3, 2006

/s/ Alan Krenek Alan Krenek	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)	August 3, 2006

* Steven A. Webster	Chairman of the Board	August 3, 2006

* James S. D’Agostino, Jr.	Director	August 3, 2006

* William E. Chiles	Director	August 3, 2006

* Robert F. Fulton	Director	August 3, 2006

* Sylvester P. Johnson, IV	Director	August 3, 2006

II-7


Signature			Date


* H.H. Wommack, III		Director	August 3, 2006

* Thomas P. Moore, Jr.		Director	August 3, 2006

*By:	/s/ Alan Krenek Name: Alan Krenek Title: Attorney-in-fact

II-8

EXHIBIT INDEX


3	.1	—	Amended and Restated Certificate of Incorporation of the Basic Energy Services, Inc. (the “Company”), dated September 22, 2005. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on September 28, 2005)
3	.2	—	Amended and Restated Bylaws of the Company, dated December 14, 2005. (Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on December 14, 2005)
4	.1	—	Specimen Stock Certificate representing common stock of the Company. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on November 4, 2005)
4	.2	—	Indenture dated April 12, 2006, among Basic Energy Services, Inc., the guarantors party thereto, and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on April 13, 2006)
4	.3	—	Form of 7.125% Senior Note due 2016. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on April 13, 2006)
4	.4	—	First Supplemental Indenture dated as of July 14, 2006, among Basic Energy Services, Inc., the guarantors party thereto, and the Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on July 20, 2006)
5	.1*	—	Opinion of Andrews Kurth LLP
10	.1	—	Asset Purchase Agreement dated as of February 21, 2006 among Basic Energy Services, LP, Basic Energy Services GP, LLC, G&L Tool, Ltd., DLH Management, LLC and LJH, Ltd. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on March 2, 2006)
10	.2	—	Contingent Earn Out Agreement dated as of February 28, 2006 among Basic Energy Services, LP and G&L Tool, Ltd. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on March 2, 2006)
10	.3	—	Third Amended and Restated Credit Agreement dated as of October 3, 2003, amended and restated as of December 15, 2005, among the Company, the subsidiary guarantors party thereto, Bank of America, N.A., as syndication agent, Hibernia National Bank, as co-documentation agent, BNP Paribas, as co-documentation agent, UBS AG, Stamford Branch, as issuing bank, administrative agent and collateral agent, and the lenders party thereto. (Incorporated by reference to Exhibit 10.10 to the Company’s Annual Report on Form 10-K filed on March 23, 2006)
10	.4	—	Amendment No. 1 to Third Amended and Restated Credit Agreement, dated March 28, 2006, by and among the Company, the subsidiary guarantors party thereto, and UBS Loan Finance LLC, Bank of America, N.A., Hibernia National Bank, BNP Paribas, UBS AG, Stamford Branch, as administrative agent, and the lenders party thereto. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on April, 3, 2006)
10	.5	—	Purchase Agreement dated April 7, 2006, among the Company, the guarantors party thereto and the initial purchasers party thereto. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on April 13, 2006)
10	.6	—	Registration Rights Agreement dated April 12, 2006, among the Company, the guarantors party thereto and the initial purchasers party thereto. (Incorporated by reference to Exhibit 10.2 on the Company’s Current Report on Form 8-K filed on April 13, 2006)


10	.7	—	Summary of 2006 salaries and other compensation for named executive officers and certain employees (Incorporated by reference to Item 1.01 of the Company’s Form 8-K filed on March 8, 2006).
10	.8	—	Form of Indemnification Agreement (Incorporated by reference to Exhibit 10.1 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517) filed on September 28, 2005)
10	.9	—	Employment Agreement dated as of March 1, 2004 with Kenneth V. Huseman (Incorporated by reference to Exhibit 10.2 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed on August 12, 2005)
10	.10	—	Employment Agreement dated as of May 1, 2003 with Dub W. Harrison (Incorporated by reference to Exhibit 10.3 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed August 12, 2005)
10	.11	—	Employment Agreement dated as of May 1, 2003 with Charles W. Swift (Incorporated by reference to Exhibit 10.4 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed August 12, 2005)
10	.12	—	Employment Agreement dated as of January 26, 2005 with Alan Krenek (Incorporated by reference to Exhibit 10.6 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed August 12, 2005)
10	.13	—	Second Amended and Restated Stockholders’ Agreement dated as of April 2, 2004 by and among Basic Energy Services, Inc. and the stockholders listed therein (Incorporated by reference to Exhibit 10.7 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed August 12, 2005)
10	.14	—	Second Amended and Restated 2003 Incentive Plan (Incorporated by reference to Exhibit 10.11 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed August 12, 2005)
10	.15	—	Form of Non-Qualified Option Grant Agreement (Executive Officer — Pre-March 1, 2005). (Incorporated by reference to Exhibit 10.12 of the Company’s Annual Report on Form 10-K filed on March 23, 2006)
10	.16	—	Form of Non-Qualified Option Grant Agreement (Executive Officer — Post-March 1, 2005). (Incorporated by reference to Exhibit 10.13 of the Company’s Annual Report on Form 10-K filed on March 23, 2006)
10	.17	—	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 Annual Report on Form 10-K filed on March 23, 2006)
10	.18	—	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 Annual Report on Form 10-K filed on March 23, 2006)
10	.19	—	Form of Restricted Stock Grant Agreement. (Incorporated by reference to Exhibit 10.16 of the Company’s Annual Report on Form 10-K filed on March 23, 2006)
10	.20	—	Form of Non-Qualified Stock Option Agreement (Director form effective March 2006) (Incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006)
10	.21	—	Form of Non-Qualified Stock Option Agreement (Employee form effective March 2006) (Incorporated by reference to Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006)
10	.22	—	Workover Unit Package Contract and Acceptance Agreement, dated as of May 17, 2005, by and between Basic Energy Services, Inc. and Taylor Rigs, LLC (Incorporated by reference to Exhibit 10.17 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-127517), filed November 4, 2005)


10	.23*	—	Fee Reimbursement Agreement, dated as of July 24, 2006, by and among the Company, Southwest Partners II, L.P., Southwest Partners III, L.P. and Fortress Holdings, LLC
21	.1	—	Subsidiaries of Basic Energy Services (Incorporated by reference to Exhibit 21.1 to the Company’s Annual Report on Form 10-K filed on March 23, 2006)
23	.1**	—	Consent of KPMG LLP
23	.3	—	Consent of Andrews Kurth LLP (Contained in Exhibit 5.1)
24	.1*	—	Power of Attorney


*	Previously filed


**	Filed herewith